MISO is likely still months away from returning its full workforce on-site to its multiple offices in the Midwest and South, based on indications this week from its pandemic incident response team.
The RTO said that while it is creating detailed return-to-work plans, it remains in a holding pattern and is still advising most non-control room employees to continue working from home.
“The problem for us, and I think everyone right now, is the situation is fluid, and we don’t have a solution yet,” MISO Executive Director of Incident Response Angela Weber told MISO South stakeholders during an Entergy Regional State Committee teleconference Monday. “It’s something we’re still working on and taking our time to do it right.”
MISO meets regularly with an infectious disease doctor and an epidemiologist for updates and advice, Weber said. “We make sure we’re responding in a very measured and informed way.”
The RTO is also monitoring infection rates around the country and pairing the Centers for Disease Control and Prevention’s recommended 14 days of sustained declining infection rates with adequate testing, contact tracing and ample hospital capacity, Weber said. If those criteria are satisfied, MISO would begin moving to normal operations, she said.
Weber’s comments came as the nation’s daily count of new infections nearly hit 66,000, the 37th straight day that the seven-day average of new infections in the U.S. had trended upward. Total COVID-19 deaths, which lag infections, are approaching 140,000.
Most of MISO’s non-control room employees have been working from home since mid-March, and the RTO has isolated its control room staff by forbidding other staff from entering control room buildings. (See Heat Counteracts COVID-19 Impact on MISO Load.) MISO’s meeting spaces are closed to in-person stakeholder meetings through at least the end of the year.
The grid operator has also expanded the financial and mental health counseling it offers its employees, Weber added.
Industry respondents criticized the team working on revisions to NERC’s standard for protection functions in automatic voltage regulators (AVR) for expanding the scope of the project beyond its initial mandate.
Comments on the proposed standard authorization request (SAR) for Project 2019-04 — modifications to reliability standard PRC-005-6 — opened June 2 and closed July 8. This is the second round of comments for the draft SAR; the first round opened in July 2019 and closed the following month.
The project was originally proposed in May 2019 by the North American Generator Forum (NAGF), which felt that the existing standard did not clearly explain its applicability to AVRs or prescribe appropriate maintenance activities for these devices. In the latest comment round, the SAR drafting team asked for comments on the following changes that it was considering:
Should bulk electric system protective functions that respond to electrical quantities inside excitation systems and other BES element control systems be included in PRC-005?
Does NERC’s current definition of “protection system” — which omits protective functions in the excitation and other control systems — create confusion concerning protective functions embedded in control systems?
Should the PRC-005 standard provide for the use of emerging DC supply technologies, battery-based or non-battery-based, and ensure that they are subject to maintenance requirements?
Is it reasonable for entities registered as under-frequency load shedding (UFLS)-only to be listed as applicable entities in the standard?
Entities Object to Scope Expansion
The scope of the changes took many respondents aback. Most notably, NAGF — despite submitting the original SAR — objected to what it characterized as an unwarranted expansion in the drafting team’s goals, particularly in their attempt to apply PRC-005 to control systems, for which it would be inappropriate.
“The updated SAR currently posted for comment appears to have expanded the scope significantly from the original wording of the NAGF SAR and evolved into a draft that the NAGF can no longer support,” NAGF’s Wayne Sipperly said in his comment on the first question. “NAGF requests that the SAR drafting team revert back to the original SAR as previously submitted … and limit this project to providing clear guidance on the scope and applicability of [AVR] protective functions on a synchronous generating unit with an installed digital AVR.”
Automatic voltage regulator
Sipperly’s comment was endorsed by a number of other industry representatives, as was his response to the second question. In that answer, he said that there was no chance that the definition of “protection system” could create confusion, unless it were extended to protective functions within control systems as the drafting team proposed.
Some respondents expressed more openness to the proposed expansion, though they were still uncertain about “vague” wording that created the chance of scope creep. Jennie Wike of Tacoma Public Utilities argued for unambiguous definitions of exactly which equipment was proposed for inclusion in the SAR.
“The protective functions should be limited to only those functions that impact the overall reliability and security of the BES,” Wike said.
Justification Falls Short, Commenters Say
Commenters also reacted with ambivalence to the proposal to set maintenance requirements for DC supply technologies as part of PRC-005. In a comment supported by several others, Edison Electric Institute’s Mark Gray said that he felt unable to support an expansion to the scope of the SAR without clear proof that the affected equipment were not covered by any existing standards.
“The description of the technology and industry need has not been adequately stated and explained in the SAR. It is also unclear how the current standard does not already address this technology,” Gray said. “Proposed changes to a reliability standard should clearly address any reliability gaps and other industry needs. … At this time, no justification has been provided nor has the increased scope been approved by the Standards Committee.”
On the final question regarding the extension of PRC-005 to cover UFLS-only entities, comments were generally supportive of including such utilities as consistent with other standards. The only significant objection came from Matthew Nutsch of Seattle City Light, who asked about “how many of these entities exist and how much impact … they have on the BES,” and whether their impact is great enough to justify the burden of requiring compliance with the standard. The potential compliance burden also weighed heavily in Nutsch’s overall reaction to the proposal.
“This SAR likely causes more burden than benefit to the protection and control of our BES assets,” Nutsch said. “If there is sufficient evidence to show that AVR trips are causing havoc across the interconnections, perhaps it is worth further consideration. However, as it is currently written, this SAR seems to add little value for the amount of effort it would entail to employ.”
