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November 16, 2024

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PJM PC/TEAC Briefs: Sept. 5, 2023

Planning Committee

PJM Presents Quick Fix on Load Forecast Guidelines

VALLEY FORGE, Pa. — The frequency and magnitude of load forecast adjustment requests PJM is receiving from electric distribution companies (EDCs) has led the RTO to bring a problem statement, issue charge and proposed manual revisions on the timeline those adjustments are approved on.

The changes are being sought through the quick-fix process, which allows an issue charge and proposed solution to be brought concurrently and voted on in an expedited manner.

PJM’s proposal would move the Load Analysis Subcommittee’s review of forecast adjustment requests to September and October to provide more time for consideration, and EDCs would be requested to provide hourly data and a 15-year forecast of their adjusted load.

PJM’s Molly Mooney told the Planning Committee on Sept. 5 that numerous factors are taken into account to avoid double-counting load during forecasting, and any types of industries reflected in federal employment figures wouldn’t be counted as a discrete large load increase. Loads from data centers, however, are difficult to forecast because of their disproportionate demand and the fast turnaround between when an interconnection is requested and the in-service date.

Paul Sotkiewicz, president of E-Cubed Policy Associates, asked what PJM’s lead time is between when it finds out about an expected load and that consumer going live on the grid.

PJM’s Dave Souder said much of the load goes through the supplemental process at the Transmission Expansion Advisory Committee, providing a few years’ notice. The issue charge seeks to obtain that information from EDCs further out so more analysis can be built into the planning process.

James Wilson, a consultant for state consumer advocates, said data centers are largely being constructed by a few major parties that are concerned about transmission constraints hindering their projects, leading them to investigate siting in multiple EDCs when only one project will come to fruition. If this is not accounted for, he said projects could be double-counted and transmission built to serve loads that are not built.

Wilson urged PJM to hire an independent consultant to do a long-term forecast of data center load and questioned what PJM’s response would be if EDCs were unwilling to do a 15-year forecast of data center loads. He said that in the event that an EDC submits a total load adjustment request for load-serving entities within their territory, those entities should be required to verify the adjustment.

Mooney said increasing the horizon on the data PJM is seeking also allows for more time to collaborate with EDCs and work through any issues distributors may have with the process.

First Read of 2023 Reserve Requirement Study

Load forecast uncertainty and increased winter risk are driving a significant increase in the reserve procurement levels recommended by the 2023 Reserve Requirement Study (RRS), which went before the PC for a first read. (See PJM Presents Preliminary 2023 Reserve Requirement Study to Stakeholders.)

The installed reserve margin (IRM), which sets the targeted capacity level above expected loads, would rise from 14.7% for the 2026/27 delivery year in the 2022 study to 17.6% for the 2027/28 DY using PRISM modeling software. The forecast pool requirement, which considers forced outage rates, also would increase from 9.18% to 11.65% for the corresponding DYs.

Numerous changes were made to the study’s processes this year, including two parallel analyses using the PRISM software historically used in the RRS, as well as using software developed to perform hourly loss-of-load modeling used in effective load-carrying capability (ELCC) and the inclusion of data from the 2014 polar vortex and the December 2022 winter storm. PJM has historically not included the 2014 storm in the RRS dataset, but experience from the storm led staff to revise that practice.

The preliminary results of PJM’s 2023 Reserve Requirement Study (RRS) would lead to higher reserve margins under both the PRISM and hourly models | PJM

The hourly modeling largely led to higher figures, yielding an IRM of 18.3% for the 2027/28 DY and 12.31% FPR, with much of the difference between the PRISM values arising from the load model. Prior to stakeholders voting on endorsement, PJM plans to recommend use of either the PRISM or hourly results, which stakeholders will have the opportunity to chose between.

PJM’s Patricio Rocha Garrido said 70% of the loss-of-load expectation (LOLE) is concentrated in the summer and 30% in the winter under the PRISM modeling, while the hourly modeling has an 80/20 balance between the summer and winter. Past modeling is now believed to have understated extreme loads, especially in the summer, he said.

“The previous load forecast model was producing values that were understated … whereas the new model that is more granular looks at every hour of the year and the weather in that hour” and the corresponding intermittent output, Rocha Garrido said.

Minimal coincidence between the PJM peak load period and the “World” peak — which is defined as MISO, NYISO, TVA and VACAR — led to the capacity benefit of ties (CBOT) value more than doubling to 2.2% from the 1% value in the 2022 study. To reduce volatility, PJM elected to average the CBOT values from 2017 to 2022 and use that figure, which landed at 1.5% instead.

Transmission Expansion Advisory Committee

PJM Updates Stakeholders on RTEP Windows

Project proposals for the first window of PJM’s 2023 Regional Transmission Expansion Plan (RTEP) are being accepted through Sept. 22, with the goal of resolving 266 flowgates, 130 of which are competitive. The window opened on July 24, and PJM is targeting receiving approval from the Board of Managers in February, PJM’s Sami Abdulsalam said during last week’s meeting.

PJM is also conducting scenario evaluations on the 72 proposals submitted in the third window of its 2022 RTEP, which opened in May to solicit solutions to load growth centered on the northern Virginia region, which is experiencing high data center load growth. Staff plans to walk stakeholders through the window evaluation results during the Oct. 3 TEAC meeting, which will be followed by a first read Oct. 31.

Several ratepayers expressed concerns about land use and cost allocation to regions they argued would not be benefited by the projects, and they urged PJM to consider historical opposition similar projects have received.

Supplemental Projects

FirstEnergy presented a project to replace a 230/34.5-kV transformer nearing its end of life and associated relays at its Windsor substation in the JCPL zone at a $6.3 million price tag. The replacement is underway and is expected to be completed in November.

FirstEnergy presented a $2.2 million project to replace circuit switcher and limiting substation conductor at its Damascus substation and a wave trap, disconnect switches and limiting substation conductor at its Mount Airy facility, which are connected by the 230-kV Damascus-Mount Airy line in its APS zone. The equipment at the two sites has a history of misoperation and cannot be repaired due to lacking spare parts and limited expertise in the technology.

