During SPP’s quarterly board meeting in October, CEO Barbara Sugg reflected on her tenure, which began shortly before the COVID-19 pandemic shut down the world in 2020.
“It is nice that after three and a half years as the CEO, we’re not talking about the pandemic anymore,” she told directors and stakeholders. “And we haven’t had a recent 100-year storm [in 2023].”
True. While the past year did not include a winter storm like those in February 2021 (Uri) and December 2022 (Elliott), it did include record-breaking heat during the summer that taxed the SPP system.
The grid operator broke the previous all-time peak several times before finally registering a record of 56.2 GW in August, a month during which it issued six conservative operations advisories for its footprint. Capacity dropped to ‑200 MW at one point during the summer, second only to the losses the RTO suffered during Winter Storm Uri. Imports from neighbors saved SPP both times.
“The summer was particularly challenging for us. It really tested our operators and your system operators as well,” Sugg told stakeholders. “The summer peak was 5% higher than the last summer, which was 5% higher than the summer before, which is incredible.”
Sugg said she is particularly concerned about the growth in demand and the variability of renewable resources. She pointed to a day in June when wind and solar resources produced only 111 MW at one point.
“That helps us really think about what we need to do to maintain reliability in the volatile climate,” she said. “The operating conditions certainly highlight the importance of maintaining the generation fleet and getting accreditation right for both conventional and renewable resources, and getting that to be as accurate as it can be.”
To that end, SPP created the Resource and Energy Adequacy Leadership (REAL) Team to mitigate resource adequacy risks and develop policies on fuel assurance, demand response and accreditation. The team — a cooperative effort between the Board of Directors, state regulators and stakeholders — has already signed off on performance-based accreditation for conventional resources and effective load-carrying capability accreditation for wind, solar and storage resources.
The REAL Team is waiting on the biennial loss-of-load expectation study to be finalized this spring. The study will fuel the effort to deliver winter and summer planning reserve margins to the team and to the July governance meetings.
FERC added to the REAL Team’s workload in November when it rejected SPP’s proposed winter resource adequacy requirement. However, the commission said the RTO can address FERC’s concerns and resubmit the proposal (ER23-2781). (See ‘Therapy Session’: SPP REAL Team Reviews Draft LOLE Study.)
Coming on the heels of Winter Storm Elliott, SPP set as its first goal improving grid resilience to prepare for extreme weather events. Staff have included winter scenarios in its 2024 and 2025 transmission plans and completed numerous recommendations from its review of the recent winter storms.
Another major priority for SPP has been improving a generator interconnection queue that contains more than 500 projects and more than 100 GW of capacity. Sugg said the RTO is still on track to meet its stated goal of clearing the original GI backlog and the 2022 cluster by the end of this year, having processed 93 GI agreements last year. Staff processed 37 agreements in 2022.
“I’m actually extremely optimistic about how far we will get with the ’22 and ’23 clusters … which is a far cry from where we were years ago when you were looking at four or five years to get answers on your generator interconnection requests,” Sugg said.
SPP also celebrated a $464 million grant from the Department of Energy to help fund its joint targeted interconnection queue projects with MISO. The portfolio and its five high-voltage transmission lines, recently revised to cost $1.86 billion, were one of several grid resilience and improvement projects to be awarded DOE funding from the Infrastructure Investment and Jobs Act. (See DOE Announces $3.46B for Grid Resilience, Improvement Projects.)
But that’s just SPP’s Eastern Interconnection footprint. Out West, where the grid operator is involved in several reliability and market initiatives, it received commitments from nine utilities that want to join its RTO West when it goes live in 2026. They are now obligated to reimburse the RTO for development expenses if membership agreements are not executed in March 2026.
In November, SPP began operating the Western Resource Adequacy Program (WRAP) on behalf of the Western Power Pool. The WRAP’s operations program produces seasonal forecasts to help determine whether participants have sufficient resources, and it enables anyone with a deficit to secure additional resources.
Western stakeholders and staff are well into the first developmental phase of Markets+, an RTO-light bundle of day-ahead and real-time market services. As 2023 wound down, stakeholders endorsed, and the Markets+ leadership approved, the market’s governance plan, helping clear much of the road to filing a tariff at FERC in February. (See IMIP Approves SPP Markets+ Governance Tariff Language.)
SPP’s Western Energy Imbalance Service added three Colorado utilities in April, expanding the reliability coordination market from 4.5 GW to 13.5 GW. The real-time balancing market, operational since 2019, provided an estimated $31.7 million in net benefits to its 12 participating utilities in 2022 at a benefit-to-cost ratio of 7-to-1, according to SPP analysis. The RTO said this resulted in reduced wholesale electricity costs by an average of $1.35/MWh over the year.
The backers of two separate initiatives to spur development of new transmission in the West are taking different approaches on when to deal with the issue of who should pay for projects.
The Western Transmission Expansion Coalition (WTEC), launched by the Western Power Pool (WPP) and backed largely by the power sector, wants discussions about cost allocation to be put on the back burner while industry stakeholders first figure out what should be built.
WPP CEO Sarah Edmonds said WTEC efforts “aren’t touching cost allocation”; the subject is outside the intended scope of the effort, which is designed to expand the geographical scope of transmission planning to include all the West. “We aren’t part of a cost allocation federal tariff,” she noted during a Dec. 11 meeting of the CAISO Western Energy Imbalance Market’s Regional Issues Forum (RIF).
“Cost allocation is kind of one of those things that has really chilled conversation in the West around transmission planning. If we took that off the table for the WTEC effort, what might we find in terms of creative ideas?” Edmonds said.
