Shareholders at FirstEnergy’s (NYSE:FE) virtual annual meeting Tuesday approved a smaller board of directors, as agreed to by the company earlier this year to resolve shareholder lawsuits stemming from the company’s bribery of a top Ohio lawmaker for a financial bailout for two nuclear power plants.
Six long-time directors agreed not to stand for re-election, according to the agreement in the court stipulation. All had been named as defendants in the lawsuits.
At 12 directors, the board returns to its traditional size. Among the 12 are two directors first appointed in 2021 who are employees of Icahn Enterprises. (See FERC Authorizes Icahn Employees for FE Board.) Icahn owned 3.32% of the company’s outstanding shares as of March 3, FirstEnergy institutional investment records show.
A third new director is connected with Blackstone, which invested $1 billion in FirstEnergy stock at the end of last year and asked for a seat on the board. Blackstone owned 5.05% of outstanding shares as of Dec. 31, 2021, according to FirstEnergy.
John W. Somerhalder II, vice chairman and executive director of the board since last year, was elected chair of the board. He previously served as interim director and CEO of CenterPoint Energy.
Shareholders also rejected two proposals by activist shareholders. One from California-based John Chevedden would have amended the company’s shareholder rights policy to give shareholders with a combined 10% of outstanding shares the right to call special shareholder meetings.
The board recommended shareholders reject the proposal — which has appeared periodically in annual meetings since 2011 — and added that it plans to set the combined ownership threshold for such special meetings at 20% in 2023.
A second proposal, offered by Steven J. Milloy of Potomac, Md., would have required the company to investigate whether child workers were involved in mining cobalt in the Congo before creating electric vehicle charging stations.
Shareholders rejected both proposals, according to unofficial results, which the company must still file with the Securities and Exchange Commission.
Following the vote, Donald Misheff, outgoing chairman and one of the six veteran board members who did not seek re-election, said it had been “a great privilege to serve on your board. Under the leadership and guidance of our 2022 director nominees and our management team, I’m confident FirstEnergy will continue to move forward as a stronger, customer-focused organization.”
In brief, previously recorded remarks following Misheff, CEO Steven Strah said the changes enacted by the board and his management team over the last two years have put the company in a position to recover its reputation as well as its profitability.
“In 2021, we embraced pivotal changes — changes which advanced a culture that prioritizes integrity and accountability. We also embraced transformation and innovation to reimagine our company and reshape it into a more forward-thinking, premier utility.
“In the last year, we’ve implemented substantial actions to resolve the challenges we’ve been working through since 2020. These actions include strengthening the leadership team, building a best-in-class compliance program and substantially modifying our approach to political engagement,” Strah said.
The proxy statement outlining the issues taken up at the annual meeting can be found here.
ATLANTA — Despite current supply chain problems, energy storage is just beginning to capture its potential, developers told the RE+ Southeast conference, sponsored by the Solar Energy Industries Association (SEIA) and Smart Electric Power Alliance (SEPA), last week.
Raafe Khan, director of energy storage for Pine Gate Renewables, said supply chain problems have “definitely put a dent in many developers’ plans” but predicted the problem will ease because of “all these giga factories coming online in the next six to 12 months.”
Speakers expressed optimism over the resource’s future in supplying capacity and reducing demand charges and offered varying projections on the need for storage of longer than four hours.
Sizes Needed
Dmitri Moundous, senior manager of storage business development for Cypress Creek Renewables, said most peaking capacity needs in the near term can be served by two- to four-hour storage, with six- and eight-hour plus storage not widely needed until the 2030s.
“Once you get into those scenarios of 90-plus percent renewables, that’s when you start seeing multi-day and seasonal needs start showing up.”
Edward May, managing partner of Energy Intelligence Partners Consulting, said the need for longer-term storage may be coming faster than anticipated.
“We have been surprised. We have seen a couple of big, integrated utilities whose draft IRPs are reflecting some level of long-duration storage relatively soon,” he said.
“There seems to be plenty of room for two- and four-hour duration for the foreseeable future, but we are seeing some of the big utilities who are running their internal models and coming back and saying, ‘Actually, our models are telling us that … there is some value from long-duration storage in certain spots, on seams, things like that.’”
Reducing Demand Charges
May said he also sees increasing use of storage to reduce demand charges: “Co-ops, which are effectively just big C&I [commercial and industrial] customers, are subject to the same demand charges that a big manufacturing plant [has]. Some are going through the court systems to be allowed … to find ways to get batteries to be used as an asset that they can utilize.”
In February, FERC ordered Duke Energy Progress (NYSE:DUK) and the North Carolina Eastern Municipal Power Agency (NCEMPA) to negotiate over how their supply contract should be changed to reflect the NCEMPA’s use of batteries to shave its demand charges (ER22-682). (See FERC Orders Negotiations in Duke-Muni Contract Dispute.)
Reducing usage during the time periods when demand charges are assessed “can save 50% off your bill,” he said. “So it’s pretty big number.”
“There are some co-ops in the Southeast that prior to energy storage … employed a person to sit at the desk and watch the weather,” he added.
“And basically, when temperatures are going to spike, they put on all their demand response and turn on diesel gensets at their largest customers.”
Storage as Capacity
Moundous said he wants to see storage grow beyond a grid following role to provide inertia support in areas like the Texas panhandle. “And we’re gonna see more and more of that on higher renewable penetration systems,” he said. “We have not scratched the surface of how much energy storage can provide capacity, in both regulated and deregulated markets, and how much you can displace uneconomic coal plants. So let’s get that done first and deploy in gigawatt scale.”
