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November 5, 2024

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Planners, Developers: Transmission not Keeping Pace with System Needs

ARLINGTON, Va. — Time is running out to build the infrastructure needed to meet climate challenges, transmission planners, generation developers and others warned last week.

“The things that we have done well are pretty modest. We’re not seeing steep changes,” Liza Reed, the Niskanen Center’s electricity transmission research manager for climate policy, said in one of many related discussions during Infocast’s Transmission & Interconnection Summit, held June 20-22 at the Hilton Crystal City hotel. “We’ve been talking about backbone [transmission] for decades — I mean decades. So, it’s not even new. … That conversation just really needs to mature very quickly.”

It’s inaccurate to describe the challenge of matching generation and transmission as a “chicken and egg” dilemma, said Joseph Rand, senior scientific engineering associate for the Lawrence Berkeley National Laboratory’s Electricity Markets and Policy Group. “When we look at the interconnection queues, we already have 1,400 GW — not megawatts, gigawatts — that’s ready to interconnect to our system now. … It’s not, ‘If we build it, they will come.’ They’re waiting for us to build it.”

“In the planning world, 2030 is tomorrow — and 2040 is the day after,” said Himali Parmar, vice president of energy advisory services, interconnection and transmission at ICF International.

Sarah Bresolin 2022-06-20 (RTO Insider LLC) FI.jpgSarah Bresolin, ENGIE North America | © RTO Insider LLC

“Lawrence Berkeley National Labs has this great graph that shows all the different RTOs and compares the [renewable portfolio standards]. And it shows that New York and ISO New England have the greatest need to bring renewables onto their grids and are bringing the least on,” said Sarah Bresolin, director of government and regulatory affairs and wholesale markets policy for ENGIE North America.

But it wasn’t all doom and gloom among the hundreds who attended the conference. FERC’s April Notice of Proposed Rulemaking on transmission planning and cost allocation (RM21-17) and its June 16 NOPR to unclog interconnection queues (RM22-14) won mostly positive reviews.

“We’ve talked about a lot of problems, and I wouldn’t want to leave this panel thinking that there aren’t opportunities,” said Bresolin.

Planning Models not Proactive

Jay Caspary, vice president of consultancy Grid Strategies, said FERC was right to call for proactive, scenario-based transmission planning in the April rulemaking.

“It’s going to take decades to build the grid of the future, so we need to think about what’s the resource mix going to be, and that’s above and beyond the known knowns. We know what units are going to retire in the next few years and know what generators are coming online. But the planning, the models [and] the analyses don’t reflect the commitments that have been made by utilities to get to zero carbon by 2040,” he said. “If you look at planning models now looking out five to 10 years in the future, there’s probably very little electrification in there. And don’t we all really think that electrification is coming in terms of transportation or buildings and industrial processes?

Arash Ghodsian 2022-06-20 (RTO Insider LLC) FI.jpgArash Ghodsian, EDF Renewables | © RTO Insider LLC

“We need to think strategically about what this grid needs to do … to share resources across time zones,” added Caspary, a former SPP planner. “We need a grid that’s bigger than the weather patterns and storms, so that we can move energy and capacity to keep the lights on. And we need studies where everybody’s involved in how we’re going to … decide what the right metrics are to quantify the benefits. I think that will be a big challenge for us, but I’m sure we’re up for that. I mean, we put a man on the moon.”

Arash Ghodsian, senior director of transmission and policy for EDF Renewables, said FERC should “bifurcate” transmission planning and cost allocation to prevent cost issues from short-circuiting planning.

Johnny Casana, North American strategy director for wind and solar developer Pattern Energy, said dealing with that lag in the Eastern Interconnection doesn’t compare to the challenges of the Western Interconnection.

Johnny Casana 2022-06-20 (RTO Insider LLC) FI.jpgJohnny Casana, Pattern Energy | © RTO Insider LLC

“I would rather have cost allocation be a hurdle at the end rather than at the beginning of the process,” he said. RTOs should “not let cost allocation discussions stop them from planning.”

Ghodsian also said he hopes FERC’s interconnection rulemaking will ensure the rest of the country adopts best practices, similar to those in MISO. The RTO’s interconnection rules are “three to four years ahead” of its neighbors SPP and PJM, “so there’s always going to be some sort of a lag between all three neighbors,” he said.

“There’s 38 balancing authorities in the West, and they are not integrated, certainly not for transmission planning; not for planning capacity shortfalls that are driven by extreme weather events for their entire region,” he said. “There’s some great studies that have come out in the last year or two talking about with the amount of changes that all of these different states have put on the books already and voluntary commitments that utilities have made to basically get out of coal within the next 10 or 15 years. … Without a wholesale electricity market or an RTO, you’re looking at $3 [billion] or $4 billion extra per year in [costs] … for the privilege of failing on your collective greenhouse gas reduction goals — because you can’t get there.”

