Fully funding Rhode Island’s Transit Master Plan could reduce residents’ vehicle miles traveled (VMT) by 8% and should be a key recommendation in the state’s next greenhouse gas emissions reduction plan, Mal Skowron, transportation program and policy coordinator at the Green Energy Consumers Alliance, told state officials Tuesday.
Skowron made her recommendation during a listening session of the Rhode Island Executive Climate Change Coordinating Council (EC4) on priorities for reducing transportation emissions that should be in the update to the 2016 GHG Emissions Reduction Plan. Rhode Island’s Act on Climate, which Gov. Dan McKee signed last spring, directs the EC4 to submit the updated plan to the legislature by the end of the year.
Listening session attendee Hans Scholl agreed with Skowron’s call to fund the plan, saying that the “vast majority of Rhode Islanders live within 10 minutes of public transportation, but it’s just totally underutilized.”
Capital costs of the Master Plan would be $1.9 billion to $3.1 billion through 2040, with operating costs of $237 million annually.
Reducing VMTs is one of the actions recommended in the 2016 GHG plan to cut transportation emissions from fossil fuels. The EC4 is considering priority actions for the plan update that could further a VMT reduction goal, including increasing transit and share ridership.
The State Planning Council adopted the transit plan in December 2020 under the umbrella of a Long-Range Transportation Plan. Funding for some of the plan was in place at the time of its adoption, but full implementation isn’t expected until 2040. Since its adoption, additional funding has been moving more of the plan forward.
U.S. Sen. Jack Reed helped secure a $900,000 grant to study a major transit corridor expansion as recommended in the plan for services that provide high-volume markets with fast and frequent service. An additional $225,000 in matching funds for the study are included in McKee’s proposed FY23 budget.
The transit plan said high-capacity services could include rapid bus routes with limited stops and light rail featuring two-car trains.
Completion of the study will allow the state to take advantage of funding opportunities in the Infrastructure Investment and Jobs Act, Reed said.
Rhode Island’s 2016 GHG reductions strategy also recommends electrification of the Rhode Island Public Transit Authority’s (RIPTA) bus fleet and state passenger and freight rail systems.
“RIPTA has made a lot of progress with electrifying its fleet,” Carrie Gill, chief economic and policy analyst at the Rhode Island Office of Energy Resources, said during the listening session.
McKee and Reed joined authority officials Friday to break ground on the state’s first charging station for electric buses to use while on a route during service hours. The governor also announced Thursday that RIPTA has issued a request for expressions of interest to design a new transit center that would support transit growth as envisioned in the master plan.
The EC4 held a listening session on the electric sector in April to inform the GHG plan update, and another session is scheduled for the thermal sector (residential, commercial and industrial heating and natural gas distribution) in June.
PJM stakeholders at last week’s Operating Committee meeting endorsed manual changes related to the stability limits and intelligent reserve deployment in markets and an operation issue charge developed in the Market Implementation Committee.
The manual changes were endorsed in a rare acclamation vote that included eight objections and 11 abstentions.
Donnie Bielak, manager of reliability engineering for PJM, reviewed the conforming changes to Manual 12: Balancing Operations, highlighting the changes in two different sections of the manual.
In section 4.1.2: Loading Reserves, language was added stating that PJM dispatch will use intelligent reserve deployment (IRD) in security constrained economic dispatch (SCED) to initiate a synchronized reserve event by approving the latest solved IRD case if there’s insufficient regulation and economic generation to recover area control error (ACE).
Bielak said the change highlighted automated and manual methods for implementing contingency reserves.
“Under normal operating conditions, we would use the automatic method and go out with an IRD case,” Bielak said. “However, we did put provisions in there for PJM actions regarding if the IRD case was invalid and how we would deploy those reserves under that scenario.”
Section 5.5: Generator Stability Limitations is a new section highlighting stability-limited generation and clarifying PJM and member actions, Bielak said.
The PJM actions in the section state, “When stability issues are identified, PJM will confirm/calculate the stability limitation and communicate the limit value(s) as a stability limit, including the effective timeframe for same, to the impacted PJM generation owner(s). This includes any changes, including cancellation, around a given stability limit. For real power (megawatt) stability limits, limits will be translated into a corresponding generator output constraint (in megawatts) for a generator whereby the generator output constraints shall be respected.”
The section says generation owners should “respond promptly to specific requests and directions” of PJM dispatchers, and generators should honor dispatch basepoints based on stability limitations by following PJM dispatch.
Paul Sotkiewicz of E-Cubed Policy Associates said he wanted to make sure PJM dispatchers will consider switching options before the generator output construct is used and make it “very clear” in the manual so “there’s nothing left to the imagination” for dispatchers to interpret.
Bielak said PJM dispatchers will evaluate any other available types of switching solutions and make sure they don’t cause “adverse implications” to other generators or overloads on the system. He said there are “a lot of different factors” that must be evaluated to go ahead with a switching solution.
“We did a full review here of all the operations manuals, and we definitely believe that the existing language or the new language that we’re proposing here in Manual 12 is the best course of action moving forward,” Bielak said.
The manual language goes to the May 25 Markets and Reliability Committee for endorsement. PJM is looking for an effective date of June 1.
Outage Coordination Issue Charge Endorsed
Stakeholders will begin examining outage coordination processes and procedures after unanimously endorsing an issue charge.
Paul McGlynn of PJM’s system operations group reviewed the proposed issue charge and problem statement intended to address the RTO’s transmission and generation outage coordination.