While acknowledging the conundrum around the matter, Matthew Tisdale — executive director of decarbonization nonprofit Gridworks, which is partnering with the Committee on Regional Electric Power Cooperation on the WSTI — sees a problem with that approach.
“I think that planning and cost allocation are sort of a chicken and an egg here,” Tisdale said at the RIF meeting. “It’s hard to do the planning without understanding what is going to be the approach to cost allocation, and it’s difficult to do the cost allocation without knowing what you’re planning for.”
Both initiatives have set the stage for conversations about who will incur the costs and reap the benefits of much needed transmission projects in the West.
A key goal of WSTI is to form a Transmission Working Group that would, among several tasks, advance the discussion on transmission cost allocation. The states, Tisdale said, will be leading the conversation and coordination around how the cost of interregional transmission could be allocated across state lines.
‘Taking the Bull by the Horns’
While Tisdale, Edmonds and CAISO officials at the meeting agreed that states should be the entities to determine cost allocation for transmission projects, some stakeholders expressed concern about the challenges of that approach for allocating costs across state lines.
Matt Lecar, principal at Pacific Gas and Electric, highlighted complexities surrounding different regulatory requirements; for example, California could agree on a cost allocation framework not matched by entities elsewhere in the region.
“I get that having the states buy in on a cost allocation framework brings down the risk barrier, but what’s going to convince me that the billion dollars or more that I spend on constructing and bringing online a project is going to lead to a successful cost recovery via a mix of jurisdictions that may or may not see eye-to-eye on whether those costs were prudently incurred?” Lecar said.
“Discussions around ratepayer recovery of transmission facilities have been challenging under [FERC] Order 1000, and we need to have the cost allocation conversation,” said Danielle Osborn Mills, director of market policy development at CAISO. “In the meantime, we’re trying to think creatively around how we can have bilateral arrangements that lead to shared benefits across the region and also appropriately shared costs.”
Michele Beck, director of the Utah Office of Consumer Services, emphasized the need for greater coordination among consumer advocates, regulators and transmission planners. She expressed concern that while the WSTI interviewed more than 40 stakeholders, consumer advocates were not included.
Beck also noted that while the WSTI has signaled it will include public interest organizations in a Western transmission conference it intends to host, consumer advocates were again left out.
“We’re very cautious about an emphasis on cost allocation and moving forward on that, especially when we may or may not be at the table,” Beck said. “In our view, sometimes that can be a euphemism for finding a way to get more people to pay for projects … that might be desired only by a subset of the folks involved.”
While there was some disagreement on how costs should be allocated, energy officials seemed to agree upon the struggle to find a better option.
“The states leading on cost allocation is probably the worst forum for developing cost allocation — except for all the other ones, because all the other ones haven’t worked for 20 years either, and so we want to see some leadership in the region,” Tisdale said. “We want to see somebody taking the bull by the horns and raising hard questions.”
A public webinar regarding the WTEC project is scheduled for Jan. 29.
“This guidance improves upon previous NIETC designation processes in response to both court decisions and updates to our authority in recent legislation,” Grid Deployment Office (GDO) Director Maria Robinson said during a webinar Jan. 3. “Specifically, I’ll note that the proposed process would designate narrow geographic areas as NIETCs, rather than large swaths of land.”
The department is taking public comment on that guidance, which is due Feb. 2, and it plans to release a list of NIETCs that it will continue to study 60 days after that.
“This list will provide the preliminary geographic boundaries of potential NIETCs, which we expect to be sort of a rough approximation,” said Gretchen Kershaw, GDO senior adviser for transmission.
The lists will also include preliminary assessment of transmission needs within the relevant area and any harms to consumers, essentially explaining the threshold need determination made in phase 1, she added.
The transmission needs study identified a need for interregional transfer capacity around the country, but Kershaw said DOE’s process would favor lines with multiple benefits in addition to increasing the ability to ship power between regions.
The list will provide high-level explanations of why potential NIETCs moved to phase 2 of the designation process, and any that did not will continue to be eligible in future designations. Stakeholders will have an additional 45 days to provide comment on those in phase 2. DOE will look to refine the NIETCs’ geographic scope and start to consider environmental assessments.
DOE will further narrow down the list and then formally propose the NIETCs in phases 3 and 4. The department is unsure of the timeline for that because of how long environmental reviews can take, Kershaw said. A standard environmental impact statement takes the department about two years to produce, she added.
The department does not plan to propose massive corridors, as it did the last time it designated a pair of NIETCs in 2007, Kershaw said. In a process that was ultimately stymied by the courts, the department picked one route that covered Southern California and parts of Arizona and another that covered much of the mid-Atlantic into New York City — both designed to ship cheap power into the two biggest cities in the U.S.
“It concentrates stakeholder attention on where new transmission is most likely to be built within a NIETC by having that narrower scope,” Kershaw said. “The narrower geographic areas also lead to more efficient preparation by DOE of environmental documents again focused on a narrower area, and also more useful environmental documents for permitting agencies including FERC.”
The Infrastructure Investment and Jobs Act granted FERC the authority to approve new transmission in the corridors when states either lack authority to site a project (if they cannot consider regional benefits, for example), have not acted on an application after a year or have denied an application for a line.
Some projects will use that authority from FERC under Federal Power Act Section 216b, but for those that do not, DOE can help coordinate all federal authorizations and environmental reviews under Section 216h of the law, Kershaw said.
Delaware’s environmental agency has proposed an offshore wind procurement strategy for one of the few East Coast states without a stated goal for developing wind energy from the ocean.