Interregional Planning Lacking

Panelists also lamented the lack of interregional transmission development since Order 1000 in 2011.

Allison Clements 2022-06-20 (RTO Insider LLC) FI.jpgFERC Commissioner Allison Clements | © RTO Insider LLC

FERC Commissioner Allison Clements, who spoke to the conference June 21, said the commission plans to revisit the issue.

“I think interregional transfer capabilities is low-hanging fruit in terms of something that has widespread support; [it] certainly has support at the commission,” she said. “FERC has a role to play, because it’s just such a massive challenge. And the idea that it can get done in a ‘1,000 flowers blooming’ approach, as opposed to federally [mandated], seems hard.”

Clements said she hoped the commission’s April proposal will lead to more initiatives like MISO’s Multi-Value Projects. She also called for prudence in spending.

“If we are going to build out the type of transmission that every credible study tells us we’re going to need to do to serve customers reliably, we have to be careful about costs. If you want to build the big transmission to interconnect regions — which we need — get on board with grid-enhancing technologies; get on board with the ability of distributed energy resources to provide low-cost, flexibility to the system, because we need all of it. … Let’s ensure that [we are] taking advantage of the cheapest resources first.”

DOE Initiatives

Michelle L Manary 2022-06-20 (RTO Insider LLC) FI.jpgMichelle L. Manary, Department of Energy | © RTO Insider LLC

Speaking after Clements, Michelle L. Manary, acting deputy assistant secretary for the Department of Energy’s Energy Resilience Division, described the department’s Building a Better Grid Initiative, announced in January. (See DOE to Tackle Tx Siting, Financing, Permitting in Better Grid Initiative.)

As part of the initiative, the National Renewable Energy and Pacific Northwest National labs will help DOE identify where transmission upgrades could relieve congestion resulting from electrification and increased renewable generation.

“The whole theory here is we have a case that is blessed by the regions; this is not something the labs go and do by themselves. … It really is working with everybody to find that those strong base cases and identify those areas,” Manary said.

She also discussed DOE’s transmission facilitation program, which allows it to borrow more than $2.5 billion to create a revolving fund to purchase capacity on new transmission to reduce developers’ risks. (See DOE Seeks Input on Tx Loan, ‘Anchor Tenant’ Programs.)

“The moment that DOE signs that capacity contract, we’re looking to resell it,” she said. “What I don’t know … is do we get keep that money [from transmission sales]? We are [in] active conversations with the Treasury.”

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MISO Membership to Become More Valuable in Future

MISO expects the savings it delivers to members under a resource sharing pool to more than triple within 20 years, according to a new, forward-looking value proposition it debuted earlier this month.

The RTO said that by 2030, it will provide $4.3 billion to $5.8 billion in annual estimated benefits and $11.6 billion to $14.3 billion by 2040. The study estimates the current 11:1 benefit-to-cost ratio, based on $3.5 billion annual savings, will more than double to 26:1. (See “MISO Sees Members’ Savings Increase,” MISO Board Meets Amid RA Concerns, Emergency Alerts.)

During a Friday teleconference with stakeholders, MISO business analyst Savannah Miller said much of the benefits stem from a reduced need for additional assets because of capacity sharing and an optimized dispatch of renewable resources. She said the benefits will jump as decarbonization picks up.

MISO used a combination of its most conservative transmission planning future and the 2021 regional resource assessment, which considered its members’ decarbonization goals, for its long-term benefit analysis. (See MISO Resource Assessment: 140 GW Needed Within 20 Years.)

That data was compared against a scenario that assumed MISO had never been formed and utilities would have to meet their entire energy needs with their own generation or through bilateral contracts.  

The grid operator concluded that its long-range transmission projects will “enable a more efficient utilization of the changing generation within MISO into the future.” The RTO assumes the $10.3 billion portfolio of 345-kV projects will come online by about 2030.

Miller said MISO expects to have a “completely different” resource mix by 2040. She said while staff know the energy transition will occur with or without it, the grid operator’s services will help members more easily access a reduced carbon fleet.

Mississippi Public Service Commission consultant Nick Puga said he wondered whether MISO’s base case was realistic enough. He suggested utilities would have banded together in some fashion to better share resources had MISO never been formed.

Staff said they simply used calculations with and without MISO calculations and didn’t think it was appropriate to hypothesize on what would have happened if MISO wasn’t formed.

The value prediction on resource sharing comes at a time when MISO is telling its members to bring more energy online or risk future load shed. (See MISO Describes Bleak RA Future, Stakeholders Push Back.)

MISO has issued a string of hot weather alerts, capacity advisories and conservative operations instructions since mid-June, mostly for MISO South.