Drought, wildfires, plant retirements and transmission outages have elevated the risk of supply shortfalls in the West, Texas, MISO and SPP, NERC said in its Summer Reliability Assessment on Wednesday.
“It’s a pretty sobering report,” John Moura, NERC’s director of reliability assessment and performance analysis, said in a media briefing. “It’s clear the risks are spreading. … Year after year, extreme weather is leading to reliability impacts.”
MISO’s North and Central areas face a “high risk of energy emergencies during peak summer conditions” because of a capacity shortfall and the outage of a key transmission line, NERC said in the assessment, which covers June to September. Drought is the cause of concern in Texas, and drought and wildfire risks will present challenges in the West, the report said.
Risk of Load Sheds in MISO/MRO
MISO has been unable to reverse capacity shortfall projections NERC has reported since 2018, with load-serving entities in four of its capacity zones currently lacking sufficient owned or contracted capacity to cover their requirements. (See OMS Drafting Letter over MISO Resource Adequacy Concerns.)
The RTO faces both a 1.7% increase in projected peak demand — largely a rebound from the pandemic — and a 2.3% (3,200 MW) reduction in generation capacity compared with summer 2021.
“System operators in MISO are more likely to need operating mitigations, such as load-modifying resources or non-firm imports, to meet reserve requirements under normal peak summer conditions,” NERC said. “More extreme temperatures, higher generation outages or low wind conditions expose the MISO North and Central areas to higher risk of temporary operator-initiated load shedding to maintain system reliability.”
MISO also will enter summer lacking a 500-kV transmission line that was damaged by a tornado in December. That will affect 1,000 MW of firm transfers between MISO Midwest and South, including parts of Arkansas, Louisiana and Mississippi. Restoration of a 4-mile section of the line is expected at the end of June.
Canada’s Saskatchewan, which is part of the Midwest Reliability Organization, has seen a 7.5% increase in projected peak demand since 2021. Although SaskPower is projected to remain above its planning reserve margin, with sufficient operating reserves for normal peak conditions, “external assistance is expected to be needed in extreme conditions that cause above-normal generator outages or demand,” NERC said.
Dry in the West, Texas, SPP
Drought conditions in Texas and much of the West threaten to reduce hydropower output and pose “unique challenges to area electricity supplies and potential impacts on demand,” NERC said.
Below-normal snowpack threatens the availability of hydroelectricity for transfers throughout the Western Interconnection, a particular risk for WECC’s California-Mexico (CA/MX) and Southwest Reserve Sharing Group (SRSG), which depend on imports to meet demand on hot summer evenings and other times when wind and solar output are reduced. “In the event of wide-area extreme heat event, all U.S. assessment areas in the Western Interconnection are at risk of energy emergencies due to the limited supply of electricity available for transfer,” the assessment said.
Much of Texas also faces extreme drought, which NERC said “can produce weather conditions that are favorable to prolonged, wide-area heat events and extreme peak electricity demand.”
The National Oceanic and Atmospheric Administration forecasts above average temperatures this summer for virtually all of the lower 48 states. | National Oceanic and Atmospheric Administration
Recent additions of solar and wind have raised ERCOT’s anticipated reserve margins above reference margin levels, meaning the grid operator should have sufficient capacity for normal peak demand. But extreme heat will increase peak demand and could cause a spike in forced outages or reduced output from generating resources. “A combination of extreme peak demand, low wind and high outage rates from thermal generators could require system operators to use emergency procedures, up to and including temporary manual load shedding,” NERC warned.
Mark Olson, NERC | NERC
Mark Olson, manager of reliability assessments, said another risk is the retirement of thermal plants and influx of renewables.
“There are fewer and fewer thermal plants in a number of areas as generation retires. So the ones that are remaining are being driven hard. They have to cycle to be able to balance variable energy,” he said.
“That takes a toll on the plants. So we can expect to see higher forced outage rates in the future [and] more generation mechanical issues.”
Continued drought in the Missouri River Basin also could result in reduced output from thermal generators in SPP that use the river for once-through cooling. Output from hydro generators on the river may also be reduced.
Solar PV Tripping Remains an Issue
Unexpected tripping of solar PV resources during grid disturbances remains a problem despite attempts to address it since 2016, with widespread losses last May and June in Texas and four events in California between last June and August.
“During these events, widespread loss of solar PV resources was also coupled with the loss of synchronous generation, unintended interactions with remedial action schemes and some tripping of distributed energy resources,” NERC said.
Since the 2016 Blue Cut Fire in California, which caused nearly 1,200 MW of solar PV to trip offline, NERC has been warning that the lack of inverter-based resources’ (IBRs) ride-through capability risks turning minor system disturbances into major ones.
NERC said a series of trips last year “reinforces that improvements to NERC reliability standards are needed to address systemic issues with IBRs,” an issue highlighted in a joint NERC-WECC report last month. (See NERC, WECC Repeat Solar Performance Warnings.)
The report said that the one inverter manufacturer involved in the Blue Cut Fire “quickly and proactively responded by ensuring that all [bulk power system]-connected solar PV facilities changed their frequency protection settings to avoid future issues. However, these disturbances in 2021 involve different inverter manufacturers, illustrating that the issue is still not widely understood or addressed across all manufacturers and plant owner/operators.”
Although NERC standards require documentation that demonstrates compliance with ride-through requirements in PRC-024-3, “they do not specify a certain degree of performance that must be met,” the organization said, calling for the standard to be retired and “replaced with a comprehensive ride-through standard that focuses specifically on the generator protections and controls.”
NERC “strongly recommends that a performance validation standard be developed that ensures that reliability coordinators, transmission operators or [balancing authorities] are assessing the performance of interconnected facilities during grid disturbances, identifying any abnormalities and executing corrective actions with affected facility owners to eliminate these issues.”