The key work activities and scope of the issue charge include education and review of current procedures for submitting, classifying, evaluating, approving and scheduling transmission and generation outage requests. The review will look at current study timelines, analytical activities such as reliability and expected congestion studies and any adjustments to submitted outages based on PJM’s review.
McGlynn said PJM will review outage planning and coordination processes required for regional transmission expansion plan project implementation by focusing on projects that could require extended outages of existing facilities such as transmission line rebuild projects.
Work also includes “proposed modification and improvements to transmission and generation outage assessments, transparency and available tools.” McGlynn said discussion of outage assessments will include reliability and congestion assessments for the PJM system and a review of the impacts on the PJM system of neighboring region outages.
Out-of-scope items in the issue charge include modifying the transmission owners’ ability to “take necessary outages on their facilities” and any proposal that conflicts with the Consolidated Transmission Owners Agreement.
Work on the issues will be completed at the OC and is expected to take up to a year to complete.
Sotkiewicz asked for a possible friendly amendment to the issue charge calling for an education portion on how the issues being discussed will be brought to other committees, including the Planning Committee and the MIC, so that the communication portion “doesn’t get overlooked in the process.”
“These outages can affect everything from credit to market operations and everything else,” Sotkiewicz said.
McGlynn said PJM can touch on dissemination of information while going through the education process, but he said processes already exist in the manual to ensure information is passed along to other committees in the stakeholder process.
“I don’t know that it’s something necessarily that we need a lot of stakeholder input on,” McGlynn said.
Manual Endorsements
Stakeholders unanimously endorsed two different manuals as part of the periodic review. They included:
Manual 36: System Restoration, with minor changes such as replacing System Restoration Coordinators Subcommittee (SRCS) with System Operations Subcommittee (SOS) and updating the under-frequency load shed table with new data.
Manual 3: Transmission Operations, with updating stability limitation process language in accordance with FERC docket ER21-1802 and aligning language with the current TO/TOP matrix language.
FERC on Friday accepted PJM’s compliance filing restoring the historical energy and ancillary services (E&AS) revenue offset used in the RTO’s capacity market, clearing a potential hurdle for the 2023/24 Base Residual Auction scheduled for June 8 (EL19-58).
The commission on Dec. 22 reversed its May 2020 approval of PJM’s forward-looking E&AS offset, a key variable in calculating the net cost of new entry (CONE) for resources in capacity auctions, ordering the RTO to revert to the previous, backward-looking offset. (See FERC Reverses Itself on PJM Reserve Market Changes.)
PJM submitted tariff revisions restoring the historical E&AS offset for all Reliability Pricing Model (RPM) auctions going forward and limiting the forward-looking option only to RPM auctions for the 2022/23 delivery year, the only one in which the forward-looking offset was used.
“PJM states that, with these revisions and a Nov. 12, 2020, effective date, the tariff will properly reflect the applicable E&AS offset used in auctions for each delivery year,” FERC said.
The RTO also included revised rules for determining the E&AS offset used for minimum offer prices for each resource type and restoring the historical approaches provisions starting with the 2023/24 delivery year. The historical offset will also be used to determine avoidable-cost rates.
The RTO asked FERC to “expeditiously accept” its compliance filing to avoid delaying the2023/24 BRA.
In a 3-1 decision, FERC mostly accepted PJM’s compliance filing, with Commissioner James Danly dissenting and Commissioner Willie Phillips not participating in the order.
The commission said PJM’s filing did not properly restore all tariff language that existed prior to the May 2020 order, pointing to a section with an incorrect sentence that was not properly incorporated in the tariff in previous revisions. FERC also identified other minor changes, including deleting the phrase “capacity factors” in one section and revising the word “must” to “may” in another section.
PJM is required to file the revised tariff changes within 15 days to the commission.
Danly, who has dissented to several of the orders regarding PJM’s proposed energy price formation revisions, said he continued to object to the process and the merits of the filing. He said the order “implements profound changes to fundamental aspects” of PJM’s capacity market and was done “recklessly” without additional briefings or supplemental information on the impact of the changes.
The “protracted, unnecessary proceedings have caused unacceptable delays in PJM’s auction schedule,” Danly said. He hoped the commission will not cause any more delays to the auction with its actions.
“How can anyone expect a market to function correctly and efficiently in the face of the uncertainty the commission has created over the last year?” Danly said. “We cannot continue to take actions that will delay PJM’s auctions or throw its market rules into further chaos. Amidst such uncertainty, the promised benefits of the market will be diminished and will eventually be lost. PJM’s ability to ensure resource adequacy will be imperiled. Prices will rise and reliability will suffer. We cannot continue down this road and keep telling ourselves that the resulting rates are just and reasonable.”
California Gov. Gavin Newsom said Friday that the state needs a $5.2 billion “strategic electric reliability reserve” to meet the challenges of extreme heat, wildfires, drought and the West’s changing resource mix.
Newsom proposed the reserve as part of the May revision to his FY 2022-23 budget, originally released in January.
He also cited supply-chain problems, including with imported solar panels, as contributing to potential supply shortfalls this summer and beyond.
“When you stack all these together, and you reflect those extremes on wildfire, heat [and] drought, we’re looking at potentially filling [supply] gaps that weren’t there even a year or two ago,” Newsom said in a budget briefing. “So how do we do that? We are requesting [that] the legislature … [create] a new strategic electricity reliability reserve, which is just a fancy way of saying ‘putting together 5,000 megawatts that’s available at a moment’s notice.’”