Last week, both Alliant Energy and WEC Energy Group postponed plans to retire three coal-fired resources in Wisconsin by at least 18 months, citing tight supply in MISO Midwest. However, Consumers Energy’s new integrated resource plan approved will accelerate the retirement of its J.H. Campbell coal plant in western Michigan to 2025, 15 years earlier than originally planned.

The grid operator’s new market system, expected to be in service by late 2024, will house more nuanced types of wholesale market participation that better accommodate distributed and intermittent resources.

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ERCOT Board of Directors Briefs: June 21, 2022

[EDITOR’S NOTE: A previous of this version of this story incorrectly reported that NPRR1110 had increased the black start servicer procurement period from two to four years. The procurement period was actually increased to only three years. (See “Board Clears NPRRs” below.]

Maintenance Outage Scheduling Methodology Approved

AUSTIN, Texas — ERCOT’s Board of Directors last week took up two contentious issues between staff and stakeholders, resolving one and setting the other aside for the time being.

The board sided with ERCOT in approving staff’s proposed methodology for approving and denying planned generation maintenance outages, granting its appeal of a nodal protocol revision request (NPRR1108) that stakeholders passed in April. (See ERCOT Board of Directors Briefs: April 28, 2022.)

Staff said the rule change gives them much needed capacity and flexibility for planned outages while maintaining reliability. Stakeholders countered that the calculation limits outages when compared to history and that its assumed 10% growth rate for renewable resources is too low.

The Technical Advisory Committee “and staff are at loggerheads,” TAC Chair Clif Lange told the board. “We just wanted to raise these issues as areas we need to be looking at.”

The ERCOT methodology includes a maximum daily resource planned outage capacity (MDRPOC) calculation that sets the planned outages that should be allowed on each day of the next 60 months. Staff will review the methodology at least annually and work with stakeholders to make any necessary adjustments in allowing resources to schedule their maintenance outages. Any changes to the methodology will need board approval.

“We are providing a significant amount of outage availability,” interim CEO Brad Jones said. “We’re asking for some of [the outages] to be moved around. We’re trying to ensure not everyone takes these outages in October and late April.

Woody Rickerson, vice president of system planning and weatherization, told the board that the calculation’s installed inverter-based capacity is based on a 10th percentile score that allows room for growth.

“Ninety percent of the time, it’ll be higher in the future,” he said. “If we need more in the MDRPOC, we can change that. We’ve got some degrees of freedom that we can use in the future.”

Rickerson said staff conducted a backcast of the calculation against 2022 to determine whether they would have had to adjust the outage schedule. That would have happened three of four times, he said.

“That’s a pretty good number. We think we have this dialed in at the right amount,” Rickerson said.

The board again tabled NPRR1112, which would lower counterparties’ unsecured credit limit from $50 million to $30 million, over uncertainty of some of ERCOT’s numbers.

Jones said staff had “reason to believe” the numbers included some inaccuracies.

“We want to get them right and get them back to the board,” he said.

At issue is the amount of outstanding unsecured credit, currently $1.4 billion, that would be eliminated with the $30 million cap. Staff said dropping the cap would reduce the total to $400 million, but they could not definitively respond to Garland Power & Light’s Darrell Cline, speaking for TAC, when he said the reduction itself would be less than $400 million.

TAC will revisit the issue during its regular monthly meeting on Monday.

The directors agreed to again take up the measure during its August meeting. Should it pass the board then, it will become effective four months after Texas Public Utility Commission approval.

ERCOT last year proposed eliminating unsecured credit, but stakeholders countered with a revision request that would lower the limit to $30 million. After TAC approved the measure in April, ERCOT appealed the decision to the board, which tabled the measure later that month and requested information on other grid operators’ unsecured credit practices. (See “ERCOT’s Credit Limits Align with Others,” ERCOT Technical Advisory Committee Briefs: May 25, 2022.)

Staff found that all other ISOs and RTOs offer unsecured credit, limited to no more than $50 million per counterparty, and with no aggregate caps on the amount of outstanding credit. The grid operators’ total unsecured credit ranges from $100 million to $1.75 billion.

IMM: Out-of-market Actions Costly

Carrie Bivens, ERCOT’s Independent Market Monitor, clarified that the grid operator’s conservative operational posture this year has resulted in $216 million to $391 million in additional costs through its out-of-market actions.

Most of those costs come from the increased use of non-spin procurement and its effect on ancillary services prices in setting aside 6.5 GW in operating reserves each day. Increased reliability unit commitment (RUC) dispatch has only resulted in about $6 million in additional market costs, Bivens said.

The more frequent use of RUCs has added about $460 million year to date to the reliability deployment price adder. The adder is an indicator of the out-of-market actions’ impact on market outcomes and counters RUCs’ suppressive effects on energy prices, Bivens told RTO Insider.

She said the operating reserve demand curve (ORDC) has yielded about $900 million in market costs this year. The ORDC helps set prices in shortage or near-shortage conditions, the key to price formation in an energy-only market design, Bivens said.