The Public Service Enterprise Group presented two projects to add substations in the South Edison and Perth Amboy area to address rising loads and aging equipment at its existing local infrastructure. The 230/13-kV South Edison substation would be built at a $56.1 million cost adjacent to the existing Meadow Road facility, which has a contingency overload of 124%. A new 69-kV line would be built from South Edison to a new 69/13-kV substation, which would be built adjacent to the Keasby facility. The $220.9 million project would support the Keasby substation, which is nearing 100 years old and in need of repairs, and the Pierson Avenue substation, which has a contingency overload of 123.3%.

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PJM OC Briefs: Sept. 7, 2023

PJM Delays Vote on Quick Fix to Information Sharing Requirements

VALLEY FORGE, Pa. — PJM on Thursday opted to hold off from seeking stakeholder endorsement of a quick-fix issue charge and proposed manual revisions aimed at reducing the circumstances under which the RTO would be compelled to provide advance notice of when it will be sharing confidential member information with third parties. (See “PJM Brings Quick Fix Issue on Data Sharing,” PJM OC Briefs: Aug. 10, 2023.)

PJM’s Becky Davis told the Operating Committee that confidential information is regularly shared with reliability coordinators, transmission owners and NERC in the course of normal business, and a notification five days before the information is shared has become “inefficient and impractical” and slowed down coordination with those parties.

Paul Sotkiewicz, president of E-Cubed Policy Associates, questioned why the change was being sought as a quick-fix change to Manual 33, rather than as a change to the Operating Agreement with a corresponding FERC filing, which he believes would be a “slam dunk” before the commission.

PJM Assistant General Counsel Thomas DeVita said the RTO considered removing the notification entirely through changes to the OA but came to the conclusion that members may prefer notification in some circumstances, such as the NERC inquiry into the December 2022 winter storm.

East Kentucky Power Cooperative’s Denise Foster Cronin suggested explicitly including the advance notice exceptions envisioned by the draft manual revisions in the OA (rather than the manual) and including a retroactive notification requirement when advance notice is not provided to allow members to remain informed about when their information has been shared without slowing down PJM’s coordination with third parties.

PJM said it will defer seeking a vote on the quick fix until the October OC meeting to work with stakeholders to incorporate their feedback into the proposal.

Stakeholders Endorse Quick Fix on Synchronized Reserve Dispatch

The OC unanimously endorsed a quick fix issue charge and manual revisions to clarify that generation owners should respond to a synchronized reserve deployment when they receive notification through any of the existing Energy Management System (EMS) datalinks. (See “PJM Proposes Synchronized Reserve Deployment Language,” PJM OC Briefs: Aug. 10, 2023.)

PJM’s Frank Hartman said the status quo language has resulted in many reserve resources waiting until they have received the all-call message from dispatchers, which takes longer to reach generators. When reserve resources receive a signal to respond, Hartman said their default is to provide the full amount they’re committed to in the market. For a resource with a 50-MW reserve obligation, he said that is the amount it should provide unless it receives instructions otherwise from dispatchers.

The quick fix is one of several solutions PJM has proposed to address a decline in response rate since the reserve market was overhauled in October. (See “PJM Seeks Stakeholder Process on Reserve Certainty,” PJM MRC/MC Briefs: July 26, 2023.)

Sotkiewicz said he finds the issue charge problematic as it does not address the possibility that there may be underlying issues with the reserve market structure that may be leading to the decline in response rates.

PJM’s Donnie Bielak said the quick fix is meant to clarify existing instructions to generators, and there are other forums where the RTO intends to address the issues that Sotkiewicz raised.

“All of your comments are well taken; it is on our radar, and it is something we collectively want to address as well,” Bielak said.

Stakeholders Endorse Manual Revisions Related to Communication Failures

The OC unanimously endorsed revisions to Manual 1 that detail when TOs would be required to notify PJM that interpersonal communication capabilities have been disrupted.

The revisions state that PJM is required to be notified when only alternative communication systems are available and a loss of portions of a TO’s interpersonal communication capability, such as a radio failure, does not require a notification so long as other voice communications detailed within the TO’s communication capability remain available. (See “PJM Proposes Manual Revisions Related to Communication Failures,” PJM OC Briefs: Aug. 10, 2023.)

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PJM MIC Briefs: Sept 6, 2023

Voltus Withdraws Issue Charge on DR Offer Parameters

VALLEY FORGE, Pa. — Voltus on Wednesday withdrew an issue charge at the PJM Market Implementation Committee addressing the parameters that demand response resources can include in their energy market offers after several stakeholders stated their opposition to using the “CBIR Lite” (Consensus Based Issue Resolution) process.

The MIC was to vote on adopting the issue charge during Wednesday’s meeting. (See “Voltus Brings Economic Demand Response Parameter Issue Charge,” PJM MIC Briefs: Aug. 9, 2023.)

David Aitoro, Voltus senior energy markets manager, said the company would further consider whether it wanted to continue to seek the CBIR Lite pathway or switch to the standard CBIR process before bringing the subject before the committee again.

Paul Sotkiewicz, representing J-Power, said the use of the CBIR Lite process prevents him from being able to support the issue charge, which he would otherwise likely support in concept.

The problem statement and issue charge say DR providers lack the ability to automatically specify a maximum run time or to set a minimum amount of time between being dispatched.

Because the documents were first brought for a first read in August, Aitoro said they were revised to make clear that the issue charge would preclude discussion of capacity market offers and is instead intended to focus on the two parameters outlined.

“We’re not touching any broad status quo rules; we’re not touching load management,” he said. DR participating in the capacity market is referred to as load management.

Monitoring Analytics President Joe Bowring | © RTO Insider LLC

Independent Market Monitor Joe Bowring said the narrow scope of the issue charge would prevent stakeholders from engaging in discussions about DR that need to be had, including interactions between DR’s participation in the capacity and energy markets. He also opposed using CBIR Lite, saying the potential impacts warrant the full stakeholder process.

“This is not a trivial thing; it has potentially significant impacts on how DR works,” he said.

AEP Energy’s Brock Ondayko raised the possibility of requiring DR resources to document when they make a change to their parameters.

Aitoro said he intends to keep the scope of the issue charge narrow, and if a broader discussion is sought by stakeholders, an additional issue charge would be the best way to initiate that.

Providing education on the status quo rules for DR, PJM’s Peter Langbein said there is about 8,451 MW of DR participating in the capacity market, the “vast majority” of which does not have an energy market offer. About 2,449 MW of DR is in the energy market.