A summary of the governor’s budget plan says the reserve could consist of “existing generation capacity that was scheduled to retire, new generation, new storage projects, clean backup generation projects, diesel and natural gas backup generation projects … and customer-side load reduction capacity that is visible to and dispatchable by the [CAISO] during grid emergencies.”
Officials have not said whether the reserve funds would be used to keep the state’s last nuclear generator, PG&E’s Diablo Canyon Power Plant, operating beyond its planned retirement in 2024-25 for reliability, as some have urged.
In late April, Newsom told the Los Angeles Timeseditorial board that California would seek a share of $6 billion in federal funds intended to keep aging nuclear plants open. The Biden administration announced the program last month.
“The requirement is by May 19 to submit an application, or you miss the opportunity to draw down any federal funds if you want to extend the life of that plant,” Newsom said, according to the Times. “We would be remiss not to put that on the table as an option.”
His cabinet secretary, Ana Matosantos, told reporters at a May 6 briefing the state needs to consider all possibilities.
“We can’t keep any options off the table,” Matosantos said. “And we are clearly looking at planned retirements and making sure that we’re looking at all options associated with those planned retirements.”
During the briefing, officials from the governor’s office, CAISO, the California Public Utilities Commission (CPUC) and the California Energy Commission (CEC) said this summer’s potential shortfalls could range from 1,700 MW under strained conditions to 5,000 MW under extreme conditions.
Newsom said Friday that the state could face up to a 7,300 MW shortage, though it was unclear where he derived that figure, which was not cited by CAISO, the CEC or the CPUC.
CAISO, CEC Examine Reliability
The governor’s revised budget proposal followed reliability discussions by the CEC and CAISO on Wednesday and Thursday that delved into the likelihood of shortfalls this summer during harsh conditions.
CAISO’s 2022 Summer Loads and Resources Assessment found that the likelihood of having to order rolling blackouts — as the ISO was forced to do in August 2020 — is less this summer than last year, largely because of the addition of 4,000 MW of battery storage since the 2020 blackouts.
“However, available capacity continues to be impacted by well below normal hydro conditions as California is in its third year of drought,” Neil Millar, the ISO’s vice president of infrastructure and operation planning, told the CAISO Board of Governors in a memo prepared for the board’s meeting Thursday.
California’s mountain snowpack, which supplies water during the state’s six-month dry season, stood at 38% of average April 1 after the three driest winter months on record.
As in the past two summers, CAISO’s “greatest operational risk is during a widespread heat wave that results in low net imports due to high peak demands in its neighboring balancing authority areas,” the memo said. “The risk increases in late summer concurrent with the diminishing effective load-carrying capability of solar resources and the wane of hydro generation.”
“Under extreme weather and events such as wildfires that diminish larger amounts of supply, the ISO could still be faced with the necessity to shed firm load,” Millar wrote.
Using a new methodology, the resource assessment found the probability of CAISO declaring a Stage 3 energy emergency is 15% this year compared to about 6% last year, but the possibility of firm load interruption decreased from 4.6% in 2021 to 4% this summer.
More extreme weather than anticipated or procurement delays for anticipated new resources could worsen the outlook, CAISO cautioned.
In a briefing to the CEC, David Erne, with the commission’s Energy Assessments Division, said supply chain issues were especially problematic this year.
High lithium prices are affecting battery production, and the U.S. Commerce Department launched an investigation in April into allegations that Southeast Asian solar panel manufacturers are using Chinese parts while evading U.S. tariffs on China. The situation could interrupt solar panel delivery and the construction of solar arrays.
“What we’ve seen from last summer and moving forward is the energy industry is particularly impacted by supply chain issues, commodity prices and tariff issues, all of which cumulatively impact our ability to build out these new projects moving forward,” Erne said. “Our reliability is dependent upon new buildout, and that new buildout is affected by these particular issues.”
Vermont is preparing to adopt four California vehicle emissions standards this year, three of which will be the state’s first substantive regulations for heavy-duty vehicles.
The Agency of Natural Resources (ANR) will file proposed rules with the Agency of Administration next month for Advanced Clean Cars II, Advanced Clean Trucks, Low Nitrogen Oxides Heavy-duty Omnibus and Phase 2 GHG Emissions Standards for Heavy-Duty Trucks and Trailers.
“Adopting the [truck rules] will be a significant build on our existing program in terms of adding regulations that address heavy-duty vehicles more robustly,” said Megan O’Toole, climate change mitigation coordinator at the ANR’s Department of Environmental Conservation.
To comply with the 2020 Global Warming Solutions Act, ANR must file the proposed rules, as recommended by the Vermont Climate Council in its initial Climate Action Plan, by July 1. The state first adopted California air emissions standards in the 1990s and has expanded those regulations over the years.
“If all of the vehicles that will be delivered to the State of Vermont, pursuant to these rules, are bought by Vermonters and fleet owners in Vermont and placed in service, that will get about a third of the way to our 2030 goal just for the transportation sector,” O’Toole said during a Climate Council meeting Monday.
Under the GWSA, transportation sector emissions must decline by 1.38 million metric tons of carbon dioxide equivalent by 2030.
Advanced Clean Cars II will amend ACC I, which Vermont adopted previously, to ensure that all passenger and light-duty vehicles sold in the state are zero-emission by 2035. The standard ramps up over time, starting with model year 2026.
Under Advanced Clean Trucks, at least 30% of medium- and heavy-duty vehicles delivered to the state must be zero-emission by 2030, starting with model year 2026 and ramping up to 40% or higher by 2035, depending on vehicle class.
