ERCOT said last week that its corporate members have approved the elections of two unaffiliated directors, the re-election of a third unaffiliated director and amendments to the grid operator’s amended and restated bylaws.
Staff conducted a ballot vote “to resolve the items” before a scheduled Friday special meeting of corporate or voting members. They received enough votes to pass each of the four motions on July 2 and canceled the special meeting.
ERCOT plans to file the three director nominations for approval with the Texas Public Utility Commission this week. It expects approval in early November.
Board Chair Craven Crowell, Vice Chair Judy Walsh and Director Karl Pfirrmann all roll off the board when their terms expire at the end of this year.
ERCOT has already filed the bylaw amendments with the PUC for its expedited approval (50918). That should come by July 31, according to the docket’s procedural schedule. The amendments address the need and processes for teleconference meetings under social-distancing requirements related to the COVID-19 pandemic.
Demand, Temps on the Rise
June’s peak demand in ERCOT’s footprint came within 116 MW of last June’s peak, a sign that consumer demand and summer heat are nearing normal levels. The grid operator recorded a peak demand of 68,043 MW during the hour ending at 6 p.m. on June 8. Peak demand last June was 68,159 MW.
Gas-fired resources accounted for 40.9% of the energy produced during the month, with wind energy responsible for 23.34%. Coal resources provided 16.6% of ERCOT’s energy in June.
Wind energy was responsible for almost a quarter of ERCOT’s energy production in June. | Apex Clean Energy
The grid operator was expecting a potential new weekend peak demand and a new all-time peak on Monday, July 13. ERCOT set a new all-time peak of 74.8 GW last year and has predicted a new mark of 75.2 GW this year, almost 1.5 GW less than staff predicted before Texas began locking down in March.
A heat wave continues to bake the Southwest and has brought triple-digit temperatures to much of Texas.
MISO’s Independent Market Monitor said the RTO would be better served by an even higher planning reserve margin, two days after it recorded its first emergency of the summer.
Monitor David Patton said the grid operator should be using a 20% planning reserve margin requirement instead of the current 18% requirement that was in place when it called a maximum generation event on July 7. MISO’s planning reserve margin has climbed steadily in recent years; in 2017, it was just under 16%.
Speaking during a Market Subcommittee teleconference Thursday, Patton said part of the problem is MISO does not assume that planned generation outages and derates occur in the summer months.
But MISO is wrong there, he said.
Had it accounted for historical planned and unreported summertime outages, MISO would find its 18% margin requirement would look more like 11%, Patton said. If the RTO only included load-modifying resources that have lead times of two hours or less, that margin would fall to 8%, he said.
Patton said he would be “comfortable significantly reducing LMR accreditation to a two-hour” notification time. He said LMRs with six-hour notification needs provide “almost no reliability value” and wondered why they were being treated comparably with more valuable resources.
“It is the case that MISO has made improvements to notify LMRs to be ready ahead of time. And that’s good. But it’s still the case that MISO cannot see emergencies that far in advance,” he said.
Patton said excluding planned outages from reserve margin planning and accrediting long-lead LMRs contributes to the footprint’s tight conditions.
“We’re not as adequate as we think we are,” he said. “I think we’re adequate for this summer, but improving how we accredit capacity and price shortages will be increasingly important.”
Patton also said MISO needs higher pricing during shortages, especially as more intermittent resources are introduced into the resource mix.
“I’m not sure that we need new [market] products as much as we need really good shortage pricing,” he said.
Another Emergency Declaration
The Monitor’s recommendations were delivered as much of MISO Midwest was gripped by a persistent heat wave.
The high temperatures prompted MISO to issue a maximum generation emergency about 1-5:30 p.m. July 7 for its Northern and Central regions.
MISO real-time prices at 3 p.m. ET July 9 | MISO
LMPs at the Michigan hub exceeded $400/MWh on July 7 and neared $700/MWh around 3 p.m. Thursday. MISO’s peak load topped out at just over 114 GW on Thursday. The RTO had planned for a 120-GW peak that day.
MISO first issued a hot-weather alert and capacity advisory on July 1 and a conservative operations declaration beginning July 6. Conservative operations — where MISO requests that all transmission and generation outages be put on hold, if possible — were in effect through Friday.
MISO imported capacity from PJM during the July 7 emergency, even as the PJM region was also experiencing stifling heat.
Patton said MISO is mostly saved from capacity deficiencies during hotter-than-normal weather combined with low wind output by its “substantial” import capability from its footprint’s neighbors. He said imports are “utilized to avoid shortages in all the hottest conditions.”
He also reminded stakeholders that MISO still has a “theoretically flawed” capacity market where demand doesn’t set capacity’s reliability value. MISO’s vertical demand curve causes resources to prematurely retire, he said.
Patton also noted that MISO had several warm days with air conditioning demand in March and April. He said spring load would have been slightly higher than average but for the languishing demand introduced by COVID-19 pandemic-related lockdowns.