A DR resource can participate both as load management, with a capacity and energy market offer, as well as a separate economic DR resource, with an energy-only offer. Langbein said the parameters included in the capacity offer would override any energy offer parameters.

There are numerous ways in which the energy market rules differ for DR resources, including their ability to manually change the availability of their offer into the market, which Langbein said is because of the lack of market power concerns.

Sotkiewicz said the differences, particularly the ability to switch availability on and off, have the potential to be discriminatory treatment.

“Why do we have different rules for economic DR than generation?” he asked.

AEP, Dominion Proposal on Capacity Obligations for Concentrated Loads

An issue charge and problem statement proposed by American Electric Power and Dominion Energy would address how capacity obligations are assigned to load-serving entities when large amounts of load are added to concentrated areas.

AEP’s Josh Burkholder said that when a large amount of load is added to a single zone, such as clusters of data centers, it can lead to the capacity obligation being dispersed broadly across the zone. For fixed resources requirement (FRR) entities, he said that can also result in the amount of capacity they’re required to procure being above what’s needed to serve their internal demand.

The issue charge also ran into questions about whether it should progress under CBIR Lite, as is currently proposed, or if it should instead use the standard CBIR process.

Discussion Continues on Multischedule Clearing in The Market Clearing Engine

Deputy Monitor Catherine Tyler presented a new joint proposal with the GT Power Group to address the computational barriers to introducing multischedule clearing in the market clearing engine (MCE). (See “First Reads on Proposals Addressing Multi-schedule Modeling in MCE,” PJM MIC Briefs: Aug. 9, 2023.)

The package is an alternative to GT Power Group’s original joint proposal with PJM, which would select resources’ cost-based offers when they fail the three-pivotal-supplier (TPS) test and their parameter-limited offers during emergency conditions, but would allow resources to choose the most cost-effective offer to send to the MCE when they have multiple valid offers, such as in the case of dual-fuel generators.

Catherine Tyler, IMM | © RTO Insider LLC

Tyler said a shortfall of the previous proposals was that dual-fuel generators may be dispatched based on schedules that would not match the most efficient fuel.

“We don’t want to commit a unit to run on a more expensive oil offer when [gas] fuel is more efficient,” she said.

Under the new proposal, if a unit with multiple offers fails the TPS test, PJM will commit the unit to operate based on the fuel the generation owner expects to use in each hour of the day. The PJM solutions would also not resolve issues that allow generators with market power to raise energy prices by using high markups and to extract uplift using inflexible parameters.

Tyler said any generators not submitting the most efficient offer may be considered to be engaging in market manipulation.

The joint package adds a fifth option to resolve an issue identified in the development of the Next Generation Markets (nGEM) overhaul of the MCE, where the number of offers the engine would have to analyze when clearing combined cycle and storage resources would cause an untenable increase in computational times. PJM’s proposal would create a formula for selecting the offer that results in the lowest total dispatch cost, which would be entered into the engine.

The first Monitor proposal would combine the lowest offer points and most flexible parameters from resources price and cost-based offers under certain scenarios, impose offer capping and parameter limits to all resources that fail the TPS test and apply parameter limits to capacity resources during emergencies.

The Monitor’s second package would do the same as above but would use the status quo rules for resources with multiple cost-based offers.

Sotkiewicz questioned if PJM would consider the proposal to be temporary until a technological solution that reduces computational times is found.

PJM’s Keyur Patel said if the technology improves, staff would be open to reverting to the status quo. Tyler, however, said the Monitor’s perspective is that the status quo would be improved by resolving the market power issues.

Competing Proposals Addressing Local Factors on Net CONE Merged

E-Cubed Policy Associates, PJM and the Monitor have merged competing proposals centered on how to account for local or state factors, such as climate legislation, which could affect the cost of new entry (CONE) for generators in that region. The new package would add a fifth CONE area for the Commonwealth Edison region but would not codify a new pathway for adding new areas in the future. (See “Stakeholders Discuss Proposals to Include Local Factors in Net CONE,” PJM MIC Briefs: Aug. 9, 2023.)

Both the original PJM and E-Cubed packages would have broken ComEd out as a new CONE area, but the E-Cubed proposal also would have automatically created new areas when local factors shortened asset lifespans or would imply a different reference resource from what is used by PJM in its calculation of CONE. Sotkiewicz, president of E-Cubed, has argued that the impact of the Illinois Climate and Equitable Jobs Act (CEJA) would shorten the lifespan of many generators, including the reference resource, located in the state. The merged proposal would include an amortization period reflecting CEJA in the fifth CONE area.

Sotkiewicz said streamlining the process to create new CONE areas in the future was his primary rationale for creating a second proposal, but that he believes the existing tariff language has been demonstrated to be adequate. He said PJM was concerned about creating an automatic process for adding CONE areas, believing it should be done on a case-by-case basis with stakeholder consideration of the variability on the ground.

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NJ Gov. Appoints Clean Energy Advocate to Head BPU

New Jersey’s Board of Public Utilities, the leading edge of the state’s aggressive push into renewable energy, will be led by Christine Guhl-Sadovy, a former organizer for the Sierra Club in the campaign against coal, Gov. Phil Murphy (D) said Monday.

Guhl-Sadovy, who joined the board in May, will replace Joseph L. Fiordaliso, who died Sept. 6th and had served for 17 years as a BPU commissioner, including five as the agency’s president. Guhl-Sadovy worked as Fiordaliso’s chief of staff at the BPU before moving to become Murphy’s cabinet secretary in October 2021.

While chief of staff, Guhl-Sadovy worked on the state’s 2019 Energy Master Plan, the 2018 Clean Energy Act and the state’s Electric Vehicle Incentive program, all of which helped shape the state’s commitment to a vigorous transition away from fossil fuels and toward renewable energy.

Murphy said he believed Guhl-Sadovy would continue what he called Fiordaliso’s “steadfast … unwavering belief that we not only can — but must — cultivate a healthier and more sustainable planet for our children and grandchildren.” (See NJ BPU President Fiordaliso Dies.)

“I’m confident that Christine, who has demonstrated her commitment to these same values time and time again throughout her invaluable service in my administration, will continue to build upon Joe’s lasting legacy,” he said. He added he expects her to “responsibly transition New Jersey to a clean energy economy, while putting the needs of consumers and New Jerseyans first.”