The PUC last year lowered the ORDC’s clearing price from $9,000/MWh to $5,000/MWh and raised its minimum contingency level from 2,000 MW to 3,000 MW. The Monitor estimated shifting the curve has added about $476 million in energy costs by causing prices to rise more quickly at low shortage levels.

Bivens acknowledged to the Texas House of Representatives’ State Affairs Committee two days after the board meeting that most of those costs are passed on to consumers.

The PUC made the changes after market prices were stuck at the $9,000 cap for four days during the February 2021 winter storm.

In its annual State of the Market report released last month, the Monitor said ERCOT’s conservative operations approach runs counter to the energy-only market’s design. It said pricing outcomes have become “disconnected” from actual operational conditions in a market where high scarcity prices are designed to incent future investment in lieu of capacity revenues. (See IMM: ERCOT Conservative Operations ‘Not Compatible’ with Energy-Only Market.)

10 GW Thermals Could Retire with EPA Rule

Staff told the directors that its preliminary analysis of a federal rule limiting nitrogen oxide emissions assumed that over 10 GW of installed thermal generation would leave the market by 2026, requiring up to $1.5 billion to resolve local reliability issues.

The study assumed 10.8 GW of thermal generation, including 8.2 GW of aging coal-fired generation without scrubbers, would be retired. It added 20 GW of new generation, with only 4% representing thermal resources.

Rickerson said a steady-state transmission analysis showed the system would need $1.2 billion to $1.5 billion to “plug the holes left by the retirements.” He said an additional $2.7 billion to $5.2 billion could be needed to improve ERCOT’s regional transfer capability without the affected generation and that the probability of load shed in 2026 increases almost nine times when solar generation becomes unavailable.

Under EPA’s Cross-State Air Pollution Rule (CSAPR) federal implementation plan, NOx emissions budgets will be established for Texas and 25 other states, beginning with the 2023 ozone season (May 1-Sept. 30). The agency says the reductions are necessary to address upwind states’ interstate transport obligations.

Asked whether anyone would invest money in thermal plants that date back as far back as 1958, Rickerson said, “There’s a chance that could happen.” He said staff have been told that some plants simply don’t have the room for emissions-reduction equipment.

Public Utility Commission Chair Peter Lake said generation owners could face spending $200 million to keep 50-year-old plants in compliance. “So that’s pretty easy [as a decision],” he said.

The PUC, ERCOT and Texas’ environmental agency will all submit comments on EPA’s implementation plan, joining other grid operators and states in doing so. There were nearly 600 comments as of Friday afternoon.

Aguilar Resigns from Texas Central

Director Carlos Aguilar was a no-show for the board meeting, his first since resigning as CEO of Texas Central, the organization behind a proposed bullet train between Dallas and Houston.

Aguilar announced his resignation with a June 11 post on LinkedIn. He cited recent “news reports in the international press” for the announcement’s timing. Aguilar joined Texas Central as CEO in 2016.

The Federal Railroad Administration in 2020 approved plans for the 240-mile railroad. On Friday, the state’s Supreme Court ruled that Texas Central, which has affirmed its status as an operating company with the court, can use eminent domain to acquire land.

“Texas and the U.S. deserve the best transportation options, and I am convinced that in time, these will become a reality. We can do this,” Aguilar said in his post.

Board Clears NPRRs

The committee unanimously approved six NPRRs and a change to the planning guide (PGRR):

      • NPRR1100: clarifies that a generator or energy storage resource (ESR) may serve customer load when the customer and the resource are both disconnected from the system because of a transmission or distribution outage. The change is limited to configurations where the resource and customer load are using privately owned transmission and distribution infrastructure during a private microgrid island operation.
      • NPRR1110: modifies the black start service (BSS) confidential information, contract period and backup fuel requirements; increases the BSS procurement period from two to three years; and adds an on-site, 72-hour priority fuel requirement that can be waived in whole or in part to procure a sufficient number or preferred combination of resources.
      • NPRR1119: deletes extraneous language that should have been removed as part of NPRR978.
      • NPRR1121: automates the market notice used in the exceptional fuel cost submission process to notify market participants when the costs have been submitted for the operating day.
      • NPRR1129: allows ERCOT to post on its website a list of electric service identifiers for transmission-voltage customer opt-outs from the securitization of $2.1 billion for load-serving entities’ extraordinary costs incurred during the February 2021 winter storm.
      • NPRR1130: extends the sunset date for weatherization inspection fees from Sept. 1, 2022, to July 31, 2023.
      • PGRR100: revises the annual planning model base case update frequency from triannual to biannual, aligning it with the Steady State Working Group’s plan to adjust its current case-building schedule to a biannual basis.
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Christie Talks up Flexibility of Transmission NOPR

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ROCKPORT, Maine — FERC’s Notice of Proposed Rulemaking on transmission planning is narrowly focused on projects driven by public policy and emphasizes flexibility for states, Commissioner Mark Christie told the NEPOOL Participants Committee at its summer meeting in Maine last week.

