Following a relatively calm weekend, SPP has again declared a resource advisory for Monday across its 14-state balancing authority area because of expected high loads and concerns over generation availability.
The advisory, which does not require public conservation, is effective from noon to 10 p.m. CT. Under the advisory, the BA can commit units earlier than under standard day-ahead market procedures and commit resources in reliability status.
The RTO’s most recent conservative operations and resource advisories expired as scheduled Thursday night.
The National Weather Service says an approaching cold front will cool down parts of the Midwest by late Sunday into Monday, but “searing heat” will remain in the Southern Plains into early this week.
A persistent high level ridge from the Southern Plains to the Southeast has resulted in record-breaking triple-digit temperatures as high as 115 degrees Fahrenheit in Oklahoma and Texas. Highs well above 100 F are expected in the early part of the week and for the foreseeable future. (See related story, ERCOT Sets Record for Demand … Again.)
SPP set a new mark for peak demand last week at 53.2 GW on July 19. It was the fourth time this year the RTO has recorded a new high. The record before this year was 51.04 GW, set last July.
SAN DIEGO — State regulators generally expressed support for minimum requirements on interregional transfer capacity Wednesday, saying they believed it could produce cross-border transmission projects where FERC Order 1000 failed.
But defining the minimum and ensuring it doesn’t result in inefficient, single-purpose transmission lines remain concerns, the regulators said during the fourth meeting of the Joint Federal-State Task Force on Electric Transmission. The session, which concluded the National Association of Regulatory Utility Commissioners (NARUC) Summer Policy Summit, focused on interregional transmission planning and project development and FERC’s April Notice of Proposed Rulemaking (RM21-17), which would require planners to use longer time horizons and consider multiple scenarios. (See Christie Talks up Flexibility of Transmission NOPR.)
Lessons from Uri
FERC Chairman Richard Glick said the need for more interregional capacity was demonstrated during Winter Storm Uri, when “a couple hundred people [in ERCOT] died, literally, just because they didn’t have access to power.” In contrast, SPP and MISO, which also lost many generating units, were able to minimize blackouts because they were able to import power from PJM and other regions, Glick said.
FERC Commissioner Mark Christie noted that PJM was able to export 6 GW of energy this week despite approaching its projected summer peak of 149 GW. “Interregional transfers do have reliability benefits, no question about it,” he said.
Several state members of the task force said minimum transfer requirements could simplify cost allocation, one of the most vexing barriers to new transmission.
“I don’t know of any regulators in the West who aren’t willing to pay for reliability and resilience,” said Utah Public Service Commission Chair Thad LeVar.
“If we are in agreement that the reason for building projects is resilience and prevention of service interruptions, I see a real possibility that there could be a more across-the-board cost allocation,” said Andrew French, chair of the Kansas Corporation Commission. “It gets much more difficult and much more granular if you start to justify lines based on economic benefits or public policy benefits.”
“It simplifies the cost allocation to set the minimum [requirement]. It also simplifies the benefit calculation by basically assuming benefits,” said Ted Thomas, chair of the Arkansas Public Service Commission. “If you can study rigorously and get the level set right, I’d rather spend that money than trying to come up with a formula that measures the impact of what might happen [in the future] and use that to come up with a cost allocation methodology. I think the minimum transfer benefit solves a lot of those other problems.”
He added: “We’re in a foot race between implementing the solution and the next time we get hit. And laying down a marker is important. If somebody gets hit and we didn’t act, it’s on us.”
Thomas said FERC should set such levels first in the organized markets. “If the non-RTOS don’t like it, you know, or want to study it or want to see what happens, that’s their choice. [I would] point out when you do that, you’re picking up a pair of dice and hoping” for the best.
Kansas regulators made a straw proposal to set the minimum at 10% of each region’s peak load. “That was essentially based on the experience during Winter Storm Uri — the level of demand that had to be interrupted, and the level of imports that we relied on,” French said. “I don’t know that we’re here saying that’s the right number. I’ve seen numbers as high as 40%.”
North Carolina: No Thanks
A numerical requirement would not be welcome in North Carolina, said North Carolina Utilities Commissioner Kimberly Duffley. Although a small part of the state is within PJM’s territory, most of it is not part of an RTO.
“Areas of the country like the Southeast — where through the IRP [integrated resource plan] process the generation is located close to load — may not need this type of interregional transmission, or they just may need less of this transfer capability,” she said.
Duffley also said the Southeastern Association of Regulatory Utility Commissioners (SEARUC) states would oppose “top-down” planning, preferring a “bottom-up” process that preserves regional flexibility.
“When I say regional differences, I mean market structures, natural resources, job development, just the geography of the different regions, to name a few,” she said, noting that Duke Energy does not measure market efficiency benefits based on LMPs, unlike PJM and other RTOs. “A one-size-fits-all approach is not an appropriate way to incent new transmission.”
She also urged caution on FERC establishing a minimum set of benefits to be considered in evaluating new transmission. “There are some states that are opposed to that, but I’m not taking any position on it here today,” she said.
Responding to Duffley, FERC Commissioner Allison Clements said that for interregional planning to be successful, two entities must come to an agreement despite having different resources, methodologies and benefit determinations. “The Order 1000 interregional coordination process kind of just assumed those differences would go away; they don’t go away,” she said.