The Department of Natural Resources and Environmental Control (DNREC) State Energy Office announced Jan. 3 that it had delivered the report to the governor and legislators.
It lays out the many moving pieces in an industry that holds great promise for producing clean energy but is experiencing severe growing pains in the United States.
Delaware, which has the shortest ocean coastline of any state with coastline except New Hampshire, currently has no plans for offshore wind procurement. The official state webpage for offshore wind leads off with a noncommittal summary: “Delaware continues to explore opportunities and challenges presented by the growing offshore wind industry.”
But the state has set a target for 40% renewable energy by 2035. And its Renewable Energy and Clean Technologies Workgroup recently recommended the state develop a procurement mechanism for at least 800 MW of offshore wind capacity.
This compares with goals of 8.5 GW in Maryland and 11 GW in New Jersey.
The strategy proposed by DNREC analyzes the cost, benefits and impact of a hypothetical 800-MW wind farm on the Outer Continental Shelf.
The report flags an inherent challenge: There are few options other than offshore wind for delivering renewable energy in the quantities needed by Delaware, but offshore wind is an industry where economy of scale is especially important, and it is hard for such a small state to achieve economy of scale on its own.
The strategy recommends looking at partnerships with neighboring states to achieve that economy.
It also reviews the uncertain and changing factors affecting the U.S. offshore wind industry, predicts developments in 2024 that will affect planning and offers recommendations on structuring a procurement.
The U.S. Bureau of Ocean Energy Management has designated wind energy areas in the vicinity of Delaware, but projects proposed to date would feed into Maryland. Delaware’s only role would be as a landing site for export cables.
Nearby, Ørsted has canceled both phases of a proposed wind farm that would feed into New Jersey. Ørsted has not canceled the proposed Skipjack Wind — a Maryland project off the Delaware coast — but it has scaled investments back to a minimum.
The report was produced by DNREC’s Division of Climate, Coastal and Energy with Synapse Energy Economics and Zooid Energy.
“This report provides the background, current economic conditions and options for the governor and state legislators to consider as Delaware charts its path forward in the development of a comprehensive offshore wind program,” DNREC Secretary Shawn M. Garvin said in announcing the proposed strategy.
New Jersey is looking to strengthen its clean energy commitment in 2024 with new wind projects, an enhanced community solar program and legislation to aggressively improve the grid after a year in which the state’s much-touted offshore wind program (OSW) suffered a major setback.
The New Jersey Board of Public Utilities (BPU) expects by March to pick the winners from the four projects submitted for the state’s third OSW solicitation, which could add capacity of 4 GW, and perhaps more, in line with solicitation guidelines.
A successful and sizable allocation of projects could help quell doubts that have swirled over the state’s OSW program since Danish developer Ørsted abandoned its two projects planned for the New Jersey coast — the 1,100-MW Ocean Wind 1 and 1,148-MW Ocean Wind 2. Ocean Wind 1, approved in 2019, was the state’s first and most advanced project.
Ørsted’s comments that the two projects were no longer economically viable raised questions about the wisdom of the state’s aggressive gambit on the OSW projects, which included the New Jersey Wind Port, to which the state has committed about $1 billion.
The projects’ demise marred a year that otherwise contained significant advances for clean energy policy. The state in November adopted California’s Advanced Clean Cars II (ACCII) rules, which require a growing proportion of new car sales to be zero-emission vehicles until all new sales must meet that criterion in 2035.
The state also created a permanent Community Solar program, based on the experience of two (heavily oversubscribed) pilot programs that confirmed developer interest. The program started accepting applications in November. And the state made aggressive moves to cut emissions from buildings, its second-highest source of greenhouse gases after transportation.
“Clean energy policy is a game of inches, and certainly the ball was moved down the field this year on a number of significant fronts,” said Doug O’Malley, director of Environment New Jersey. “Obviously, there’s always going to be bumps along the way.”
He called Ørsted’s withdrawal a “sucker punch,” but noted that offshore wind projects continue to advance in other East Coast states, and cited New Jersey’s third solicitation as evidence that the sector marches on.
“There are multiple projects in the queue that will allow New Jersey to benefit from offshore wind in the future,” he said.
Decarbonizing Buildings
Gov. Phil Murphy (D) set the tone on building decarbonization, signing executive orders in February designed to “advance the electrification of commercial and residential buildings.” He also set a goal of electrifying 400,000 additional dwelling units and 20,000 additional commercial spaces or public facilities by December 2030.
The same day, Murphy signed an executive order that required the BPU to look at how to mitigate the impact on the gas industry and its workforce as the state switched to using electric hot water and heating appliances in pursuit of a 50% reduction in greenhouse gas emissions below 2006 levels by 2030.
In line with that intent, the New Jersey Economic Development Authority (EDA) in December launched a $15 million grant program to help commercial building owners retrofit heating or cooling systems.
The prospective shift has stoked vigorous opposition among business groups, unions and fossil fuel companies. In November, they backed a bill, A577, that would enable the use of renewable natural gas in the state’s gas infrastructure. But environmentalists, who say it is an unproven technology, fear that allowing renewable natural gas would weaken the state’s commitment to electrification. (See NJ Advances Multifaceted Building Decarbonization Strategy.)
New Master Plan
Murphy, and the BPU, remain committed to the wind sector. The governor’s vision of the state’s energy future likely will be laid out in the release of a new energy master plan some time this year. The last version of the plan, “Pathway to 2050,” released in 2019, has been a cornerstone of the state’s drive toward a zero-emissions energy policy. Business groups and Republicans have expressed concerns about the cost of the initiatives, which the governor has yet to fully outline.