Guhl-Sadovy’s appointment takes effect immediately. New Jersey law requires the governor to nominate BPU commissioner candidates subject to confirmation by the state Senate. But Murphy can appoint the president from commissioners who already gained Senate approval. (See NJ Senate Approves Two BPU Commissioners.)

She takes the helm as the board faces a growing pushback against Murphy’s clean energy policies, with vigorous opposition to the state’s offshore wind plans from shore residents and tourism advocates, and concerns from offshore wind developers that approved projects no longer may be economically viable because of rising costs.

Murphy expects to nominate Stephanie Lagos, deputy chief of staff to the governor and his wife’s chief of staff, to fill the open seat on the five-member board, according to a source close to the governor. She would go for confirmation by the Senate in the fall.

The BPU has cancelled its next meeting, which was scheduled for Thursday.

Beyond Coal, Planned Parenthood

Guhl-Sadovy, in a statement released by Murphy, said she’s looking forward to “continuing to serve the people of New Jersey in this role, and making the planet healthier.”

A graduate in psychology from Rutgers University, Guhl-Sadovy also gained a certificate in leadership, organizing and action from the Harvard Kennedy School, according to her LinkedIn page. She worked on energy and environmental issues with the national Sierra Club as a representative of the Beyond Coal campaign and while at Planned Parenthood she worked to ensure the election of pro-women’s health candidates and on the successful effort to pass legislation to restore funding in New Jersey for family planning.

Guhl-Sadovy drew support from the environmental community during her confirmation as commissioner, and Doug O’Malley, director of Environment New Jersey, welcomed her appointment as BPU head.

“Christine started her career working to fight climate change, and now she’s in the bully pulpit,” he said. “She’ll clearly continue the legacy of President Fiordaliso, and she’s a force in her own right.”

He called her an “an incredibly strong pick to lead the board,” in part because of the wealth of knowledge she brings to the position from having worked as Fiordaliso’s chief of staff.

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NY State Reliability Council Executive Committee Briefs: Sept. 8, 2023

Emergency Operating Procedures

ALBANY, N.Y. — The New York State Reliability Council Executive Committee on Friday approved the preliminary base case for the upcoming capability year and new emergency operating procedures aimed at enhancing grid reliability.

The base case was approved after it received approval from both the NYSRC’s Installed Capacity Subcommittee, other committee members and NYISO, with the ISO’s COO, Rick Gonzales, saying during the meeting, “This is a step in the right direction, and the ISO supports this change,” in reference to the proposed revisions.

NYISO COO Rick Gonzales | NYISO

The base case is particularly crucial for resource adequacy modeling, as it sets the foundation for assessing the reliability of the power system by establishing assumptions concerning load forecasts, generator availability, transmission constraints and other factors that influence the modeling.

Previously, the ICS reported how conditions are tightening in the New York Control Area and that conservatively adjusting the ISO’s emergency operating modeling and its base case is necessary as the state relies on neighboring systems, particularly in the winter, to support reliability during emergencies. (See “Emergency Operating Procedures,” NY State Reliability Council Executive Committee Briefs: June 9, 2023.)

The ICS and NYISO staff will continue to conduct sensitivity analyses using these new assumptions to better understand the impact they will have on the state’s installed reserve margins and then report back to the committee.

Stakeholders were asked to share input before anything is finalized at the ICS meeting on Oct. 4.

Inverter-based Resources Standard

The committee discussed NERC’s new risk priorities list in light of a recent inverter-based resource (IBR) event in Utah that caused grid instability.

NERC for the first time updated its risk priorities list to include energy policy as a risk profile after it determined that policymakers’ decisions are becoming increasingly crucial to ensure the reliability of the grid. (See ERO Adds Energy Policy to Risk Priorities List.) New York has been working to finalize rule requirements and comply with NERC standards for IBRs.

Last month a solar disturbance in southwest Utah raised further questions about the reliability of IBRs and prompted NERC to reiterate the importance that generators and developers follow its Level 2 alert, which set out IBR guidelines. (See NERC Utah Event Report Underlines Ongoing IBR Issues.)

Mayer Sasson, former chair of the Executive Committee, commented that when reading NERC’s report on the incident, he felt like its authors were “angry and upset,” as utilities and the wider industry were “not taking [NERC’s] event analysis and recommendations seriously.”

Roger Clayton, chair of the NYSRC’s Reliability Rules Subcommittee, who has been leading the charge of implementing IBRs, said that the incident “is more evidence that we need to get this right,” adding that the state “must learn the lessons from these incidents and avoid such incidents from happening in New York.”

NYISO Updates & Eclipse Prep

NYISO informed the EC that it has made notable progress on several market development projects, such as its dynamic reserves, duct firing model improvements and four-year demand curve reset, as well as begun preparing for an upcoming solar eclipse.

Aaron Markham, NYISO vice president of operations, also told the committee that August was a “pretty benign month” and experienced a peak load of 24,970 MW.

NYISO has begun preparing for an anticipated partial solar eclipse in October, which is expected to reduce solar energy by roughly 700 MW, though the ISO believes it will have enough resources available to meet load at the time.

The ISO is also looking ahead to a total solar eclipse expected in April 2024 that will pass through the state.

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BOEM Completes Environmental Review of Empire Wind

Federal regulators have completed their environmental analysis of plans for Empire Wind, finding potentially significant impact on the fishing industry and endorsing some changes to the 2.1-GW offshore wind farm proposal.

The Bureau of Ocean Energy Management on Monday released its final environmental impact statement for the proposal.

Publication of the EIS typically is one of the final steps in the review process. It’s the third EIS that BOEM has published in the past four months for a major offshore wind project; the previous two were followed five to six weeks later by records of decision approving construction and operation of Ocean Wind 1 and then Revolution Wind.

Empire Wind is a joint venture of Equinor and BP that would stand as close as 12 nautical miles south of New York and 17 nautical miles east of New Jersey. New York State has contracted with it to deliver 816 MW and 1,260 MW in Phase 1 and Phase 2, respectively.

Impact Statement

The details differ, but the final EIS announced Monday for Empire Wind reaches conclusions similar to EIS reviews prepared recently for other projects. They offer an often-wide range of possible outcomes for the criteria examined.