Those factors made him enthusiastic about the proposal, which he called a “product of compromise” among members of the commission that has “creativity and flexibility absolutely written in.”

Released in April, the NOPR would direct transmission providers to revise their planning processes to identify infrastructure needs on a long-term, forward-looking basis and propose a list of benefits on which they would base their selections of proposed projects to meet those needs. (See FERC Issues 1st Proposal out of Transmission Proceeding.)

“This particular, specific category … of public policy-driven projects are being driven largely by state policies. So state regulators should be at the forefront of deciding what should be the criteria for these projects, the benefits that get used in evaluation” and the cost allocation, Christie said. “I don’t know as much as you do about what goes on in Massachusetts, Maine or Vermont.”

That’s not to argue that FERC shouldn’t play a role in transmission planning, Christie said.

“We have a duty. I’m not saying that FERC doesn’t have a role. But I think when we get into something like planning for public policy projects … that we ought to defer and be respectful of what you all know more than we do.”

The proposal’s flexibility expands to cost allocation within RTOs, he said.

“That flexibility is there for large RTOs … to have cost allocation that can be granular enough to meet the needs not only of different RTOs, but different subsections within RTOs.”

Christie also emphasized that the proposed rulemaking is light on mandates, with only a long-term planning process required.

“Yes, there’s a lot of stuff listed in there,” he said. “But it’s not mandated. If the states say, ‘Thank you very much, FERC, but we don’t want to use these,’ the states can do that.”

Other PC Actions

In addition to hearing from ISO-NE and state leaders, the Participants Committee approved:

  • tariff revisions recommended by the Markets Committee to allow storage resources that inject energy into the grid but do not receive energy from it to register and operate as a continuous storage facility;
  • changes to tariff Schedules 22 (Standard Large Generator Interconnection Procedures), 23 (Standard Small Generator Interconnection Procedures) and 25 (Standard Elective Transmission Upgrade Interconnection Procedures) to identify that all new distribution-connected generation should proceed through the state interconnection process, as recommended by the Transmission Committee;
  • changes to Schedule 18 (Standard Large Generator Interconnection Procedures) and the incorporation of a new Attachment Q in response to FERC Order 881’s directive to incorporate the use of ambient-adjusted ratings for transmission lines, as recommended by the TC;
  • changes to Operating Procedure No. 22 (Disturbance Monitoring Requirements), including general updates, the listing of an additional facility in confidential Appendices A and B, and the addition of Appendix C (New England PMU Registration), as recommended by the Reliability Committee; and
  • changes to section 3.2 of tariff Attachment D to meet mandatory cybersecurity reporting requirements and section I.2.2 to modify confidentiality restrictions when the RTO is reporting cybersecurity incidents and events to certain federal agencies, as recommended by the MC.
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SERC Board of Directors Briefs: June 23, 2022

Summer Assessment Shows Challenges Ahead

CHARLOTTE, N.C. — Entities in the footprint of SERC Reliability can expect the 2022 summer season to bring continued challenges, attendees heard at Thursday’s open meeting of the organization’s Board of Directors.

Presenting SERC’s recently published 2022 Regional Summer Assessment, Melinda Montgomery, the regional entity’s senior director of engineering and advanced analytics, observed that elevated temperatures are expected across nearly all of the continental U.S. According to the National Oceanic and Atmospheric Administration’s (NOAA) projections issued in May, most of SERC’s footprint have a 40 to 50% chance of higher-than-normal temperatures in June through August.

“Back in May, I was really surprised to see the level of hot weather that we were already experiencing,” Montgomery said. “And it wasn’t just in isolated areas; it [was] over large sections of the Southeast, and actually across the country.”

Despite the elevated temperatures, SERC’s assessment shows that most of the region is likely to meet the season’s expected summer peak demands without resorting to emergency resources, non-firm energy imports and demand-side management. By comparison, NERC’s Summer Reliability Assessment, released last month, showed an elevated or high risk of energy emergencies across the Western Interconnection, Texas and much of the Midwest. (See West, Texas, Midwest at Risk of Summer Shortfalls, NERC Says.)

Summer Resource Reliability Outlook Map (SERC) Content.jpgSERC’s 2022 Summer Resource Reliability Outlook shows most of the Southeast at low risk of resource shortfalls, except for the SERC MISO Central subregion, which may need to turn to emergency resources, non-firm energy imports, or demand side management to maintain reliability. | SERC

The one exception to this forecast is the MISO Central subregion, comprising parts of Illinois, Iowa, Missouri and Kentucky. SERC predicts that the subregion could lack sufficient resources to meet peak demand on its own under normal conditions and could have to rely on emergency measures in the case of higher-than-expected generation outages, high loads or other extreme scenarios.