Role for NERC
Duffley endorsed Michigan Public Service Commission Chair Dan Scripps’ proposal that any minimum transfer requirement be a “definition” rather than a number, “so that non-RTO states are not burdened with a too high of any type of minimum.” Christie, who has warned against FERC being overly prescriptive in its rulemaking, also expressed support for a definition.
Vermont Public Utility Commissioner Riley Allen said he was “intrigued” by a minimum transfer capability but feared that it could lead to “stopgap solutions that are kind of singularly focused on one category … undercutting the benefit cost or the economic case for a larger solution.”
If the focus is on reliability and resilience, he said, perhaps NERC should “identify what that level should be and whether it should vary between regions.”
LeVar said it was unclear how a minimum transfer capacity would affect the WestConnect and NorthernGrid planning regions, which have little or no cost allocation authority. “If that’s an issue that’s going to be pursued, the NERC reliability standards process is a great process for an issue like that,” he said. “WECC can be a valuable tool … because they don’t have an agenda other than reliability.”
Glick also hinted at a role for NERC, saying a FERC rulemaking could be based not just on Federal Power Act sections 205 and 206 — the source of much of FERC’s authority — but also under its reliability authority under Section 215, which the commission used to delegate to NERC the power to impose mandatory reliability standards.
FERC Commissioner Willie Phillips said he hoped the national laboratories’ efforts to quantify the resilience benefits of new construction would provide a foundation for a FERC rulemaking. Under current rules, he said interregional projects have often foundered because neighboring regions could not agree on benefit calculations. When “those projects fall out … we do wash, rinse, repeat — things don’t get built.” Phillips said.
FERC Commissioner James Danly, the lone dissent on the April NOPR, questioned whether FERC could make the “showing” necessary for the commission to issue any requirements.
“I have yet to hear anything that makes me think we’re going to be able to make that showing for us to actually impose something,” he said. “I don’t believe that every wrong can be remedied under the statutes that we administrate.”
Thomas and French disagreed, citing Uri. “I frankly think we have a pretty strong evidentiary basis right now that something needs to be done,” French said.
Pushback on ROFR Reversal
Another subject of discussion was the NOPR’s proposal to reverse Order 1000 and allow incumbent transmission owners a federal right of first refusal (ROFR) if they give an unaffiliated company a “meaningful level of participation and investment” in the project. (See Ratepayers Protest FERC Retreat on Transmission Competition.)
“I can’t say we have consensus in the West about this … but I can speak for myself and the PUC,” said California Public Utilities Commissioner Clifford Rechtschaffen. “We strongly oppose the idea of a conditional ROFR. We think it’s a step backwards.
“We’ve had experience with competitive bidding in California: It’s worked,” he said. “It’s reduced prices. It’s been successful. We have a lot of regionally cost-allocated projects. There’s no real evidence that in states with ROFRs, that they have more regional projects, or that costs are lower.”
Rechtschaffen said FERC should consider other steps to address “legitimate concerns” about unanticipated effects of Order 1000’s ROFR provision. “At a minimum, our recommendation is that FERC leave it up to each state to determine whether or not transmission should be developed competitively,” he said.
Kansas’ French said he had “very complicated” thoughts on the issue. “But we have seen tremendous cost savings in our region, as well, over the last few years on several projects. And it seems the wrong time to turn away from that,” he said.
Rechtschaffen said he welcomed the NOPR’s proposals for more transparency in local transmission planning and said they should include “repair and replacement” or supplementary projects, which receive little or no scrutiny under regional planning processes.
Rechtschaffen said these “utility self-approved” projects represent half of all investor-owned utility spending in RTOs and ISOs.
“In 2022, our largest utility, PG&E, forecast $1.2 billion on capital spending; 88% of that will be spent on utility self-approved projects,” he said. “We heard a similar story yesterday on a panel from Greg Poulos,” executive director of the Consumer Advocates of the PJM States.
Appreciative of FERC Outreach
Several of the state commissioners praised FERC for establishing the task force and including in the NOPR a requirement that planners seek states’ agreement on cost allocation.
“We’re very pleased in terms of the direction and tone of the NOPR,” said Pennsylvania Public Utility Commission Chair Gladys Brown Dutrieuille. “We’re very appreciative because you did put a lot of effort into understanding and hearing the concerns that were expressed by not only us but other people.”
Brown Dutrieuille said she supported FERC’s proposal to consider an expanded set of benefits in transmission planning and cost allocation but said they should not be “mandatory nor exclusive.
“I do have some concern that list of potential benefit metrics includes metrics that may double count the same benefit,” she said.
“It’s really hard to be frustrated with FERC when they’re actually listening to you,” said Maryland Public Service Commission Chair Jason Stanek, a former FERC staffer. “When I first read the NOPR, I felt like the dog that caught the car. So be careful what you wish for, because FERC is saying if you want a seat at the table, pull up a chair, and you have 90 days to sort it out amongst yourselves.”
Stanek also called on East Coast states to coordinate on building transmission to serve their offshore wind projects, saying New Jersey so far is “going it alone” under PJM’s state agreement approach. (See PJM Sees Wide Range of Costs in NJ OSW Tx Proposals.)
“That is not the way for us to be developing transmission along the coast,” he said. “We have to have clear open communication coordination between the RTOs.”