Empire Wind is expected to have minor to moderate beneficial effects on air quality and economics, for example.

It’s expected to have minor to moderate adverse effects on environmental justice communities and vessel navigation.

The effects on birds could be adverse or beneficial, or both.

The EIS also looks at the results of not building Empire Wind — the effects of climate change continuing unchecked as fossil fuels are burned to generate the electricity the offshore wind turbines otherwise would produce. In this no-action scenario, the adverse impacts on birds or people or fish often are projected to be of a similar magnitude even as the specific details are different.

But one thing is consistent in every EIS: the impact on the Northeast fishing industry.

BOEM forecasts Empire Wind will have a minor to major adverse effect on fishing, depending on the type of vessel and the species it’s harvesting.

Combined with the other 19 offshore wind farms that potentially could stand between Cape Cod and Cape May, the cumulative impact on commercial and for-hire recreational fishing is expected to be major.

For Empire Wind’s lease area OCS-A 0512, the greatest commercial impact is expected to be on the scallop fishery. Most of the area produced more than $4,000 worth of sea scallops per square kilometer per year from 2008 to 2018, and the harvest in a large swath exceeded $8,000 mean annual value.

Other major adverse impacts from Empire Wind are projected on the view from shore, search and rescue operations, and scientific surveys. Adverse effects on the critically endangered North Atlantic right whale could range from negligible to major.

Changes

Empire Wind 1 was proposed to have up to 57 turbines and Empire Wind 2 as many as 90. Their rotors would reach as high as 951 feet above sea level. They would be served by two offshore substations and up to 260 miles of inter-array cables. Up to 67 miles of export cable would run to landfall points in Brooklyn and farther east on Long Island.

However, after the draft environmental impact statement was published, Empire and BOEM conducted further analysis of glauconite soils in the lease area. Monopile foundations are so difficult to drive into glauconite that Empire concluded 40 of its potential turbine sites might not be viable. This cut the maximum number of turbines to 138.

Meanwhile, BOEM endorsed four changes to the routing and construction technique of the export and onshore cables.

BOEM has gathered these changes into a “preferred alternative”; it is the option the agency is leaning toward as it moves to its final Record of Decision.

Headwinds

Empire Wind is in line to be the fifth utility-scale offshore wind farm green-lighted in U.S. waters. The first two, Vineyard Wind and South Fork Wind, are under construction.

But Ocean, Revolution and Empire all have significant cost and supply challenges to overcome before they can start construction, as do other developers in the new U.S. offshore wind sector.

Equinor and BP have told New York they may not be able to proceed with Empire without substantially more money than was agreed upon.

Ørsted is seeking more money for Ocean and Revolution before it makes a final investment decision and has pushed the completion date for Ocean back a year.

Developers of two of Massachusetts’ three contracted offshore wind facilities are paying $100 million in penalties to back out of their power purchase agreements in hopes of bidding back into the Bay State’s latest solicitation at higher costs.

Earlier this summer, Orsted’s proposal for Revolution Wind 2 was rejected as too expensive in Rhode Island. And New York has invited bidders in its latest offshore solicitation to resubmit bids with lower price tags.

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Nation’s Grid Faces ‘Rendezvous with Reality’

DFW AIRPORT, Texas — Keeping the lights on has long been a simple proposition for grid operators. Look at historical demand, add in growth expectations and ensure you have enough generation available to meet that demand.

No more. With older thermal plants retiring or breaking down and being replaced by a flood of more variable renewable resources, grid operators need a more comprehensive focus to ensure they have enough capacity and reserves to keep the system in balance.

SPP last week invited federal and state regulators, academics, market participants and other stakeholders to its inaugural Resource Adequacy Summit. There, they discussed the events that have led the industry to this juncture and the actions necessary to improve the grid’s reliability in the face of enormous change.

“This is the first opportunity we’ve really had to kind of open up a stakeholder, customer and just simply interested party dialogue on a very important topic,” SPP COO Lanny Nickell said in kicking off the Thursday summit.

FERC Commissioner Mark Christie likened the current state to that of the Great Depression, when President Franklin D. Roosevelt said the country was facing a rendezvous with destiny.

“We’re at a very critical time … reliability means, ‘Are the lights going to stay on?’ That’s what it means to the general public,” Christie said. “Are the lights going to stay on? We’re really at a point where that’s coming into serious question. Are the lights going to stay on?

“Right now, when it comes to the reliability of our grid, the United States is facing a rendezvous with reality. Reality is just around the corner. You may think you can avoid it for a while, but reality will track you down. And reality is tracking us down when it comes to the reliability of our grid,” he added.

Testifying before the Senate’s Energy and Natural Resources Committee in May, Christie told lawmakers the grid is facing “potentially catastrophic consequences.” He said he was not trying to be melodramatic. (See Senators Praise Phillips, FERC’s Output at Oversight Hearing.)

“We were not trying to get a sound bite out there into the media. I used the term ‘catastrophic’ because when we have multiple-day outages … that’s catastrophic by any definition. People die if it’s a cold-weather outage, and so that is catastrophic.”

The core reason, Christie said, is not necessarily the vast amount of wind and solar generation that is being added to the grid. It’s the subtraction of coal, gas and other dispatchable thermal resources at a pace that is unsustainable, he said.

“The first rule of holes is if you’re in one, stop digging,” he said. “If the fundamental problem we’re facing is we’re shutting down dispatchable resources far too prematurely, then the answer is to stop shutting down dispatchable resources far too prematurely.”

Christie brought receipts with him. He said PJM forecasts the loss of 40 GW of mostly dispatchable capacity by 2030. He said MISO expects to be 9 GW short by 2028. He noted an earlier presentation from Nickell saying SPP has installed 24 GW of wind and solar in recent years but has lost 8 GW of dispatchable resources.

“And by the way, that is before the EPA came out with the power plant rule, which is going to make that number even worse, as every RTO knows,” Christie said. “The numbers don’t add up. You lose 8 gigs of dispatchable and you pick up 24 gigs of wind and solar, [you think] you’re fine right now. You’re not fine, because as we all know, a megawatt of nameplate wind and solar is not equal to a megawatt of nameplate coal or gas. It’s just reality.”

