ATLANTIC CITY, N.J. — New York officials told the Business Network for Offshore Wind’s 2022 International Partnering Forum last week that they are considering doubling the state’s initial 9-GW offshore wind target.
“One thing we’ll be starting this year is the next Offshore Wind Master Plan, focusing on deep water,” said Doreen Harris, CEO of the New York State Energy Research and Development Authority (NYSERDA). “Because we know … time is not on our side with respect to climate change.”
Laila El-Ashmawy, a project manager with NYSERDA’s OSW team, noted that 9 GW represents a third of the state’s energy demand. “But we’re also considering that that might double” with electrification of transportation and building heating, she said. “And so when we really think about how much offshore wind [we need], we’re not really thinking about this nine-year cycle. We’re thinking about … an economy-wide decarbonization by 2050. So we expect this number to be … on the order of 15 to 20 GW of offshore wind. So, while we know 9 GW is challenging enough to plan for … the totality of those goals are what’s driving our transmission planning.”
Mesh-ready Requirement
The state’s 2021 power grid study concluded the current grid can handle 9 GW of OSW based on radial lines from each wind farm. “To do that, effectively, we need about 6 GW going into New York City, where most of our demand is. And that already starts to trigger a key limitation we have, which is that critical ocean right of way in ecologically sensitive areas: a lot of marine traffic; you have one of the biggest ports in the world, going through the Narrows [the tidal strait separating Staten Island and Brooklyn],” El-Ashmawy said. “So how we are going to get cables even for 6 GW into New York City is super, super challenging.”
The proposed solution: the mesh-ready concept. “Our projects will still be procured on that radial basis — one offshore wind project, one intertie, one point of interconnection — but we’d like to build them keeping in mind some common assumptions around what might be needed in the future; designing these offshore platforms with enough space to accommodate more equipment. We can’t go back and build it retroactively; [that] becomes much more expensive. So for incremental, upfront, modest costs, we can preserve a lot of optionality in the future,” she said.
NYSERDA’s draft offshore renewable energy credits (ORECs) request for proposals spelled out the technical requirements. “Each platform should be able to connect to two different wind farms. We’d like to be able to transfer around 350 MW of power. And that’s an AC offshore grid, contemplating 230-kV lines for those AC connections,” El-Ashmawy said. “These are not being built today; we’re just building with that in mind. This allows these projects to pivot to a future grid, where projects just in New York are interconnected and can reroute power between zones. But it also allows these to pivot and think about interregional interconnections, which might come in the future.”
El-Ashmawy said the next version of the RFP will provide more detail on the mesh-ready concept and clarification on “what is paid for now and what is paid for later.”
Pete Kohnstam, business development manager for Siemens Energy, said the mesh-ready approach could be risky because of the lack of standardization on what will be required in an offshore grid.
“The risks I see in doing the [mesh-ready] right out of the gate is if we have not got everything defined, is there sufficient space [in the platform]? Is there sufficient equipment in that to make it work?”
1st Offshore HVDC Project in the US
New York’s first OSW project, the 924-MW Sunrise Wind farm south of Long Island, will not be mesh-ready. But it will be the first implementation in the U.S. of an offshore HVDC grid connection.
Siemens and Aker Solutions were hired by developers Ørsted and Eversource Energy for the project, which will have an offshore converter station to collect the 66-kV AC power from the wind turbines and transform it to 320-kV DC for transmission through a 100-mile export cable. An onshore converter at Holbrook, Long Island, will convert the power back to AC to feed into the distribution grid.
Kohnstam explained the project during a workshop session that attracted dozens of attendees.
“DC obviously offers us lots of opportunities for going that long distance, getting more power into the network with fewer cable connections,” Kohnstam, said. “If you’ve been in several of the other panels and workshops, you’ll hear there’s an awful lot of concern about minimizing cable routes and minimizing access points. And DC is obviously perfect for that. So it’s happening. It’s real.”
Directors Approve RTO’s 4th Competitive Project Under Order 1000
DALLAS — SPP’s Board of Directors last week approved the RTO’s fourth competitive transmission project, awarding a $55 million, 345-kV facility in Oklahoma to NextEra Energy Transmission (NEET) Southwest (NYSE:NEE).
An industry expert panel (IEP) comprising five industry experts recommended the NextEra subsidiary be selected as the project’s designated transmission owner. The panel gave NEET Southwest’s bid the highest score among six other competitors, saying it presented the best evidence that it could produce a successful project that is constructed on time and within budget.
“There’s a clear winner here,” IEP Chair Steve Strickland, a 35-year veteran with Entergy Arkansas, told the board and Members Committee. “It’s significant to note that while [its bid] provided the highest cost savings, it also scored highest in engineering design and management. That indicated there is substance behind [the bid] in meeting cost commitments.”
The panel gave NEET Southwest’s bid a 1,000.38 score, 70 points higher than the next closest competitor. The other proposals’ scores ranged from 843 to 930.13. NEET Southwest’s bid received 225 points for rate analysis, representing the lowest cost to SPP customers in both construction and operating costs. The losing bids’ costs were between $74 million and $97 million. All seven proposals received the maximum 100 incentive points under SPP’s competitive transmission owner selection process, which is required by FERC Order 1000.
Strickland assured the board that “significant” supply chain issues and cost increases would not be an issue.
The IEP unanimously recommended Transource Oklahoma as the alternate designated TO after its bid received the second-highest point total.
The 48.4-mile connection between substations in Minco and Draper is an economic project designed to ease congestion around Oklahoma City. It has a July 2024 completion date, six months ahead of schedule.
“The early in-service date would allow lower-cost energy to flow across the project’s transmission lines, to the benefit of SPP’s customers, sooner than targeted by SPP,” the panel said in its report.
Matt Valle, NEET’s president, said the company was pleased to win the project’s construction. The project is the second time NEET Southwest has been awarded a competitive project, having won a bid last October for the 345-kV Wolf Creek-Blackberry project in Kansas and Missouri. (See SPP Board of Directors/Members Committee Briefs: Oct. 26, 2021.)
“This project award … furthers our goal of creating America’s leading competitive transmission company and is consistent with our strategy of adding high-quality regulated assets to our portfolio,” Valle said in a statement.
Oklahoma Gas & Electric opposed both motions approving NEET Southwest and Transource as the projects’ designated TOs. Seven members abstained from the NEET Southwest vote and six from the Transource vote.
Keith Collins, vice president of market monitoring at SPP, said rising natural gas prices and congestion from increased wind capacity is contributing to ongoing negative prices, curtailments and make-whole payments.
Sharing a draft of the Market Monitoring Unit’s State of the Market report, Collins said gas prices have doubled to $7/MMBtu and congestion was “materially higher” last year — at $1.2 billion — and had little to do with the February winter storm.