Facing an unprecedented number of new generator applicants, MISO this week reaffirmed its aim to speed up its interconnection queue.
The grid operator hopes to shrink the time it takes to complete generation interconnection agreement negotiations and clear the queue’s three-part definitive planning phase (DPP), when it performs interconnection studies.
Currently, the queue’s DPP alone takes approximately a year to complete. Combined with interconnection agreement negotiations, the timeline grows to about 505 days. Earlier this year, stakeholders asked through a formal submission to the Steering Committee that MISO address DPP delays.
MISO has said that if the queue’s DPP and GIA negotiations could be shortened to a year total, it would further its goal of aligning the interconnection queue with planning under its annual Transmission Expansion Plan. (See MISO Targets Swifter Queue Processing.)
A speedier process could keep MISO executing interconnection agreements as it prepares to face its largest-ever queue. The June 2020 cycle of prospective projects could bring the interconnection queue to more than 750 projects totaling 112 GW.
Through early June, the RTO was performing interconnection studies on 406 projects totaling 62 GW, more than half of it solar generation. More than 350 additional projects totaling more than 50 GW applied to enter the interconnection queue before the June 25 deadline, interconnection engineer Cody Doll told the Interconnection Process Working Group on Tuesday.
Not all of the 350 projects may survive MISO’s application validation. “We won’t know until we go through and validate the projects which ones will be in the 2020 cycle,” Manager of Resource Utilization Project Management Jesse Phillips said.
This isn’t the first time the queue will exceed 100 GW. It peaked at a proposed 101 GW worth of projects in 2019 before declining as projects withdrew. MISO says about 20% of projects entering the queue complete the interconnection process.
“The cycles are massive, and they’re not slowing down,” Doll said. “It’s going to lead to challenges because there are so many projects.”
Doll said that with increased queue entrants, MISO’s ability to handle the administrative processing of the interconnection requests may be stretched thin. “We may need to throw more people at certain tasks,” he said.
Doll also said affected-system studies, where MISO must wait on other RTOs to study projects near the seams for impacts, remain an obstacle to shortening the timelines.
Several active queue cycles dating from 2017 are currently delayed at least into fall by ongoing affected-system studies. SPP’s studies are affecting projects in the Central and West planning regions, while PJM’s impact the East region’s projects.
Phillips said MISO continues to work with SPP on how the two can cut down on the time needed to conduct affected-system studies.
MISO’s next queue application deadline is March 18, 2021.
New England needs to build much more onshore transmission to facilitate the incoming surge of offshore wind generation, panelists on a Northeast Energy and Commerce Association webinar said Wednesday.
NECA convened the webinar to discuss how much offshore wind New England can integrate, with representatives from the New England States Committee on Electricity (NESCOE), Anbaric Development Partners and RENEW Northeast summarizing the results of studies their organizations requested from ISO-NE Planning Advisory Committee Briefs: June 17, 2020.)
NESCOE counsel and analyst Ben D’Antonio provided an overview of ISO-NE’s findings under the organization’s requested assumptions. The RTO concluded that about 5.8 GW of offshore wind can be interconnected using AC transmission without significant upgrades to the onshore grid. That’s “if you do it in a strategic way,” at certain points of interconnection, D’Antonio said.
But “above that threshold … major reinforcements to the system were identified as being necessary.” The RTO identified at least four 345-kV onshore lines that would need to be built to facilitate additional offshore resources.
ISO-NE identified several strategic points of interconnection for offshore wind resources that would negate the need for major onshore transmission upgrades — but only up to 5.8 GW. | ISO-NE
It also determined that it’s possible to interconnect up to an additional 2.2 GW — for a total of 8 GW — through long-distance HVDC lines without the need for new onshore transmission. But regardless of the solution, it found the costs to reaching the 8-GW mark were comparable: about $1 billion, D’Antonio said.
Perhaps more stark, however, is the huge amount of renewable energy that would be “spilled,” or curtailed, even with the additional transmission identified: more than 15 TWh/year. Most of that is attributable to oversupply during the fall and spring shoulder months, when load is low, and not to transmission congestion.
ISO-NE estimated the amount of renewables would be “spilled” under NESCOE’s scenarios. | ISO-NE
“This loss of clean generation can undermine state initiatives to reduce our carbon footprint,” said Katie Bellezza, senior vice president of commercial management and strategy for Novatus Energy, a RENEW member. RENEW’s study focused on Maine’s existing onshore wind, which already experiences significant curtailment.
“Land-based wind and new transmission is currently the least-cost renewable resource available in New England,” she said. “However, due to smaller procurements, it’s difficult to justify those transmission costs. With infrequent onshore renewable procurements of limited scale, we really need to look at other ways besides procurement to fund transmission.”
Anbaric requested that ISO-NE look at higher penetration levels than NESCOE, up to 12 GW. “When we put that request in just last year, it seemed potentially pretty ambitious, but it’s just been remarkable to see the [state OSW] goals increase,” said Peter Shattuck, Anbaric senior vice president for communications.
“When we look big-picture, what we need to avoid is the sort of situation we have now in Maine, where transmission was considered essentially an afterthought, and now there are a lot of bottled-up resources,” he said.