Businesses are concerned they don’t know enough about the cost of the state’s proposed initiatives, especially the shift from fossil fuel use in buildings to electricity, said Michael Egenton, a lobbyist for the New Jersey Chamber of Commerce. He said he’d like to see more transparency this year and to see the Legislature more involved in clean energy decision-making, not just the BPU.
“I’m not saying that things should not be pursued, but it has to be done practically, logically, timely,” he said, expressing skepticism that the state can meet Murphy’s targets, such as the ACCII rule to have all new vehicles sold be electric vehicles by 2035.
“We need more information, we need to know what this is going to cost, and who’s going to be responsible for those costs,” he said.
Murphy’s task likely was made more challenging by the death Sept. 7. of Joseph L. Fiordaliso, the well-regarded BPU board president and a BPU commissioner since 2005, who led Murphy’s efforts to transform the state. Murphy immediately appointed Christine Guhl-Sadovy, a clean energy advocate and Fiordaliso’s former chief of staff, as the board’s leader. (See NJ BPU President Fiordaliso Dies.)
Yet the board enters this year short of the depth of experience Fiordaliso possessed, with three remaining members who joined the board in the past two years. The Senate approved a fourth member, Michael Bange, a manager for New Jersey American Water, on Dec. 21.
Legislative Push
The Legislature also has pushed a vigorous clean energy agenda. Some Democrats and environmentalists saw the results of the November 2023 legislative elections — in which Democrats held their majority in the Senate and added five seats in the Assembly — as evidence the public backs clean energy initiatives. The GOP in some races sought to depict such initiatives as excessive and expensive.
Sen. Bob Smith (D), chairman of the influential Senate Environment and Energy Committee, which shapes many of the Legislature’s clean energy bills, sees two bills as key elements of the 2024 session. Legislators debated but did not act on either bill in the current legislative session, which ends Jan. 8. They will be heard in the next session, which starts Jan. 9.
One of the bills, S2978 in the current session, would put into law a Murphy executive order that set a state goal of reaching 100% clean energy by 2035. A second bill, S3992, would allocate $500 million in state and federal money to invest in upgrades to the state grid to prepare it for the expected surge in clean energy use, Smith said.
“Our grid is made up of bobby pins and chewing gum — the grid’s in terrible shape,” Smith said. “You can’t connect [a project] to the grid, because the utility, the [electric distribution company], will say, ‘Well, we have to do a study, and you’re gonna have to pay for improvements to the grid’” that are needed to handle the proposed project, he said.
Prior to the close of the current legislative session, there are several bills on Murphy’s desk that Smith hopes could produce important clean energy policy, provided he signs them. If he doesn’t, the sponsors would have to start the process again in the next session.
Bill S3723, the Electric and Hybrid Vehicle Battery Management Act, would prohibit the disposal of vehicle batteries in the solid waste stream and create a framework for the proper disposal and recycling of the batteries. Smith believes it is the first legislation of its kind in the nation.
A second bill, S3490, would adjust the rules for make-ready charging stations to make it easier to install EV chargers in certain situations, especially in multi-dwelling units.
O’Malley said the need to accelerate the installation of EV chargers is an example of an issue the state, for all its clean energy efforts, needs to address more aggressively this year.
“New Jersey is way behind other states on the national electric vehicle infrastructure implementation,” he said. “We need to expand our charging network everywhere, not just the Turnpike and Parkway. It should be as easy to find an electric vehicle charging station as it is to find a 7-Eleven or a Wawa.”
FERC has approved ISO-NE’s proposal to delay Forward Capacity Auction (FCA) 19 by one year, pushing the auction to February 2026 (ER24-339). The auction is for the capacity commitment period (CCP) that runs from June 2028 through May 2029.
Further changes could be on the horizon for FCA 19. ISO-NE has initiated the delay to update how it accredits the capacity value of different resources, as well as to consider structural changes to the capacity auction’s timing.
The RTO and its stakeholders are contemplating whether to change the capacity market from a forward-annual auction format to a prompt-seasonal format. While the current forward auction is held more than three years before the CCP, a prompt auction would be held just months prior to the CCP. A seasonal format would break up the yearlong CCP into distinct seasons with separately procured capacity.
In December, Analysis Group recommended that ISO-NE move to a prompt and seasonal auction for FCA 19, saying it would help the region cope with the rapidly changing influx of clean energy resources. (See Analysis Group Recommends Prompt, Seasonal Capacity Market for ISO-NE.) If ISO-NE ultimately moves to a prompt market for FCA 19, this could delay the auction to early 2028.
FERC found ISO-NE’s proposal of a one-year delay to be just and reasonable, noting that “the requested delay will allow ISO-NE the time necessary to develop a revised capacity accreditation methodology, in addition to further potential changes to the [forward capacity market] design.”
The filing was not opposed by any stakeholder groups, and was supported by the New England Power Generators Association, FirstLight Power and a coalition of public power entities.
FERC on Dec. 29 approved Dairyland Power Cooperative’s request for transmission rate incentives for its investment in the Wilmarth-North Rochester-Tremval project, a 169-mile line spanning Minnesota and Wisconsin that is part of MISO’s 2021 Transmission Expansion Plan (MTEP 21) (ER24-260).
The Wisconsin-based cooperative received authorization for the construction work in progress (CWIP) and abandoned plant incentives for the 345-kV span, which will connect the Wilmarth substation near Mankato, Minn., to the Tremval substation near Blair, Wis. The project involves building a new 161/69-kV substation near Kellogg, Minn., north of Rochester, and upgrading existing 161-kV facilities.