“Clearly, congestion is having an impact,” he said. “As renewables are more and more a part of the system, we should anticipate those effects to continue and start taking action. In the interim, we’ll continue to experience these challenges.”
According to the report, SPP’s installed wind capacity hit 30.5 GW last year, up from 27.3 GW in 2020 and 22.5 GW in 2019. Wind curtailments averaged 675 GWh in 2021, up from 130 GWh in 2019.
The increase in gas prices has made coal more competitive, Collins said. Coal accounted for 36% of SPP’s generation in 2021, just nudging out wind at 35%. “We see those trends continuing into 2022,” he said.
The MMU is recommending an emphasis on previous years’ recommendations by updating market and outage requirements to improve transmission congestion rights’ funding; improving market-to-market (M2M) efficiencies by collaborating with MISO; and addressing inefficiencies when forecasted resources under-schedule the day-ahead market.
The Monitor added one new recommendation, calling for SPP to expand or adjust the multiconfiguration combined cycle resource model to include additional multiconfiguration resource types. Collins said coal and other resources would be able to offer into the market more efficiently with the multiconfiguration logic’s additional applications.
Collins also drew attention to recent comments by David Patton, MISO’s Independent Market Monitor, that SPP is not properly recognizing M2M flowgate constraints with its seam neighbor in its day-ahead market. Patton told a MISO stakeholder group that the oversight must be costing SPP members several million dollars in balancing congestion. (See MISO and SPP Announce New Interregional Stakeholder Meetings.)
SPP responded that it does model MISO’s system and constraints in the day-ahead market and that it believes the market should best reflect expected real-time operating conditions and not necessarily create day-ahead congestion based on calculated firm flow entitlement values.
“The difference between SPP and MISO is how we reflect expected operating conditions in the day-ahead market,” SPP spokesperson Meghan Sever said in an email, saying the RTO has been transparent about its approach. “MISO automatically binds on constraints based on a calculated firm flow entitlement value and not real flows. SPP employs an injection/withdrawal projection based on similar operating days and expected actual operating conditions.”
Developers’ Self-funding Appeal Fails
The directors rejected an appeal by renewable developers of a revision request (RR465) that allows transmission facilities constructed to facilitate generator interconnections to be treated on a consistent cost basis with other infrastructure if the TO self-funds the work.
The measure easily passed over the developers’ objections last month during the Markets and Operations Policy Committee meeting. (See “Surplus Interconnection Service Change Remanded,” SPP Markets and Operations Policy Committee Briefs: April 11-12, 2022.) As is their right, they filed an appeal with the board that it further consider the self-funding mechanism and that it do so “more holistically” in the stakeholder process by including input from the Regional State Committee (RSC) and the MMU.
Writing for the seven developers April 22, EDP Renewables North America’s David Mindham said SPP TOs “severely mischaracterized” legal precedent by claiming “they are simply implementing a mechanism to which they already have a right.” He argued that FERC has never indicated that self-funding is allowed outside of MISO “and has been extremely clear” that the MISO example does not require its implementation in any other region.
He also noted that FERC’s decision to grant self-funding to MISO TOs is currently before the D.C. Circuit Court of Appeals and that the commission had not found a similar PJM proposal to be just and reasonable, though it did allow it to go into effect subject to refund after a paper hearing. (See MISO Gauging Aftershocks of TO Self-fund Order.) And on Friday, FERC rejected a MISO proposal to allow TO self-funding for merchant HVDC projects. (See related story,FERC Blocks MISO Self-fund Rule for Merchant HVDC Line Upgrades.)
“To use that as the basis that it should be used in SPP is not right,” Mindham told the board last week. “This construct increases the costs of network interconnection upgrades to the customers. It would behoove all of us to have that discussion broadly within the stakeholder process. We should have a discussion before suggesting a cost-recovery mechanism.”
Southwest Public Service’s Jarred Cooley countered that there had been significant discussion of the issue and that SPP’s tariff already includes language that allows self-funding, which he said can be potentially discriminatory.
“This revision request was identified to help produce a consistent and repeatable process for the staff and TOs, to put the rules around it so that then these opportunities to fund on the TO side are more clear and transparent,” Cooley said.
SPP Legal counsel Paul Suskie said staff would ensure the RSC is educated on RR465’s documents and provides feedback before filing its proposal at FERC.
The Advanced Power Alliance, Enel Green Power North America and Tenaska all sided in favor of the appeal during the Members Committee’s vote.
Counterflow Optimization not Dead Yet
The board and stakeholders agreed with board Chair Larry Altenbaumer’s suggestion to direct staff and stakeholders to work together in reaching some semblance of consensus and adding counterflow optimization (CFO) to the market.
It hasn’t been easy. The Holistic Integrated Tariff Team recommended three years ago that counterflow optimization, limited to excess auction revenue, be added to SPP’s market mechanism that hedges load against congestion charges. The process, which keeps system transmission flows between two points in balanced, was meant to address concerns about how congestion rights instruments are awarded and the current process’s efficiency.
The Market Working Group spent months trying to reach agreement on how best to add CFO, only to eventually turn it over to the Strategic Planning Committee. (See SPP SPC Takes on Congestion Hedging Issues.)
“There’s been no shortage of analysis. It’s simply a lack of consensus,” Altenbaumer said. “Lack of consensus doesn’t mean we have a lack of an issue. It’s reached a point where it doesn’t mean we should delay our concerns.”
Altenbaumer said he discussed a path forward with SPP’s leadership. Under his proposal, stakeholders, the MMU and state regulators will submit specific congestion-hedging recommendations with near- and long-term solutions. Staff will be responsible for setting parameters for the submissions, reviewing them and conducting a workshop to summarize the recommendations.
With staff freed from the stakeholder process, Altenbaumer envisions them working with regulators, the Strategic Planning Committee and the Cost Allocation Working Group (CAWG) to develop a final recommendation that could be brought to MOPC and the board in October.
NPPD Project to be Re-evaluated
The directors approved a re-evaluation of a 115-kV project interconnecting an industrial facility in Nebraska that has undergone a 24% escalation in costs.
Nebraska Public Power District (NPPD) pulled the item off the consent agenda so that it could move ahead with the project. Its costs went from $43.4 million to $53.8 million when a 345-kV substation was moved, resulting in $3.9 million for additional 345-kV ties. A 115-kV substation was expanded to accommodate three load-serving transformers, adding another $3.7 million in costs.
“We fully expect the answer will be the same,” NPPD CEO Tom Kent said, anticipating that SPP’s restudy to again result in a notification to construct. “I don’t see the value of going through the restudy process and getting the same result when the planning staff has other important work to do. We want the board to say, ‘No,’ so we can move forward.”