MISO executives said they will prepare data on and a review of the July 7 emergency event for the Reliability Subcommittee meeting July 30.
MISO’s market platform upgrade project is $20 million over budget as staff and vendors navigate the intricacies of replacing a decades-old system and pandemic-related supply chain issues.
The project’s costs have risen to nearly $160 million, up from the $140 million projected last year. MISO Executive Director of Digital Strategy Jeff Bladen said the increase is largely because of the complexities of swapping out system components that couldn’t be foreseen two years ago.
Speaking during Thursday’s Market Subcommittee meeting, Bladen also said implementing MISO’s new private cloud server was held up by the ongoing coronavirus pandemic’s interruptions of the supply chain. The new private cloud will house the modular platform, replacing the current server-based platform. (See Test Phase Approaches for MISO Market Platform.)
“We are moving ahead,” Bladen said. “We have been impacted by that to some degree in the buildout of the private cloud.”
Bladen said the private cloud will probably be online later this month, a month later than the RTO anticipated pre-pandemic.
MISO Director Baljit Dail said that even with the cost increase of the project, the cost-benefit is “still significant.”
“I think it’s important to remember that the legacy system was installed in 2009. It’s over a decade old,” Dail said at MISO’s June board meeting. He said staff stretched the original platform as far as they could, adding software and market products to keep up with a changing grid.
Bladen said the existing system’s architecture was originally designed for PJM in the mid-1990s.
MISO is replacing the platform gradually, turning off core elements of the old system one at a time and replacing them with new microservers. The day-ahead market is set to go live on the new platform in 2023.
“We’ve started down this path in earnest, with actual coding as we speak,” Bladen told stakeholders.
The old market platform will be completely retired in 2026. However, the bulk of the replacement will be complete by late 2024, Bladen said. The real-time market will likely go live on the new platform in early 2025.
Additionally, the new market participant interface test environment has been open since April and will be until June 2021. Parallel operations of the new and old interfaces will take place July-October 2021.
“We have seen some traffic and activity, but several companies have not tested it yet,” MISO Senior IT Director Curtis Reister said.
Energy storage advocates scored a key victory Friday when the D.C. Circuit Court of Appeals rejected challenges to FERC rules that restrict states from prohibiting behind-the-meter storage resources from participating in organized wholesale electricity markets.
State regulators, utilities and public power groups last year petitioned the court to overturn the provisions of FERC Order 841 that require states to provide energy storage resources (ESRs) connected to distribution systems full access to federally regulated energy markets, calling the rules “arbitrary and capricious” and “not in accordance with law.” (See States, Public Power Challenge FERC Storage Rule.)
The National Association of Regulatory Utility Commissioners spearheaded the challenge, with the Edison Electric Institute, the American Public Power Association, the National Rural Electric Cooperative Association and American Municipal Power filing a separate complaint.
“Petitioners argue FERC is offsides in Order No. 841 by prohibiting states from barring electric storage resources on their distribution and retail systems from participating in federal markets. We find no foul here, so we deny the petitions,” Judge Robert Wilkins wrote on behalf of the panel.
In Order 841-A, FERC denied rehearing of Order 841’s express lack of a state opt-out for behind-the-meter retail ESRs, arguing that its authority to regulate RTO/ISO markets gave it “authority to determine which resources are eligible to participate” in those markets.
In its arguments before the court, Wilkins noted, “FERC emphasized, again, that Order No. 841 did ‘not specify any terms of sale at retail,’ but a state may not ‘broadly prohibit all retail customers from participating in RTO/ISO markets,’ since states cannot … intrude on the commission’s jurisdiction by prohibiting all consumers from selling into the wholesale market.’”
The court agreed with FERC’s contention that “Order No. 841 does not modify states’ authority to regulate the distribution system, including the terms of access, provided that they do not aim directly at the RTO/ISO markets.”
“Order No. 841 solely targets the manner in which an ESR may participate in wholesale markets,” the court wrote. “This action is intentionally designed to increase wholesale competition, thereby reducing wholesale rates. Keeping the gates open to all types of ESRs — regardless of their interconnection points in the electric energy systems — ensures that technological advances in energy storage are fully realized in the marketplace, and efficient energy storage leads to greater competition, thereby reducing wholesale rates.”
Even NARUC acknowledged the potential benefits from local ESRs participating in wholesale markets, the court said.
“If ‘directly affecting’ wholesale rates were a target, this program hits the bullseye,” the court wrote.
In rejecting the petitioners’ complaints that the lack of an opt-out provision violates states’ authority to regulate their distribution systems, the court acknowledged “there is little doubt that favorable participation models will lure local ESRs to the federal marketplace,” requiring use of those systems. Still, “nothing in Order No. 841 directly regulates those distribution systems. … States remain equipped with every tool they possessed prior to Order No. 841 to manage their facilities and systems,” the court said.