“These types of risks have the potential to have a widespread impact across the entire interconnection, and that’s really the entire Western Interconnection, or the entire Eastern Interconnection, or the entire Texas Interconnection if you’re in ERCOT,” Moura said. “It’s a matter of keeping the balance of supply and demand. And if the supply and demand balance is shifted — even 1,000 MW very quickly — that really creates real trouble for the operators. They’re not used to dealing with this huge imbalance.
“The inverter tripping challenge is really one of the most risky issues I think we have to deal with as an industry in order to ensure we can reliably integrate interconnect the nearly 500 GW of solar we see coming online in the next 10 years,” he added.
NERC also has issued recommendations that electromagnetic transient (EMT) modeling and studies be incorporated into its reliability standards. “Existing positive sequence simulation platforms have limitations in their ability to identify possible performance issues, many of which can be identified using EMT modeling and studies,” NERC said. “As the penetration of IBRs continues to grow across North America, the need for EMT modeling and studies will only grow exponentially. Furthermore, NERC reliability standards need enhancements to ensure that model accuracy and model quality checks are explicitly defined.”
Moura said NERC wants FERC to add a requirement for EMT modeling in its pro forma interconnection agreement to ensure reliable connection of asynchronous inverter-based resources: solar, batteries or wind.
“In the past, when you interconnected a synchronous generator, you simply do a power flow analysis, a voltage stability analysis and a feasibility study,” he said.
When IBR resources were a smaller contributor, “maybe we didn’t need to do those [EMT] studies. But as … we’re seeing more and more, these types of studies are absolutely necessary. We cannot integrate resources reliably without doing those studies.”
Other Reliability Issues
NERC also identified several other concerns:
Supply chain problems and staffing shortages are hampering efforts to complete new generation and transmission projects needed for reliability. WECC-CA/MX and WECC-SRSG “have sizeable amounts of generation capacity in development and included in their resource projections for summer,” while ERCOT is rushing to complete transmission projects to address transmission constraints and maintain system stability, NERC said. It warned of transmission congestion during peak conditions and reduced ability to serve load in localized areas. It said generator and transmission owners must inform their BAs, TOPs and RCs of any delays so they can develop responses.
Supply chain problems are also making it difficult for some coal-fired generators to obtain fuel and other supplies, with coal stockpiles “relatively low” compared to historical levels. Coal plants say their fuel supplies have been pinched by mine closures, rail shipping limitations and increased coal exports. “No specific BPS reliability impacts are currently foreseen,” NERC said.
The grid and other critical infrastructure sectors face cybersecurity threats from Russia and other potential actors, particularly because of Russia’s invasion of Ukraine. The Electricity Information Sharing and Analysis Center is sharing information with its members on potential threats.
An active late-summer wildfire season in the Western U.S. and Canada also poses threats. Above-normal wildfire risk is expected beginning in June across much of Canada, in the U.S. South Central states and in Northern California. In New Mexico, the Hermits Peak/Calf Canyon Fire has grown to almost 300,000 acres, making it the largest in state history. “If drought conditions persist, the fire outlook for late summer would likely extend across the Western half of North America,” NERC said, noting the potential for damage to transmission lines or pre-emptive shutdowns to avoid sparking blazes. In addition, smoke from wildfires can reduce output from solar PV.
A month after its capacity auction indicated a Midwestern supply scarcity, MISO’s Independent Market Monitor and a MISO vice president debated the path forward in front of Illinois regulators.
During a special policy session of the Illinois Commerce Commission (ICC) last Friday on MISO’s resource adequacy, ICC Chair Carrie Zalewski said the commission wanted “to gain a fuller understanding” of the 2022-23 planning resource auction (PRA) clearing at the cost-of-new-generation entry and to discuss steps to preserve reliability and affordability as the RTO’s resource mix transitions.
Zalewski said the $236.66/MW-day clearing price in MISO Midwest is a significant increase over the $5/MW-day clearing price during the 2021-22 capacity auction. The grid operator has told stakeholders to prepare for the possibility of temporary, controlled load sheds during the summer months because of a 1.2 GW capacity shortfall in the Midwest. (See MISO’s 2022/23 Capacity Auction Lays Bare Shortfalls in Midwest.)
Melissa Seymour, MISO’s vice president of external affairs for its Central Region, said members must build more capacity quickly. The IMM’s David Patton said the RTO is duty-bound to design an auction that results in higher clearing prices to prevent its existing thermal fleet from hemorrhaging more units.
Seymour said accredited capacity in MISO Midwest sank about 3.2 GW since the 2021-22 auction, primarily because of coal plant retirements. She said that though MISO continues to add more installed capacity year-over-year, retiring thermal generation has higher accredited capacity values than the accredited value of new renewable generation.
“Wind and solar do not get the same capacity credit as a traditional thermal unit,” Seymour told the ICC. MISO’s wind generation receives about a 15.5% capacity credit, while solar receives an approximately 50% capacity credit during summer peak times.
“We believe that unless more capacity is built over the next year, we’ll continue to see what we saw in this auction continue in the future,” she said. “We will do everything we can to make sure the overall grid stays reliable and dependable, and that the system won’t be compromised. But we do have less than a one-day-in-10 [year] loss-of-load probability because of the auction not meeting the requirements, so there is a chance that we might have to take actions to prevent blackout situations or rolling brownout situations.”
Seymour said MISO will likely take steps to increase visibility into the supply and demand picture ahead of capacity auctions.
She also said she thought that some market participants had more capacity that they could have offered, namely demand response resources. No market participants violated MISO’s 50-MW withholding threshold in the 2022-23 auction.