“A cursory look suggests it’s not likely to change,” said Antoine Lucas, SPP’s vice president of engineering. “All re-evaluations aren’t created equal, but the nature of this particular project will be simpler than some others. It’s not a very heavy lift.”
NPPD staff said the project’s load has changed several times, and the utility only recently firmed up its design with the industrial facility, which will produce hydrogen and carbon black. They said the Project Cost Working Group was notified as soon as NPPD had a handle on the cost increase.
With the board’s action, the restudy’s results will have to go before the Transmission Working Group and MOPC before being brought back to the board, possibly in July.
“We can probably live with the outcome. I don’t think it’s the right thing to use resources when we know outcome,” Kent said. “At the end of the day, we’ll be fine. We’ll move forward.”
RSC Adds 2 New Members
The RSC welcomed two new members during its first in-person meeting in more than two years: Minnesota Public Utilities Commissioner John Tuma and Nebraska Power Review Board Member Chuck Hutchison.
Tuma was eligible for membership because SPP member East River Electric Cooperative has distribution cooperatives with load in Minnesota. The RSC comprises state regulators and responsible for providing input of approval of rate-related issues and other matters of “regional importance.”
Hutchison replaces Dennis Grennan, who chaired the RSC in 2020.
In other actions during the April 25 meeting, the committee directed the CAWG to analyze RR465 for any potential effects on retail rates. It also endorsed staff’s recommendation to not add CFO to the current market construct and approved a pair of changes to its bylaws that remove a membership classification not used in 18 years and clarify that RSC membership is based on SPP’s RTO footprint.
SPP Releases Online Annual Report
SPP’s slick digital 2021 annual report finds the RTO at “another pivotal point” in its continuing growth and development with both challenges and opportunities, including the continuing COVID-19 pandemic, the historic February 2021 winter storm and establishing relationships with new stakeholders in the West.
In their joint letter to stakeholders, CEO Barbara Sugg and Chair Altenbaumer said the previous two years have “prepared us well for the next chapter in SPP’s history.”
“We’ve learned valuable lessons from managing reliability in historically unprecedented circumstances, collaborating closely while separated by physical distance and building consensus among an increasingly diverse group of stakeholders,” they wrote. “The adaptability we have shown in responding to the unexpected will remain an important part of our ongoing strategy.”
MISO’s financing options for transmission system upgrades on merchant HVDC lines are not on equal footing with those for interconnecting generators, and therefore not subject to the RTO’s self-fund order, FERC said last week in a ruling that could save transmission developers millions.
The April 29 ruling pertains to the commission’s 2019 decision that restored transmission owners’ option to unilaterally self-fund network upgrades before the interconnection customers are offered the chance to finance them. FERC said the initial funding option cannot be extended to upgrades needed for merchant HVDC lines because those developers aren’t offered the same array of financing options as generation developers under some circumstances. (ER22-477).
Commissioner James Danly dissented, claiming his fellow commissioners’ decision rested on a technicality.
In late 2021, MISO filed to extend the self-fund option to transmission owners building upgrades to accommodate merchant HVDC lines. The RTO argued that “both types of connections result in upgrades on the MISO transmission system.”
MISO transmission owners agreed that merchant HVDC line-related upgrades should be treated comparably with generator interconnection-related network upgrades. The MISO TOs said they saw no meaningful difference between the two types of projects because both require TOs to install and maintain upgrades that would not be needed but for the projects.
Clean energy organizations, including American Clean Power Association and Clean Grid Alliance, banded together to protest the self-funding expansion. They said the filing “rests on an unproven assertion of comparability” between the two types of upgrades. They said facilities needed for merchant HVDC are developed under a different business model, and a TO self-funding option — which would subject HVDC developers to a TO rate of return rather than a market-based interest rate — could cause upgrade costs to balloon.
SOO Green HVDC Link, which is developing a 350-mile HVDC line running along corridors from Iowa to Illinois, contended TO financing could cause upgrade costs to increase by 30-40%, meaning a merchant developer with $100 million in upgrades could be charged tens of millions more at the higher rate of return.
The clean energy group also said MISO’s proposal would introduce discriminatory treatment between merchant HVDC-to-transmission owner interconnections and transmission owner-to-transmission owner interconnections “even though all such facilities will be operated as part of an integrated grid.”
FERC’s decision, however, rested on the differing financing option available for the two types of upgrades rather than material differences between the upgrades themselves.
MISO failed to show how the expansion of TOs’ self-funding option to merchant HVDC lines wasn’t discriminatory or preferential, the commission decided.
MISO could not insist that the upgrades are “functionally identical” when it doesn’t offer all available funding options to merchant HVDC developers when they haven’t secured injection rights, FERC said. MISO doesn’t include an option to build or liquidated damages provisions in transmission connection agreements for merchant HVDC developers without injection rights, or a pre-certification from MISO that its system can handle the capacity and energy the line plans to deliver. MISO allows merchant HVDC lines to connect to the system without injection rights, but those lines are considered non-firm and the upgrades to accommodate the line are classified as necessary upgrades instead of network upgrades. “MISO created the category of necessary upgrades because it believed that necessary upgrades would be necessary simply for a physical connection between the MHVDC transmission line and the MISO transmission system and thus would likely be limited in scope,” FERC explained.
MISO’s option-to-build safeguard allows interconnection customers to take over construction of network upgrades when a transmission provider cannot meet pre-negotiated milestones. The liquated damages provision lets an interconnection customer collect damages when a transmission provider lags in completing upgrades.
FERC also said while MISO characterized its filing as simple housekeeping related to the 2019 self-fund order, the grid operator was actually expanding TO initial funding “into new areas” of its tariff where the option hasn’t historically existed. The commission pointed out that its 2019 self-funding order did not address merchant HVDC upgrades.
In his dissent, Danly said the commission’s decision “denies the transmission owners’ right to receive a return on and of the capital costs of network upgrades, necessary upgrades, and transmission owner system protection facilities.”
Danly pointed out that FERC has accepted TO initial funding provisions for merchant HVDC upgrades in other areas of the country.
“…[A]bsent some evidence to the contrary, MISO’s proposed tariff revisions bear all the hallmarks of relatively minor improvements to a tariff already deemed just and reasonable,” Danly wrote.
NYISO made it through last winter without any problems — and without any power from coal generation or the Indian Point nuclear plant, ISO officials reported to stakeholders last week.
But the ISO is focusing intensely on coordinating with natural gas system operators for next winter as prices remain high while the Russo-Ukrainian War rages on.