FERC also granted Dairyland a hypothetical capital structure of 50% equity and 50% debt for the life of the financing of the project. The line is expected to be in service by June 2028 and cost about $689 million.
“Dairyland expects to invest an estimated $207.5 million in the project, or 44% of its projected 2023 net transmission plant in rate base,” the commission said. “The project’s multiple owners and complexity present significant risk, and the record shows that this investment could put downward pressure on Dairyland’s financial metrics. We find that the hypothetical capital structure and CWIP incentives will provide upfront certainty, bolster Dairyland’s financial metrics to help ensure maintenance of its current credit rating and facilitate its participation in the project.”
Xcel Energy, Southern Minnesota Municipal Power Agency and Rochester Public Utilities are co-owners of the project.
In a concurrence, Commissioner Mark Christie continued to urge the commission to reconsider its policies on incentives, although he acknowledged that Dairyland met the standards the commission laid out in Order 679.
“Just as the CWIP incentive effectively makes consumers the bank for transmission developers, the abandoned plant incentive effectively makes them the insurer of last resort as well,” he wrote. “As this commission considers other potential reforms related to regional transmission planning and development, it is imperative that incentives like the CWIP incentive, abandoned plant incentive and RTO participation adder are all revisited to ensure that all the costs and risks associated with transmission construction are not unfairly inflicted on consumers while transmission developers and owners stand to gain all the financial reward.”
Commissioner James Danly, who left the commission at the end of the year, recused himself.
SPP announced Jan. 3 that it has selected Felek Abbas as its next chief security officer, effective immediately, to oversee the RTO’s cyber and physical security, emergency management and business continuity.
CEO Barbara Sugg said Abbas has the necessary expertise to help SPP address the “challenges presented by a global cyber threat landscape.”
“Cyber and physical security is a very real risk to the electric utility industry,” she said.
Abbas has nearly 30 years of electric industry experience in cybersecurity, engineering, consulting, risk management, audit and compliance. He most recently served as senior manager of cybersecurity for power and utilities at Ernst & Young, where he supported clients with cybersecurity program transformations in both IT and operational technology.
He has additional experience as a NERC Critical Infrastructure Protection (CIP) compliance adviser and auditor, where he helped shape and implement the NERC CIP v5 cybersecurity standards. Abbas also has operational experience as a SCADA engineer at Progress Energy, Mirant Corp. and Georgia Power. He holds an electrical engineering degree from Auburn University and is a certified information systems security professional.
Sam Ellis, SPP vice president of information technology, will transfer his security responsibilities to Abbas and focus on future grid strategies and ensuring the RTO has the right technologies to support the organization’s strategic aspirations.
VALLEY FORGE, Pa. — The PJM Markets and Reliability Committee on Dec. 20 endorsed a proposal to add multi-schedule modeling capability to the market clearing engine (MCE) without causing a substantial increase in computational times. It would do so by using a formula to narrow the number of market seller offers entered into the engine.
The proposal, originally sponsored by PJM at the Market Implementation Committee, would adopt the formula currently used in the day-ahead market to select one schedule from a resource to be modeled by the MCE, with the aim of arriving at the lowest total dispatch cost. The introduction of multi-schedule modeling is one part of a larger overhaul of the engine under PJM’s Next Generation Markets (nGEM) initiative. (See “Endorsement of Multi-schedule Modeling Solution Deferred,” PJM MRC/MC Briefs: Nov. 15, 2023.)
The package received 72% support, heading off consideration of an alternative brought by GT Power Group and PJM that modified the formulaic approach by reducing the offer types considered when a resource is mitigated for market power and during emergency conditions. Resources that fail the three-pivotal-supplier (TPS) test would be mitigated to their cost-based offers, disregarding any price-based offers; during emergency conditions, capacity resources would be limited to their price-based parameter-limited offers.
The new approach is meant to address an issue PJM identified with multi-schedule modeling in which the number of configurations under which a combined cycle generator can operate leads to a large number of schedules that those resources can offer into the real-time market. Considering all of those schedules would lead to an exponential increase in computational times, exceeding the 2.5-hour clearing window, PJM said in the MIC-approved problem statement.
The changes to the MCE redesign planned in the nGEM process also includes expanding the ability to consider the varying operating models for energy storage and hybrid resources, which PJM said may also increase solution times.
PJM’s Danielle Croop said the formulaic approach will look at the highest configuration for combined cycle generators and will be applied to storage when those resources are discharging.
Deputy Independent Market Monitor Catherine Tyler said PJM’s approach would open new opportunities for market power exercise and market manipulation that don’t exist now, particularly through a “crossing curves” issue where the engine considers offers only at their economic minimum (EcoMin) value even if that offer becomes more expensive at higher outputs. The alternative motion sought to address that possibility by using cost-based offers to mitigate resources that have the potential to exercise market power and using parameter-limited schedules during emergency scenarios.
Tyler also highlighted a concern that by considering only one of a resource’s cost-based offers, dual-fuel generators may be selected to run on a schedule using a fuel that is not economical for a portion of the day. She said neither of the proposals before the MRC would have resolved the issue.
Paul Sotkiewicz, president of E-Cubed Policy Associates and representing J-Power USA, said PJM’s proposal puts market monitoring ahead of least-cost operations. But he argued that it still is the best choice for implementing multi-schedule modeling out of a series of bad options stemming from the vendor administering the nGEM being unable to deliver on its promised capabilities. He argued PJM could have invested more effort into exploring algorithms and higher computational power as solutions that leave market design intact.