While NERC’s assessment warned that ongoing droughts could lead to generation shortfalls in the Western Interconnection, Montgomery said this is not likely to be an issue in the Southeast; according to NOAA, the region has either a 50% or higher likelihood of greater-than-average precipitation this summer. The greater danger is from hurricanes: Colorado State University’s hurricane forecast, updated earlier this month, predicts the third above-average hurricane season in a row, with 20 named storms, all of which are expected to be hurricanes.

SERC CEO Jason Blake called the assessment “daunting” and said the RE is working to “really lean in and help make sure that we are … putting [utilities] in the best possible position.”

“You’re hearing already [that] we’re hitting peak demands in June,” Blake said. “So that’s something that is sobering, and something that we need to be very mindful of.”

Budget Approved with Merit Pay Adjustment

Jason Blake 2022-06-23 (RTO Insider LLC) FI.jpgSERC CEO Jason Blake | © RTO Insider LLC

Board members voted to approve SERC’s final business plan and budget for 2023. NERC will now submit the document, along with the business plans and budgets for the rest of the ERO Enterprise, to FERC for approval, which is expected by October.

SERC’s total expenses are expected to rise to $28.2 million next year, according to the final budget, slightly higher than the draft approved at the previous board meeting in March. (See “2023 Business Plan and Budget,” SERC Board of Directors/Members Briefs: March 30, 2022.) CFO George Krogstie explained that the difference was because the RE’s Finance and Audit Committee decided to expand the planned 3% increase to the market adjustment category — which governs spending on merit-based raises and promotions — by another 1.5%, in light of the high demand for cybersecurity personnel pushing up salaries for these positions.

The board approved this increase in advance at the March meeting as well. After SERC’s draft budget was approved by the board, it was submitted to NERC and posted for a 30-day stakeholder comment period. No comments were received, leading SERC’s FAC to accept the budget at its meeting on Wednesday with no changes.

New Members Accepted

As part of the consent agenda, the board agreed to accept four utilities as new members:

      • BayWa r.e. Operation Services: performs generator owner and generator operator functions for its sister company, Fern Solar, in North Carolina;
      • Capital Power: owns and operates the Cardinal Point wind facility in Illinois and the Decatur Energy Center in Alabama;
      • Silicon Ranch: owns solar farms across the U.S., including seven states in the SERC footprint; and
      • WestRock: owns and operates Green Power Solutions, a biomass power plant in Dublin, Ga.

All four new members will join SERC’s Merchant Electricity Generating Sector and participate in the RE’s Generator Working Group.

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NYISO Business Issues Committee Briefs: June 22, 2022

Constraint Specific Tx Shortage Pricing

NYISO’s Business Issues Committee on Wednesday recommended that the Management Committee approve a pricing proposal for multiple active transmission constraints (MATCs).

Enhancements to the current transmission constraint pricing logic will enable NYISO’s market software to re-dispatch suppliers efficiently in the short term to alleviate constraints, as well as incentivize long-term investment in locations where suppliers could provide the greatest benefits, said Kanchan Upadhyay, energy market design specialist with the ISO.

MATCs can occur for two main reasons, either from topology or from the evaluation of contingencies on the same facility. MATCs arising because of topology, also referred to as “lines in series/lines in parallel,” show the same transmission line represented as multiple segments in the network topology (long radial lines) or parallel line segments. Transmission facilities that are constrained in multiple scenarios (base case and contingency case scenarios) being evaluated are referred to as “MATCs on the same facility.”

NYISO is proposing to develop functionality in the market software to identify redundant constraints across in-series and parallel transmission facilities, the most limiting of which would be binding and utilized for pricing purposes in application of the transmission demand curve mechanism (TDC). The remaining of such redundant transmission constraints would be non-binding and not utilized for pricing purposes in the application of the TDC.

The proposed solution seeks to provide better alignment between the use of physical resources versus the TDC in solving transmission constraints. It also aligns with the operational philosophy that relieving the worst/most limiting constraint across a transmission facility would generally alleviate other transmission constraints across the facility.

If prioritized for 2023, implementation would be contingent on approval by the NYISO Board of Directors and acceptance by FERC.

Critical Infrastructure Load

The BIC also approved a proposal to restrict participation of certain types of demand response in ISO-administered programs in order to protect critical electric system infrastructure load. The limitations were proposed to comply with NERC’s October 6, 2021, Standard Authorization Request to address extreme cold weather grid operations, preparedness and coordination.

Standard Recommendation No. 8 says, “Balancing Authorities’ operating plans (for contingency reserves and to mitigate capacity and energy emergencies) are to prohibit use of critical natural gas infrastructure loads for demand response.”