“But because FERC has the exclusive authority to determine who may participate in the wholesale markets, the Supremacy Clause — not Order No. 841 — requires that states not interfere” with those markets, the court found.
In that vein, the court rebuffed NARUC’s contention that local ESRs cannot participate in federally regulated wholesale markets — and therefore do not fall under FERC’s authority — until they can navigate state-regulated facilities.
“Any state effort that aims directly at destroying FERC’s jurisdiction by ‘necessarily deal[ing] with matters which directly affect the ability of the [commission] to regulate comprehensively and effectively’ over that which it has exclusive jurisdiction ‘invalidly invade[s] the federal agency’s exclusive domain,’” the court said, citing precedent from 1962’s Northern Natural Gas Company decision.
The court also pointed out that under Order 841, states keep their authority to prohibit ESRs from simultaneously participating in interstate and intrastate markets.
“States retain their authority to impose safety and reliability requirements without interference from FERC, and ESRs must still obtain all requisite permits, agreements and other documentation necessary to participate in federal wholesale markets, all of which may lawfully hinder FERC’s goal of making the federal markets more friendly to local ESRs,” the court said.
The court additionally acknowledged that individual states will be free to challenge the rules “applied to their own state regulations or imposed conditions.”
“Petitioners are likely correct that litigation will follow as States try to navigate this line, but such is the nature of facial challenges,” the court wrote.
Renewable energy and storage advocates applauded the decision.
“This is an enormous step for energy storage, with the affirmation that energy storage connected at the distribution level must have the option to access wholesale markets, allowing homes and businesses to contribute to the resiliency, efficiency, sustainability and affordability of the grid,” Energy Storage Association CEO Kelly Speakes-Backman said in a statement. “This latest affirmation of Order 841 is especially important as it ensures energy storage can contribute all its values to the grid, regardless of its connection point. As our electric system becomes more modernized and distributed, we are seeing the regulatory frameworks at both the wholesale and retail levels adjust to that reality.”
“During a time of great uncertainty over the scope of the Federal Power Act, today the court rightfully recognized the important role energy storage plays in our nation’s wholesale electricity markets,” American Council on Renewable Energy CEO Gregory Wetstone said in a statement. “This decision will provide the clarity necessary to widely deploy energy storage, an essential component to securing the carbon-free grid we need to properly combat the climate crisis.”
FERC Chair Neil Chatterjee also expressed pleasure with the ruling, saying the removal of market barriers for storage has been one of his “top priorities.”
“I have said repeatedly that I think … we may look down the road and say [Order 841] was one of the single most significant … actions taken by a government agency to address carbon mitigation and the transition to a clean energy future. And so, if in fact our initial read of this decision is correct, this is a very significant victory indeed,” Chatterjee said.
Plaintiffs in the case were expectedly dissatisfied with the outcome.
“We are, of course, disappointed in the court’s decision,” said NARUC Director of Communications and Public Affairs Regina Davis. “We are still reviewing the opinion and weighing our options at this time. We may issue a formal statement next week after we’ve had time to review today’s decision.”
“We believe that the jurisdiction over local distribution facilities left to state and local authorities under the Federal Power Act includes the authority to determine whether those facilities may be used by electric storage resources to access FERC-regulated wholesale markets,” said APPA General Counsel Delia Patterson. “Although APPA is encouraged that the court emphasizes that state and local regulators retain authority to impose safety, reliability, and other requirements on storage resources’ use of the distribution system to access wholesale markets, the inability to adopt a clear prohibition on such use is likely to lead to further litigation over particular state and local requirements, as the court acknowledges.”
NERC issued its second Level 2 alert of the year on Wednesday to gather data on the bulk power system’s exposure to “foreign adversaries,” at the same time the Department of Energy published a request for information on the industry’s practices for identifying and mitigating supply chain vulnerabilities for BPS components.
DOE’s request and NERC’s alert are both in response to President Trump’s declaration of a national emergency in May that aimed to restrict the purchase of BPS equipment from suppliers suspected of connections with foreign adversaries — defined as any foreign government or nongovernment person connected with threats against the U.S. or its allies. (See Trump Declares BPS Supply Chain Emergency.) The order also created a task force that would work with the electricity, oil and natural gas industries to develop unified energy infrastructure procurement policies.
NERC Seeks Foreign-made Equipment Data
Details of NERC’s alert are confidential, but a representative of the organization confirmed to ERO Insider that it was drafted “in support of” the emergency declaration. NERC CEO Jim Robb said in May that the aim of the alert would be to determine “whether this is a huge problem or a very surgical problem.”
“This isn’t going to be rip and replace — [we want to] assure ourselves that we don’t have untoward activity going on out on the system,” Robb said. (See NERC Planning Level 2 Supply Chain Alert.)
Further information was provided on Thursday by Mark Kuras, senior lead engineer in PJM’s Reliability Compliance unit, who told the RTO’s Operating Committee that the alert is “broader than the six technologies listed in the earlier alerts” — referring to NERC’s previous supply chain alerts issued in 2017 and 2019.