New York experienced several cold snaps in January — before the Russian invasion began and prices spiked — including one late in the month that included heavy snow. NYISO forecast a peak load of 24,025 MW for the season; the actual peak came in at 23,237 MW on Jan. 11, a mostly sunny day but extremely cold, with the high temperature upstate not breaking 20 degrees Fahrenheit.
NYISO fuel prices cratered during the onset of the COVID-19 pandemic, and they have skyrocketed since Russia’s invasion of Ukraine. | NYISO
Wes Yeomans | NYISO
During a presentation to the NYISO Management Committee on Wednesday, Wes Yeomans, the ISO’s vice president of operations, said if that cold weather had come earlier in the month “when there was more load from lighting, I absolutely believe we would have hit” the forecasted peak. Jan. 11 was not the coldest day, but there was still significant lighting load that day, he said.
January’s average temperatures were 3 to 4 degrees lower than normal. The lowest temperature recorded during the season was -9 F on Jan. 22 and 30 F in Syracuse.
Despite the sometimes extreme cold, the grid performed well. NYISO did not have to use any emergency procedures or call on demand response resources; all inter- and intrastate gas pipelines remained in service; and behind-the-meter solar contributed more than expected.
Yeomans was especially complimentary of the state’s gas system, which he said was “very tight, but … it worked very well.”
“We’re laser-focused, in light of the Texas events of February 2021, on the performance of the gas system,” Yeomans said.
Local distribution companies and interstate pipeline companies issued many operational flow orders (OFOs) throughout the winter, Yeomans said. OFOs tell gas producers that they need to carefully balance their supply with demand on a daily or even hourly basis within a specified bandwidth; during winter, they’re most likely to be used to meet increased demand.
“Oh, this is good,” Yeomans said in reading off a bullet point in his presentation, which noted that in many cases, the notices were “‘issued with enough lead time before the day-ahead market closed to properly account for the impacts in the day-ahead market solution.’ So in other words, we greatly appreciate the gas industry to the extent that they predict very tight conditions or they think they’re going to declare hourly OFOs. … If they can get those out to their gas customers prior to the close of the day-ahead, that really helps our generators understand what the fuel situation is.”
Energy efficiency also helped. During his presentation, Yeomans displayed a graph showing that peak loads have trended downward even with comparable winter temperatures. For example, the peak loads during both the winter of 2007/08 and last winter occurred with temperatures around 15 F, but the peak load this year was nearly 2,000 MW lower.
New York is heavily dependent on gas generation. The state’s last coal plant shuttered March 31, 2020, and Indian Point closed a year later.
According to NYISO COO Rick Gonzales, gas prices for March 2022 were nearly double those of March 2021, while diesel prices were more than double, at $4.47/MMBtu and $27.02/MMBtu, respectively.
Those prices coincided with a near doubling of locational-based marginal prices for electricity: $56.78/MWh this March compared to $28.59/MWh last year. Energy sendout was only slightly higher compared to March 2021: 390 GWh/day compared to 381.
A stakeholder noticed that NYISO saw a spike in LBMPs during the last days of March. Yeomans said that the state experienced some unusual cold weather, “but you know, this Ukraine-Russia war … I think that was beginning to be impactful on LNG and oil prices, and it may be that gas prices followed.”
Fond Farewell to Yeomans
The MC meeting was the last for Yeomans, who retired at the end of last week. He was replaced by Aaron Markham, the former director of grid operations who was promoted in late February.
There are “very few times in life when you come across a person who is perfectly matched for the position that he or she held,” committee Chair Chris Wentlent, of the Municipal Electric Utilities Association of New York State, told Yeomans. “And in my mind, you fit that picture perfectly.”
The next MC meeting on May 25 will be held in person. Wentlent also reminded attendees to “book your hotel reservations” for the joint meeting of the committee and the Board of Directors on June 13.
The U.S. Department of Energy on Tuesday issued new energy-efficiency standards for light bulbs that will effectively phase out incandescent bulbs in the country by July 2023.
The new standards require “general service” light bulbs — those used in most residential lamps and lighting — to produce 45 lumens/W. Lumens are a measure of brightness; LED bulbs can easily meet the new standards, which will go into effect 60 days after they are published in the Federal Register; incandescent bulbs will not.
In practical terms, the new standards mean light bulb manufacturers in the U.S. will have to stop making incandescent bulbs in January 2023, and U.S. retailers will have to stop selling them by July 2023.
According to DOE estimates, the new standard could save American consumers and businesses up to $3 billion per year on utility bills while cutting carbon emissions by 222 MMT over the next 30 years.
The light bulb standard, originally set in 2017, was put on hold in 2019 by former President Donald Trump. It is one of 57 “delayed” energy efficiency standards that DOE inherited from the previous administration, Energy Secretary Jennifer Granholm told the House Energy and Commerce Subcommittee on Energy during a Thursday hearing on the department’s 2023 budget request.
“Our goal this year is to get totally caught up from that and issue about 100 orders to make sure that we can keep appliances efficient for American citizens so that they don’t have to pay the money that they would have to pay if they were using inefficient technology,” Granholm said. “We’re very proud of the actions that we are taking; we’re going to be very aggressive about trying to reduce costs for people.”
“This is a victory for consumers and for the climate, one that’s been a long time coming,” said Steven Nadel, executive director of the American Council for an Energy-Efficient Economy. “LEDs have become so inexpensive that there’s no good reason for manufacturers to keep selling 19th-century technology that just isn’t very good at turning electrical energy into light. These standards will finally phase out energy-wasting bulbs across the country.”
$2.3B for Grid Improvements
Continuing its rollout of funding opportunities from the Infrastructure Investment and Jobs Act, DOE on Wednesday released a request for information (RFI) for a $2.3 billion grant program aimed at helping states and tribes to update and improve the resilience of their transmission and distribution systems.
The program will provide “formula grants” to each of the 50 states, five territories, 547 Native American tribes and communities, and D.C., according to the projected grant allocations issued by the department. The grants are not competitive, but states and tribes will have to apply for them.
The five-year program will provide a total of $459 million per year. Grant amounts for the states range from $33.8 million for California to $1.7 million for Rhode Island.
According to a Notice of Intent, also released by DOE, that money could go to T&D owners, operators and providers, as well as generation owners and fuel suppliers for a broad range of resilience-related projects, such as:
utility pole upkeep and removal of trees and other vegetation affecting grid performance;
undergrounding electrical equipment, and relocating or reconductoring lines;
improvements to make the grid resistant to extreme weather and fires;
implementing monitoring, controls and advanced modeling for real-time situational awareness; and
integrating distributed energy resources like microgrids and energy storage.