Phase 2 GHG standards, which build on Phase 1 standards, are the first to cover certain trailers used with heavy-duty tractors and are based on technology requirements for manufacturers to reduce fuel consumption and emissions. The requirements will be effective starting with model year 2026. Low NOx, Heavy-duty Omnibus is a required companion standard to the Phase 2 program that does not relate directly to greenhouse gases. The California Air Resources Board expects the regulation to establish NOx emission standards that are 90% lower than today, effective for model year 2026.
ANR plans to have all four rules adopted by the end of the year so they will be effective for the 2026 model year, O’Toole said. The agency will hold rulemaking hearings in the late summer and early fall.
Climate Planning
While early Climate Council analyses showed significant GHG emission reductions can come from adopting the California regulations, ANR has not released final emissions data in its draft rules. The reductions could equate to 10% of the overall GWSA target of a 40% reduction below 1990 levels in 2030, Jared Duval, council member and executive director of the Energy Action Network, said during the meeting
Vermont also must reduce its GHG emissions 26% below 2005 levels by 2025 and 80% below 1990 levels by 2050.
As it stands, adopting the California regulations is the only action moving forward this year from the climate action plan that can achieve “double-digit” reductions, Duval said. The council had expected to recommend Vermont join the Transportation and Climate Initiative Program (TCI-P) last year, but that program has since stalled, leaving a significant gap in the transportation sector emissions reductions needed in the climate plan.
The state also is not moving forward this year with a climate plan recommendation for the state to adopt a clean heat standard to reduce emissions in the building sector. Earlier this month, Gov. Phil Scott vetoed a bill that would have directed regulators to develop a CHS. (See Vt. House Sustains Veto of Clean Heat Standard Bill.) Transportation and buildings are Vermont’s No. 1 and 2 top emitting sectors, respectively.
The climate plan “was already on thin ice with TCI-P not moving forward,” Duval said. “Without the clean heat standard, which we were counting on to be the largest single emissions-reduction measure in the plan, I don’t see how we can have any confidence that we will come anywhere close to the 2030 requirements.”
In vetoing the clean heat standard bill on May 6, Scott pointed to his $216 million climate-related budget package as evidence that he understands the importance of reducing GHG emissions. That budget, which the legislature amended and passed before adjourning last week, is a “short-term opportunity” to use federal and state funding to reduce Vermonters’ dependence on fossil fuels,” Duval said.
“It may help us meet the 2025 target, but it will likely be going away at exactly the time that we need to be ramping up significantly to have any chance, any hope, of meeting the 2030 requirements,” he said.
As passed, the state budget includes $80 million for weatherization, but Duval said that will only help an estimated 8,000 of the 90,000 homes the climate plan recommended for building sector emission reductions by 2030. And an additional $12 million for electric vehicle purchase incentives would put an estimate 3,000-4,000 EVs on the road of the 126,000 needed for transportation sector reductions by 2030, Duval said.
Short-term investments must be backed up by long-term policy and market clarity and the incentives residents need to make changes, according to Duval.
“We can’t keep pretending that we live in a pre-Solutions Act world, where it’s okay to be off track of the legal requirements without any serious, feasible plan to meet these requirements,” he said.
SPP staff said last week they are conducting internal discussions on how they manage MISO constraints in their RTO’s day-ahead market as part of their market-to-market (M2M) process.
Clint Savoy, SPP senior interregional coordinator, told the Seam Advisory Group on Friday that the MISO Independent Market Monitor’s recent comments on SPP’s M2M management has caused staff to review their processes.
“We’re doing an assessment on the impacts of changing our process and evaluating the impacts on price convergence of market-to-market settlements … the impact on uplifts and virtual payments,” he said. “We want to understand the impact of the changes before we make those changes.”
Savoy said members should expect more detailed presentations on the issue coming to the group and SPP’s Market Working Group.
MISO Monitor David Patton said last month 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 has said 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 (FFE) values.
The discussion came as SPP accrued another $24.1 million in M2M settlements from MISO during February, its second-highest monthly total since the process began in March 2015. That pushed the amount MISO owes its neighbor for congestion to $279.1 million.
Temporary flowgates accounted for $18.4 million in settlements during the month, binding for 2,064 hours. The two grid operators exchange settlements for redispatch based on the non-monitoring RTO’s market flow in relation to FFEs.
It was the 12th straight month M2M settlements have accrued in SPP’s favor and the 27th time in the last 29 months. SPP has piled up nearly $180 million in settlements since September 2020, despite more than $50 million in settlements to MISO during the severe winter storm in February 2021.
New Members Welcomed
The SAG welcomed three new members: ITC Holdings’ Raju Brahmandhabheri, Arkansas Electric Cooperative Corp.’s Rick Running and the American Clean Power Association’s Daniel Hall, a former member of the Missouri Public Service Commission.
American Electric Power’s Jim Jacoby, the group’s chair, welcomed the diversity the new members bring in representing their companies’ differing interests.
“I think it brings a different perspective to some of the issues that we’re dealing with,” he said, “So, thank you for putting your name into the hat and being part of the team.”
Staff gave the new members an overview of the different initiatives SPP and MISO are currently working on together. The newly created Common Seams Initiative met today, and the RTOs’ staffs this Friday plan to share a “very substantive” cost allocation proposal for their Joint Targeted Interconnection Queue study.