Kuras said the information requested by NERC focuses on transformer control and protection systems — transformers, load tap changers, cooling systems and sudden pressure relays — that are 10 years old or newer, and that the alert applied mostly to generation and transmission owners and “distribution providers to some extent.”
“This has to do with … trying to restrict your use of equipment that is manufactured outside the U.S.,” he added. “While the countries that are being restricted have not been defined yet, I think you can assume … at least China and Russia will be included in that list.”
DOE Probes Supply Chain Vetting
DOE’s information request also identifies China and Russia as “foreign adversaries,” along with Iran, Cuba, North Korea and Venezuela, though the list is subject to change by Energy Secretary Dan Brouillette in consultation with other agency heads. Inclusion on the list “does not reflect a determination … about the nature of” the countries named except as it relates to Trump’s executive order.
Electric insulators and transformers
The department based its information request on the National Counterintelligence and Security Center’s supply chain risk management (SCRM) framework and NERC’s critical infrastructure protection standards, in addition to the work of standards development organizations such as the International Organization for Standardization and the National Institute of Standards and Technology. DOE’s interest focuses on entities’ use of evidence-based cybersecurity maturity metrics along with foreign ownership, control and influence (FOCI), and includes the following questions:
Do energy sector asset owners and/or vendors conduct enterprise risk assessments, including a cyber maturity model evaluation, on a periodic basis?
Do asset owners and/or vendors identify, evaluate and/or mitigate FOCI risks with respect to company and utility data, potential sub-tier supply chain manufacturers, and assets and services?
Do changes need to be made to established SCRM standards in order to protect source code, establish a secure software and firmware development cycle, and maintain software integrity?
How are benchmarks documented and tracked?
Additionally, the department seeks information on the economic costs of compliance with the executive order. This includes developing compliance plans and frameworks, implementation, and periodic review and mitigation of issues. Utilities are also asked whether certain categories of BPS equipment could present more problems under the executive order, and if there are any unique challenges the order could pose for small businesses.
NERC’s alert requires registered entities to acknowledge receipt by July 16; responses are required no later than Aug. 21. Comments on DOE’s information request are due by Aug. 7.
The COVID-19 pandemic has added an extra layer of complexity to near-term electricity demand forecasting, but energy companies and policymakers must avoid drawing hasty conclusions about its long-term impact on the electricity sector, industry officials told FERC on Wednesday.
“My key takeaway for you is that COVID-19 must not be viewed by our industry as a rationale to halt progress and defer planning and reform,” LS Power CEO Paul Segal said during a panel focused on the pandemic’s effects on transmission planning and system forecasting, part of a two-day virtual FERC technical conference focused on pandemic-related issues for the energy sector.
Paul Segal, LS Power | FERC
“I worry that the easy takeaway from our very recent experience will lead the industry to extrapolate forward to an environment with lower demand,” he said.
Segal thinks “the most difficult economic parts of COVID-19 are hopefully behind us” because of the fiscal stimulus enacted by Congress and aggressive actions taken by the Federal Reserve to rescue financial markets from “freefall,” which opened credit markets to even the most “impacted” economic sectors such as airlines and cruise line companies.
“I expect within a year, our perception of COVID-19 will be very different because we learn how to live with it,” Segal said. “Our actions will change the trajectory of the disease, [and] we will learn how to treat the symptoms to reduce severity and/or immunize against it.
“It would be dangerous” to rely too heavily on the recent experience of declining electricity demand to predict new trends in energy use in the U.S., he said, cautioning that “events like COVID-19 tend to trigger paradigm shifts.”
“Today there are many paradigm shifts happening all at once. That leaves us needing to consider a number of questions about how these changes will impact demand and usage patterns for electricity,” Segal said.
One “key” shift? The way people work, with more staff working from home and “less densification” in offices.
“Fundamentally, I expect this to lead to the less efficient use of space and, as a result, the less efficient use of energy, including electricity,” Segal said. “Office electrical systems will need to run perhaps at a modestly lower capacity level than might’ve been required otherwise, but more people will be at home, and this will lead to the use of electricity to heat, cool and light the home when previously it might’ve been unoccupied. In the aggregate, this may result in a meaningful increase in electric demand, in the intermediate term.”
Working from home could also drive consumption of natural gas, which could be problematic for areas like New England, where supplies can become constrained during winter, producing knock-on effects that can be “non-linear and multifactorial,” which “can often be derivative of one another.”
“For example, the recent [economic] collapse has crushed drilling for oil in many shale plays,” Segal said. “The indirect consequence will be the reduction in the availability of essentially free, associated natural gas. Natural gas prices will need to incentivize more drilling for natural gas as we move forward, and it’s conceivable that in this new paradigm, we will have natural gas prices move into a range that’s persistently 50% higher than what we would’ve expected them to be before COVID-19.”