LeVar said “it’s obvious FERC went to great lengths to try to preserve flexibility and state input.”
“What I don’t know … is what impact this different planning scenario would have on momentum towards RTO development in the West. … I think it’s a real issue.”
French voiced a similar worry, saying FERC should ensure that any new requirements not interrupt ongoing intraregional work. “I have some concerns that could inadvertently press a pause button on some of the important work that’s taking place,” he said.
The task force’s next meeting is scheduled for November at the NARUC annual meeting in New Orleans.
In Alaska, the supply chain delays now plaguing the U.S. energy storage market mean a federally funded microgrid project that was scheduled to come online in August has been delayed for at least a year.
Equipment ordered from Germany didn’t get on the ship to the U.S. as scheduled, said William Thomson, technical and engineering adviser for the Alaska Village Electric Cooperative, which serves 58 communities across the state, many of them only accessible by river or air.
“Our deliveries are made by small plane, and the heavy stuff is always delivered on a seasonal basis by barge,” Thomson said. “The shipping season is from mid-May to early October. If you don’t make that window … you’re stuck; you’re going to have to [go] into next year.”
The cooperative still doesn’t have a delivery date for the storage equipment, he said.
Thomson was speaking at a Clean Energy States Alliance (CESA) webinar on July 14, one of two recent webinars focusing on the U.S. storage market and the challenges it now faces as the speed of technological innovation collides with the drag of supply chain delays and inflation.
Prices are up, investors are becoming more cautious, and building out the domestic supply chain for the lithium-ion batteries needed for transportation electrification could take years. Still, innovation is driving an upside, with the industry working to optimize the efficiency and value of lithium-ion batteries, while also developing long-duration, non-lithium alternatives.
At the Brookhaven National Laboratory in New York, Esther Takeuchi, chair of the lab’s Interdisciplinary Science Department, said her team is working on batteries with a higher energy density, using new materials with a longer life. The result could be EV batteries that can be charged up in 10 minutes, she said.
Speaking at a July 13 webinar on storage innovation hosted by Our Energy Policy (OEP), Takeuchi said another lab priority is “scalable” or big storage, which could be used for grid-scale projects, and “what are the characteristics needed to be big?”
“What are the actual materials?” she said. “How toxic are they? How available? Are they available domestically? Are they only available from a few places on earth, and sometimes those places have their own geopolitical challenges? How do you make things big, functional [and] safe?”
Supply chains will also be a core consideration for big storage, Takeuchi said. At the CESA webinar, both Thomson and Harvey Rambarath, assistant director of planning and development for the Seminole Tribe of Florida, reeled off a string of facts and figures on price increases for key components of solar and storage projects they are developing.
While planning a solar and storage project that would provide power for key tribal community buildings, Rambarath saw price increases of 84.7% for steel pipe and tubes and 44.9% for fabricated structural steel. As a result, he said, project costs increased from the original contract figure of about $2.9 million to over $3.5 million.
Flight to Quality
In other words, said Imre Gyuk, director of energy storage research at the Department of Energy’s Office of Electricity, the U.S. “battery supply chain is not really very robust.”
“The lithium battery industry relies on China, South Korea and Japan,” Gyuk said at the CESA webinar. “Transporting the batteries to the U.S. … adds another 4.1 kg of carbon dioxide to every kWh of battery [capacity].”
The U.S. does have lithium supplies, he said, in geothermal brine at the Salton Sea in California and in hard rock deposits in North Carolina and Nevada. “But mining is extremely capital investment intensive, and you need commitments to get started,” Gyuk said.
The lack of a domestic supply chain, the resulting delays and other market disruptions in the U.S. have sidelined 1.2 GW of new grid-scale storage projects that were scheduled to come online in the first quarter of 2022, according to industry analysts Wood Mackenzie. Still, the industry had a record first quarter, with 955 MW of new projects installed. Grid-scale projects accounted for more than 75% of the total.
Supply chain delays could affect the market — though to a lesser extent — through 2023, Wood Mackenzie said.
Sameer Reddy, managing partner at venture firm Energy Impact Partners (EIP), agrees that supply, not demand, is one of the biggest constraints on the U.S. energy storage market; the other is transmission.
“We just can’t build transmission quickly enough,” Reddy said at the OEP innovation webinar. “As we think about utility-scale solar and wind and attaching storage to that, we can only do that as quickly as we can build out transmission capacity.”
On the financial side of the equation, Reddy sees supply chain disruptions, inflation and threats of a recession driving “a flight to quality” across capital markets, including in the storage sector. “In times like these, the winners get stronger, and the losers get weaker,” he said.
“The infrastructure market for lithium-ion-based projects is incredibly healthy,” Reddy said. Pre-revenue startups developing alternatives to lithium-ion will also be able to secure funding, he said, “as long as they have a very clear story around how they beat lithium-ion technology. … The gap that I am seeing right now in capital markets is all of these new medium- and longer-duration storage technologies.
“It’s really incumbent upon the utilities, in many cases, to pilot those projects and sort of take the initial leap of faith on those technologies to help validate them to the market,” he said.
At the same time, Reddy sees extreme weather events, like the current heat waves in Texas and other parts of the U.S. triggering more “urgency to bring those long-duration technologies on sooner [rather] than later,” The good news, he said, is that several long-duration technologies — gravity-based storage, flow batteries and zinc batteries — are attracting significant investment.