PJM Presents Regulation Market Rework
Stakeholders endorsed a proposal to overhaul the regulation market to operate on a single price signal and rely on two products representing a resource’s ability to adjust their output up or down. (See “PJM Presents Regulation Market Rework,” PJM MRC/MC Briefs: Nov. 15, 2023.)
The proposal would shift the market to a single signal and resources offering regulation up and down products, rather than the current approach of having both Regulation A for long deployments and Regulation D for fast response paired with a bidirectional product offered by generators.
The market redesign also contains several smaller changes, including using a ramp-limited lost opportunity cost (LOC) calculation designed to avoid overestimating LOC; a 30-minute clearing and commitment period; and a reworking of performance scoring to consider only the precision of a resource’s deployment, rather than accuracy, delay and precision. The number of qualification tests for new resources also would drop from three to two, and disqualified resources would need to pass one test rather than three to re-enter the market. Croop said PJM’s experience has been the number of tests conducted is higher than necessary.
Croop said PJM intends to bring the proposal to the Members Committee for endorsement this month and likely would ask FERC for a one-year implementation period, with a prospective effective date in spring 2025.
The market overhaul would be split into two phases, with the first year introducing all the changes except the RegUp and RegDn products, which would be added in the second year. Croop said implementing the products involves many changes and splitting the proposal into phases would provide the time necessary to do the work properly without holding up the other components.
Monitor Joe Bowring said the proposal would significantly improve the regulation market, but it also raises several areas of concern. He said the plan to introduce separate regulation up and down products is “clearly not fully developed and requires more modeling to understand the potential impacts, including interactions with the energy market.”
Bowring also said the proposal includes inflated opportunity costs that are inappropriately carried from hour to hour in the hourly regulation market. He argued that regulation revenues should be included in the calculation of uplift payments, as they had been in the past, to be consistent with the treatment of all other market revenues in defining the need for uplift. The arbitrary exclusion of regulation revenues results in an unsupported increase in uplift payments, he said.
While generation revenues likely would decline due to the LOC changes, Calpine’s David “Scarp” Scarpignato said the changes still are needed because of how dysfunctional the market is.
Energy Price Formation Senior Task Force Sunset
The MRC voted to sunset the Energy Price Formation Senior Task Force as part of the consent agenda, concluding a process focused on creating a “circuit breaker” to limit extreme pricing that outweighs any added reliability.
The group considered several packages, but none received majority support from the task force. Two were brought to the MRC in October 2022, where they also did not receive endorsement during a December 2022 vote. Greg Poulos, executive director of the Consumer Advocates of the PJM States, said advocates were frustrated the process was being closed before a circuit breaker design could be reached and are concerned about the potential for PJM to see the price spikes ERCOT experienced during the February 2021 winter storm. (See “Two Proposals on ‘Circuit Breaker’ Fail,” PJM MRC/MC Briefs: Dec. 21, 2022.)
Scarp said a decision ultimately had to be made and many flaws were identified with the circuit breaker designs.
“Sometimes the medicine is worse than the disease you’re trying to cure,” he said.
Members Committee
Elections Held for Several Stakeholder Positions
The MC approved a slate of new Finance Committee members, sector whips and its vice chair for 2024.
Lynn Horning, director of PJM regulatory affairs at American Municipal Power, was selected to be the MC vice chair, which puts her in place to assume the chair position in 2025 under the committee’s rotating schedule.
The new Finance Committee members, whose terms expire in 2026, include:
Barney Farnsworth, of the Wellsboro Electric Co., representing Electric Distributors;
Poulos, representing End-Use Customers;
George Kogut, of the New York Power Authority, representing Other Suppliers; and
Gary Mason, of Monongahela Power, representing Transmission Owners.
The 2024 sector whips, who serve one-year terms, include:
Bill Pezalla, of Old Dominion Electric Cooperative, for Electric Distributors;
Poulos, for End-Use Customers;
Scarp, for Generation Owners;
Steven Kirk, of NextEra Energy Marketing, for Other Suppliers; and
Jim Davis, of Dominion Energy, for Transmission Owners.
Scarp, the outgoing MC chair, finished his term by saying that 2023 will go down as a consequential year of change for PJM, with several major changes made to the markets to bolster reliability and prepare for the clean energy transition. He said stakeholders worked constructively during the Critical Issue Fast Path process, resulting in two filings pending at FERC that support the fundamentals of supply and demand.
Multi-schedule Modeling Proposal Approved
The committee also endorsed PJM’s proposal for implementing multi-schedule modeling, receiving 70% sector-weighted support. The item was added to the committee’s agenda following the MRC vote.
Future historians of the U.S. electricity sector one day might conclude the development of an RTO (or RTOs) in the West hinged on two separate but interrelated events occurring July 14, 2023.
On that date, a group of utility commissioners from Arizona, California, New Mexico, Oregon and Washington issued a letter launching the West-wide Governance Pathways Initiative (WWGPI), an effort to build the framework for an independently governed RTO that could encompass the entire Western Interconnection, with the express aim of including CAISO.
Backers of the initiative also envisioned that the ISO, whose real-time Western Energy Imbalance Market (WEIM) already covers about 80% of the West’s electricity load, would be the RTO’s market service provider. (See Regulators Propose New Independent Western RTO.)
A key objective of the proposal: to overcome the California grid operator’s historic inability to fully regionalize its operations because of objections to its governance structure, which is subject to oversight by California’s government.