The proposed tariff revision will address Standard Recommendation No. 8 as it relates to the NYISO demand response programs, said Francesco Biancardi, market design specialist for new resource integration.

The ISO is targeting July 2022 to file the applicable tariff language with FERC for implementation on Nov. 1, the first day of 2022-23 Winter Capability Period.

Bad Debt Loss Methodology

The BIC also recommended that the Management Committee approve a proposal from DC Energy to change the ‘look back’ period used in determining allocations to each participant to recover bad debt losses and payment defaults, expanding the period to three months.

Bruce Bleiweis, director of market affairs for DC Energy, presented the change and said the company believes the goal of the payment default and bad debt loss allocation methodology is to spread the loss fairly based on NYISO stakeholders’ overall billing determinants.

Market participants’ billing activity is not consistent within a month nor throughout the year, and this creates peaks and valleys for participants as a percent of total, whereas the new methodology “will smooth out the peaks and valleys” and represent an average obligation, he said.

The current methodology calculated each participant’s obligation “in the Billing Period in which the payment obligation that resulted in the loss occurred’ — DC Energy is bringing the same motion to MISO because they have a similar clause in their tariff, Bleiweis said.

One stakeholder asked whether NYISO supported the proposal or had any comment.

“We are indifferent to that timeframe,” said Sheri Prevratil, NYISO manager of corporate credit.

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MISO Warming to Patton’s Sloped Demand Curve

MISO Independent Market Monitor David Patton has been calling for a sloped demand curve in the RTO’s capacity market for what seems like forever.

The Potomac Economics president includes it as a recommendation in his annual State of the Market report for MISO every year; he even asked FERC to order the RTO to implement it in 2018. Nevertheless, MISO still has a vertical curve.

This year is a bit different, however. MISO is facing a 1.2-GW capacity shortfall in its Midwest region, and it is driven in part by inefficiently low prices “contributing to a sustained trend of retirements of resources that would have been economic to remain in operation,” according to this year’s report, presented by Patton to the MISO Board of Directors’ Markets Committee on Wednesday.

MISO’s current demand “curve” — a straight vertical line at the minimum capacity requirement — represents the fact that the RTO does not pay extra for surplus capacity, only increasing prices when there is a deficiency in a zone.

“The implication of a vertical demand curve is that the last megawatt of capacity needed to satisfy the minimum requirement has a value equal to the deficiency price, while the first megawatt of surplus has no value,” the report says. “Since prices will be set where the supply offers intersect with the demand curve, a vertical demand curve will almost always set the price close to zero when the market has even a small surplus of capacity.”

Or, as Patton told the committee, “When we impose a vertical demand curve, we’re basically saying, ‘We see no reliability value for any megawatts above the minimum requirement.’ That’s obviously not true.”

The clearing price for seven of MISO’s 10 capacity zones in the 2022/23 Planning Resource Auction (PRA) in April was the cost of new entry (CONE) of $236.66/MW-day, while the other three zones, in MISO South, cleared at $2.88. (See MISO’s 2022/23 Capacity Auction Lays Bare Shortfalls in Midwest.) That marked a huge spike from the prices in the previous auction, which ranged from 1 cent in MISO South to $5 in the rest of the footprint. (See MISO Capacity Auction Values South Capacity at a Penny.) The jump signals an urgent need for additional capacity, especially in the northern zones.

With Patton’s sloped, or “reliability-based,” curve, prices are capped until the minimum requirement is fulfilled, and each subsequent megawatt is priced at a diminishing rate. Had it been used in the 2021/22 auction, prices would have ranged from $13 in MISO South to $150 in MISO Midwest. “Although this remains well below the cost of new entry of roughly $250/MW-day, this price would ensure existing resources that were needed to maintain reliability would remain in operation,” the report says.

MISO Response

Patton’s presentation on the curve received favorable responses from MISO officials and directors.

“I really think this is what we need to do,” CEO John Bear said. He argued, however, that generator retirements are not being driven by economics but by environmental policies. “So even if we fix this, we may have some troubles.”

Patton agreed that a different curve would not “magically solve the problem overnight.” But he countered that retirements purely for environmental reasons are rare.

“Sometimes there is an interplay because there can be an environmental requirement that comes out that requires a resource owner to spend money to comply … and that would be embedded in the going-forward costs,” he said. “That may be one of the reasons why the going-forward cost is as high as it is.

“But when a market doesn’t provide the revenues to cover those sorts of costs, then the unit retires, and it may look like an environmental retirement, but had we provided the revenue, some of these units would not have retired.”

Patton also said that “this isn’t entirely a MISO issue. I view this as also being a FERC issue. I don’t know how FERC looks at the actual prices there and finds them to be just and reasonable, because they don’t serve the basic purpose of why you have a capacity market in the first place.”

Director H.B. “Trip” Doggett, chair of the committee, noted that he has “asked MISO to attempt to arrange some training for us later this year … and one of [the] topics would be the sloped demand curve so that we can fully understand it.”