That would translate into higher electricity prices, which could in turn improve the economic fortunes of coal and nuclear power plants enough to prompt a political response for increased green energy investment.
Time to Invest
Segal’s advice to the commission was fitting for the CEO of competitive transmission developer: In short, clear the way for the construction of new transmission to aid in economic recovery and relief.
“As we focus on the road back, we should keep in mind that affordable electricity to a large extent is a function, to a large extent, of transmission grid optimization,” he said. “Competitive procurement in regional planning of transmission must remain a priority as we tackle affordability going forward. The regional planning process must be robust enough to enable the RTOs to plan for and facilitate the construction of the power grid of the future, one that anticipates and supports states’ evolving energy investment policies and goals, rather than sitting idly by while every element of yesterday’s aging grid is simply rebuilt and replaced with the same facilities that have reached the end of their useful lives.”
Vistra Energy CEO Curt Morgan similarly took up the importance of FERC continuing to foster competition in response to economic decline, but with the differing spin of the head of competitive generation company that’s been critical of state support for favored renewable resources.
Curt Morgan, Vistra Energy | FERC
“The multitude of market-rule changes in FERC jurisdictional markets over the last several years, many driven by out-of-market activities, and the unpredictable and uneven pace with which these changes are implemented, have created a sector-specific risk for integrated competitive energy companies like Vistra and created questions in the minds of investors about our sector,” he said.
But he counseled FERC against pushing the industry to respond too quickly in response to the pandemic.
“We expect that until we get a vaccine or an effective therapeutic, it is going to be an uneven economy with fits and starts, but our advice in this is not to take the early effects of COVID and extrapolate this too far into the future,” he said. “We don’t know enough about what’s going to happen, and we certainly don’t want to contribute to long-term ripple effects.”
Gil Quiniones, NYPA | FERC
Gil Quiniones, CEO of the New York Power Authority, expressed concern that the economic downturn could pose challenges for New York’s efforts to generate 70% of its electricity from renewables by 2030 and have a carbon-free grid by 2040. As one of the original epicenters of the pandemic, the state experienced a 10% decline in electric load at the height of the outbreak, Quiniones noted.
“In addition, New York state’s strong economy, the prime driver of the state’s electric load, has seen a decline, and might not return to 2019 levels for quite some time,” he said. “This reduction in load and the uncertain pace of recovery will have a direct effect on planning the much-needed expansion and upgrades to major power infrastructure. While transmission planning might be difficult, now is the time to invest in the power grid, to meet clean energy goals and to help restart the economy.”
“Practically speaking, we don’t see this as having a long-term planning impact,” MISO President Clair Moeller said, adding that load in his RTO’s footprint has been flat since 2007.
“The dominant transmission we are building is to accommodate the change in generation fleet. We do not see our members changing those plans, so at this point in time, we don’t see a need to adjust any of our planning practices — but of course we’ll keep that front and center because that’s one of the more important parts of what we do,” he said.
‘Fluid’ Situation
Moeller also told commissioners that MISO’s load profiles have flattened since the outset of the pandemic, reducing the need to ramp the system to meet demand.
“That contrasts significantly with polar vortex kinds of problems, where the ramp problem is exacerbated by the cold-weather events,” he said. “We only have four months of experience with this event. We expect the situation to continue to be fluid into the future.”
FERC Chair Neil Chatterjee asked Moeller to elaborate on how the pandemic might affect RTOs’ approach to short- and long-term load forecasting.
Clair Moeller, MISO | FERC
Moeller said that the self-learning neural network software most grid operators rely on for forecasting struggled at the outset of the pandemic because it lacked an applicable history for producing short-term forecast under new conditions.
“The forecasts that we initially provided typically were for too much capacity to be on rather than not enough, so while the mistakes were important in terms of efficiency, they didn’t have a negative impact on reliability at all because typically we would start one unit too many rather that one unit too few,” Moeller said, adding that the forecasting tools eventually learned to adjust to the new patterns.
“The change from shutdown to reopening is more gradual, so we’re not seeing the kinds of errors as the economy reopens that we saw when it shut down suddenly,” he said.
Moeller said the pandemic has not yet provoked MISO to make any changes to its long-term load forecasting.
“We continue to think that challenges to the electric system [will] have to do with the change in resources, mostly, and then the question around the electrification of transportation is an important one in a five- [to] 10-year kind of time horizon,” he said.
‘Every Kernel’
Richard Glick, FERC | FERC
FERC Commissioner Richard Glick asked the panelists if they felt RTOs and ISOs have been transparent enough in the how they have updated their load forecasting processes.
“I think the processes are reasonably transparent,” Segal said. “What I worry about is there can be a tendency to fall back on tools that have been used in the past, and I think we’re in an environment that needs to consider a much broader range of possibilities. We’re going to be OK if we have too much generation and too much transmission capacity. We’re going to have big problems if we’re surprised and have less generation available than we need.”