The RFI seeks feedback from prospective program applicants and other stakeholders about how the grants and application process should be structured. “Specific feedback is requested about anticipated application challenges, technical assistance support and other critical data sources,” the DOE announcement said.
The deadline for comments is May 27.
Environmental Justice in Lithium Valley
During a recent tour of Southern California energy and cleantech sites, Granholm became the first U.S. cabinet secretary to make an official visit to Imperial County and the Salton Sea region now widely known as Lithium Valley, according to a report in The Desert Sun.
Accompanied by Rep. Raul Ruiz (D-Calif.), Granholm attended two community “listening sessions,” where local officials and residents voiced concerns about the potential health and environmental impacts of proposed lithium extraction projects in and around the Salton Sea. While Imperial County may be sitting on an estimated 15 MMT of lithium — a critical mineral used in batteries — local communities have suffered from the environmental and health impacts of the drying up of the sea. The exposure of the seabed could increase already-high levels of air pollution in the region.
“We know about the opportunities coming with lithium, but we have a lot of concern, especially for the public health of our kids,” local resident Elizabeth Jaime said in Spanish through a translator, as reported in The Desert Sun. “What assurance do we have as parents that this industry won’t generate more pollution?”
Recent research found that Imperial County’s rate of emergency room visits for pediatric asthma were double the statewide average.
With federal funding opportunities for battery storage coming soon, Granholm said that “anybody who is getting funding from the federal government [will have to] consult with the local community to make sure that your voices are heard.”
The day before Granholm’s visit, plans for the construction of a 54-GWh electric vehicle battery factory were announced by Controlled Thermal Resources and Italvolt. (See 54 GWh EV Battery Plant Proposed for Lithium Valley.)
ATLANTIC CITY, N.J. — The U.S. offshore wind industry is beginning to deliver on port improvements and other infrastructure, but it’s also experiencing some growing pains, attendees at the Business Network for Offshore Wind’s (BNOW) 2022 International Partnering Forum said last week.
The event drew about 2,700 people and 300 exhibitors from 25 countries.
BNOW CEO Liz Burdock noted the progress the industry has made since last year’s IPF: the $4.37 billion New York Bight auction; the entry of six new offshore wind developers into the U.S. market; and the Biden administration’s plans to lease seven new wind energy areas by 2025, including the West Coast and the Gulf of Mexico.
With the latest procurements from Maryland and Massachusetts, the U.S. now has 19,580 MW in offshore wind under development.
“We’ve had nine primary component manufacturers start to establish operations and manufacturing on the East Coast. We’ve had more than 1,000 sub-supplier contracts given to businesses across 33 states,” Burdock said. “Offshore wind is becoming a national industry.”
Jane Cohen, executive director for New Jersey Gov. Phil Murphy’s Office on Climate Action, expressed pride in the state’s $500 million investment in the New Jersey Wind Port in Salem County. “There are people there right now working to prepare that for the marshalling, the manufacturing. Five years ago, we didn’t have that; three years ago, we didn’t have that. And today we have a real infrastructure asset for offshore wind in southern New Jersey. Same with our … new monopile facility in Paulsboro. The first monopile is arriving on Friday.”
More ports will be needed, industry officials say, to reach the Biden administration’s goal of 30 GW of OSW by 2030.
“It’s no surprise to anyone that ports are a significant limitation. They represent some of the longest lead … infrastructure improvement items required,” Joshua Weinstein, vice president and head of offshore development for Invenergy, said during a panel discussion Wednesday. “The ports are the places where manufacturing is completed. The ports are the places where staging is completed. They are the key enablement to not only delivery of components, but also installation of components. And that is, by and large, the scarcity that we have here in the U.S.”
Cost Pressures
There was much optimism at the conference. Clint Plummer, CEO of Rise Light & Power, a subsidiary of LS Power, said offshore wind is becoming more competitive with other sources of generation.
“I’ve been in this industry for 15 years, and when we started this back in 2007, offshore wind was seen as this wildly expensive science project. Cape Wind was way too expensive, right? The Delaware project was way too expensive,” he said, referring to two canceled projects. “But now, projects like South Fork [off Long Island] are showing that it’s actually cheaper to use offshore wind to supply renewables to densely populated coastal areas.”
Others, however, said they are concerned by thin margins, rising lease prices and supply chain problems.
Stephen Bull, executive vice president for renewables for Aker Solutions, an Oslo-based engineering company, cited research that every offshore wind turbine in Europe generates 10 million euros in economic activity annually. Europe has about 5,500 offshore wind turbines producing 25 GW.
“There are about 250 factories in Europe producing turbines and their parts. And the wind sector employs about 300,000 people in offshore wind alone,” he said.
But he said many in the industry are struggling with thin profit margins, in part because of supply chain problems resulting from the COVID-19 pandemic and Russia’s invasion of Ukraine.
“Pushing all this risk back onto the supply chain is not the answer,” he said. “A new deal between developers and the supply chain is required. The traditional procurement model of playing supply chain companies against each other, overloading them with risk, obsessively pushing down towards lump sum contracts — that really cannot continue.”
Instead, Bull called for a “collaborative approach.”
“Some examples could be setting levelized cost of energy targets together; incentivizing around value improvements; ensuring a new level of transparency or ‘open book’ approach; employ a most-likely cost concept for greater risk sharing; and also defining a healthier mix between reimbursable and lump sum contracts,” he said. “We need to devise a risk-reward structure that gives sustainable rewards for everybody. Perhaps the U.S. is the market that we can crack the code for this.”
“Market volatility and cost competitiveness have become key industry challenges,” said Laura Beane, president of Vestas North America, which will supply turbines for the 2.1-GW Empire Wind project. “The U.S. market will need to adapt to build and maintain an economically viable offshore industry that is sustainable over the long term and free from the boom-and-bust cycles that have largely defined the clean energy buildout here.”
Plummer also expressed concern.
“Offshore wind leases are now really expensive. The New York Bight auction showed that for the first time in the history of American offshore wind industry, the cost of the lease itself is now going to be a non-trivial part of the overall capital expense of that project and, therefore, a non-trivial cost to ratepayers,” he said.
Federal Reinvestment Sought
BNOW’s Burdock called for a “national industrialization strategy,” saying the industry was not capturing the value it will provide in economic benefits, energy security and mitigating climate change.
“Wedges between social and private costs or returns lead to inefficient markets, and in some cases, they may even prevent markets from emerging. A low-cost pricing structure could eventually hold this industry back,” she said.
“The federal government and Congress must match the states’ swift and bold actions to create an offshore wind market with equally swift and bold actions to create a U.S. offshore wind domestic supply chain. We need incentives, policies and programs that help businesses overcome challenges and create resiliency.”