Clockwise from top left: Mary Usovicz, MUConnections; Katie Bellezza, Novatus Energy; Ben D’Antonio, NESCOE; Peter Shattuck, Anbaric; and Eric Wilkinson, Orsted. | NECA
Usovicz asked the panelists whether they thought there was a better solution.
Shattuck, whose company submitted its own proposal, said, “It just seems like this decision was made on a very narrow, capital-cost basis, and that [basis] risks deferring the upgrades that are going to be needed [for OSW]. … It was essentially a missed opportunity to think bigger picture and really reflect the moment that we’re in right now in New England, where we need a grid that’s centered on renewables.”
“I’ll just kind of state the obvious and say that [decision] was done for reliability, and trying to right-size a solution for reliability is a little bit different than trying to right-size it for maybe a public policy-related issue,” D’Antonio said.
Utilities and cooperatives in the Southeast have been meeting for months on a plan to create a regional 15-minute energy market, officials confirmed Wednesday.
The talks, led by Southern Co. and Duke Energy, were largely secret until Monday, when the initiative was mentioned at a meeting of stakeholders working on North Carolina Gov. Roy Cooper’s Clean Energy Plan. The Charlotte Business Journal was the first to report on the plan Tuesday, saying as many as 20 companies may be involved.
Officials of Southern, Duke and the Tennessee Valley Authority confirmed the talks Wednesday, saying the Southeast Energy Exchange Market (SEEM) would be a 15-minute energy market designed to lower customer costs, optimize new renewable energy resources and improve reliability.
Dominion Energy South Carolina; Oglethorpe Power; PPL subsidiary LG&E and KU Energy; Santee Cooper (the South Carolina Public Service Authority); the North Carolina Electric Membership Corp.; the North Carolina municipal members of ElectriCities; and several electric cooperatives also are reportedly involved in the talks.
‘Exploratory Stage’
Southern Co. spokesman Schuyler Baehman said talks are in the “exploratory stage.”
“If we determine that partnering with our neighbors makes sense, we’ll certainly take the appropriate steps to describe that more fully for regulators and stakeholders,” he said.
“While we’re still early in the learning phase, we’re eager to see the kind of benefits a regional energy market might have for our customers, particularly if it helps improve how we can jointly operate growing solar resources on our systems,” Duke spokeswoman Erin Culbert said. “This evaluation is a response to stakeholder interest we’ve been hearing for a few years on a potential energy market so we can advance these concepts and see if they make sense.”
| ISO/RTO Council
“If we determine that partnering with our neighbors makes sense, we’ll certainly take the appropriate steps to describe that more fully for the 10 million people we serve,” TVA spokesman Jim Hopson said.
The Southeast is the only region of the continental U.S. that has not moved to some form of regional market, continuing to be served by vertically integrated monopoly utilities. Lawmakers in North and South Carolina, however, have been discussing prospects for joining or creating a new regional market for more than a year.
Culbert said the SEEM would be limited to energy — not capacity — and build on the existing bilateral market. It would use the “same principles” as the Western Energy Imbalance Market but be less “granular [and] costly to set up,” she said.
“It would allow participants to buy and sell power close to the time electricity is consumed and would give system operators real-time visibility across neighboring electric grids,” she said, adding that better integration of renewables could mean fewer solar curtailments.
“This isn’t a regional transmission organization, nor does it prohibit the ability for any of the companies to form or join an RTO in the future,” she added. “No decisions have been made yet. As we learn more details, we’ll be sharing those with regulators and stakeholders and, if we proceed, would make the appropriate filings with FERC, etc.”
Lack of Transparency?
News of the utility discussions alarmed some stakeholders.
“More competition in the electricity sector is inherently good for ratepayers and the economy, but it’s not truly competition if vertically integrated utilities can continue exercising their monopoly power,” Katherine Gensler, vice president of regulatory affairs for the Solar Energy Industries Association, said in a statement. “As details emerge, policymakers must ensure that this imbalance market has the proper governance to ensure that ratepayers, generators and participating utilities can all share the benefits.
“While an energy imbalance market may be the best solution for the Southeast, we should take a collaborative approach to discussing utility business model reforms, including robust stakeholder input,” Gensler continued. “We cannot be in the situation where utilities ignore stakeholders and state legislators and simply announce their preferred solution. We care deeply about expanding competition, but today’s news shows an alarming lack of transparency.”
“The South’s power sector — dominated by large monopolies with not enough accountability or competition — is in need of significant change,” said Frank Rambo, senior attorney for the Southern Environmental Law Center. “A fully open wholesale electricity market could produce the efficiencies and competition that would result in cleaner energy and lower power bills, but a plan hatched in secret by the monopoly utilities that have most benefited from the status quo is not a promising vehicle to deliver that kind of change.”
A spokesman for the South Carolina Public Service Commission said he was unaware of the discussions. The North Carolina Utilities Commission did not immediately respond to a request for comment.
RTO Legislation
North Carolina House Bill 958, introduced in April 2019, would authorize the NCUC to require the state’s investor-owned utilities establish or join a regional transmission entity after determining such a move would be in the public interest. It was referred to the House Committee on Rules, Calendar and Operations of the House.
South Carolina lawmakers introduced legislation (S. 998 and H. 4940) in January 2020 that would establish an Electricity Market Reform Measures Study Committee to study the benefits of electricity market reforms and whether the legislature should adopt them. In February, H. 4940 crossed over to the Senate.