Seymour predicted high clearing prices will continue until MISO’s members bring more capacity online. But she also said the RTO’s proposed seasonal auction design — waiting on FERC approval — and new capacity accreditation calculations based on actual generation availability should help alleviate future shortages. (See MISO’s Seasonal Capacity Proposal Opposed at FERC.)
But Seymour also reminded commissioners that MISO’s capacity auction is a residual auction that functions like a “balancing market,” and that it isn’t meant for market participants to procure all resources to meet demand.
IMM: Capacity Auction Design the Culprit
Patton laid the shortfall’s blame squarely on “poor market signals” in the capacity auction.
“It’s not hard to understand how we got here,” Patton said. He told the ICC that the “unfortunate truth” is that MISO’s capacity market isn’t designed to signal when to stave off generation retirements or make investments. He said the vertical demand curve isn’t “aligned” with the reliability value of capacity and clearing prices have been “grossly understated” for years.
MISO IMM David Patton speaks to the Illinois Commerce Commission | ICC
Patton said about 4 GW of MISO’s merchant capacity has retired over the past four years because of economic reasons. He said some of that generation would have remained online had clearing prices more closely reflected a unit’s going-forward costs of about $110-$175/MW-day. He said an efficient capacity price might even cover some of the units’ capital costs for new emissions controls to comply with environmental regulations.
“If we’re going to learn anything from this, we ought to learn that market signals really do matter and we ought to fix this market so that it will help the region maintain enough capacity to maintain reliability,” Patton said.
He urged the commissioners to support a sloped demand curve in MISO’s auction.
“That’s the only thing in the long term that’s going to solve this problem,” Patton said. “And I think the only reason MISO doesn’t have it is because the states have opposed it. And now, one-by-one, the states are starting to either be interested or support it. And I think the more states that voice their support for it, the more momentum there will be to come to a consensus.”
Illinois, as a retail choice state, should weigh in on the demand curve and persuade the Organization of MISO States to move the issue forward, Patton said.
He also pushed back on the argument that lower-accredited renewable energy is ousting higher-accredited thermal units.
“It’s not as if participants say, ‘I’m going to retire a 100-MW gas plant and replace it with 100 MW of wind,’ imagining in their minds that that’s a one-for-one tradeoff. The reality is the investment in renewables is happening independent of the decision to retire resources,” Patton said. “So, it’s true that they’re coming in at lower accredited values, but the real problem is that a number of the resources that retired really should not have retired, regardless of what was going on in the renewables side of the equation. It’s just that we didn’t give them the economic incentive to stick around.”
Seymour countered that MISO’s capacity auction is not designed to incentivize resources or bring new capacity online because states oversee their own resource adequacy planning.
She agreed that a sloped demand curve in previous auctions may have led to higher auction prices and driven some generation construction and prevented some generation from retiring. She also said MISO’s pending request at FERC to employ a minimum capacity obligation rule, where load-serving entities must procure 50% of their load obligation ahead of the auction, may assuage capacity deficiencies.
Patton said he didn’t see how a minimum capacity rule would increase supply. He said the rule would only have load-serving entities bilaterally contracting for the same stock of surplus.
“It’s hard to imagine that it’s going to increase the amount of physical supply that exists. It just moves some of the settlements from the PRA into the bilateral market,” he said. “Until you fix the price in the PRA, you’re not creating an incentive for anybody to build anything that would help you get out of the shortage.”
MISO expects about 11 GW of generation to retire over the next year, Seymour said.
“Excess is going away in most instances. We’re seeing people come more in balance or a little bit short of their total requirement, mostly because people are deciding to retire their older units … and not replacing [with] a one-for-one … whether it be thermal or wind and solar,” Seymour said.
She said federal environmental regulations and utilities’ own green goals are creating a “gap” between resource retirements and resource additions. MISO expects to be in a “mind-the-gap” situation in the 2023-2025 timeframe, Seymour said.
In a majority-renewable future, the RTO is probably going to have resources that don’t run very often to provide inertia, frequency response and voltage support, she said.
ICC Commissioner Maria Bocanegra said one of her biggest fears is repeating a blackout situation similar to ERCOT’s prolonged blackouts during the February 2021 severe winter storm.
Seymour said that unlike ERCOT, MISO is not an island and can import considerable amounts of power.
“That is one of the biggest things that we have going for us that ERCOT didn’t,” she said. “They had minimal access to anything outside of the ERCOT footprint to be able to import to serve their need.”
Seymour reminded commissioners that during the same winter storm, MISO was able to import supply from PJM and in turn, export power to SPP.
Patton Says Real Threat Begins Next Summer
Patton told commissioners that he doesn’t expect blackouts in MISO this summer.
“I think load shed in MISO is extremely unlikely this summer, because some of the resources that didn’t sell in the capacity auction are actually still going to be around during the summer,” he said. “They’re retiring after the summer. So, I don’t think the threat of load shed is very high for MISO for this planning year. I’m a little more worried about after some of these retirements that are in process disappear … and they won’t be there next summer.”
The IMM allows retiring generators an exemption from offering into the PRA when they plan to retire and won’t be available for the entire planning year.
Late-spring heat paired with seasonal maintenance outages has already forced MISO to issue two emergency advisories before the June 1 start of the 2022-23 planning year.
MISO declared a maximum generation emergency alert Friday afternoon for its Central region. The grid operator said it was experiencing forced generation outages, above normal temperatures and higher than forecasted load. On Tuesday, the RTO declared conservative operations for its South region through Friday.
The Industrial Energy Consumers of America (IECA) sent a letter to FERC Chair Richard Glick, urging the commission to issue a notice of proposed rulemaking to overturn the state opt-out for demand response.