Duke Energy (NYSE:DUK) on Monday filed a proposal with the North Carolina Utilities Commission (NCUC) that presents four broad paths to reducing carbon emissions by 70% by 2030 and achieving net-zero emissions by 2050.
Under development for months in a process that included stakeholder discussions with representatives of more than 300 interested organizations, the plan does not go into specifics. The company noted that the lack of specificity in its “all of the above” mix offers “regulators multiple options that balance affordability and reliability for customers.”
Under the proposal, Duke’s remaining coal-fired plants in the state would be retired by 2035, replaced by wind, solar, battery backup, “hydrogen-ready” gas turbines and perhaps a small modular nuclear plant, though the cost of any of these plans is not specified.
The company does point out that in the next two years, any of the multiple options it offers will have limited impact on costs. But beginning in 2025, customer bills would increase by 1.9 to 2.7% through 2035.
“The plan’s first portfolio achieves the 70% target by 2030, while the other three portfolios achieve the 70% target by 2032 or 2034 through increased reliance on both onshore and offshore wind and/or small modular nuclear generation, leveraging the law’s flexibility intended to help advance cutting-edge, carbon-free generation. All four portfolios reach carbon neutrality by 2050,” the company said in a statement issued with its filing.
“In the near term, the plan focuses on aggressive energy efficiency and demand-side management, along with grid upgrades to enable significant growth in renewables. That includes between 7,600 MW and 11,900 MW of new solar by 2035, depending on the portfolio, on top of the 5,000 MW of solar expected online by year-end and an additional 1,900 MW of solar currently planned or under development.
“Approaching the 2030s, wind and small modular nuclear come into play to diversify the carbon-free energy mix. This diversity is key to meeting the least-cost and reliability mandates required by state law.”
A coalition of advocacy groups — the Natural Resources Defense Council, Southern Alliance for Clean Energy and Sierra Club, represented by the Southern Environmental Law Center, along with the North Carolina Sustainable Energy Association — issued a statement following the company’s filing, noting that the organizations are preparing for NCUC hearings over the next 60 days and have already “commissioned expert analysis of the proposed Duke plan that will be filed along with an alternative plan on July 15.”
The company’s proposal includes four public hearings in July and a virtual hearing in August.
WASHINGTON — Anxiety over the clogged interconnection queues of RTOs and the ever more pressing need for more interregional transmission saturates the energy industry, and the near complete failure of the Texas Interconnection last year still looms large.
This was evident based on some of the discussions last week at the Energy Bar Association’s annual meeting, held in-person for the first time in three years at the Marriott Marquis Washington, DC hotel. Unlike several of the post-COVID-lockdown conferences, in which attendance might be capped or some speakers appear virtually, this was a fully in-person event; meeting rooms and the banquet hall were filled nearly to capacity.
In a panel on generation interconnection Wednesday, moderator Jason Stanek, chair of the Maryland Public Service Commission, paused to inform the audience that the front row of seats was open to those standing in the back of the room. It had remained open despite his joke at the beginning of the session, when he noticed “MISO people coming in late today. … You should be in the front row.”
Indeed, Stanek was sort of the odd man out: The panel was made up of both current and former MISO employees and a MISO stakeholder. But he noted that the lack of interstate transmission was a nationwide problem, referencing his state’s ambitious clean energy targets and neighboring Pennsylvania’s rejection last year of the Independence Energy Connection, which would have consisted of two lines in Western and Eastern Maryland connecting to existing lines across the border.
“The queue backlogs are not the problem, but a symptom of a much larger problem,” Stanek said, reporting what he has heard as a member of the Joint Federal-State Task Force on Electric Transmission at a meeting just the week before the conference. (See FERC-State Task Force Considers Clustering, ‘Fast Track’ to Clear Queues.)
Aubrey Johnson, executive director of system planning and competitive transmission at MISO, noted that FERC recently approved an RTO proposal to give generators the opportunity to cut the number of days in its interconnection process. (See FERC Allows Quicker MISO Interconnection Queue Option.)
“So fundamentally, the queue is continuing to make improvements, but in many ways, we’re trying to use the queue today for things that it was not originally intended to do,” he said. “I certainly believe we should continue to work on queue reform and queue improvements. … But I also want us to think about what the real issues are.”
Johnson noted that MISO’s queue currently has about 800 projects worth about 126 GW, with about 60 to 70% of that being solar. “With a 200-GW system and a 130-GW peak — I don’t think all those projects in the queue are actually needed.” Only about 20% of projects that enter the queue actually reach a generator interconnection agreement, he said. “The real question should be: How do we deal with that 20%?”
Stanek quoted Massachusetts Department of Public Utilities Chair Matthew Nelson at the task force meeting: “‘Being in the queue should mean something.’
“The fact that only 20% of these projects, at most, ever actually make it to fruition shows us that we have an issue with gaming; with queue squatting,” Stanek said.
Jeff Bladen, global director of energy for Facebook parent company Meta, agreed that in general, not all of the projects in the queue are needed. But the former executive director of digital strategy for MISO noted that “there’s a lot more that needs to get built than has historically gotten built if we’re going to move forward with the electrification of many different sectors, and the growth of things like data centers is a signal of how much” clean energy is going to be needed. “It’s hard to believe it’s just going to be 20%.”
Meta is not just a rebranding of Facebook; it’s also the parent for photo-sharing service Instagram, messaging service WhatsApp and virtual reality producer Reality Labs (formerly known as Oculus), among other digital service companies. They collectively require a massive amount of data processing, which in turn requires a massive amount of energy for Meta’s 17 data centers across the U.S. — all of it renewable, according to the company.