For example, EIP has invested in Form Energy, a Boston-based start-up that is developing 100-hour-duration storage, Reddy said.
“As we electrify different loads across the grid, we’re going to need long-duration sources of storage to really insulate us from a resiliency perspective,” he said.
But Takeuchi stressed that, looking ahead, geography may determine the form of any given storage project. “Whatever form of storage we use, the location where the storage is going to be placed really determines many of the characteristics that are needed,” she said. “Things that are appropriate in wide open areas are not appropriate for areas like New York City or Chicago or [Los Angeles].”
Lifetime performance and costs should also be essential considerations, Takeuchi said. “It’s one thing to set up a system, but then how often do you need to replace it, fix it. If we had very long-life batteries, then things such as second-life batteries become viable.”
The EV Factor
The growing electric vehicle market is another and perhaps even more critical factor in current state of the U.S. energy storage market and supply chains, with exponential growth projected over the next four years, according to Vinayak Walimbe, vice president of emerging technologies at Customized Energy Solutions, an energy management firm.
The global demand for EV batteries stood at 286 GWh at the end of 2021, but is expected increase to 1,100 GWh by 2025, which will require a 40% year-over-year growth in battery production, Walimbe told the CESA supply chain webinar.
Electric vehicles worldwide put 286 GWh of battery storage on the road last year, but that number could jump to 1,100 GWh by 2025. | Adamas Intelligence
A major increase in raw material costs could be a drag on that kind of accelerated growth, Walimbe said. The industry celebrated when battery cell prices fell beneath $100/kWh in 2021, he said, but steep price increases in lithium and nickel have created a “bullwhip effect,” where small changes in one area of the industry ripple through the supply chain.
Walimbe sees the current supply chain disruptions affecting industries and countries around the world. “They are going to come up with ways to mitigate this.”
For storage, he sees two solutions ― developing a domestic supply chain and recycling — both of which are targeted by funding in the Infrastructure Investment and Jobs Act, he said.
John Rhodes, special assistant to the president in the White House Office of Domestic Climate Policy, agreed that the long-term solution is to bring a lot of mining and manufacturing capacity “on shore, and that’s going to take concerted, broad effort around new solutions” for lithium extraction and creating assured markets.
Rhodes pointed to the “nascent market” for electric vehicle chargers with built-in storage as one such domestic opportunity.
“It’s a self-evident solution to some grid build-out issues that confront a charging station developer,” Rhodes said at the OEP webinar. “Just the emergence of digital solutions around controls and situational awareness and fast response … [is] enabling storage through these enhanced controls to play a better and better role,” which will spur further market growth, he said.
With a construction site at what was once a 1,500-MW coal plant as his backdrop, President Biden on Wednesday proclaimed climate change a “clear and present danger” to the U.S., to which he would respond “with urgency and resolve.”
In his speech at the former Brayton Point coal plant in Somerset, Mass., Biden did not declare an official national emergency, but he said, “When it comes to fighting climate change, I will not take ‘no’ for an answer.”
Congress has failed in its duty to act on climate, Biden said, “and in the coming weeks, I’m going to use the power I have as president to turn these words into formal, official government actions through the appropriate proclamations, executive orders and regulatory power that the president possesses.”
Among that will be $2.3 billion in federal funding “to help communities across the country build infrastructure that’s designed to withstand the full range of [climate] disasters,” the president announced.
According to a senior administration official earlier in the day, those funds will come from the Federal Emergency Management Agency’s Building Resilient Infrastructure and Communities Program. Another $385 million in funding from the Low Income Home Energy Assistance Program, traditionally used for energy-efficient upgrades for homes in low-income communities, is being made available for states to use to set up cooling centers and help low-income residents buy air-conditioning units, the official said.
But both the official and National Climate Advisor Gina McCarthy, in a morning appearance on CNN’s “New Day,” talked around questions about if and when the president might declare climate change a national emergency and what actions he might take.
Declaring climate change a national emergency is “just not the announcement today,” McCarthy said. “The announcement today is going to be about making the case that climate change is an emergency [and] outlining actions that we’re going to moving forward over the coming weeks.
“We are going to act,” she said. “But the president is going to outline that at his pace.”
Clearing the Way for OSW
That deliberate pacing could account for Biden burying possibly his administration’s most important action halfway through his speech.
The president announced the next step in opening the Gulf of Mexico to offshore wind projects, with the Bureau of Ocean Energy Management (BOEM) identifying two potential wind energy areas (WEAs) in the gulf and opening a 30-day comment period on the sites.
According to a press release from the Department of the Interior, one of the proposed sites, totaling 546,645 acres, is located 24 nautical miles off Galveston, Texas, while the other, with 188,023 acres, is located approximately 56 nautical miles off the coast of Lake Charles, La.
The sites were chosen using “the most current scientific data to analyze 30 million acres in the [gulf] to find the best spaces for wind energy development,” said BOEM Director Amanda Lefton. “We are invested in working in partnership with states and communities to find areas that avoid or minimize conflicts with other ocean uses and marine life in the Gulf of Mexico.”