IECA CEO Paul N. Cicio said it is “of immediate importance” that FERC reverse the opt-out, which allows states within a regional grid to block distributed resources from participating in wholesale energy markets.
“This action will reduce inflation, electricity costs and improve reliability,” the IECA wrote. “We believe that your action will impact the next PRA in MISO and help to drive down prices of which all consumers will benefit. This could ensure that our factories continue to operate and maintain jobs at a time when our economy desperately needs the assistance.”
IECA argued a continuation of the rule has contributed to MISO’s capacity crisis.
The Port of Seattle is studying if and how it should get into the business of producing and distributing hydrogen.
Realistically, that move — if made — is a few years down the road.
The port wants to trim its carbon footprint and be a player in the fledgling hydrogen supply economy, Ryan Calkins, president of the port’s commission, told NetZero Insider. There is some urgency for the port getting into the field as medium- and heavy-duty trucks, plus ships are likely to switch to hydrogen fuels. “We really need to build this soon,” Calkins said.
For example, a handful of hydrogen-fueled ships, mostly ferries, are now in use in northern Europe and Japan. Calkins believes the shipping industry, which accounts for 2.2% of worldwide greenhouse gas emissions, could gradually expand more into using hydrogen as a fuel, which would mean those vessels will use ports where hydrogen is stored.
The Port of Seattle and some partners are conducting two studies covering whether the port should get into the hydrogen business and how, where to locate facilities, costs, potential customers and storage. The federal government has provided $2.12 million to the port to tackle the studies.
“This is to get a better understanding of what this will look like,” Calkins said.
The port is one year into a two-year study on the big picture of getting into the hydrogen fuel business. Its partners on the study are Seattle City Light, Pacific Northwest National Laboratory and Sandia National Laboratory.
A second two-year study by the port and Seattle City Light is expected to start soon and will look at hydrogen storage issues, such as types and sizes of tanks, and examine safety risks, such as the potential for explosions.
Washington officials are making a big push to have the U.S. Department of Energy select the state as one of four to eight national “hydrogen hubs” to be funded by $8 billion in appropriations from the Infrastructure Investment and Jobs Act. State lawmakers in March passed a bill to create a new Office of Renewable fuels to support the develop of hydrogen and other renewable fuels. (See Green Hydrogen Bill Passes Wash. Legislature.)
At a carbon policy forum held in Seattle last month, state Sen. Reuven Carlyle said, “This is a ruthless competition nationwide. It’ll be political malpractice not to leave everything on the field.”
Hydrogen efforts are already taking shape in other parts of the state. In Central Washington, Douglas County Public Utility District is constructing what will be the state’s first green hydrogen production facility near its Wells Dam on the Columbia River. The $25 million project is expected to go online in late 2022 or early 2023.
Last week, Australia-based Fortescue Future Industries said it would examine converting a disused Centralia, Wash., coal mine into a green hydrogen production facility. Centralia is located about 85 miles south of Seattle. (See Australian Company Eyes Closed Wash. Coal Mine as Green Hydrogen Site.)
MISO and SPP staff and stakeholders discussed transmission reconfigurations and the search for smaller interregional transmission projects Tuesday during their inaugural Common Seams Initiatives (CSI) meeting.
Staff said the meetings make sense because both RTOs list seams work as strategic priorities. They will replace the grid operators’ joint operating agreement meetings and no votes will be held.
SPP Senior Interregional Coordinator Clint Savoy said the virtual, informational meetings will span the RTOs’ planning, operations, markets and regulatory activity and serve as an “all-encompassing ‘here’s what we’re working on.’”
RTO staffs said they’re working to create web pages for CSI meetings. Savoy said the grid operators are open to hearing stakeholder-led presentations and that some meetings may be held in-person.
Tuesday, staff focused on five recommendations state regulators handed down to MISO and SPP in early 2021. The Organization of MISO States and SPP’s Regional State Committee’s Seams Liaison Committee (SLC) have advised the RTOs to consider creating targeted market efficiency projects (TMEPs), improve their respective generator interconnection queue processes, track and address rate pancaking at the seams, keep state regulators apprised of long-range planning efforts and devise coordinated transaction scheduling and market-to-market (M2M) interface pricing. (See MISO, SPP Regulators Call for Pancaking Fix, Smaller Projects.)
In February, the grid operators announced plans to conduct a TMEP study this year that will search for smaller, congestion-relieving cross-border transmission projects. (See MISO, SPP Take on 2nd Interregional Planning Effort.)
Savoy said MISO and SPP are aiming for an “easily repeatable” process that could be conducted every year, if necessary. He said the RTOs are compiling two years’ worth of seams congestion data to identify potential projects and will negotiate a cost-allocation design in 2023.
The two have also participated in the SLC’s Rate Pancaking Working Group to inventory instances of rate pancaking and develop solutions.
Debate on MISO Tx Reconfiguration
Savoy said SPP is conducting a constraint management analysis of its day-ahead handling of MISO market-to-market constraints “to see if anything needs to change.” The results will eventually be shared with MISO and stakeholders. (See SPP Reviewing its M2M Processes After MISO Monitor’s Comments.)
Meanwhile, MISO has formed the nonpublic Reconfiguration for Congestion Cost Task Team (RCCTT), which focuses on plans to reroute transmission flows during times of heavy congestion costs. Tony Rowan, senior manager of north reliability coordination, said MISO’s increasing transmission congestion caused some of its northern market participants and third-party vendors to suggest reconfiguration options. Rowan said the requests were unusual and that transmission owners rejected most of the recommendations over reliability concerns.