Prior Studies
In May, law firm Nelson Mullins Riley & Scarborough sponsored a webinar on “How Markets and Reform Can Reduce Electricity Costs in the Carolinas.”
Among those who spoke were Jennifer Chen of Duke University’s Nicholas Institute for Environmental Policy Solutions and the author of a March 2020 policy brief titled “Evaluating Options for Enhancing Wholesale Competition and Implications for the Southeastern United States.”
Rachel Wilson of Synapse Energy Economics shared evidence indicating that membership in an RTO would result in savings for Duke customers.
She said the 2012 merger of Duke and Progress Energy, which combined their generation fleets in the Carolinas, “resulted in hundreds of millions of dollars in savings,” prompting questions about whether joining an RTO would produce bigger savings.
One study estimated that joining PJM could reduce production costs for Duke’s North Carolina customers by up to $600 million annually, a savings of 9 to 11%, Wilson said.
In Duke’s 2018 integrated resource plan proceedings, Synapse compared the company’s proposed IRP with an alternative scenario for the North Carolina Sustainable Energy Association.
While the Duke IRP called for using new gas resources to meet future demand, the “market scenario” used solar paired with storage, as well as standalone solar and battery resources, to meet projected peak.
Under Duke’s IRP, fossil fuels would be 42% of its fuel mix with renewables representing 9%. The market scenario reduced coal to 1% and gas to 8%, with renewables taking a 27% share, imports representing 18% and nuclear making up most of the rest.
By 2033, Synapse said, wholesale costs under the market scenario would be 30% lower than under the IRP.
SPP’s Strategic Planning Committee on Monday unanimously endorsed its Strategic Market Roadmap for 2020 that is designed to improve market efficiency, reliability and price formation.
Staff told committee members a “calculated, holistic approach” to implementing the roadmap process will increase its value and affordability. As proposed, staff and stakeholders will annually identify, educate, rank and approve new and existing Integrated Marketplace initiatives for development over the next two to five years.
SPP says the roadmap ensures its strategic plan’s foundational strategies are driving the initiatives, increasing transparency and collaboration. SPP and stakeholders will gain efficiencies in budgeting, project management, cross-departmental resource planning and teamwork because of proactive planning and alignment of work, according to the RTO.
SPP’s annual Strategic Market Roadmap is developed beginning in October of each year. Above is the approval process for the next roadmap. | SPP
“This is a remarkable step forward,” said Larry Altenbaumer, chair of both the SPC and SPP Board of Directors.
The 2020 roadmap resulted in 44 initiatives, ranging from offering an uncertainty market product to developing a real-time hedging product, dispersed into three buckets through 2025: high priority, medium priority and parking lot. Most of the initiatives (38 of 44) seek to improve market efficiency.
The Markets and Operations Policy Committee will consider the roadmap Wednesday during its quarterly meeting.
Erin Cathey, SPP senior market design analyst, piloted the process with the Market Working Group in 2017-18. Additional structure was added to the process before work on the 2020 development cycle last October.
SPP staff and stakeholders have prioritized 44 strategic market initiatives. | SPP
She said managing the roadmap will be an ongoing effort, calling it a “living work plan” necessitated by a “dynamic environment with diverse and changing needs.”
Subsequent development cycles will be condensed, beginning in October and finishing in time for approval during the regular April governance meetings.
Over the next few years, the roadmap will be added to SPP’s transmission planning, operations and supply adequacy functional areas.
Members narrowly approved a recommendation, by an 8-5 vote, to maintain a 1.0 benefit-to-cost threshold for economic projects, which brought out the usual divisions between transmission owners and transmission customers. The Economic Studies Working Group analyzed whether SPP should increase the B/C ratio to between 1.05 and 1.25 before deciding to stick with the status quo.
“There’s almost a [transmission] consumer-IOU [investor-owned utility] dichotomy,” said Golden Spread Electric Cooperative’s Mike Wise, who voted against the measure. “We’ve got to do better than this. This was an effort by consumers to ensure we’re not inappropriately building transmission that doesn’t have a cost benefit.”
NextEra’s Holly Carias updates the Strategic Planning Committee on the Markets and Operations Policy Committee’s work. | SPP
Oklahoma Gas & Electric’s Greg McAuley asked to correct the record and said, “We’re one IOU in favor of raising the benefit-cost ratio.
“We’re talking about 40-year assets,” he said. “We’re looking for a little bit more security in the decision to ensure what is being constructed will deliver those benefits.”
A 1.25 threshold would have required a Tariff change and revisions to the transmission planning process, SPP General Counsel Paul Suskie said.
The SPC unanimously approved the addition of ramping capability to the Integrated Marketplace and a study of essential reliability service and other reliability service. Wise abstained from the latter vote, noting the three stakeholder groups that had already approved the study voted on whether SPP had finished its work.
The MOPC will vote on ramping capability as a revision request (MWG RR402) on its consent agenda. The measure introduces a design change that uses near-real-time economic dispatch to evaluate intraday reliability unit commitments for fast-start resources.
The D.C. Circuit Court of Appeals on Tuesday ordered the Environmental Protection Agency to reopen a complaint filed by New York state over air pollution from upwind coal generators in nine other states.