But the initiative’s more immediate goal appeared to be supporting CAISO’s efforts to win participants for its Extended Day-Ahead Market (EDAM) as it faced increasing competition from SPP’s day-ahead offering, Markets+, which by late spring had become a serious challenger to EDAM, particularly in the Pacific Northwest. (See In Contest for the West, Markets+ Gathers Momentum — and Skeptics.)
‘Momentum’
The timing of the release of the WWGPI proposal was curious because July 14 also marked the first of a series of stakeholder workshops hosted by the Bonneville Power Administration to determine which of the two day-ahead markets it would join.
As the operator of 15,000 miles of transmission and nearly 17,500 MW of generating capacity in the Northwest, BPA’s decision will carry significant weight. And officials from the federal power marketing agency made clear during that first workshop at its Portland, Ore., headquarters that BPA’s day-ahead decision likely would set the course for future RTO membership.
For BPA, CAISO’s state-run governance has long been a hurdle for deepening the relationship between the two entities. The federal statute governing BPA prohibits the agency from being subject to the oversight of a state.
“One of the things we think about [regarding] governance, market design etc. is which options create the opportunity to create more verticality, potentially going to an RTO or adding these functions as part of it, and which ones have had that sort of limitation,” Russ Mantifel, BPA’s director of market initiatives, told participants at the July 14 workshop.
Mantifel said the workshop process would be “open-ended” and that BPA had not decided on a market. The agency said it would issue a “policy direction” on a market in February or March of 2024, but some stakeholders in the region told RTO Insider they thought the agency already was leaning heavily toward Markets+.
Among the factors favoring SPP, they said, was more favorable treatment for hydroelectric generation in Markets+, a CAISO bias in favor of California load that restricts wheel-throughs in the ISO during critical periods and the unresolved CAISO governance issue.
One staffer at a Northwest utility not authorized to speak on behalf of their organization at the time commented on momentum that seemed to be building for SPP. “They may not beat WEIM to a day-ahead market, but they have more momentum for a Western RTO,” the staffer said.
“I think if there was one word to describe the Markets+ zeitgeist, it’s ‘momentum,’” Scott Miller, executive director of the Western Power Trading Forum (WPTF), told RTO Insider in an interview in July.
“SPP is making a lot of progress,” he said. “Its stakeholder process has so charmed people that it’s added to that momentum.”
But some stakeholders weren’t so caught up in the zeitgeist.
“I can’t see how we can have two markets in the West, particularly with PacifiCorp going with EDAM — and possibly [Portland General Electric],” a representative of one environmental group told RTO Insider. They also pointed out that two competing markets would put “a big seam” in the West, echoing the concerns of other such groups that hope the geographic diversity of a single market would maximize the use of the region’s renewables and reduce curtailments.
‘General Positivity’
The heavy turnout at an August CAISO-hosted forum to celebrate the filing of the EDAM tariff with FERC signaled that the ISO was gathering some momentum of its own. About 240 electric industry stakeholders — including top utility executives — showed up at the event in Las Vegas, with an additional 300 attending online, according to the ISO. (See Forum Turnout, Tone Could Signal Growing Support for EDAM.)
The conference kicked off with the Balancing Authority of Northern California (BANC) announcing it would be the second entity to commit to joining the EDAM, after PacifiCorp. With 5,000 MW of load, BANC is the third-largest balancing authority in California, and it functions as the system operator for the Sacramento Municipal Utility District (SMUD), Modesto Irrigation District (MID), Roseville Electric, Redding Electric Utility (REU), Trinity Public Utility District (TPUD) and City of Shasta Lake. Its footprint also includes the Western Area Power Authority’s Sierra Nevada region transmission grid. (See BANC Moving to Join CAISO’s EDAM.)
BANC General Manager Jim Shetler said the organization’s decision really came down to geography, an assessment that could foreshadow the decisions of other utilities.
“I think the main driver for any market decision is what … your transmission capabilities [are] and who you’re interconnected with, and we have tremendous interconnection capability with the ISO through our footprint,” Shetler said. “And it just made sense for us when we did our evaluation, both from a cost standpoint [and a] potential benefits standpoint, that EDAM came out as a clear winner.”
WPTF’s Miller said he was impressed by what he saw at the EDAM forum.
“This really changes the calculus of my thinking around” Western markets development, Miller told RTO Insider immediately after the event concluded.
“It was the general positivity — even from CEOs whose folks are involved in Markets+ — that struck me as interesting,” he said.
Pathway to Independence
The Las Vegas forum also gave backers of the Pathways Initiative a platform to demonstrate the seriousness of the project and explain how quickly they intended to proceed with their mission. (See Backers of Independent Western RTO Seek to Move Quickly.)
“I think there’s a lot of work in front of us to make sure that stakeholders are widely engaged, that public power has a seat at the table, [and] that the [investor-owned utilities], the public interest organizations, the consumer advocates are all invited into that conversation and that it moves with all urgency,” Oregon Public Utility Commissioner Letha Tawney, a signatory of the July letter, said at the forum.
Another signatory, California Public Utilities Commission President Alice Reynolds, made clear that the initiative was intended to remove CAISO governance from the equation and examine what an independent RTO “needs to look like.”
Supporters of the initiative hit the ground running shortly after the forum, but the effort still faces some fundamental challenges, foremost being how it will be funded in a way that alleviates concerns about its own independence. In September, the Idaho Public Utilities Commission voted unanimously not to join the effort, saying the initiative “has been less than transparent concerning its creating and funding.” (See Idaho PUC Declines to Join Western RTO Governance Effort.)