“There’s really no reason why we should be retiring perfectly good resources in this country,” said Zachary Ming, a director with San Francisco-based consulting firm Energy and Environmental Economics (the folks behind ERCOT’s market redesign).

Zachary Ming, E3 | © RTO Insider LLC

“We should be focusing on building as many new resources, primarily renewables and storage, and keeping the firm dispatchable resources online that we have. That is both going to maximize affordability, and it’s going to maximize environmental benefits as well,” Ming said. “You reduce emissions by building renewable resources that come first in the dispatch order and will dispatch ahead of dispatchable resources. All building renewables will do is allow us to use the dispatchable resources less, but renewables have limited contributions to reliability. So, it doesn’t mean we can retire the resources. It just means that we can use them less. They will have less emissions, and they will have environmental benefits, and they’ll still stay there for reliability.”

“We’re facing reality very, very simply. I think everybody knows that,” Christie said. “The question is, is there going to be the political will to make a turn in policy and recognize that we’re not going to get to where everybody wants to get, which is a lower-carbon grid, without reality being part of the equation, because reality will track you down. We’re headed to some bad outcomes and none of us want to be around when those outcomes hit, because that’s when the finger-pointing starts.”

Sitting next to Christie, NERC CEO Jim Robb said the industry’s ability to conduct resource planning with a “highly variable intermittent generating system” will define the industry’s next 10 to 15 years.

“That’s the challenge that’s in front of us, and it’s not our grandfathers’ resource adequacy problem,” he said, noting NERC would like to hold an event similar to SPP’s. “I think we have to recognize that we take constructs that we all grew up with and we’ve been trying to modify them to adapt to a system that’s just fundamentally very, very different than what we grew up with. Whatever [resource adequacy] construct you look at is a very important number, but it’s no longer close to being a sufficient number for planning and operating the system.”

Robb pointed out that the traditional resource adequacy constructs are based on meeting demand during peak hours with enough of a margin to account for the “random independent equipment failures.”

“That doesn’t work anymore,” he said, pointing to what he called “common conditional failures” of the emerging generation fleet that is flush with renewables.

“A wind drought, solar drought, cloud cover, unexpected cloud cover, extreme cold weather affects the ability of large amounts of generation to operate, so this whole notion of kind of random failure being the driver of how much generation we need isn’t sufficient,” Robb said.

FERC Commissioner Mark Christie (left) and NERC CEO Jim Robb listen to an audience question. | © RTO Insider LLC

Policymakers need to “come to grips” with three questions, he said: how frequently they can tolerate loss-of-load events, how long an event are they willing to tolerate and how much are they willing to pay to prevent them.

“We know we can’t afford a 100% reliable system,” he said. “We’re going to have to make important tradeoffs between reliability and those three parameters [frequency, duration and scale] and how much we will be paid to avoid that. Resilience and reliability is not free.”

Robb said he’s encouraged by recent research into what customers are willing to pay to avoid multiday outages. He said those numbers are “much, much higher” than what he’s seen in the past.

“We’ve taken away the obligation to serve, and in these market areas, we rely on commercial constructs to try to recreate that,” he said. “It’s an imperfect substitute, but we have to figure out how to get the market rules to reward reliability with investments that aren’t going to be naturally paid for during the 98% of the normal periods.”

SPP is taking those steps with several recent changes. It increased its planning reserve margin from 12% to 15% last year and made several tariff changes for load-responsible entities’ deficiency payments and a payment structure based on a sufficiency valuation cure.

Those changes were approved by FERC in April. (See FERC Approves SPP’s Resource Adequacy Changes.)

Buddy Hasten, CEO of Arkansas Electric Cooperative Corp., one of SPP’s LREs, called for fairness in meeting reliability commitments.

“We’re propping up reliability, but we get paid nothing for it,” he said. “When the wind blows hard enough or the sun shines bright enough, we have to pay the market to just keep our resources online to prop up the market to be there for reliability. So when [prices] go negative, I’m paying to keep that resource online.

Buddy Hasten, AECC | © RTO Insider LLC

“We like to play games. You create the rules of the game, and everyone plays it, and it’s all about who can get the lowest cost because we’ve turned electricity into a commodity instead of an essential service,” Hasten added. “At some point, there has to be a financial metric rule, some payments, something somewhere to pay for that reliability. Otherwise, everyone’s going to keep playing the game and just chasing the cheapest electron.”

A nuclear submariner for 20 years, Hasten said he’s very aware of the importance of resource adequacy.

“If you don’t have enough resources, you go to the bottom of the ocean,” he said. “Resource adequacy is life or death. I’d hate to be the person that go to those folks’ home and says, ‘Hey, I’m sorry, you froze to death.’ … 2021 was the first time we sent linemen out and white bucket trucks to go open breakers and put people on the dark. That’s called progress, I guess.”

Several speakers pointed out the role natural gas played during that winter storm. Gas plants without firm fuel contracts — and some with firm contracts — were unable to get those supplies as heating homes took precedent. Other thermal generators simply weren’t prepared for the extreme winter conditions.

Aubrey Johnson, MISO | © RTO Insider LLC

Aubrey Johnson, MISO’s vice president of system planning and competitive transmission, said aging plants in the RTO’s fleet also played a role in the 2021 and 2022 winter storms.

“It’s actually a fleet that’s not responsive when you actually need it,” said Johnson, who has a background in power plants. “Working with Southern Co., we used to have real competition about how you showed up during peak season and how well your plants performed. When I look at some of the performance numbers today, I’m kind of shocked. You would spend a lot of time in the principal’s office with those kinds of performance numbers.

“The No. 1 way to ensure resource adequacy is ensuring you have adequate resources,” he added.

Given a chance to provide suggestions to the audience during a lightning Q&A round, Johnson’s message was simple.

“Build. Just build,” he said.

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Apple Supports Proposed California Emissions Reporting Bill

Apple put its considerable heft behind a California bill that will, if passed, increase the emissions reporting requirements for more than 5,000 large companies that do business in the state.

In a move lauded by the bill’s author, Apple, the $2.8 trillion behemoth, came out in support of The Climate Corporate Data Accountability Act (SB 253). The bill was approved Monday in the state Assembly and now goes to the state Senate.