Morgan said his biggest concern regarding forecasting was “really trying to extrapolate anything meaningful going forward from the effects of a virus, where human behavior — such as not wearing a mask or going into a large crowd — can change what’s happening in a given state within a couple of weeks.”
Morgan said Vistra is “looking for every bit and every kernel of information” from government officials and state utility commissions to identify as early as possible whether states are going to shut down or put in stay-at-home measures again.
“Because this thing is so fluid right now … you can’t really extrapolate off of it at all,” he said.
Sam Randazzo, PUCO | FERC
Chatterjee asked Public Utilities Commission of Ohio Chair Sam Randazzo what he and his colleagues “have been thinking about most during this time.”
“The global observation that I would make is that we’re not dealing with an energy infrastructure problem; we’re dealing with a public health problem,” Randazzo said, adding that regulators can best contribute to addressing the health emergency by providing “flexibility” to those on the front lines of contending with the pandemic.
“From a planning perspective, the pandemic scenario is really a people problem: You’ve got to have enough people; you’ve got to take care of your people — the human resources that you need — because the virus affects human resources,” he said. “So, if you can tell me the public health scenario that we’ll be dealing with tomorrow, we can probably then plan from an infrastructure and resource perspective what we can do to contribute to a positive resolution to the public health emergency.”
Neil Chatterjee, FERC | FERC
In response to Chatterjee’s question about what industrial energy consumers are taking away from the pandemic experience, Electricity Consumers Resource Council (ELCON) CEO Travis Fisher expressed concern that while his member companies “are taking cuts where needed,” those in the utility space are “basically keeping their plans the same.”
“I’m a little bit concerned about that because the costs of the transition that those folks are undertaking … are ultimately going to fall on consumers like ELCON members,” Fisher said.
Responding to Chatterjee’s question about what impact the pandemic has had on the Western U.S., Stefan Bird, CEO of PacifiCorp’s Pacific Power subsidiary, specifically addressed his company’s position.
Stefan Bird, Pacific Power | FERC
“COVID, for us, has not much impact on our ability to deliver our core mission of reliability, affordability and safe service of electricity while we continue to radically change our portfolio,” Bird said, noting that PacifiCorp has the advantage of drawing on resources from a 10-state footprint.
“I would argue the most expensive route would be to isolate yourself on an island and limit your options. And, thankfully in the West, we’ve got this tremendous abundance of low-cost resources, but they are very diverse,” he said.
Bird also said the pandemic has had no effect on PacifiCorp’s ability to prepare for the looming wildfire season. “There’s been no impact to our efforts to really dramatically increase our resilience and hardening efforts,” he said.
The Pennsylvania House of Representatives voted Wednesday to pass a bill limiting the state’s entry into the Regional Greenhouse Gas Initiative (RGGI), but experts expect the state will ultimately enter the environmental compact despite concerns from legislators.
House Bill 2025 passed by a bipartisan majority of 130-71. It would require the legislature’s approval before Pennsylvania can enter any multistate program like RGGI that imposes taxes. The Department of Environmental Protection would need to submit “a description of the economic and fiscal impacts that would result” from joining such a program to aid the legislature in its decision.
The bill would also require legislative authorization before the state can impose a carbon tax on employers engaged in electric generation, manufacturing or other industries.
Gov. Tom Wolf signed an executive order in October directing the DEP to develop a rulemaking for joining RGGI by July 31; citing the pandemic, Wolf provided the department with a six-week extension, to Sept. 15. His authority to issue such an order has been continually challenged by the Republican-controlled legislature. (See GOP Continues Opposition to Pa. RGGI Plans.)
Rep. Jim Struzzi speaks June 8 before the vote on his bill limiting Pennsylvania’s entry into the Regional Greenhouse Gas Initiative. | Pa. House
“This bill gives a voice back to the people by allowing those of us who represent them to have say in this process,” Rep. Jim Struzzi, the bill’s primary sponsor, said during Wednesday’s House session and vote. “The action to enter RGGI would have serious ramifications on Pennsylvania businesses, jobs, energy prices and future economic opportunities that are not being considered by the governor.”
RGGI, which includes New York and the six New England states, currently has three PJM states: Delaware, Maryland and New Jersey. On Wednesday, Virginia Gov. Ralph Northam announced that the state had finalized a rule in preparation for it joining the compact on Jan. 1. (See PJM Panel Weighs Impact of Pa., Va. Joining RGGI.)
The bill now goes before the State Senate for consideration, with sessions scheduled for July 13 and 14. The body may take up the House bill or consider its companion bill, Senate Bill 950, which currently has 20 Republican sponsors, representing 40% of the 50-seat chamber.
During Wednesday’s session, House Majority Leader Kerry Benninghoff (R) said that of the nine states that have already entered into RGGI, all of them voted to join through votes in their respective legislatures. Benninghoff also called RGGI a “job killing” measure that will drive high-paying jobs out of Pennsylvania and into Ohio and West Virginia, the state’s two neighbors that are neither part of nor considering joining the compact.