More important than the queue backlogs, Bladen argued, is “the reliability of the grid. We’re starting to see the grid fray as we have more and more critical weather emergencies. … The reliability of the grid is an area of increasing and probably primary focus for us as we move forward.”
Meta has set a goal of net-zero emissions across its entire operations by 2030, “which is unlocked by transmission. Our core energy strategy is relatively simple: reliable, affordable and sustainable. And there are very few things that we think about as investments or areas of focus for policy that get us all three, and one of those few is transmission,” Bladen said.
Q&A
Stanek asked the panel if FERC needed to implement a rule on interconnection, or if the RTOs could fix their respective problems themselves.
“Having some leadership from FERC would generally be helpful,” Bladen answered. “Some general direction of what the expectations are is important so that the stakeholder processes have something to work towards. When they don’t have something to work towards … you end up with various vested interests running into each other, and it’s very difficult for an RTO to resolve those. …
“I think there’s a role for FERC to play; just don’t be overly prescriptive about exactly how you accomplish the outcome.”
Dehn Stevens, vice president of transmission development and planning at MidAmerican Energy, concurred. “I’ve heard someone say, or several someones say, that what we need is one interconnection queue, one system model, across everywhere. And I just have to say that’s the worst idea I’ve ever heard.
Rather, “an appropriate role for FERC would be to require accountability. If the regions are coming up with queue reforms, have a feedback loop about how it’s going,” with the RTOs filing annual reports on their progress.
One audience member told the panel that his clients often complain about what they see as unfair cost allocation, as their projects are somehow the ones that trigger the need for expensive transmission upgrades. At the same time, they are told that these upgrades are not showing up as needed in the RTOs’ transmission planning process. He asked what the difference was between interconnection studies and transmission planning studies, and “why, it seems to me, there’s a big disconnect between what’s showing up” in each.
“Fundamentally, generator interconnection planning is about trying to stress the local system — to make sure all the generators in a local area can operate reliably,” Stevens answered.
On the other hand, “long-term planning then looks at how all those generators will most likely be dispatched in the seasons that we’re trying to analyze. … So there’s a fundamental difference between the two paradigms in the way that the planners look at the world. …
“In order to make not every generator on the hook for some tiny slice of everything from coast to coast, we apply significance criteria,” which determine the amount of impact on a transmission facility a generator has to have before it’s responsible for upgrade costs. “What that means is there could be issues accumulating, but no one is yet held responsible … until the fateful day comes when a generator connects to the grid, and they have an impact above the significance factor cutoff,” Stevens continued.
“I would just say we can’t forget that all of the generators that came before that one all got the benefit of not having to have any responsibility to fix [the grid] because we all decided it was better to not hold everyone hostage across a wide area.”
Arash Ghodsian, senior director of transmission and policy for EDF Renewables North America — and another former MISO employee — said that proactive planning would eliminate that problem. “Unfortunately, until we get there, you’re going to hear that, because rather than me fixing the line for the X percentage that I have contributed to, I often get, ‘well, we need to rebuild the whole line.’”
Stakeholders at last week’s PJM Market Implementation Committee meeting peppered RTO staff with questions about a proposal on cost-based energy offers.
Melissa Pilong, lead analyst in PJM’s performance compliance department, provided a first read of the proposal by PJM and the Independent Market Monitor. Developed in the Cost Development Subcommittee (CDS), the plan is meant to provide guidance and updates to rules related to variable environmental charges and/or credits and their inclusion in cost-based energy offers.
Pilong said the proposal was initiated to ensure that PJM’s fuel cost policy is up to date. She said the key work activities and scope of the issue charge created by the CDS focused on the annual emissions review process and requirements to include environmental credits in non-zero cost-based offers.
Stakeholders affected by the proposal include sellers of generation receiving production tax credits and/or renewable energy credits and who also submit non-zero cost-based offers into the energy market. If both those conditions are met, the seller must account for the credits in the resource’s fuel cost policy, Pilong said.
One of the proposed changes includes adjusting review of emissions rates from an annual to a periodic basis and requiring that market sellers are responsible for updating the rates. Pilong said the change was made to align with the periodic fuel cost policy review process so that emissions rates do not change drastically year-to-year.
Another proposed change is for market sellers to “clearly document standards of review for emissions allowance adders.” Pilong said the change provides transparency around required information from market sellers, where the data must be submitted and the expectation for updating data.
Pilong said a minor change is proposed to remove a reference to “emissions policy” in Manual 15 because emissions policies are no longer utilized and emissions allowance information instead resides in the fuel cost policy.
He said the proposed deadline for implementation is six months following PJM’s FERC filing date to give market sellers an opportunity to update their fuel cost policies.
Heather Svenson, RTO strategy manager for PSEG, said her company was “surprised” to see the proposed solution brought to the MIC as a first read without first having taken a vote on the issue charge. Svenson said PSEG didn’t think that the CDS had approval authority over new issues, based on language in Manual 34.
Svenson said PSEG hoped PJM could compromise and consider bringing the proposed solution back to the MIC for a second first read to “make sure the right company resources are engaged on this topic so that we can make an informed decision.”
“Our concern is that solutions are being brought forward on an issue for a first read that maybe hasn’t received the same level of rigorous review as other issue charges in the stakeholder process,” Svenson said.