The proposed legislation would require corporations with total annual revenue greater than $1 billion that do business in California to report the prior year’s Scope 1 and Scope 2 emissions by a date yet to be determined in 2026 and Scope 3 in 2027, with annual reports thereafter. Scope 1, 2 and 3 emissions are used globally to define the different types of greenhouse gas emissions of companies:

    • Scope 1 emissions are direct greenhouse gases emitted by a company, for example from running boilers, burning fuel in a manufacturing process or powering non-electric vehicles;
    • Scope 2 emissions are indirect emissions from electricity, steam, heating or cooling purchased by the company for uses ranging from lighting to charging electric vehicles;
    • Scope 3 emissions are indirect and related to a company’s supply chain, both its inputs through to the end use and eventual disposal of the goods. These emissions may include goods and services a company buys, employees’ commuting and work travel, emissions from transporting and distributing a product to consumers and final use and disposal of the product. This is not only the largest category of emissions but also the hardest to measure.

State Sen. Scott Weiner (D–San Francisco) on Friday posted a message on X (formerly Twitter) about Apple’s move: “Huge new endorsement — @Apple — of our groundbreaking climate bill to require large corporations to disclose their carbon footprint (SB 253). Thank you, Apple, for making clear that this is doable & a critically important piece of climate action.”

The endorsement of the bill came in a letter to Weiner which stated, in part:

“We’re strongly supportive of climate disclosures to improve transparency and drive progress in the fight against climate change, and we’re grateful for your leadership to drive comprehensive emissions disclosure.”

Apple’s support comes more than two weeks after a group of companies including Microsoft, Adobe, IKEA USA and Atlassian issued a joint statement in support of SB 253 that said “California is on track to be the fourth-largest economy in the world and this bill would set a global standard for emissions disclosure. SB 253 would level the playing field by ensuring that all major public and private companies disclose their full emissions inventory, creating a pathway for collective reduction strategies.”

By requiring Scope 3 emissions reporting, SB 253 exceeds the proposed Securities and Exchange Commission (SEC) rule, which largely lets companies out of reporting them unless they already have a stated target for reducing them or if they are material, that is, if a “reasonable investor” would be “substantially likely” to consider them important when making an investment or voting decision.

This is not Weiner’s first attempt at passing the bill: SB 253 failed to pass by one vote in 2022, but has been amended to delay Scope 3 emissions reporting by a year, aligning the bill with the International Sustainability Standards Board’s IFRS S2 Climate-related Disclosures standard issued in June 2023.

Corporate Support is Far from Unanimous

In August, a policy advocate specializing in energy issues at the California Chamber of Commerce, Brady Van Engelen, critiqued the bill, calling for legislators “to reject an onerous emissions tracking and paperwork requirement that will increase costs on California businesses.”

Much of CalChamber’s concern centers on the use of secondary data or industry averages for calculating Scope 3 emissions.

“Secondary data is inherently flawed and unreliable, nor does it paint an accurate picture. This flawed method of calculating Scope 3 emissions means that virtually every reporting entity could be subject to a violation,” Van Engelen said in his August 23 post.

CalChamber, along with many other companies and associations including the Western States Petroleum Association, the California Retailers Association and the California Manufacturers and Technology Association, issued a joint statement opposing the bill, which stated in part: “At this juncture, Scope 3 emissions reporting is more of an art than it is a science. Due to the likelihood of double counting, assessing Scope 3 emissions data with any degree of accuracy is not yet possible.”

The letter from Apple directly addressed the challenge of Scope 3 emissions reporting, highlighting its own efforts: “We acknowledge that there is inherent uncertainty in modeling carbon emissions, primarily due to data limitations. Scope 3 emissions, in particular, involve making educated assumptions and complex modeling. We believe, however, that our reports attest to the feasibility of reasonably modeling, measuring and reporting on all three scopes of emissions, including scope 3 emissions, which represent the overwhelming majority of most companies’ carbon footprint and are therefore critical to include.”

The bill is not the only proposed climate-related legislation being considered in California. Senate Bill 261, the Climate-Related Financial Risk Act (SB 261), would require companies with greater than $500 million in revenue to report on “material risk of harm to immediate and long-term financial outcomes due to physical and transition risks,” by the beginning of 2026 and biennially thereafter. Assembly Bill 1305, the Voluntary Carbon Market Disclosures Act  (AB 1305), requires much more detailed disclosures on the websites of companies marketing or selling voluntary carbon offsets within the state.

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US Small-scale Solar Grew by a Record 6.4 GW in 2022

Installed small-scale solar capacity increased by an estimated 6.4 GW in 2022 — a record amount, even amid supply chain constraints and rising costs.

The Energy Information Administration highlighted the data Monday and said small-scale solar nationwide totaled 39.5 GW by the end of 2022 — about a third of U.S. installed solar capacity.

EIA defines small-scale or distributed solar as systems with up to 1 MW nameplate capacity. But most small-scale solar is much smaller than 1 MW — rooftop residential installations account for most small-scale capacity.

When EIA began its annual estimates of the subsector in 2014, it placed the installed capacity at just 7.3 GW. Since then, falling solar panel costs, government incentives, policy changes and rising retail electric costs have helped accelerate the buildout.

California, with its abundant sunshine and statutory requirement that new residential buildings be equipped with solar panels, accounted for 36% of installed capacity nationwide, by far the most of any state.

But Hawaii, which has historically relied on expensive imported fuel to power its electric generation, has by far the greatest market penetration: 541 watts of installed solar capacity per capita. California is second, at 364 watts.

Other top states for installed small-scale solar capacity include New York, New Jersey and Massachusetts. None of the three have optimal amounts of sunshine, but all have strong and long-standing policies that encourage installation.

New York is No. 2 in the nation, at 2.6 GW, and New Jersey is third, at 2.4 GW.

Sun Belt states Texas (2.2 GW) and Arizona (2.1 GW) are catching up, however, and have surpassed Massachusetts (2.0 GW).

Sunny Florida is close behind, at 1.9 GW. Every other state is estimated to have 1 GW or less of small-scale solar generation installed on homes, businesses and industrial sites.

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MTEP 23 Catapults to $9.4B; MISO Replaces South Reliability Projects

MISO said it will seek approval from its board of directors for 578 transmission projects totaling $9.4 billion in December.