“We’re going to make sure that the ocean is open for the clean energy of our future,” Biden said. Projects off the Atlantic Coast and the gulf could provide “a real opportunity to power millions of additional homes from wind,” he said. “Let’s clear the way for clean energy and connect these projects to the grid.”
Biden also highlighted progress on Vineyard Wind 1, the 804-MW offshore project now under construction off Martha’s Vineyard. Brayton Point is now being repurposed as an DC-to-AC converter station to interconnect Vineyard, and potentially other OSW projects, to the grid through underwater transmission. (See Ex-Coal Plant Site Chosen for Mass. OSW Hub.)
On a Tight Rope
Since Sen. Joe Manchin (D-W.Va.) last week shut down negotiations over a pared-down budget reconciliation package that included a number of clean energy tax credits and other incentives, exactly what Biden will do and when he will do it has been a topic of debate and speculation.
Biden’s speech echoed his initial reaction to Manchin’s decision, citing concerns about June’s record 9.1% consumer price index and inflation. (See Biden: ‘I Will not Back Down” on Climate Action.)
Declaring a national emergency would add to a list of more than 40 executive orders in effect under the 1976 National Emergencies Act (NEA), with some issued nearly 30 years ago by President Bill Clinton. But a group of nine senators said in a letter to Biden that it would “unlock powers to rebuild a better economy with significant concrete actions.”
Led by Sen. Jeff Merkley (D-Ore.), the group said, “You could redirect spending to build out renewable energy systems on military bases, implement large-scale clean transportation systems and finance energy projects to boost climate resiliency,” the group said
Joining the letter, sent Wednesday, were Sens. Ed Markey (D-Mass.), Cory Booker (D-N.J.), Bernie Sanders (I-Vt.), Elizabeth Warren (D-Mass.), Sen. Sheldon Whitehouse (D-R.I.), Brian Schatz (D-Hawaii), Martin Heinrich (D-N.M.) and Alex Padilla (D-Calif.).
Meanwhile, Sen. John Barrasso (R-Wyo.), ranking member of the Senate Energy and Natural Resources Committee, was quick to criticize Biden’s focus on climate as out of touch with American families who “need energy that is affordable and reliable. Instead of taking action to ease the pain at the pump, the president doubled down today on his extreme climate agenda. This will only push energy prices higher.”
But Sheila Hollis, acting executive director of the U.S. Energy Association, saw Biden’s speech as an exercise in balance and pragmatism.
“He’s trying to make a statement [that] is in the realm of reality, as opposed to super long-term visions of how things should be,” Hollis said in a phone interview. “He did about the best he could under circumstances because there’s so many competing interests, competing concerns, international concerns and just the complexities of our system of regulating and distributing and making energy available.
“Anybody that is not simply didactic has to walk a tightrope,” Hollis said. “He’s on a tight rope.”
At its first in-person meeting since the beginning of the COVID-19 pandemic, NERC’s Standards Committee on Wednesday approved a standard authorization request (SAR) that would introduce electromagnetic transient (EMT) modeling to three of the organization’s reliability standards.
Most of the committee met at the Denver offices of Xcel Energy, with some members joining via conference call. Chair Amy Casuscelli — Xcel’s manager of reliability assurance and risk management — said she was glad to finally be hosting members again. She noted that not only were attendees likely to be “a little bit rusty” on meeting practices after more than two years of exclusive conference calls, but “14 of our 22-member roster are new since” the committee’s last face-to-face meeting and might have never seen the other members in person at all, and thanked them for contributing.
“We know that traveling is expensive for us and our companies. It’s time away from our day job, time away from our families, and we’re all facing tighter budgets,” Casuscelli said. “You guys are all here today because you see value in these interactions and [so do] your companies … so I would challenge you today to think through how we can maximize our time.”
Action Items Pass Without Exception
The EMT modeling SAR was proposed by NERC’s Inverter-based Resources Performance Subcommittee (IRPS) and endorsed by the Reliability and Security Technical Committee at its meeting last month. (See “Procedural Confusion on EMT SAR,” NERC RSTC Briefs: June 8-9, 2022.) It would require transmission planners (TPs) and planning coordinators (PCs) to conduct EMT studies, and apply to:
MOD-032-1 — Data for power system modeling and analysis; and
TPL-001-4 — Transmission system planning performance requirements.
The IRPS proposed the SAR in light of the bulk power system’s “rapid transformation towards high penetrations of inverter-based resources”; the subcommittee noted that many TPs and PCs “are concerned about the lack of accurate modeling data” to help plan the introduction of these resources and suggested that putting the modeling requirement in the standards would ensure they apply equally to all stakeholders.
Marty Hostler, reliability compliance manager for the Northern California Power Agency, expressed misgivings about the SAR, warning that it was unrealistic to expect TPs and PCs to be the only ones affected by the new requirements when other stakeholders, including generator owners, might have to be involved in the interconnection process as well.
“A lot of times these EMT models aren’t available, and they’re going to have to hire extra staff that has training on how to do that. So it’s not just going to be, in my view, the planning coordinators and transmission planners that are going to have to do this,” Hostler said. “It’s going to have to be all the people [having] to do system impact studies on their own facilities.”
Despite his concern, Hostler did not vote against the measure. The SAR passed unanimously, with no abstentions.