Dave Anders, PJM director of stakeholder affairs, said a subcommittee can undertake any work that fits within its charter. He said if there’s a lack of consensus by stakeholders on an issue charge at the subcommittee, then it will be voted on at its parent committee, in this case the MIC.
John Horstmann, senior director of RTO affairs at AES Ohio, asked if PJM could provide a list of CDS members who participated in the variable environmental costs and credits issue. He said discussions at the CDS have historically been about “determining how to report fossil fuel costs,” and he wanted to have a better idea whether there was representation from all the sectors at the subcommittee.
“I don’t know how well-attended the meeting was, and I don’t know whether this is representative of very few members, which typically attend the CDS, or whether it was well attended and a good cross section of stakeholders,” Horstmann said.
PJM said it plans to put the issue on the June MIC agenda as a voting item.
Stability Limit Changes Endorsed
Stakeholders endorsed manual changes regarding stability limits in markets and operations.
Last year, stakeholders endorsed PJM’s proposal on stability limits capacity constraints that included language limiting lost opportunity cost (LOC) credits for any generation reduction required to honor the stability limit in the RTO. The limiting of LOC compensation provoked debates among PJM members. (See “Stability Limits Endorsed,” PJM MRC/MC Briefs: Jan. 27, 2021.)
FERC ruled in February that PJM has the right to refuse LOC payments to generators that are temporarily required to limit output to prevent loss of synchronization and additional strain on the system during transmission outages. (See FERC: PJM Right to Block Gen Stability Limit Payments.) The tariff changes take effect June 1.
Zhenyu said PJM will use a new generator output constraint to enforce the stability limit for real power megawatt-only limits. He said the shadow price of the constraint will not be included or reflected in locational marginal pricing.
To provide greater transparency, Zhenyu said PJM added a new section to Manual 11 related to stability limits that describes the modeling, clearing and reporting process on the stability limit in the market. Updated language related to stability limits in Manual 28 included additional clarification that LOC credits are not paid for megawatts associated with a stability limit reduction.
“The revisions were relatively short,” Zhenyu said. “It’s about clarifying that generators will not be eligible for lost opportunity cost credits for reductions due to stability limit reasons.”
The manual changes will be voted on at the May 25 Markets and Reliability Committee meeting.
Intelligent Reserve Deployment Changes Endorsed
Stakeholders unanimously endorsed manual changes related to intelligent reserve deployment (IRD).
Damon Fereshetian, senior engineer in PJM’s real-time market operations, reviewed the updates to Manual 11 and Manual 28 associated with the IRD issue.
Stakeholders in December endorsed a PJM proposal to improve the deployment of synchronized reserves during a spin event. (See “Synchronous Reserve Endorsed,” PJM MRC/MC Briefs: Dec. 15, 2021.) The proposal created an IRD, which is a security-constrained economic dispatch (SCED) case simulating the loss of the largest generation contingent on the system and for which approval of the case will trigger a spin event.
The proposal also included taking the megawatts of the largest generator contingency and adding them to the RTO forecast to simulate the unit loss. PJM can then flip condensers and other inflexible synchronized resources cleared for reserves to energy megawatts and procure additional reserves to meet the next largest contingency.
Fereshetian said in the verification section of Manual 11, PJM added clarifying language that the response to a synchronized reserve event is “based on the resource following dispatch instructions and is capped at the expected response.”
PJM originally intended to include new Manual 11 language that an approved IRD case “supersedes” any other approved real-time SCED cases for the same target time to be used as the reference case for the locational pricing calculator, but Fereshetian said discussion with stakeholders led to the language removal.
Manual 28 included minor clarifying changes.
The MRC will be asked to endorse the revisions at its May 25 meeting.
Manual 29 Revisions Endorsed
Stakeholders unanimously endorsed minor revisions to Manual 29: Billing as part of the periodic review.
Natasha Holter, manager of PJM’s market settlement operations, reviewed the Manual 29 revisions, saying there were no “substantive changes” in the language and mostly included updates to terminology and reference materials.
Several new subsections were added to the manual, Holter said, including one called “Billing Notifications” that provides guidance on how to obtain notifications for billing statements. Another subsection, “Billing Adjustments,” added language to describe what a billing adjustment is and how to identify one.
Stakeholders will be asked to endorse the revisions at the June 29 MRC meeting.
ATLANTA — A Southern Co. (NYSE:SO) official gamely defended the Southeast Energy Exchange Market (SEEM) last week in a debate with RTO proponents at the RE+ Southeast conference.
Noel Black, Southern’s vice president of federal regulatory affairs and chair of SEEM’s board of directors, battled with three skeptics at the conference, sponsored by the Solar Energy Industries Association (SEIA) and Smart Electric Power Alliance (SEPA).
More than a dozen utilities and cooperatives, including Southern, the Tennessee Valley Authority and Duke Energy (NYSE:DUK), proposed SEEM to reduce the “friction” in bilateral trading by introducing automation, eliminating transmission rate pancaking and allowing 15-minute energy transactions. It is expected to be operational in the third quarter of this year.
Black said SEEM would reduce curtailments of solar power and provide consumers cheaper power than an RTO.
“We wanted to get out of the way of solar, so if your loads are low in the shoulder periods, you have somebody else’s territory to take that energy. So it’s a really efficient way of dealing with that,” he said.
Others on the panel, however, said SEEM’s bilateral trading and limited transparency fall far short of what’s needed to incorporate as much renewable power as is required by efforts to decarbonize by midcentury.