New York petitioned the EPA in 2018 to find that power-generating and other facilities in Illinois, Indiana, Kentucky, Maryland, Michigan, Ohio, Pennsylvania, Virginia and West Virginia were violating the “good neighbor” provision of the Clean Air Act with emissions that made it difficult for the New York metropolitan area to maintain compliance with the National Ambient Air Quality Standards (NAAQS) for ozone.
The EPA denied New York’s petition on the grounds that it failed to meet standards for proving “good neighbor” violations by demonstrating that cost-effective controls could be imposed on the pollution sources.
But in a unanimous decision, the three-judge panel determined that the EPA’s decision was “convoluted and seemingly unworkable” and relied on “faulty interpretations” of the Clean Air Act, which led it to conclude that New York did not have an air quality problem under the 2008 NAAQS.
“The EPA’s test, at best, was a moving target and, at worst, demanded likely unattainable standards of proof,” Judge Patricia A. Millett wrote in her opinion.
New York City
In March 2018, New York filed a Section 126(b) petition asking the EPA to find that approximately 350 sources of nitrogen oxides, mostly coal-fired power plants, were contributing significantly to the New York metro area’s — Northern New Jersey, Long Island, New York City and Connecticut — nonattainment under the 2008 and 2015 NAAQS. Although New York state filed the petition, New Jersey and New York City joined in appealing the EPA’s ruling.
The court said, although EPA’s October 2019 ruling assumed that the emissions in the nine states were “linked” to air quality problems in the New York metro area, it denied the petition based on New York’s failure to establish significant contributions from upwind sources under either the 2008 or 2015 NAAQS.
The EPA said New York’s “assessment of whether the sources” could be “further controlled through implementation of cost-effective controls [was] insufficient” and could have met its “evidentiary burden” through several analyses, including describing or quantifying available emissions reductions from the named sources or describing the downwind air quality impacts of controlling the sources located in the nine states.
In its decision, the court said the EPA’s reasons for rejecting the petition were “arbitrary and capricious” because the agency failed to provide a “reasoned explanation” why the petition failed to show that the named sources of pollution contributed to environmental nonattainment in the state and that the New York metro area did not have a “cognizable air quality problem” under the 2008 NAAQS.
The petition will now go before review at the EPA with the judges not imposing a formal deadline for a decision. New York had asked the court to impose a 60-day deadline for a decision.
“Although we decline to impose a formal deadline at this time, we fully expect the EPA to act promptly on remand,” the court said.
Environmental groups hailed the court’s decision.
“Today’s decision will help protect the lives and health of millions of New Yorkers who are threatened by the smog that blows across state lines,” said Liana James, attorney for the Environmental Defense Fund. “The ‘good neighbor’ provisions of the Clean Air Act exist so that downwind states don’t have to struggle with dangerous pollution alone. Today, the court reinforced that fundamental ideal and ordered EPA to do its job.”
Presumptive Democratic presidential nominee Joe Biden on Tuesday outlined a $2 trillion plan to eliminate power sector carbon emissions by 2035 and make the U.S. the leader in electric vehicle production, calling the climate change challenge a “once-in-a-lifetime opportunity to jolt new life into our economy, strengthen our global leadership [and] protect our planet for future generations.”
In a 23-minute speech at the Chase Center in Wilmington, Del., Biden pledged to build on the billions in clean energy investments of the Obama administration, rejoin the Paris Agreement on climate change and reverse the Trump administration’s environmental rollbacks.
Developed with input from former presidential candidates Sen. Bernie Sanders (I-Vt.) and Gov. Jay Inslee (D-Wash.), among others, Biden’s plan is markedly more ambitious than the policies he backed during the primaries, when he called for spending $1.7 trillion over 10 years and eliminating CO2 emissions from power plants by 2050.
The shift reflects both his desire to motivate the liberal wing of the Democratic Party and to provide an economic stimulus to aid recovery from the coronavirus pandemic. How successful he is in implementing the agenda will depend not just on his election but also on Democratic gains in Congress, particularly whether they regain control of the Senate.
“We’re not just going to tinker around the edges,” he said. “Science tells us we have nine years [to cut emissions] before the damage is irreversible, so my timetable [for] results is my first four years as president.”
To reach net-zero emissions economy-wide by 2050, Biden proposed:
Converting the federal vehicle fleet to EVs and adding 500,000 EV charging stations, moves he claimed would create 1 million new jobs in the U.S. auto industry and its supply chains.
Zero-emission public transit for every city with 100,000 or more residents.
Improving energy efficiency of 4 million buildings and 2 million homes over his first term through direct cash rebates and low-cost financing.
Investments to reduce the costs of clean energy technologies, including battery storage, negative emissions technologies, next-generation building materials, renewable hydrogen and advanced nuclear.
Creating a Civilian Climate Corps to work in “climate-smart” agriculture, resilience and conservation, including 250,000 jobs plugging abandoned oil and natural gas wells and reclaiming abandoned mines, an idea championed by Inslee and modeled after the New Deal Civilian Conservation Corps.
Seeking to head off likely criticism that the plan will harm the economy, Biden framed his proposal as an economic development program, repeatedly referring to creation of “union” jobs. Building on the “Buy American” theme he sounded in his economic plan released July 9, Biden also made clear he will contest President Trump’s economic nationalism.
“When Donald Trump thinks about climate change, the only word he can muster is ‘hoax.’ When I think about climate change, the word I think of is ‘jobs,’ good-paying, union jobs,” Biden said.