Frequency Response
The committee also approved without objection the posting of the proposed reliability standard BAL-003-3 (Frequency response and frequency bias setting) for a 45-day formal comment and ballot period after its submission by the standard development team for Project 2017-01 (Modifications to BAL-003). BAL-003-3 is intended to “make the [Interconnection Frequency Response Obligation] calculations and associated allocations better reflect current conditions and better consider characteristics affecting frequency response.”
The Standards Committee’s next in-person meeting is scheduled to be held Sept. 21 at ERCOT’s offices in Austin, Texas. The August meeting will be held via conference call, as will the October and November meetings. The committee will gather in person for the final meeting of the year in Atlanta on Dec. 13.
Massachusetts legislators on Thursday passed a compromise bill that aims to boost clean energy and electric vehicles and give cities and towns new options for greening buildings.
The bill (H.5060) comes after more than two months of negotiation between the House of Representatives and Senate, which had presented differing visions for the climate bill. (See Mass. Legislators Try to Hash out Next Climate Bill).
“Massachusetts needs to open up huge new sources of green electric power if it’s to stay on course for reducing emissions,” said bill sponsors Rep. Jeff Roy (D) and Sen. Mike Barrett (D) in a joint statement. “Today’s compromise aims to ramp up clean power, especially offshore wind but also solar, storage and networked geothermal, and run it through cars, trucks, buses and buildings — the biggest sources of emissions in the state.”
The bill has wide support in the state, including from groups such as the Green Energy Consumers Alliance and Environmental League of Massachusetts.
Here are highlights of the bill, which now goes to the governor for his consideration.
OSW and Clean Energy
The bill would create a new Clean Energy Investment Fund within the Massachusetts Clean Energy Center to support clean energy technology, research, workforce development and infrastructure.
It would also build a new Massachusetts OSW industry investment program and an accompanying trust fund to boost wind employment and economic development.
Helping the OSW industry was central to the House version of the bill and is a key priority of House Speaker Ron Mariano (D).
Electric Vehicles
Key to the Senate version of the bill is a focus on transportation, including changes to the state’s EV rebate program, which made it into the final agreement on the bill.
It would raise the cap on the purchase price of EVs eligible for the rebate to $55,000 from $50,000.
It would also add a $1,500 additional rebate for low-income EV buyers and expand eligibility to used EVs, if they were not sold in the prior two years.
The Baker administration might disagree with the new purchase price cap increase, since the administration previously said it wants to lower the cap to keep the program financially sustainable. (See Changes Coming to Mass. EV Rebate Program, Energy Commissioner Says). But the Department of Energy Resources will likely support the expansion to used vehicles and low-income provisions, which it has supported.
The bill would maintain a higher subsidy for the purchase of medium- and heavy-duty electric vehicles, with a minimum $4,500 rebate. And it would add new reporting and outreach requirements for the state to try to continue expanding the use of the program.
Other EV provisions include a mandate for the state to build charging infrastructure at service plazas and some transit stops and for distribution companies to propose off-peak and time-of-use EV charging rates.
Buildings
The bill addresses an ongoing debate in Massachusetts over whether cities and towns should be allowed to mandate zero-emission buildings.
It authorizes a “demonstration project” for up to 10 cities or towns to adopt zoning ordinances or bylaws that prohibit new building construction projects that are not fossil-fuel free. To participate, a municipality would have to comply with a state law that requires 10% of housing to be affordable.
The state government would then collect data from the demonstration project about the impacts on emissions, building costs, operating costs and other criteria.
Local leaders have been clamoring for the state to allow them to require fossil-fuel free buildings, but the Baker administration has held off from doing so even as it moves to update state energy building code rules. (See Mass. Net-zero Building Code Proposal Faces Barrage of Criticism).
MISO’s second competitively-bid transmission project appears dead in the water because new generation in the region has evaporated the line’s benefits, according to the grid operator’s assessment.
During a special South Technical Studies Task Force meeting Wednesday, MISO planners said about 2.7 GW of planned capacity in southeast Texas negates the Hartburg-Sabine Junction project’s economic benefits. The transmission line was approved in 2017 as a market efficiency project.
“There’s more capacity planned in Entergy Texas that is going to contribute,” said Clayton Mayfield, senior engineer of economic studies.
MISO has not yet officially cancelled the $130 million, 500-kV project in East Texas. Brian Pedersen, senior manager of competitive transmission administration, said planners will share the study results with a MISO staff committee that focuses on competitive transmission. That committee will decide whether to cancel the project or reassign it to a new developer.
Pedersen said MISO will make a formal recommendation in August.
Tea leaves don’t need to be read to deduce which direction the RTO is leaning. The RTO said Hartburg-Sabine “no longer provides any meaningful production cost benefits based on the planning analysis performed and using the latest modeling information.” The grid operator said its analysis couldn’t find “substantive” congestion relief or adjusted production cost benefits.
In 2017, staff said Hartburg-Sabine would alleviate congestion, ease import limitations and allow access to lower cost generation for customers in the chronically congested West of the Atchafalaya Basin and Entergy load pockets in MISO South.
MISO in late April announced it would reassess the Hartburg-Sabine junction project under its variance analysis procedures. Depending on study results, the RTO said it has one of two options: cancel the project or confer the line to Entergy in accordance with Texas’s recent right of first refusal (ROFR) law for incumbent utilities. (See MISO Study to Decide Fate of Texas Competitive Project.)