The RTO’s 2023 Transmission Expansion Plan (MTEP 23) makes for MISO’s largest-ever annual planning cycle and includes a substitution for two MISO South reliability projects. That’s according to MISO’s final round of subregional planning meetings for the year Sept. 5-8.

MISO South transmission owners plan to build 76 new projects at $4.3 billion, most of them to meet their own reliability planning criteria or NERC’s reliability standards. The dramatic jump in proposed spending led some stakeholders this year to allege Entergy was circumventing more comprehensive and cost-shared regional projects. (See Initial MTEP 23 Ignites Familiar Arguments over MISO South’s Reliability Spending.)

By comparison, MTEP 22 yielded a total $4.3 billion investment package. MISO’s first long-range transmission plan (LRTP) portfolio approved last year — considered separate from the annual MTEP planning — produced a $10 billion investment.

MISO this year tested alternative designs for 11 proposed projects that represented 40% of MTEP 23 spending. Planning staff previously said multiple MISO South reliability projects, particularly substation work, might benefit from substitute projects. (See MISO Weighs MTEP 23 Alternatives to South Reliability Projects.)

Now, MISO said it’s pursuing an alternative for the first phase of the three-part, nearly $2 billion Amite South line and substation work in Entergy Louisiana’s southern territory. MISO said its selected alternative, the 500-kV Commodore-Waterford-Churchill loop project, will tie the area’s 230- and 500-kV systems together at three points instead of two and better equip the system for future load growth in both the Amite South and Downstream of Gypsy load pockets in Louisiana. The extended 500-kV line will negate the need for another MTEP 23 project proposed by Entergy Louisiana, the 27-mile, 230-kV Downstream of Gypsy reliability project.

The project alternative is pricier than the original two projects combined, at $1.7 billion instead of the originally proposed $1.4 billion for Amite South Phase 1 and the $164 million for the Downstream of Gypsy project. The project involves building a new 500/230-kV substation; stringing a new 60-mile, 230-kV line and a new 85-mile, 500-kV line; upgrading an existing substation; and upgrading an existing nearby 230-kV line to 500 kV.

“So, we chose one project alternative to replace two proposed projects,” Manager of MISO South Expansion Planning Trevor Armstrong said during a Sept. 6 South Subregional Planning Meeting. “The alternative is more expensive, but it provided more load-serving opportunity for growth.”

Entergy expects 2 GW of new load across the Amite South load pocket soon.

MISO also said the larger project will improve system resilience when extreme events strike and will address coming generation retirements in Amite South by allowing the option to cut multiple sources into existing stations.

The project still will have a 100% local allocation to load. MISO South’s first regionally cost-shared, market efficiency project remains elusive.

Southern Renewable Energy Association’s Andy Kowalczyk asked if Entergy pitched the idea for the substitution.

Armstrong said the design was on Entergy’s list of alternative project suggestions, but it resembled a project idea MISO independently devised. He said the alternative ultimately was developed in conjunction with Entergy.

“This was the only one we felt needed to be selected in place of the original projects,” Armstrong said.

Kowalczyk asked whether MISO planners will develop load growth projections for its planning modeling. MISO was forced to perform a separate sensitivity outside of its usual modeling to test for alternatives because it doesn’t account for forward-looking load additions and generation retirements in modeling.

“I think they’re credible inputs that need to be considered. I think it’ll be a bit of a shock every year to have projects this size, and you have to perform a separate sensitivity,” Kowalczyk said. “Maybe we’re not accounting for future needs in the most cost-efficient way.”

MISO planners said they don’t have definite plans to include load growth estimates in planning modeling.

Armstrong said the majority of the South region’s MTEP 23 projects will be placed into service within the next three years.

Armstrong added that MISO still is working to develop possible alternatives to the third phase of Entergy Louisiana’s Amite South reliability project. He said MISO likely will delay project approval into 2024; MISO planners said they didn’t know whether the project will be included as a late addition to MTEP 23 or be deferred into the 2024 planning cycle.

However, MISO left standing the controversial $1.1 billion, 150-mile 500-kV line and substation project Entergy proposed for Southeast Texas. Planners said they couldn’t find a better alternative in terms of economics or reliability to the baseline reliability project consisting of a 150-mile, 500-kV line, 500-kV substation and 500-230-138-kV substation.

Entergy said the Southeast Texas project will help meet its local planning criteria, reduce dependence on aging and increasingly unavailable resources, and be useful when restoring the grid from extremes wrought by winter storms and hurricanes.

During the Planning Advisory Committee last week, MISO Director of Cost Allocation Jeremiah Doner said load growth and reliability issues are driving the need for more transmission investment.

Because of the size of this year’s MTEP, MISO will add another meeting of the System Planning Committee of the Board of Directors in mid-October to give MISO board members more time to understand the package’s contents.

Sustainable FERC Project’s Natalie McIntire asked MISO to revisit its definition of “other” projects because most of the spending is classed under the category this year. MISO’s other project category includes reliability projects based on TOs’ self-imposed criteria separate from NERC standards, projects needed for load growth and projects to address the age and condition of existing facilities. Other projects have become the lion’s share of MTEP spending since the 2018 cycle.

MISO is accepting stakeholder suggestions and considering what additional planning studies it may undertake as part of MTEP 24. However, planning staff warned that MISO is limited next year in what it can accomplish because it’s performing extensive analysis under its ongoing LRTP.

MISO will hold stakeholder workshops on the nascent, second LRTP portfolio again Dec. 1 and at the end of January.

MISO: Expedited Review Process Needs Revamp

Lastly, MISO said the MTEP 23 planning cycle has made it clear it should rethink its expedited project review process for projects that can’t wait until the usual December MTEP approval to begin construction. MISO said it fielded more than 30 expedited project review requests — double the number it received in 2022 — predominantly because of new load interconnections.

Armstrong said some expedited requests were “simple, while others have become quite complex.” He said MISO planning staff is struggling to complete on-time studies on the out-of-cycle requests. MISO likely will need to overhaul its expedited processing to make the ever-increasing analyses manageable, he said.

“We have seen some ones that cause harm to the system and require some back and forth. At this volume, it’s not sustainable,” Senior Manager of Expansion Planning Amanda Schiro added during a Sept. 8 East Subregional Planning Meeting.

Schiro told stakeholders MISO staff is discussing internally how to best modify its process and said stakeholders should expect a proposal in coming months.