The RCCTT is maintaining a monthly list of MISO’s top congested constraints, including M2M flowgates. SPP staff said they have been meeting with RCCTT leadership to share their information on flowgate congestion.
EDF Renewables’ Arash Ghodsian pointed out that much of the RTOs’ work to address seams congestion is being done behind closed doors.
“We talk about urgency. Obviously near-term congestion is happening,” Ghodsian said. He asked for future educational sessions on staffs’ work on seams congestion.
Minnesota Public Utilities Commission staffer Hwikwo Ham asked the grid operators to research Iowa’s Interstate Power and Light’s recent transmission reconfiguration, which he said has lowered ratepayer bills.
“Southwest Minnesota is a total mess at this point,” Ham said of the need for reconfiguration. “We are leaving tons of money on the table given the level of congestion in Southwest Minnesota and Iowa.”
American Electric Power’s Jim Jacoby said he is concerned that MISO’s reconfiguration work might harm system reliability.
“I would think you’d want to fix a problem before reconfiguring the system,” he said.
Rowan said some the congestion may already have led to transmission projects. He said RCCTT members are working to avoid simply “masking” congestion problems and keeping them open for project opportunities.
“That is very much at the forefront of discussions in the RCCTT,” Rowan said.
WPPI Energy’s Steve Leovy said the reconfiguration work is focused on congestion caused by temporary, unusual conditions.
“We need to both improve the system and squeeze more out of the system if we can to operate the system as efficiently as we can. … I see room for both,” Leovy said.
Before closing the meeting, MISO’s Jack Dannis said the RTOs are monitoring a possible minimum transmission transfer capacity, as suggested by FERC’s Joint Federal-State Task Force on Electric Transmission.
Dannis said the November CSI meeting will focus on a possible transfer requirement between the regions.
Savoy said SPP intends to include a minimum transfer capacity with MISO in its five-year strategic plan. “This is something we should be discussing and determining how it will look,” he said.
American Clean Power Association’s Daniel Hall thanked the RTOs for teeing up the topic.
“I certainly think the tea leaves are such that FERC will do something in this arena. I think it behooves all of us for MISO and SPP to look into this,” he said.
Fully funding Rhode Island’s Transit Master Plan could reduce residents’ vehicle miles traveled (VMT) by 8% and should be a key recommendation in the state’s next greenhouse gas emissions reduction plan, Mal Skowron, transportation program and policy coordinator at the Green Energy Consumers Alliance, told state officials Tuesday.
Skowron made her recommendation during a listening session of the Rhode Island Executive Climate Change Coordinating Council (EC4) on priorities for reducing transportation emissions that should be in the update to the 2016 GHG Emissions Reduction Plan. Rhode Island’s Act on Climate, which Gov. Dan McKee signed last spring, directs the EC4 to submit the updated plan to the legislature by the end of the year.
Listening session attendee Hans Scholl agreed with Skowron’s call to fund the plan, saying that the “vast majority of Rhode Islanders live within 10 minutes of public transportation, but it’s just totally underutilized.”
Capital costs of the Master Plan would be $1.9 billion to $3.1 billion through 2040, with operating costs of $237 million annually.
Reducing VMTs is one of the actions recommended in the 2016 GHG plan to cut transportation emissions from fossil fuels. The EC4 is considering priority actions for the plan update that could further a VMT reduction goal, including increasing transit and share ridership.
The State Planning Council adopted the transit plan in December 2020 under the umbrella of a Long-Range Transportation Plan. Funding for some of the plan was in place at the time of its adoption, but full implementation isn’t expected until 2040. Since its adoption, additional funding has been moving more of the plan forward.
U.S. Sen. Jack Reed helped secure a $900,000 grant to study a major transit corridor expansion as recommended in the plan for services that provide high-volume markets with fast and frequent service. An additional $225,000 in matching funds for the study are included in McKee’s proposed FY23 budget.
The transit plan said high-capacity services could include rapid bus routes with limited stops and light rail featuring two-car trains.
Completion of the study will allow the state to take advantage of funding opportunities in the Infrastructure Investment and Jobs Act, Reed said.
Rhode Island’s 2016 GHG reductions strategy also recommends electrification of the Rhode Island Public Transit Authority’s (RIPTA) bus fleet and state passenger and freight rail systems.
“RIPTA has made a lot of progress with electrifying its fleet,” Carrie Gill, chief economic and policy analyst at the Rhode Island Office of Energy Resources, said during the listening session.
McKee and Reed joined authority officials Friday to break ground on the state’s first charging station for electric buses to use while on a route during service hours. The governor also announced Thursday that RIPTA has issued a request for expressions of interest to design a new transit center that would support transit growth as envisioned in the master plan.
The EC4 held a listening session on the electric sector in April to inform the GHG plan update, and another session is scheduled for the thermal sector (residential, commercial and industrial heating and natural gas distribution) in June.
PJM stakeholders at last week’s Operating Committee meeting endorsed manual changes related to the stability limits and intelligent reserve deployment in markets and an operation issue charge developed in the Market Implementation Committee.
The manual changes were endorsed in a rare acclamation vote that included eight objections and 11 abstentions.
Donnie Bielak, manager of reliability engineering for PJM, reviewed the conforming changes to Manual 12: Balancing Operations, highlighting the changes in two different sections of the manual.
In section 4.1.2: Loading Reserves, language was added stating that PJM dispatch will use intelligent reserve deployment (IRD) in security constrained economic dispatch (SCED) to initiate a synchronized reserve event by approving the latest solved IRD case if there’s insufficient regulation and economic generation to recover area control error (ACE).
Bielak said the change highlighted automated and manual methods for implementing contingency reserves.