Sam Eaton, executive vice president of offshore development in the Americas for RWE, also said the federal government should do more to nurture the industry.
“The states have done a fantastic job. … I think we can’t say enough about all the great work that’s been done over the last five years. But I think at the federal level, there’s a little bit more we can do. And I think the $4.5 billion that we’re talking about for New York Bight offers one of those great opportunities,” he said.
Invenergy’s Weinstein agreed, calling for investment in risk mitigation, workforce training and ports development.
Despite the growing pains, Bill White, CEO of Avangrid Renewables, said the industry has a solid foundation.
“The problems that we have as an industry are beautiful problems to have. We are working too hard, and we’re too busy. We’ve got too many [requests for proposals] to respond to. We’ve got too many contracts to deliver. We’ve got too many projects to negotiate,” he said. “Isn’t this what we all wanted?”
American Electric Power (NASDAQ:AEP) last week said it is continuing to transform its energy system for the future and de-risking and simplifying itself.
The company told financial analysts during its first-quarter earnings conference call Thursday that it expects to close the sale of its Kentucky operations by July and that it is preparing to market its 1.6-GW portfolio of unregulated contracted renewables during the second half of the year. The latter’s sale proceeds will be directed toward additional investment in AEP’s regulated businesses.
“We already have shifted $1.5 billion in capital to transmission, bringing our planned five-year capital spend to $14.4 billion in transmission and $10.4 billion in distribution,” AEP CEO Nick Akins told analysts.
The Columbus, Ohio-based company announced last October that it planned to sell its Kentucky utility and transmission companies to Liberty Utilities, a subsidiary of Algonquin Power & Utilities (NYSE:AQN), for $2.85 billion. (See AEP to Sell Kentucky Operations to Algonquin.)
AEP said during its earnings call in February that it will sell some or all of its unregulated contracted wind and solar energy resources and redirect capital previously allocated to that business to its transmission assets. (See AEP to Sell Unregulated Renewables Portfolio.)
Akins said the company is making “substantial progress” in transitioning its generating capacity to 50% renewables this decade. It recently commercialized the last of three wind farms making up the almost 1.5-GW North Central Energy Facilities in Oklahoma.
AEP reported earnings of $715 million ($1.41/share), up from 2021’s first-quarter performance of $575 million ($1.16/share). Its share price closed at $99.53 the day before the earnings call. It finished the week down 42 cents at $99.11.
Xcel Earnings up 4.7%
Xcel Energy (NASDAQ:XEL) also announced first-quarter earnings Thursday. The Minneapolis-based company reported income of $380 million ($0.70/share), compared to $362 million ($0.67/share) in the same period in 2021.
CEO Bob Frenzel told analysts Xcel had reached “constructive regulatory outcomes” on several key matters, including its Upper Midwest Resource Plan, the Colorado Power Pathway transmission project and a rate case in Colorado.
The Upper Midwest Resource Plan would add 5.8 GW of wind and solar energy to Xcel’s system, extend the life of its Monticello nuclear plant in Minnesota to 2040, and retire its regional coal fleet by 2030. The $1.7 billion Colorado transmission project would enable 5.5 GW of new renewables, Franzel said.
Xcel’s Comanche Peak 3 coal-fired plant in Colorado is out of service following a “transmission event” and is not expected to be back in service until June because of supply-chain constraints. The outage is expected to cost the company about $25 million.
Clean Attribute Procurement Task Force Established
PJM stakeholders at last week’s Markets and Reliability Committee meeting endorsed an issue charge creating a new senior task force to study a potential market construct for procuring clean resource attributes in the RTO’s markets.
The issue charge, which was developed in the Resource Adequacy Senior Task Force (RASTF) over several months of debate, was endorsed with a sector-weighted vote of 3.513 (70.2%), surpassing the necessary 2.5 threshold.
Dave Anders, director of stakeholder affairs for PJM, reviewed a revised issue charge from the RASTF, saying the first key work activity in the original called for determining whether the “forward procurement of clean resource attributes” should be pursued by stakeholders and examining the inclusion of the social cost of carbon in PJM markets. He said 70% of RASTF members endorsed pursuing a new issue charge calling for a “comprehensive discussion of market enhancements” that would enable states and other buyers to procure clean resource attributes “on a voluntary basis, through a regional and centralized procurement or market.”
Work will start in the new Clean Attribute Procurement Senior Task Force with education on the procurement of clean resource attributes, including defining clean resource attributes across jurisdictions, markets and procurement mechanisms. The second step calls for discussing the objectives of a market construct to enable voluntary procurement of clean resource attributes.
PJM and stakeholders will determine an approach to conduct analysis and select one or more market design solutions for further development. Expected deliverables in the issue charge include proposed market rules to implement the preferred design, if one is found.
“The universe of high-level approaches could vary very widely,” Anders said.
Denise Foster Cronin of the East Kentucky Power Cooperative (EKPC) proposed a friendly amendment to the issue charge, adding language delineating that “for any market design endorsed by the MRC,” stakeholders will conduct a “detailed design and develop market rules for implementation.”
“It’s not intended to be a substantive change to the work that’s going to be undertaken,” Foster Cronin said.
Greg Poulos, executive director of the Consumer Advocates of the PJM States, objected, saying that some of the advocates were “concerned” that the amendment could “add delay or extra layers of steps to the process.”
The amendment was not adopted in the endorsed issue charge.
Chris Pilong, senior director of operations planning, and Alex Scheirer, senior client manager for PJM, also provided an update on the Operating Committee’s recommendation regarding additional reliability products and services related to the issue charge. The OC approved an initial recommendation at its April 14 meeting for the evaluation of adding more reliability-based generation as greater numbers of intermittent resources are integrated into PJM’s grid. (See “Reliability Products and Services Assessment Endorsed,” PJM Operating Committee Briefs: April 14, 2022.)
Deactivation Process Timing Update Endorsed
Members endorsed a PJM proposal to update the process timing for generation deactivations, with one stakeholder voting against it.
David Egan, manager of PJM’s system planning modeling and support department, reviewed the proposal and presented the revisions to Manual 14D and the tariff.
Current tariff language provides 90 days advance notice and 30 days to complete deactivation studies, which Egan said is causing “insufficient and unsustainable” time for PJM staff to determine adverse impacts on reliability if more than one deactivation notice is made in a single study period. New state energy policies are also adding to the number of deactivations, creating more pressure on PJM staff to finish studies.
Example of a generation deactivation timeline in PJM from June-August 2021. | PJM
The proposal calls for establishing quarterly study times for requests, with periods beginning Jan. 1, April 1, July 1 and Oct. 1. PJM staff would study deactivations in batches for more accurate results for the impacts on the system. Egan said the quarterly schedule would allow enough time for additional required seasonal, interim year and short-circuit analyses; scheduling upgrades and cost estimates; and for PJM operations to identify additional needed operational measures.