“We believe that some type of wholesale market that’s organized in the Southeast is critical for integrating renewable energy, encouraging development and reducing emissions at the scale that’s required to actively combat climate change,” said Nick Guidi, federal energy regulatory attorney for the Southern Environmental Law Center.
Jamey Goldin, Google’s (NASDAQ:GOOG) energy regulatory counsel for global energy markets and policy, noted that the company has pledged to match its loads to carbon-free generation around the clock. “Just last week, we [committed] to net zero across all lines, including Pixel, Pixelbook, everything; it’s not just data centers anymore,” he said.
‘Nothing Burger’
But he said delivering on that commitment will be most difficult in Asia and the Southeastern U.S.
“Our carbon-free energy [availability] is abysmal in the Southeast, and we’re not going to get there without an RTO. … It’s just not going to happen,” he said, dismissing SEEM as “a nothing burger.”
“When you have true competition, a true, free market for generation, you have economic dispatch and multilateral opportunities for buyers and renewable developers to work together,” he said, citing Google’s work with AES to aggregate renewable projects in PJM. The economies of scale provided by such projects are “impossible in any of these vertically integrated monopoly states,” he said.
“I don’t know what the technical definition of a ‘nothing burger’ is, but it’s definitely not what SEEM is,” Black responded.
He and Goldin cited widely varying statistics on the installed solar power in the three states in which Southern operates. According to February 2022 data from the Energy Information Administration, Georgia ranks sixth among states with 3,088 MW. Alabama was 23rd with 424 MW, and Mississippi ranked 30th with 219 MW.
At a time when natural gas prices have more than doubled to $8/MMBtu, Black said SEEM’s joint dispatch, which will charge customers based on the weighted average cost of fuel, is better for consumers than the single price clearing mechanism used by RTOs.
“Let’s just say you have 80% of your generation from wind or solar. Pretty cheap, right? … Twenty percent of the energy is coming from gas at $8. You set a price at $8. I can’t quite understand how that’s fair to customers, so that they can’t see the real cost of that energy,” Black said. “That’s something that’s going to be under a lot of pressure as RTOs move ahead and get more zero-marginal-cost” resources.
SEEM’s website cites EIA data showing SEEM members’ average rates are below U.S. and RTO averages.
‘True Competition’
Black said SEEM provides “true competition” that would be lacking if a utility cedes to an RTO its transmission operations and planning, “the very things that differentiate me and my ability to best serve my customers.”
“I want to be held accountable. And with accountability comes the opportunity to differentiate. If I turn that over to someone else, you lose competition. It’s just a fact. I mean, I compete by doing the best job of serving my customers reliable, sustainable, affordable energy.”
Maggie Shober, director of utility reform for the Southern Alliance for Clean Energy (SACE), rejected Black’s definition of competition.
“We have this vertically integrated model [in which] you are able to set the rules, largely, on rooftop solar; you control a lot of the energy efficiency. Many customers literally do not have a choice except for their monopoly utility. And so calling that competition, I think, is a misuse of the term, quite frankly.”
Market Oversight
Guidi said SEEM won’t generate real-time energy market prices that would provide price signals to spur renewable development.
He also cited the lack of an independent market monitor to police market power and market manipulation.
“SEEM allows all market participants to toggle off other participants so they can choose who not to trade with. And we think this could be problematic if utilities … decide not to buy from [independent power producers], or merchant generators,” he said. “They might have a cost incentive to buy from them on an individual trade basis. But if they want to favor their generation long term, they might not want to provide those investment opportunities for developers to enter the market.”
He also noted that only load-serving entities will have a say in SEEM’s governance. “There’s no real stakeholder process where customers are represented, public interest organizations are represented, states are represented. And we think that’s problematic, because to have a real thorough market reform in the Southeast, everybody needs to be involved.”
Black insisted there is no incentive for SEEM members to discourage participation. “We’re doing everything in the world to outreach, to focus on participation,” he said. “I have heard that criticism that there’s an opportunity for us to hold people [out]. … It happens not to be true. We want you in the market; we encourage you to be in a market. That will be good for our customers.”
Black also said he was encouraged that more utilities in Florida are studying whether to join the effort. “I have a good feeling that hopefully in 2023 … they’re likely to join SEEM as well,” he said. Duke, whose Carolina utilities are part of SEEM, had previously expressed concern over peninsular Florida’s limited interconnections to the rest of the Southeast; PowerSouth Energy Cooperative, which serves the state’s panhandle, is already a member.
He also cited the clogged interconnection queues in RTOs such as PJM and MISO. “Southern Co. doesn’t have an interconnection problem,” he said.
‘Missed Opportunity’
Shober said SEEM is a “missed opportunity” for customers, citing SACE’s analysis that SEEM would save only $1 per customer per year.
She agreed that “there are issues with a lot of RTO structures out there.”
“So in the Southeast, I see that as a huge opportunity. We’re not trying to work within an existing system that was set up in the ’90s, before we had … all the benefits and technologies that we have today,” she said. “We know that the Southeastern utilities can come together and talk through this because they did so to develop SEEM. Let’s take that to the next level. Let’s look at, what does this Southeast RTO look like? Can we get there? I don’t think it’s going to happen in five years. But can we get there in in 10 years?”
Southern Co. “seems pretty happy with the trajectory we’re on,” Shober observed. “We’re not happy with the trajectory that we’re seeing in the Southeast. We look at [integrated resource plans] every year. We have some IRPs and some utilities that are not on track to get to zero carbon until after 2100 — not even 2050.
“We have a lot of work to do. And it’s just not going to happen in the current status quo.”