“No governor has the authority to rule by the swipe of a pen without the input or the consent of the people of Pennsylvania,” Benninghoff said. “No governor has the authority to implement a tax, and no governor has the authority to enter into a binding compact or agreement. That authority lies with the people of Pennsylvania and the members of this chamber sent by the people.”
Rep. Leanne Krueger (D), a supporter of RGGI, said H.B. 2025 was an attempt to downplay the significance of reducing carbon dioxide emissions in Pennsylvania and at the same time scare people into thinking the actions of joining the group will harm them financially.
“Joining RGGI is the biggest climate action that Pennsylvania will have ever taken, the biggest environmental action certainly of my generation,” Krueger said in comments after the bill passed. “And yet we’re facing a bill that would stop the governor in his tracks and not allow us to join this common-sense” market.
Outside View
Despite Wednesday’s vote, outside observers said Pennsylvania still stands a strong chance of joining RGGI.
ClearView Energy Partners predicted in a report that Wolf is guaranteed to veto any bills passed by the legislature overriding his executive order. And although Wednesday’s bill passed with bipartisan support, ClearView said there most likely won’t be enough votes to overcome a veto.
ClearView said legislators may rely on a strategy of inserting H.B. 2025 language into November’s budget, forcing Wolf to take a stand on budget debates. However, it pointed out Wolf has line-item veto authority over the budget and has used his power before to reject abortion language inserted in last year’s budget.
Another possible Republican strategy, according to ClearView, is a legal challenge, as legislators have argued that Wolf’s executive order did not cite specific provisions within the Pennsylvania Air Pollution Control Act, which does not describe CO2 as a “pollutant.”
Coal trade organization America’s Power has countered a recent Union of Concerned Scientists analysis that claimed coal generation self-commitments are unnecessarily costing Midwestern ratepayers millions.
The group, formerly known as the American Coalition for Clean Coal Electricity, said that far from conducting uneconomic behavior, MISO’s coal units closely follow energy demand. The group said that in 2018, changes in electricity demand and coal generation output correlated about 87% of the time, regardless of utility or whether MISO issued dispatch instructions. It also said the percentage was the same as natural-gas fired generation in the footprint.
“Not only are coal-fired generating units run economically, they are run according to market demand as much any other type of generation in MISO,” America’s Power said in its rebuttal, released June 25 and titled “Never Let the Truth Get in the Way of a Good Story.”
“Self-committing coal-fired power plants is not a trick to rip off ratepayers,” it said. “Rather, it benefits ratepayers and helps maintain the reliability of the electricity grid.”
UCS’ June analysis concluded that coal plant self-commitments saddled Midwest electricity customers with $350 million in avoidable costs in 2018. The study also said individual ratepayers could have saved an average $60 apiece over the year if the most efficient existing resources in MISO were deployed instead of coal plant self-scheduling. UCS used the study to make a case for state regulators to open investigatory dockets into utilities that exhibit high costs. (See UCS Analysis Knocks Coal Self-commitments.)
| America’s Power
MISO has said about 90% of energy from its coal is either from economic commitments or economically dispatched above the units’ economic minimum levels.
“Some claim that self-commitment of coal-fired resources results in prolonged run times and uneconomic outcomes for end-use customers,” MISO said in an April report. “Further, they say self-commitment distorts the markets by allowing coal units to displace lower-cost renewables and other resources from the grid. In fact, the vast majority of all self-committed coal generation in MISO is actually dispatched economically — meaning it is the lowest-cost resource option that MISO markets have available at the time to serve load.”
MISO Executive Director of Market Operations Shawn McFarlane said most self-committed, coal-fired energy is dispatched economically.
“We try to minimize any uneconomic dispatch … taking into account operational constraints,” McFarlane said during the Market Subcommittee meeting in May.
Monitor to Weigh in
On Thursday, MISO’s Independent Market Monitor David Patton told the MSC that he will publish his own report on coal self-commitments next month, but he doesn’t anticipate alerting staff and stakeholders to a problem.
Coal resources that offer in the day-ahead market as must-run are overwhelmingly offered economically, Patton said. He said 98% of available offline coal units offered economically in the day-ahead market this spring, up from 89% last year.
“As gas prices fall, it’s becoming harder to predict when it will be economic for coal resources to run,” Patton said. Offering in must-run status prevent the units from incurring expensive cycling costs when they’re decommitted and brought back online later, he said.
MISO will evaluate the merits of defining new seasonal reliability criteria and implementing a sub-annual capacity construct, stakeholders learned Wednesday.
The new evaluation stage is another, more formal step toward creating a seasonal capacity construct. The RTO has repeatedly said it is considering defining unique system reliability requirements for the footprint because of analyses that signal an emerging wintertime loss-of-load risk.