MISO’s study accounted for last year’s addition of Entergy’s 993-MW Montgomery County Power Station in southeast Texas and assumed the utility builds its planned 1.2-GW natural gas and hydrogen-powered Orange County Advanced Power Station by 2026. The Orange County plant has a signed generator interconnection agreement in MISO.
The grid operator considered that Entergy pushed back retirement of its nearby 500-MW, gas-fired Lewis Creek plant from 2025 to 2034. It also factored in the addition of two small nearby baseline reliability projects, one rated at 138 kV and the other at 230 kV.
Mayfield added that the RTO’s long-range transmission plan will soon study congestion patterns in MISO South and possibly come up with new transmission solutions.
“The Hartburg-Sabine Junction just isn’t economically solving the congestion we’re seeing,” Mayfield told stakeholders.
The line would have been MISO South’s first market efficiency project.
Stakeholders pointed out that the Texas Public Utility Commission has not yet approved the Orange County plant.
“The plant is in a holding pattern,” said Andy Kowalczyk of activist group 350 New Orleans.
“It seems like it’d be an awful shame not to at least do a sensitivity case with regard to the generation addition, whether it changes the outcomes for Hartburg-Sabine,” the Coalition of Midwest Transmission Customers’ attorney Jim Dauphinais said.
He said MISO might find itself “bringing the project back to the table” a year from now if the plant is not approved.
Energy consultant Jennifer Vosburg said the Orange County plant is already a few hundred million above its original budget.
MISO planners said even if plant approvals fall through, it wouldn’t make the line economic or necessary.
But Dauphinais said MISO wasn’t presenting any study results showing that the line remains unnecessary without Orange County.
WEC Energy Group’s Chris Plante said the Hartburg-Sabine was a market efficiency project that overcame several analyses to show benefits.
“I think that just demonstrates that as we go forward, we need to ensure that we have robustness testing, that even with small changes in assumptions … we still have a project that’s beneficial,” he said.
“I do hope that this serves as a lesson for how MISO approaches congestion planning and how durable and defensible these projects are over time,” Kowalczyk said. “I am worried that the market efficiency project tariff doesn’t produce projects, and this one was undermined by the ROFR, by bottom-up [transmission] projects and by signed generator interconnection agreements.”
The D.C. Circuit Court of Appeals on Tuesday upheld FERC’s May 2020 rejection of Public Service Company of Colorado’s proposal to change its large generator interconnection procedures, agreeing that the changes could have given the utility an unfair advantage over competing generators (20-1295).
PSCo, an Xcel Energy (NASDAQ:XEL) company, had proposed a fast-track process for generators looking to replace an existing power plant with a new one on the same site, saying it would avoid wasteful grid-impact studies and would allow new generators to interconnect more quickly.
But while FERC had previously granted a virtually identical request by MISO, it said such procedures had different implications for vertically integrated monopolies such as PSCo. Because 60% of PSCo’s existing designated network resources are generators owned by itself or an affiliate, “we find that the proposed generator replacement process could give PSCo an undue preference,” FERC said (ER20-1153). (See FERC Rejects PSCo’s Interconnection Process.)
The D.C. Circuit’s July 19 ruling upholding the commission came more than a year after FERC approved PSCo’s modified fast-track plan.
Order 2003
Under FERC Order 2003, grid operators generally consider interconnection requests on a first-come, first-served basis. The commission said vertically integrated operators cannot deviate from the standard interconnection process unless they show that their proposed changes are “consistent with or superior to” the commission’s standard large generator interconnection procedures (LGIP).
Because they do not own generation, independent grid operators such as MISO can win FERC approval for more flexible rules under the “independent entity variation” standard.
In March 2019, FERC accepted MISO’s proposed generator replacement procedure, saying it “will avoid duplicative study costs and operational costs that otherwise would occur when the request to replace an existing generating facility must proceed through the interconnection study queue process” (ER19-1065).
In rejecting PSCo’s proposal, FERC noted that when an existing generator retires, its transmission capacity can be made available for a new generator. But under PSCo’s plan, the retiree’s transmission capacity would instead likely be locked up by incumbent generators, such as the company itself.
Unlike PSCo, MISO does not “have an incentive to obstruct independent generation from accessing the grid,” the commission said.
The D.C. Circuit said FERC had provided an adequate explanation of its rejection.
“There was nothing arbitrary or capricious about its decision to bar a vertically integrated grid operator from adopting a rule that could favor its own generators and so cement its dominant market position,” it said. “The commission’s holding is consonant with decades of agency policy reflected in orders upheld by the Supreme Court and our court.”
Decision Moot
The court noted that the impact of its ruling was moot, however.
Shortly after rejecting PSCo’s proposal, FERC in November 2020 accepted Dominion Energy’s (NYSE:D) plan for a streamlined replacement generator program administered by a neutral third party, which the commission said would protect “against discriminatory implementation” of the new process (ER20-1668-003).
“In 2021, while this case was pending here, [PSCo] filed a request with the commission to adopt a streamlined replacement generator program administered by an independent entity,” the court noted. “The agency approved that proposal for the same reasons it gave in Dominion Energy” (ER21-1287).