Paul Sotkiewicz of E-Cubed Policy Associates thanked PJM for working with stakeholders to amend some of the tariff language that creates exemptions so that generation owners aren’t penalized if a unit is forced to deactivate through state legislation or actions by the federal government.
Stakeholders will vote on final endorsement of the proposal at the Members Committee meeting May 17. Conforming Manual 14D language will also go through the OC and System Operations Subcommittee.
Dynamic Line Ratings
PJM provided a first read of the RTO’s proposal and manual revisions supporting the interim integration of dynamic line ratings (DLRs) into its operations.
Stakeholders unanimously approved an issue charge and endorsed a proposed solution as part of the “quick fix” process at last month’s Planning Committee meeting. (See “Dynamic Rating Issue Endorsed,” PJM Operating Committee Briefs: April 14, 2022.)
A PPL helicopter crew installs dynamic line rating sensors on transmission lines. | PPL
Chris Callaghan, PJM senior business solution engineer, reviewed the proposal. PPL is tentatively scheduled to go live in June with a DLR system on some of its transmission lines, Callaghan said, and PJM wanted to “enable the operational implementation of dynamic ratings” through temporary manual revisions, which will be in place pending submission of the RTO’s FERC Order 881 compliance filing, scheduled to be finalized this month.
In December, FERC ordered transmission providers to end the use of static line ratings in evaluating near-term transmission service and required transmission providers to employ ambient-adjusted ratings for short-term transmission requests of 10 days or less for all lines that are impacted by air temperature. (See FERC Orders End to Static Tx Line Ratings.)
Some of the manual revisions include adding timeline requirements to notify PJM about any new DLR systems to be installed on the grid and to provide details on requirements for real-time and forecasted DLR submissions.
“Our goal with the timeline requirement is to provide for both PJM and other stakeholders to be aware of the implementation and be prepared for it as well,” Derin said.
Susan Bruce, counsel to the PJM Industrial Customer Coalition, said she appreciated PJM and PPL “looking at ways to get more out of existing transmission assets.”
Consent Agenda
Stakeholders unanimously endorsed several items, including manual, Operating Agreement and task force charter revisions, as part of the MRC consent agenda. They included:
revisions to Manual 14F: Competitive Planning Process resulting from a periodic review. The changes included updating language so that the Secure File Transfer Tool used to submit all proposals was replaced with a requirement to use “Competitive Planner” to submit proposals.
revisions to the OA intended to appropriately document the underfrequency load shedding (UFLS) relay requirements applicable to EKPC. A recent review of revisions showed “potential confusion” in EKPC’s appropriate UFLS requirement that needed to be corrected.
revisions to the Energy Price Formation Senior Task Force charter. The proposed charter edits relate to the delay in reserve price formation implementation, from May 1 to Oct. 1.
Members Committee
Definition of Workshops
Members are looking to add a definition of “workshops” to the PJM manual to better explain their purpose in the stakeholder process.
At last week’s Members Committee meeting, John Horstmann, director of RTO affairs at AES Ohio, presented the proposed revisions to Manual 34: PJM Stakeholder Process. The language was partially developed at the Stakeholder Process Forum.
The proposed definition states that workshops are “a series of meetings occasionally convened by PJM to discuss emerging topics and objectives as outlined in its initial communication and meeting. Workshops are non-decisional meetings and will not develop rule changes. Rather, they are formed to engage in education, foster dialogue, share ideas and gather stakeholder feedback.”
Calpine’s David “Scarp” Scarpignato thanked PJM and Horstmann for the work on coming up with a clear definition, saying it was “much needed.”
“They’re getting used more and more often, and it adds some clarity around these things,” Scarp said.
Remote Voting Endorsed
Stakeholders unanimously endorsed revisions to Manual 34 to allow for remote voting for the Board of Managers election at the PJM Annual Meeting on May 17.
Previous manual language requires written paper ballots for the elections of board members and the Members Committee vice chair. The revisions to Manual 34 strikes that language.
PJM said it identified the need to “exercise flexibility” to conduct the 2020 and 2021 board elections because of precautions surrounding the COVID-19 pandemic.
The 2020 board election was done remotely through the PJM Voting Application with special auditing provisions, and the 2021 board election was conducted through a secure, third-party online election service, Survey & Ballot Systems.PJM is continuing to use a secure third-party voting system for stakeholders not attending the Annual Meeting in person.
Maine Gov. Janet Mills on Wednesday vetoed a bill designed to limit development of transmission lines that would deliver electricity out of the state.
“The bill (LD 170) would create inappropriate barriers to the development of transmission lines, which could hinder the ability of the state and region to meet our critically important climate and energy goals,” Mills said in a veto letter.
As passed with a committee amendment, the bill sets guidelines for regulatory approval of transmission lines that are deemed “nonessential,” in that they are not needed primarily for in-state electric reliability, in-state retail electric service or meeting Maine’s climate goals.
“LD 170 does not prevent future transmission lines in Maine to serve Massachusetts and others in the region,” Rep. Seth Berry (D), House chair of the joint Energy, Utilities and Technology (EUT) Committee, said in a statement. “On the contrary, it asks that they be developed for mutual benefit and in consultation with communities and landowners who may otherwise be forced to host new infrastructure.”
Designating transmission lines as nonessential based on their functional benefit outside of Maine misrepresents the regional nature of the New England power grid and the global nature of the climate crisis, according to Mills. For Maine and other states in New England to meet their climate goals, “it will be essential to work strategically on a regional level, and this bill would seriously interfere with those efforts,” she said.
Amendments made by the EUT Committee established nonessential line approval requirements that Mills called “vague, ill-considered and unworkable.” The requirements included ensuring the developer demonstrates it has negotiated with stakeholders, attempted to work with impacted communities and negotiated for shared ownership if the developer cannot finance the project through revenue bonds.
The bill also would direct regulators to consult with municipal governments affected by the potential taking of land by eminent domain for a proposed transmission line before approving it.
“I worked hard to address concerns that the public flagged in the [New England Clean Energy Connect (NECEC)] debate so that we have a more transparent and accountable process moving forward and that our clean energy transition proceeds at the necessary pace to meet our climate goals,” the bill’s sponsor, Rep. Nicole Grohoski (D), said in a statement.
Mills has been a steadfast proponent of the NECEC project, which is planned to deliver Canadian hydropower to the New England grid via a 145-mile transmission line that would run through Maine. Voters in the state, however, approved a measure in November to halt construction of the project.