Presumptive Democratic presidential nominee Joe Biden announced his climate plan in a speech at the Chase Center in Wilmington, Del. | C-SPAN
The Trump campaign accused Biden of a bait-and-switch, saying “his so-called ‘Build Back Better’ plan and radical proposal to spend $2 trillion in four years on Green New Deal policies make it clear that union jobs related to oil, natural gas, fracking and energy infrastructure will be on the chopping block.”
Biden would use the federal government’s buying power to raise wages — requiring vendors receiving government contracts to pay at least $15/hour — and provide demand for EVs while also offering rebates for car owners to switch from gasoline-powered autos.
“The United States owns and maintains an enormous fleet of vehicles, and we’re going to convert these government fleets to electric vehicles, made and sourced right here in America, with the government providing the demand and the grants to retool factories that are struggling to compete. The U.S. auto industry and its deep bench of suppliers will step up, expanding capacity so that the United States — not China — leads the world in clean vehicle production,” Biden said.
“We know how to do this. [The Obama] administration rescued the auto industry and helped it retool; made solar energy the same cost as traditional energy; weatherized more than 1 million homes. And we’ll do it again, but this time bigger and faster and smarter,” he continued. “These aren’t pie-in-the-sky dreams. These are actionable policies that we can work on right away. We can live up to our responsibilities [and] meet the challenge of a world at risk of a climate catastrophe.”
Environmental Justice
Biden also pledged to address pollution’s impact on poor and minority communities, in part by ordering the attorney general to implement via executive action key parts of Sen. Cory Booker’s (D-N.J.) Environmental Justice Act of 2019, which would strengthen residents’ legal protections against polluters.
Drawing from New York state’s Climate Leadership and Community Protection Act, Biden said he would target 40% of the government’s clean energy investments to poor communities, including clean energy and energy efficiency deployment; clean transportation; affordable and sustainable housing; training and workforce development; and the remediation of legacy pollution.
He also would establish an Environmental and Climate Justice Division within the Department of Justice. Biden said the Trump administration’s EPA has referred the fewest number of criminal antipollution cases to DOJ in 30 years.
Separately, the Government Accountability Office reported Tuesday that the Trump administration low-balled its estimate on the social cost of carbon to justify repealing or weakening climate change regulations. The report said the administration’s estimates were seven times lower than previous federal estimates.
Reaction
Biden took no questions after his speech, and his campaign has not detailed how he would fund the spending program. He has called for additional economic stimulus funding, raising the corporate income tax rate to 28% from 21% and increasing income taxes on the wealthy.
While some climate activists complained Biden would not ban fracking, others praised his agenda as the most ambitious climate plan of any U.S. presidential nominee. “We shaved 15 years off Biden’s previous target for 100% clean energy,” tweeted Rep. Alexandria Ocasio-Cortez (D-N.Y.), co-author of the Green New Deal, who served as chair of Biden’s climate task force.
Republicans said it would bust the budget and be a drag on the economy. “Joe Biden’s radical climate agenda would kill 10 million jobs, enrich our enemies and send your taxes through the roof,” tweeted Republican National Committee Chairwoman Ronna McDaniel.
The American Petroleum Institute had a muted reaction. “You can’t address the risks of climate change without America’s natural gas and oil industry, which continues to lead the world in emissions reductions while delivering affordable, reliable and cleaner energy to all Americans,” it said in a statement.
MISO this week said it foresees hundreds of gigawatts in mostly carbon-free resource additions through 2039, according to its new transmission planning future scenarios.
The prediction is part of the development of three, 20-year scenarios to be used in MISO’s transmission planning beginning with the 2021 cycle of its Transmission Expansion Plan (MTEP 21).
Each scenario takes into account different variables such as members and states meeting their renewable-procurement targets, electric vehicle adoption rates and emission reductions.
Future I assumes an 85% probability that companies’ renewable growth and carbon-cutting goals materialize and full certainty that states’ clean energy plans come to pass. It also assumes a 40% reduction in carbon emissions from 2005 levels by 2040. Under this scenario, MISO predicts that 132 GW of new resources are built — more than half of which are renewable — and 83 GW retire from 2020 to 2039.
Future II assumes members meet or exceed decarbonization plans while carbon emissions drop 60% from 2005 levels. EV adoption stimulates demand, while residential and commercial electrification flourishes, resulting in 30% energy growth footprint-wide by 2040. With that comes 154 GW of new resources with a larger share of renewables than Future I and 82 GW of retirements.
Future III also assumes members fulfill their renewable plans and consumers adopt EVs. It foresees a sharp increase in demand from residential and commercial electrification, resulting in 50% energy growth. MISO also experiences a minimum 50% renewable penetration level as carbon emissions dip 80% below 2005 levels. The RTO predicts 261 GW of new resources — including more than 137 GW of renewables — and 114.5 GW in retirements by 2040 under this scenario.
“It’s Future III, where we have heavy carbon constraints, that we start to see retirement,” MISO Planning Manager Tony Hunziker said during a special teleconference Monday to discuss the futures. “Specifically, with Future III, you see many more resources added to get to that 80% carbon-reduction goal.”
Solar is the dominant new resource in Futures I and II, while it breaks even with wind in Future III. MISO planners said an increase in energy demand from electrification also contributes to the steep jump in generation expansion from Future II to Future III.