The North American bulk electric system faced “unprecedented challenges” in 2021 that resulted in significant hardships to customers even though grid operators were largely able to maintain reliability, NERC said in its 2022 State of Reliability Report issued Wednesday.
Unlike the ERO’s seasonal and long-term reliability assessments, the State of Reliability is meant to review the performance of the electric grid in the prior year, identify performance trends and emerging reliability risks, and measure the success of mitigation activities. NERC staff previewed the report in May for the organization’s Board of Trustees, which approved the report earlier this month. (See NERC Board Accepts State of Reliability Report.)
Winter Storms Lead Review
This year’s report identified six key findings, four of which had to do with severe weather and other impacts of climate change. First, the winter storms of February 2021 “demonstrated that a significant portion of the generation fleet in the impacted areas was unable to supply electrical energy during extreme cold weather.”
The storm resulted in more than 23,000 MW of manual firm load shed across Texas and the South Central U.S., the largest controlled firm load shed event in U.S. history, according to FERC and NERC’s joint report on the event released last year. (See FERC, NERC Release Final Texas Storm Report.) Solely because of this one event, the ERO recorded 70.5 hours of operator-initiated firm load shed in 2021, higher than any other year since 2017.
At the other extreme was the Northwest Heat Dome, which affected the Pacific Northwest in June and July and caused temperatures to hit record highs — for example, 108 degrees Fahrenheit in Seattle and 116 in Portland. During the heat wave, which resulted in more than 1,000 deaths, “utilities across the region [set] new all-time summer peak demand records [and] several substation distribution transformers reached internal hotspot levels causing outages in some areas.”
Along with the severe weather events themselves — which also included the California wildfires, Hurricane Ida’s impact on Louisiana and Mississippi, and the storm system that spawned tornadoes in eight states in December — NERC’s report singled out electricity and natural gas interdependencies as another key finding. The vulnerability of the BES to disruptions in the natural gas supply has been a topic of concern for years, but it was highlighted in the February storms, when multiple gas generation plants were unable to perform because of freezing temperatures, resulting in a knock-on effect in which other gas generators could not function because of lack of electricity.
“It is now evident that these risks are no longer emerging; they are certain and expected to increase. Natural gas-fired generators are now necessary balancing resources for reliable integration of … renewable energy resources and can be expected to remain so until new storage technologies are fully developed and deployed at scale,” the report said.
While the direct effects of climate change are visible in the growth of severe weather events, the efforts of grid planners to prevent such impacts by adding wind and solar plants has also created reliability risks.
Left: AC circuit outages initiated by human error since 2017; right: Transformer outages initiated by human error since 2017. | NERC
NERC’s report cited the Odessa Disturbance — in which nearly 20 solar and wind facilities suffered reduced voltage as a result of a fault in a combined cycle plant in Odessa, Texas — as well as four disruptions in California as evidence of “continued BES reliability risks associated with inadequately interconnected” inverter-based resources (IBRs). (See Texas RE, WECC Call For Coordination on DER Issues.) In addition, NERC noted that in several areas, “peak demand could not be met without renewable generation,” suggesting that future disruptions to IBRs could lead to larger outages.
Cybersecurity Still Poses Problems
Among non-weather-related challenges, the threat of cyberattacks loomed large in 2021, with NERC noting “a series of attacks on the digital supply chain” and suspicious incidents across the industry such as phishing, malware and denial-of-service attacks. Threats came from both cyber criminals and nation-state adversaries such as China, Iran, North Korea and Russia.
In a media call introducing the report, John Moura, NERC’s director of reliability assessment and performance analysis, declined to specify how many of last year’s cyber incidents involved attacks against the industrial control systems that directly control the grid, as opposed to utilities’ information technology networks. He did, however, emphasize the “increased sophistication” displayed by the attackers and the need for ongoing vigilance by the industry, NERC and the Electricity Information Sharing and Analysis Center.
Finally, the report noted that despite frequent calls for new metrics to “evaluate the resilience of the [bulk power system] to the changing resource mix,” such measurements have not yet emerged. While NERC acknowledged that various stakeholders are working to develop new metrics, it will be difficult to properly evaluate the resilience of the grid until the task is completed.
ERCOT demand came within 12 MW of breaking the 80-GW barrier Wednesday afternoon, but the Texas grid operator was still able to set a record, its 11th of the year, as load averaged 79.8 GW during the hour ending at 5 p.m. CT.
Temperatures have reached up to 115 degrees Fahrenheit in Texas and Oklahoma, as the Southern Plains continue to bake under a heat dome that is diverting the jet stream northward. Oklahoma City hit 110 F on Tuesday, breaking a record that stood since 1936, while Wichita Falls to the south reached 115, a July record.
Other cities in the region could face the same dangerous conditions in the next few days. The National Weather Service has issued heat advisories and excessive heat warnings in 28 states.
“Another day of exceptional heat lies ahead with triple-digit highs forecast for all of North and Central Texas,” wrote the National Weather Service in Fort Worth in an online technical discussion.
SPP, which set its latest record for peak demand Tuesday, again extended the conservative operations advisory for its 14-state balancing authority area by 24 hours because of continued high loads and generation availability. The advisory is now effective through 10 p.m. Thursday.
The RTO’s grid is also operating under a resource advisory through Thursday.