“Under normal operating conditions, we would use the automatic method and go out with an IRD case,” Bielak said. “However, we did put provisions in there for PJM actions regarding if the IRD case was invalid and how we would deploy those reserves under that scenario.”
Section 5.5: Generator Stability Limitations is a new section highlighting stability-limited generation and clarifying PJM and member actions, Bielak said.
The PJM actions in the section state, “When stability issues are identified, PJM will confirm/calculate the stability limitation and communicate the limit value(s) as a stability limit, including the effective timeframe for same, to the impacted PJM generation owner(s). This includes any changes, including cancellation, around a given stability limit. For real power (megawatt) stability limits, limits will be translated into a corresponding generator output constraint (in megawatts) for a generator whereby the generator output constraints shall be respected.”
The section says generation owners should “respond promptly to specific requests and directions” of PJM dispatchers, and generators should honor dispatch basepoints based on stability limitations by following PJM dispatch.
Paul Sotkiewicz of E-Cubed Policy Associates said he wanted to make sure PJM dispatchers will consider switching options before the generator output construct is used and make it “very clear” in the manual so “there’s nothing left to the imagination” for dispatchers to interpret.
Bielak said PJM dispatchers will evaluate any other available types of switching solutions and make sure they don’t cause “adverse implications” to other generators or overloads on the system. He said there are “a lot of different factors” that must be evaluated to go ahead with a switching solution.
“We did a full review here of all the operations manuals, and we definitely believe that the existing language or the new language that we’re proposing here in Manual 12 is the best course of action moving forward,” Bielak said.
The manual language goes to the May 25 Markets and Reliability Committee for endorsement. PJM is looking for an effective date of June 1.
Outage Coordination Issue Charge Endorsed
Stakeholders will begin examining outage coordination processes and procedures after unanimously endorsing an issue charge.
Paul McGlynn of PJM’s system operations group reviewed the proposed issue charge and problem statement intended to address the RTO’s transmission and generation outage coordination.
The key work activities and scope of the issue charge include education and review of current procedures for submitting, classifying, evaluating, approving and scheduling transmission and generation outage requests. The review will look at current study timelines, analytical activities such as reliability and expected congestion studies and any adjustments to submitted outages based on PJM’s review.
McGlynn said PJM will review outage planning and coordination processes required for regional transmission expansion plan project implementation by focusing on projects that could require extended outages of existing facilities such as transmission line rebuild projects.
Work also includes “proposed modification and improvements to transmission and generation outage assessments, transparency and available tools.” McGlynn said discussion of outage assessments will include reliability and congestion assessments for the PJM system and a review of the impacts on the PJM system of neighboring region outages.
Out-of-scope items in the issue charge include modifying the transmission owners’ ability to “take necessary outages on their facilities” and any proposal that conflicts with the Consolidated Transmission Owners Agreement.
Work on the issues will be completed at the OC and is expected to take up to a year to complete.
Sotkiewicz asked for a possible friendly amendment to the issue charge calling for an education portion on how the issues being discussed will be brought to other committees, including the Planning Committee and the MIC, so that the communication portion “doesn’t get overlooked in the process.”
“These outages can affect everything from credit to market operations and everything else,” Sotkiewicz said.
McGlynn said PJM can touch on dissemination of information while going through the education process, but he said processes already exist in the manual to ensure information is passed along to other committees in the stakeholder process.
“I don’t know that it’s something necessarily that we need a lot of stakeholder input on,” McGlynn said.
Manual Endorsements
Stakeholders unanimously endorsed two different manuals as part of the periodic review. They included:
Manual 36: System Restoration, with minor changes such as replacing System Restoration Coordinators Subcommittee (SRCS) with System Operations Subcommittee (SOS) and updating the under-frequency load shed table with new data.
Manual 3: Transmission Operations, with updating stability limitation process language in accordance with FERC docket ER21-1802 and aligning language with the current TO/TOP matrix language.
FERC on Friday accepted PJM’s compliance filing restoring the historical energy and ancillary services (E&AS) revenue offset used in the RTO’s capacity market, clearing a potential hurdle for the 2023/24 Base Residual Auction scheduled for June 8 (EL19-58).
The commission on Dec. 22 reversed its May 2020 approval of PJM’s forward-looking E&AS offset, a key variable in calculating the net cost of new entry (CONE) for resources in capacity auctions, ordering the RTO to revert to the previous, backward-looking offset. (See FERC Reverses Itself on PJM Reserve Market Changes.)
PJM submitted tariff revisions restoring the historical E&AS offset for all Reliability Pricing Model (RPM) auctions going forward and limiting the forward-looking option only to RPM auctions for the 2022/23 delivery year, the only one in which the forward-looking offset was used.
“PJM states that, with these revisions and a Nov. 12, 2020, effective date, the tariff will properly reflect the applicable E&AS offset used in auctions for each delivery year,” FERC said.
The RTO also included revised rules for determining the E&AS offset used for minimum offer prices for each resource type and restoring the historical approaches provisions starting with the 2023/24 delivery year. The historical offset will also be used to determine avoidable-cost rates.
The RTO asked FERC to “expeditiously accept” its compliance filing to avoid delaying the2023/24 BRA.
In a 3-1 decision, FERC mostly accepted PJM’s compliance filing, with Commissioner James Danly dissenting and Commissioner Willie Phillips not participating in the order.
The commission said PJM’s filing did not properly restore all tariff language that existed prior to the May 2020 order, pointing to a section with an incorrect sentence that was not properly incorporated in the tariff in previous revisions. FERC also identified other minor changes, including deleting the phrase “capacity factors” in one section and revising the word “must” to “may” in another section.