Hunziker said MISO still has to present forecasted capacity additions broken down by local resource zones. It did not break down the predicted retirements by resource type.
The new trio of futures are considered nearly finalized despite some stakeholders’ calls for an additional 20-year scenario that contemplates the impact of the COVID-19 pandemic on resource expansion. (See COVID-19, Electrification Stir MISO Futures Debate.)
“Really, it’s too soon to determine the impact,” MISO CEO John Bear said in mid-May.
During March Board Week, Jennifer Curran, vice president of system planning, said she had been fielding stakeholder inquiries over whether the 20-year planning scenarios remain the best estimate considering an economic slowdown spurred by the pandemic.
Curran said it was her “hunch” that the least aggressive renewable predictions would continue to be relevant, especially considering that the futures are meant to cover 20 years of planning. She said her planning team would “stress test” the predictions.
The RTO plans to present finalized futures in August.
The Queue and a Long-term Tx Plan
Curran’s hunch at the beginning of the pandemic may prove correct.
MISO’s interconnection queue could come close to doubling in size despite months of states of emergency in its footprint that laid waste to recent economic gains.
The RTO’s last queue application cycle, which closed in late June, stands to bring the interconnection queue to about 115 GW, “the largest queue in MISO history,” according to Executive Director of System Planning Aubrey Johnson.
“Everything that comes into the queue does not represent an interconnection agreement, but it does signal a healthy appetite,” Johnson told stakeholders at a virtual Entergy State Regional Committee meeting on Monday.
Earlier in June, the interconnection queue contained 406 projects, totaling just 62 GW, enough capacity to cover about half of MISO peak load.
Johnson said MISO now plans to embark on a series of long-range transmission planning studies separate from the annual MTEP study cycle. He said the RTO believes conditions today are pointing to a lower carbon portfolio, and it may need some major transmission projects to accommodate the change.
So far, MISO has committed to an expanded North Region Economic Transfer, which evaluates system limitations caused by non-thermal constraints between the renewable-rich northwestern portions of the footprint and load centers in the Upper Midwest. (See CapX2050 Prompts MISO Focus onMidwest Tx.) The grid operator is also conducting a study to determine options for Lower Michigan to increase its capacity import and export limits, which have gotten increasingly tight.
Johnson said MISO is also open to other ideas for long-range studies from stakeholders. “I think we’re going to take a look at all requests.”
The announcement comes after MISO executives for months have been noncommittal about such studies.
Curran said in March that it comes as no surprise that a second long-range transmission plan draws arguments from either side of the fence. “There are some who say, ‘Why haven’t you done this already?’ and some who say, ‘Why are you doing this?’ It’s a wide range of opinions,” Curran said.
MISO last took on a long-range transmission package in 2011 with the Multi-Value Project portfolio.
California is moving quickly to adopt microgrids to store wind and solar energy and to provide electricity during public safety power shutoffs (PSPS) in wildfire season, but long-term energy storage and resilience remain problems, panelists said last week at a California Energy Commission workshop on “Assessing the Future Role for Microgrids.”
Leaders of the CEC, the California Public Utilities Commission and CAISO met in three sessions over two days during the workshop, hearing from panelists and presenters on the challenges and promise of microgrids: small-scale generation and distribution systems that can power a single building or a whole community.
Over a total of six hours, participants discussed using microgrids to offset fire-prevention blackouts starting this fall and, in the longer term, to store renewable power and make up for possible capacity shortfalls during the switch from natural gas plants to renewable resources in the next three years.
Senate Bill 100, passed in 2018, requires load-serving entities to provide only zero-carbon electricity to retail customers by 2045.
“Microgrids are one of the tools that will help the state get to our 100% clean energy standard in the most efficient and equitable way possible,” said CEC Vice Chair Janea Scott, who led the sessions.
CPUC President Marybel Batjer said she’s worried about Pacific Gas and Electric’s plan to use diesel generators to supply electricity during PSPS events this summer and fall. PG&E intends to connect hundreds of diesel generators at substations to supply customers during the shutoffs.
“I am concerned that this wildfire season, we will see a lot of diesel generation used to ensure resiliency, and we have to get to a cleaner and quieter form of resiliency backup power,” Batjer said.
Neil Millar, CAISO’s vice president for transmission planning and infrastructure development, said it was important for the ISO to learn about the “different flavors of microgrids that are evolving” and to ensure “our existing processes are adequate for accommodating them.”
CAISO and the CPUC are working to manage the connection of microgrids to the statewide grid and to include microgrids in the state’s resource planning process, he noted.
Fast-tracked Measures
Senate Bill 1339, passed in 2018, directed the CPUC to “facilitate the commercialization of microgrids for distribution customers of large electrical corporations” by Dec. 1.
In response, the CPUC established a new section in its Energy Division focused on microgrids and fast-tracked rulemaking to speed the connection of microgrids in anticipation of this year’s fire season, which typically lasts from late summer through November.
In June, it adopted a proposed decision ordering investor-owned utilities to streamline and expedite interconnection processes for microgrid resilience projects and to work with local and tribal governments to bring the projects online by late summer, in time for the anticipated power shutoffs. (See California PUC Approves Microgrids, Fire Plans.)