Avangrid subsidiary Central Maine Power, developer of the project, agreed to stop constructing NECEC while the courts consider its claim that the referendum is unconstitutional.
Legislators will return May 9 to consider LD 170 and other vetoed bills. Mills urged the legislature to sustain her veto.
Grohoski said she is “surprised and disappointed” by Mills’ veto and hoped her colleagues will join her in voting to override it.
CAISO on Thursday published its much-anticipated proposal to add a day-ahead market to its real-time Western Energy Imbalance Market as it tries to secure a larger share of a more regionalized Western energy landscape.
The extended day-ahead market (EDAM) plan covers key components, including transmission commitment, resource sufficiency evaluation and market-power mitigation.
“EDAM is a voluntary day-ahead electricity market with the potential to deliver significant economic, environmental, and reliability benefits for participants across the West,” CAISO said in the straw proposal. It “builds upon the proven ability of the Western Energy Imbalance Market (WEIM) to increase regional coordination, support state policy goals, and cost effectively meet demand.”
The WEIM recently surpassed $2 billion in cumulative benefits for participants since it went live in November 2014. It has 17 members and is expected to grow to 22 participants by 2023, its benefits keeping pace with participation, CAISO said. (See Western EIM Tops $2B in Benefits.)
CAISO is hoping that the WEIM’s growth record will attract new and current members to its day-ahead offering and fend off competition from SPP, which also has a real-time market — the Western Energy Imbalance Service (WEIS) — and is planning to start its own day-ahead market in the West as part of its Markets+ program, now under development. (See Western Utilities to Support SPP Market Development.)
A map in CAISO’s Q1 2022 benefits report shows transfer paths in the Western Energy Imbalance Market. | CAISO
The stakes in the CAISO-SPP day-ahead competition could be higher than in the real-time segment because real-time trades account for only about 5-10% of energy transactions in the Western Interconnection while the day-ahead market accounts for 40% or more of all transactions, according to WECC.
CAISO projects EDAM benefits, above those already seen in the WEIM, at $95 million to $400 million annually. The ability to trade greater amounts of renewable output and reduce curtailments as states transition from fossil fuels to clean energy is viewed as a primary benefit of the EDAM.
The day-ahead market will also promote reliability, a prime concern in the West, where resources have been spread thin during summer heat waves as fossil-fuel plants retire and weather-dependent wind and solar resources take their place.
“The EDAM will … enhance reliability across [its] footprint … through a robust resource sufficiency evaluation and an imbalance reserve product that accounts for a level of uncertainty … between the day-ahead and real-time [markets],” CAISO said.
The Western Power Pool’s Western Resource Adequacy Program (WRAP), covering much of the West, is aimed at the same problem — one of a number of current efforts to promote greater regional cooperation in the balkanized Western Interconnection.
Some FERC commissioners have urged the formation of one or more RTOs in the West, while CAISO and SPP have been developing their own regional market programs, including SPP’s planned RTO West. (See Changing Grid, State Policies Favor Western RTO.)
Key Components
After a pandemic hiatus, CAISO fast-tracked EDAM development starting last fall. Three stakeholder working groups met from January through mid-March to offer input on important design elements, and CAISO incorporated the groups’ results into Thursday’s straw proposal.
“First, voluntary participation is a key feature, as it is with the WEIM,” the straw proposal said. “This will allow for voluntary entry and exit, as well as resource participation.” Ensuring fair rates for EDAM participation and confidence in market transfers were additional “threshold features” determined by the stakeholder groups, CAISO said.
Transmission commitment was another must-have, the ISO said.
“An EDAM entity and its transmission customers will need to make transmission available for the market to commit supply optimally within the EDAM [balancing authority areas] and identify transfers between EDAM BAAs,” it said. “The proposal retains the transmission bucket concept previously put forward by WEIM entities, where high-quality firm or conditional firm transmission is made available to support transfers between EDAM BAAs.”
The proposal requires participants to pass a day-ahead resource sufficiency evaluation (RSE) to show they have enough supply to meet internal demand and reserve requirements to avoid “leaning” on the market for additional supply. Failure to pass the RSE could lead to transfer limits or an opportunity for the entity to cure the deficiency through residual supply for a fee.
Other elements of the straw proposal include:
Integrated forward market (IFM) and residual unit commitment (RUC)would be “two primary processes of the day-ahead market,” CAISO said. “The IFM balances supply and demand, which results in optimized supply commitment schedules and identification of market transfers. The RUC process runs after the IFM and will procure incremental or decremental capacity, as a backstop to the IFM, to ensure there is sufficient physical capacity to meet demand in real-time.”
Market power mitigation tools would ensure that, when supply is limited, “suppliers cannot exercise market power to influence prices at arbitrarily high levels,” it said. “As a starting point for consideration, we propose to extend the WEIM market power mitigation methodology for EDAM but seek stakeholder input on the need for potential enhancements to evaluate market power across groupings of BAAs, instead of individual BAAs [in the WEIM], to better account for dynamic constraints affecting the groupings.”
Convergence bidding would allow submission of financial bids in the IFM that do not represent physical supply or demand, CAISO said. “Convergence bidding is a common feature of forward electricity markets and is designed to improve price convergence between the day-ahead and real-time market,” it said.
External resource participation would let resources outside of the EDAM footprint offer supply into the market. “These resources may be pseudo-tied or dynamically scheduled into an EDAM BAA,” CAISO said. “We propose that economic bids and self-schedules continue to be supported in the EDAM.”
Transfer revenue is the “settlement difference between the revenue paid to the import transfers and the cost charged to the export transfers,” CAISO said. “The ISO will distribute the transfer revenue to the EDAM entity that made the transmission available to the day-ahead market. The distribution of the transfer revenue between BAAs depends on the type of transmission used to facilitate the transfer at the transfer point. We are proposing a transmission settlement method to ensure each EDAM BAA is equitably compensated for releasing transmission capacity at each transfer point that is optimized in the day-ahead market.”
For greenhouse gas (GHG) accounting and reporting, the EDAM proposal recommends two potential options: a “resource-specific bidding and attribution approach, an extension of the WEIM framework for GHG accounting, and the zonal approach, which allows resources to be reflected as internal to a GHG regulation area or utilizes a hurdle rate for transfers.”
“We are considering deploying the resource specific approach at the onset of EDAM because it is more developed and better aligned with the WEIM design,” CAISO said.
The 37-page straw proposal goes into greater detail on these elements and more. A stakeholder meeting on the proposal is scheduled for May 25-26, both in-person at CAISO headquarters, in Folsom, Calif., and via a virtual option.
NYSERDA CEO Doreen Harris | © RTO Insider LLC
Pete Kohnstam, Siemens Energy | © RTO Insider LLC