PJM is required to file the revised tariff changes within 15 days to the commission.
Danly, who has dissented to several of the orders regarding PJM’s proposed energy price formation revisions, said he continued to object to the process and the merits of the filing. He said the order “implements profound changes to fundamental aspects” of PJM’s capacity market and was done “recklessly” without additional briefings or supplemental information on the impact of the changes.
The “protracted, unnecessary proceedings have caused unacceptable delays in PJM’s auction schedule,” Danly said. He hoped the commission will not cause any more delays to the auction with its actions.
“How can anyone expect a market to function correctly and efficiently in the face of the uncertainty the commission has created over the last year?” Danly said. “We cannot continue to take actions that will delay PJM’s auctions or throw its market rules into further chaos. Amidst such uncertainty, the promised benefits of the market will be diminished and will eventually be lost. PJM’s ability to ensure resource adequacy will be imperiled. Prices will rise and reliability will suffer. We cannot continue down this road and keep telling ourselves that the resulting rates are just and reasonable.”
California Gov. Gavin Newsom said Friday that the state needs a $5.2 billion “strategic electric reliability reserve” to meet the challenges of extreme heat, wildfires, drought and the West’s changing resource mix.
Newsom proposed the reserve as part of the May revision to his FY 2022-23 budget, originally released in January.
He also cited supply-chain problems, including with imported solar panels, as contributing to potential supply shortfalls this summer and beyond.
“When you stack all these together, and you reflect those extremes on wildfire, heat [and] drought, we’re looking at potentially filling [supply] gaps that weren’t there even a year or two ago,” Newsom said in a budget briefing. “So how do we do that? We are requesting [that] the legislature … [create] a new strategic electricity reliability reserve, which is just a fancy way of saying ‘putting together 5,000 megawatts that’s available at a moment’s notice.’”
A summary of the governor’s budget plan says the reserve could consist of “existing generation capacity that was scheduled to retire, new generation, new storage projects, clean backup generation projects, diesel and natural gas backup generation projects … and customer-side load reduction capacity that is visible to and dispatchable by the [CAISO] during grid emergencies.”
Officials have not said whether the reserve funds would be used to keep the state’s last nuclear generator, PG&E’s Diablo Canyon Power Plant, operating beyond its planned retirement in 2024-25 for reliability, as some have urged.
In late April, Newsom told the Los Angeles Timeseditorial board that California would seek a share of $6 billion in federal funds intended to keep aging nuclear plants open. The Biden administration announced the program last month.
“The requirement is by May 19 to submit an application, or you miss the opportunity to draw down any federal funds if you want to extend the life of that plant,” Newsom said, according to the Times. “We would be remiss not to put that on the table as an option.”
His cabinet secretary, Ana Matosantos, told reporters at a May 6 briefing the state needs to consider all possibilities.
“We can’t keep any options off the table,” Matosantos said. “And we are clearly looking at planned retirements and making sure that we’re looking at all options associated with those planned retirements.”
During the briefing, officials from the governor’s office, CAISO, the California Public Utilities Commission (CPUC) and the California Energy Commission (CEC) said this summer’s potential shortfalls could range from 1,700 MW under strained conditions to 5,000 MW under extreme conditions.
Newsom said Friday that the state could face up to a 7,300 MW shortage, though it was unclear where he derived that figure, which was not cited by CAISO, the CEC or the CPUC.
CAISO, CEC Examine Reliability
The governor’s revised budget proposal followed reliability discussions by the CEC and CAISO on Wednesday and Thursday that delved into the likelihood of shortfalls this summer during harsh conditions.
CAISO’s 2022 Summer Loads and Resources Assessment found that the likelihood of having to order rolling blackouts — as the ISO was forced to do in August 2020 — is less this summer than last year, largely because of the addition of 4,000 MW of battery storage since the 2020 blackouts.
“However, available capacity continues to be impacted by well below normal hydro conditions as California is in its third year of drought,” Neil Millar, the ISO’s vice president of infrastructure and operation planning, told the CAISO Board of Governors in a memo prepared for the board’s meeting Thursday.
California’s mountain snowpack, which supplies water during the state’s six-month dry season, stood at 38% of average April 1 after the three driest winter months on record.
As in the past two summers, CAISO’s “greatest operational risk is during a widespread heat wave that results in low net imports due to high peak demands in its neighboring balancing authority areas,” the memo said. “The risk increases in late summer concurrent with the diminishing effective load-carrying capability of solar resources and the wane of hydro generation.”
“Under extreme weather and events such as wildfires that diminish larger amounts of supply, the ISO could still be faced with the necessity to shed firm load,” Millar wrote.
Using a new methodology, the resource assessment found the probability of CAISO declaring a Stage 3 energy emergency is 15% this year compared to about 6% last year, but the possibility of firm load interruption decreased from 4.6% in 2021 to 4% this summer.
More extreme weather than anticipated or procurement delays for anticipated new resources could worsen the outlook, CAISO cautioned.
In a briefing to the CEC, David Erne, with the commission’s Energy Assessments Division, said supply chain issues were especially problematic this year.
High lithium prices are affecting battery production, and the U.S. Commerce Department launched an investigation in April into allegations that Southeast Asian solar panel manufacturers are using Chinese parts while evading U.S. tariffs on China. The situation could interrupt solar panel delivery and the construction of solar arrays.
“What we’ve seen from last summer and moving forward is the energy industry is particularly impacted by supply chain issues, commodity prices and tariff issues, all of which cumulatively impact our ability to build out these new projects moving forward,” Erne said. “Our reliability is dependent upon new buildout, and that new buildout is affected by these particular issues.”