The move could have MISO issuing sub-annual reserve margins based on seasons, beyond NERC’s annual reliability standards. The RTO plans to publish a white paper on reliability needs in the third quarter.
Brattle Group Principal Sam Newell told stakeholders that supply shortage risks are shifting from the summer peak.
“As MISO looks to a future with more wind and solar and less coal and seasonal mothballing, the risks will continue to shift,” Newell said during a Resource Adequacy Subcommittee conference call Wednesday.
Some stakeholders have said seasonal reliability criteria could infringe on states’ jurisdiction over resource adequacy and told MISO the existing annual local clearing requirements and planning reserve margins it provides are sufficient. (See Stakeholders Split on Potential MISO RA Requirements.)
But on Tuesday, 11 utilities and power organizations urged MISO in a letter to move ahead with a sub-annual capacity construct. The group — including Xcel Energy, Ameren, DTE Energy, Consumers Energy and WEC Energy Group — said the RTO should pursue a segmented capacity auction and capacity resource accreditation changes based on seasons or months.
“The reliability risks facing the MISO footprint have been plainly identified, appropriately articulated to stakeholders and demonstrated by the significant number of emergency actions taken by MISO operators since June 1, 2016,” the group wrote. “The transition to a sub-annual capacity construct would provide MISO and stakeholders with the ability to procure more tailored capacity commitments to address non-summer capacity risk.”
MISO also added another maximum generation emergency event to its tally Tuesday for its Northern and Central regions, as much of MISO Midwest was gripped by a persistent heat wave.
This year’s resource adequacy survey conducted by MISO and the Organization of MISO States indicated that the RTO could face a 400-MW capacity shortfall as early as 2022, and the next five years could contain surpluses as high as 12.5 GW or deficits as steep as 6.8 GW. (See OMS-MISO Survey Sees Uncertain Supply Future.)
MISO Executive Vice President of Market and Grid Strategy Richard Doying said change in some form is inevitable for the Planning Resource Auction. He said the capacity auction needs to send signals to buy or build generation when appropriate.
“I don’t believe we can say, ‘Most load is covered, so we’re good,’” Doying said. “It’s a varied landscape that we need to navigate here.”
The California Energy Commission approved $22 million in grants Wednesday to fund long-term energy storage projects, considered key to the state’s decarbonization goals, and another $6 million to test the possibilities of using repurposed electric vehicle batteries for solar storage.
The long-term storage grants included $13 million to Native American tribes to test systems that could deliver stored solar and wind power for hours longer than lithium-ion batteries.
“The importance of sustained investments in this space can’t be understated,” CEC Vice Chair Janea Scott said.
The funding is vital “to help push this type of technology forward and to really be looking in the storage space at long-term of ‘what’s the next step,’ so we’re always just a little out ahead of where we’re trying to push the technology as we go in our quest toward 100% clean energy,” Scott said.
The CEC funds energy research through its Electric Program Investment Charge (EPIC) grant program. California load-serving entities are required by Senate Bill 100 to provide retail customers with 100% clean energy by 2045.
Commissioners voted unanimously Wednesday to award $7.3 million to the Rincon Band of Luiseño Indians in San Diego County to connect solar arrays to a vanadium redox flow battery, which uses tanks of chemicals, and a flywheel storage system. Each storage method will provide 400 kW of load for up to 12 hours, creating a microgrid that will power a wastewater treatment plant and a public emergency shelter, among other buildings, the tribe said.
The Rincon Band of Luiseño Indians in San Diego County received $7.3 in grants for long-term storage projects. | Rincon Band of Luiseño Indians
Several other tribes won grants to integrate flow batteries and flywheels with solar arrays.
Indian Energy, a Native American-owned company that provides energy solutions to tribes and the military, won a $5 million grant to install a zinc hybrid cathode battery, a flow battery and a mechanical flywheel at Marine Corps Base Camp Pendleton, north of San Diego.
Antelope Valley Water Storage, in the Mojave Desert northeast of Los Angeles, was given $2 million to fund an aquifer pumped-hydro system, which stores water underground to produce hydroelectric power when solar goes offline at night.
Used-car Batteries
The commission also funded projects that will test “retired” EV batteries for use in stationary storage systems.
Technicians remove EV batteries near the end of their useful life, but many can still hold a charge. Connected together to store solar power, the batteries create a microgrid while avoiding waste. BMW is among the companies that have experimented with “second-life” car batteries on a large scale in Europe.
The CEC is funding research on using second-life EV batteries for energy storage. | BMW
The CEC awarded $2.8 million to the San Diego State University Research Foundation to pair second-life EV batteries with a solar photovoltaic system. Rejoule was given $2.9 million “to develop novel battery grading tools to more quickly and accurately assess the health of repurposed EV batteries for stationary storage.”
“With California leading the nation in electric vehicle acceptance, [it] will have the largest opportunity to fully utilize these batteries that have substantial energy left for stationary use,” Mike Gravely, research program manager at the Energy Commission, told the commissioners.