At a Nov. 17 public meeting of the WWGPI’s Launch Committee, Shetler, co-chair of the committee’s Administrative Work Group, acknowledged the need for an “unbiased source of funding.” He said the group was pursuing $800,000 in grants through a Department of Energy Funding Opportunity Announcement (FOA) to support operations over two years. (See Western RTO Group Seeking $800K in DOE Funding.)
“This funding is necessary for major Pathways support functions — development of informational materials; outreach to key stakeholders; regular convenings through virtual and in-person gatherings; and facilitation to ensure meaningful participation by those who wish to engage,” the group said in a concept paper it submitted with its grant application.
If awarded, the money would arrive by the middle of 2024 at the earliest, Shetler said.
During the November meeting, the Launch Committee also discussed the formation of “work groups” to tackle other issues related to creating an independent entity. One of those groups is charged with the complex matter of addressing legal questions associated with creating a market structure that integrates CAISO, including minimum changes to California law needed to alter the ISO’s governance and operations. (See West-Wide Governance Pathway Group Digs into its Work.)
“Our goal is to define a range of solutions — or pathway options — that are related to tariff management for the markets and other services [and] what the governance structure looks like for a potential new regional entity,” said Spencer Gray, executive director of the Northwest & Intermountain Power Producers Coalition (NIPPC) and co-chair of the Launch Committee’s Priority Functions and Scope Work Group.
The Launch Committee in December outlined five governance options for an independent Western RTO, stopping short of calling them proposals or recommendations and instead saying they should represent a starting point for discussions. The options sit between two “bookends,” ranging from one in which CAISO’s Board of Governors and WEIM’s Governing Body would continue to hold shared authority over market rules but eliminate the CAISO board’s veto rights to one in which a new “regional organization” would fully absorb the ISO’s staff and operate the market itself — with variations in between. (See Western RTO Initiative Outlines Governance Options.)
The Pathways Initiative also is working quickly achieve other key objectives for its governance early this year, including establishing a nominating committee for a foundational board of directors in January, then identifying and seating board members in March.
Milestones Met
December saw CAISO and SPP both hit important milestones in their day-ahead market efforts.
CAISO’s was by far the most significant, with FERC approving nearly every portion of the EDAM tariff in a 181-page order issued Dec. 21 (ER23-2686). The approval covered creation of a set of Day-Ahead Market Enhancements (DAME), market products intended to reduce load imbalances between the ISO’s day-ahead and real-time markets, as well as EDAM implementation measures. (See CAISO Wins (Nearly) Sweeping FERC Approval for EDAM.)
The only aspect of the filing rejected by FERC dealt with a temporary measure intended to compensate transmission operators for losses incurred during a BA’s transition into the EDAM, something CAISO considered “severable” from the rest of the proposal. Even so, the commission made clear the rejection was without prejudice and opened the door for CAISO to resubmit a revised version of the measure.
SPP scored a success Dec. 7 when the stakeholder-led Markets+ Participants Executive Committee approved the market’s governance plan, an important step on the road to filing a tariff in February. But the approval was somewhat marred by a disagreement ahead of the vote over the voting structure of the “Independents” sector. That left the plan passing with just 73% in favor in the face of “no” votes from independent power producers and environmental and clean energy groups. (See SPP’s MPEC Approves Markets+ Governance Plan.)
The Interim Markets+ Independent Panel (IMIP), which consists of three SPP independent directors, stamped its approval on the governance plan during a call Dec. 19. (See IMIP Approves SPP Markets+ Governance Tariff Language.)
‘Extreme Pressure’
With the new year underway, Western stakeholders are closely following BPA as it approaches its decision point. At the agency’s most recent day-ahead markets workshop in November, BPA officials said they intend to stick to their original timeline of issuing a policy direction by the end of the first quarter. They also indicated there would be a shift in the content of that decision. In response to concerns expressed by some of BPA’s public power customers, the decision now is likely to deal with the agency’s statutory authority to join a day-ahead market, while also conveying a “leaning” on what market it is favoring at the time, Mantifel said during the workshop.
“I think it’s fair to expect that that policy direction will establish our authority to join a market and will establish the business case for pursuing a market,” Mantifel said.
During that meeting, BPA officials also suggested that the leaning could be subject to change based on further developments. Mantifel noted that any expected action after issuance of the leaning is “still up in the air.”
“The processes for joining the markets themselves are still somewhat fluid, as opposed to EIM,” he said.
BPA Senior Vice President of Power Services Suzanne Cooper acknowledged that some Northwest stakeholders want the agency to hold off on a final decision to evaluate more thoroughly the “cost advantages” of a single market in the West. She said the agency will continue to monitor the progress of the Pathways Initiative, a process in which it is not directly participating.
“We have heard and definitely acknowledge the requests that we’ve heard for taking some more time for additional analysis and to allow the Pathways concept to develop,” Cooper said. “We’ve heard also from many entities, including within our public power customers, that desire for BPA to maintain our current timeline.”
One non-BPA participant in the stakeholder process told RTO Insider in December: “The subtext is we [BPA] are announcing our decision in Q1, but they are saying there’s room to move in phase 2 [of Markets+ development] in case something drastic happens.”
That participant also said BPA is under “extreme pressure from many angles” to move quickly on a decision. They said the pressure is being applied both internally and externally — the latter referring to the agency’s public power customers, who are “dividing into two camps” over which market to join.
Whatever the specific outcomes, the momentum toward a Western RTO — or two — will continue to build in 2024.