The CPUC directed energy storage facilities to import power from the grid prior to PSPS events. It permitted PG&E to upgrade substations and install diesel generators, but only for the 2020 fire season. And it ordered IOUs to increase staffing to hasten microgrid interconnections.
“We’re really focused on … fast-tracking near-term strategies and actions we can put in place in time for this year’s wildfire season,” PUC Senior Analyst Jessica Tse said during the first microgrid workshop session on July 7.
Beyond the next few months, the CPUC and CEC are seeking ways to build microgrids that use wind and solar with battery storage to ride out power outages. (See CPUC Proposal Would Promote Microgrids.)
The CEC is funding millions of dollars in pilot projects to find microgrid solutions that can be replicated and installed on a larger scale. The projects are on military bases and tribal lands, at ports and airports, in industrial settings and wastewater treatment plants, and in low-income and disadvantaged communities.
Projects recently approved include $6 million to determine if it might be feasible to use banks of batteries that have been removed from electric vehicles, but still have plenty of useful life, for storage in microgrids. With 750,00 EVs sold so far, and millions more expected to hit California roads in the next decade, there will be a lot of used batteries, CEC Chair David Hochschild said. (See Calif. Energy Commission OKs $22M for Storage.)
The city of Fremont, Calif., employs solar and battery storage to power critical facilities such as fire stations. | City of Fremont
In another CEC-funded project, the city of Fremont is using solar and battery storage to allow critical facilities such as fire stations to “island” from the grid for up to three hours. But local jurisdictions need the ability to provide power while disconnected from the grid for longer periods, said Rachel DiFranco, the city’s sustainability manager.
PG&E’s fire-safety blackouts in the fall of 2019, affecting hundreds of thousands of customers, lasted for days at a time. (See CPUC Orders Changes to PG&E Shutoff Rules.)
Earthquakes and wildfires could sever ties to the grid for even longer periods, said Rosa Vivian Fernández, CEO of the San Benito Health Foundation, a small clinic that serves thousands of farmworkers in the city of Hollister. In August 2019, San Benito became the first health care facility in California to run entirely on its own zero-carbon microgrid using a rooftop solar array and lithium-ion battery storage.
Fernandez said she learned from visiting Puerto Rico after Hurricane Maria in 2017 that health care facilities could be disconnected from power for weeks, unable to serve patients.
“When disaster strikes … [you] may have severe damage to infrastructure,” she said during the first of Thursday’s two workshop sessions.
Seth Baruch, director of energy and utilities for health care giant Kaiser Permanente, explained why Kaiser had decided to install microgrids at a growing number of its facilities.
In 2018, the Kaiser Permanente Richmond Medical Center was the first hospital in California to install a renewable-energy microgrid for backup power during outages. Hospitals generally use diesel generators for emergency power, but Kaiser is pursuing microgrids as it seeks to become carbon neutral and because diesel fuel can run short in emergencies, Baruch said.
“When you need diesel, everyone needs diesel,” he said. With power shutoffs and potential surges in COVID-19 cases, Kaiser wants to ensure its facilities have power “24/7” for days at a time, he said.
Hydrogen Fuel Cells
The need for microgrids that can supply long-term backup power prompted a discussion Thursday, during the workshop’s final session, on deploying microgrids that use hydrogen fuel cells, which produce electricity through an electrochemical reaction of hydrogen and oxygen.
Lithium-ion batteries can only provide power for short-duration outages. Fuel cells can provide power indefinitely given a supply of hydrogen and oxygen produced by separating water into its components with a solar-powered electrolyzer, advocates said Thursday.
Stone Edge Farm, a 16-acre Sonoma County winery, has a microgrid with solar panels, batteries, an electrolyzer that produces hydrogen from rainwater and a bank of hydrogen fuel cells, winery owner Mac McQuown told commissioners.
“Our objective in our microgrid is to be independent of the utility grid 24/7, 365,” McQuown said.
Stone Edge Farm in Sonoma County, Calif., uses an electrolyzer and hydrogen fuel cells to store solar energy for use during the winter rainy season. | Stone Edge Farm
Microgrids using fuel cells power a low-income housing community in Brooklyn, a college in Bridgeport, Conn., and a high school and fire stations in Woodbury, Conn., said Jack Brouwer, director of the National Fuel Cell Research Center at the University of California, Irvine.
“Fuel cells have this opportunity to do that because they have very high power capabilities to power a whole community,” Brouwer said.
The big problem is cost. In applications such as microgrids, fuel cells produce electricity at $4,000 or more per kilowatt, the NFCRC says on its website. Fuel cells would be competitive in providing power for stationary loads if they reach an installed cost of $1,500 or less per kilowatt, it says.
Current research is seeking to reduce costs by using less expensive materials and producing fuel cells on a larger scale, the NFCRC says.
Brouwer said using hydrogen technology in conjunction with wind, solar and battery storage is another way to make fuel cells more practical. Existing natural gas pipelines might also be able to carry hydrogen, but that idea has proven controversial among clean-energy advocates who want to do away with natural gas entirely, he said.
Still, he said, California may ultimately need hydrogen fuel cells to provide electricity during long outages and to meet its ambitious decarbonization goals.
Hydrogen can “deliver resilience for weeks on end,” Brouwer said, and “the solution to get all the way to zero [carbon] needs something like fuel cells and hydrogen.”
Millar, with CAISO, said he agreed. “The solution here isn’t one or the other; it’s all of the above,” he said.