Short vs. Long Term

The report says that as long as the footprint does not experience above-normal heat this summer — a big “if” given the high temperatures already this month — MISO’s resources should be adequate. Though retiring units did not offer into the auction, they will still be operational for at least this summer, and the RTO is able to import power into practically any region of its footprint. And despite the shortfall in the auction, it saw a 200-MW net increase in capacity last year, with a 1-GW gas-fired plant coming online in MISO South and nearly 2 GW of wind resources across the footprint.

“In the long term, however, we are very concerned about MISO’s resource adequacy given the relatively low net revenues generated by MISO’s capacity market,” the report says.

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FERC Investigating ISO-NE over Gas Plant’s Alleged Capacity Market Fraud

FERC is investigating ISO-NE’s role in alleged fraud by a project developer taking part in the RTO’s capacity market, the grid operator disclosed Thursday.

The existence of the investigation was first revealed in a bankruptcy filing by Salem Harbor Power Development, the company behind a natural gas plant north of Boston in Salem, Mass. The company filed for Chapter 11 bankruptcy in March after being ordered to pay $236 million to Iberdrola, its partner on the project, according to Reuters.

According to the filing, dated April 20, FERC’s Office of Enforcement started its investigation in 2017 and released preliminary findings in 2020. Those findings alleged that Salem Harbor violated FERC and ISO-NE rules by failing to provide “accurate and complete critical path schedule updates” to the grid operator.

FERC also alleged that the project’s developers “engaged in a fraudulent scheme to deceive ISO-NE and the market into believing that the facility would meet the” 2017 commercial operation date and to collect capacity payments regardless of the project’s delays.

The company has denied the allegations and is in talks with FERC over a potential settlement, according to the filing.

But potentially more significant is that ISO-NE itself is under investigation for failing to figure out that the project would be delayed, allegedly giving the developer advice to help it skirt the consequences of failing to meet its COD and not forcing it to sell its capacity supply obligation (CSO).

Neither FERC nor ISO-NE provided further details about the alleged violations, but in a statement Thursday, the RTO said it denies them.

It also pointed to changes it made in response to the incident, including an automatic financial penalty for projects in the capacity market that are under development and miss their deadlines.

“The penalty serves as an enhanced incentive for project sponsors to meet their commercial operation date and eliminates the need for ISO New England to assess the veracity of the information submitted to it by project sponsors,” the grid operator said.

ISO-NE said it’s cooperating in the investigation and has asked FERC to dismiss the enforcement case against it.

FERC declined RTO Insider’s request for comment, citing its policy to not comment on ongoing investigations.

Stakeholders in NEPOOL have over the last few months been debating changes to the region’s financial assurance rules, with the goal of handing out harsher penalties to companies that are behind on development milestones. (See NEPOOL Participants Committee Briefs: May 5, 2022.)

That effort took on extra significance because of the controversy around a different natural gas plant, Killingly Energy Center in Connecticut, which had its CSO pulled by the grid operator because of its failure to meet milestones and stay on track for its COD.

The results of this year’s capacity auction were significantly delayed while ISO-NE waited for FERC and the D.C. Circuit Court of Appeals to settle the matter. (See ISO-NE Announces Capacity Auction Results After Killingly Delay.)

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California PUC Approves PG&E Regionalization Plan

The California Public Utilities Commission on Thursday approved a proposal by Pacific Gas and Electric to divide its operations into five large service areas, a move that regulators hope will bolster safety and local responsiveness in the problem-plagued utility.

The CPUC made the regionalization effort a condition of its approval of PG&E’s bankruptcy plan in May 2020, following years of devastating wildfires. (See CPUC Approves PG&E Bankruptcy Plan.)

“The CPUC’s bankruptcy decision required regional restructuring so that PG&E would be more present in the community and better able to serve the diverse values and needs of its customers,” Commissioner Clifford Rechtschaffen said a statement following Thursday’s decision. “Regionalization is one of the many ways we are looking to see if PG&E has transformed itself into a safer, more reliable and more customer serving utility since emerging from bankruptcy two years ago.”

Since then, the company has held stakeholder meetings in the five regions to solicit input and report back to the CPUC. It also reached a multiparty settlement on the plan with the California Farm Bureau Federation, the California Large Energy Consumers Association and the Coalition of California Utility Employees, among others.

Commissioners accepted the settlement as part of the proposed decision approved Thursday.

“PG&E asserts its proposal would help the company refocus on core operations, safety, its customers and frontline employees,” the decision said. “PG&E asserts regionalization will also enhance its ability to meet its safety obligations.”

The company emerged from bankruptcy after paying billions of dollars to fire victims and insurers and pleading guilty to 84 counts of involuntary manslaughter in the November 2018 Camp Fire, which destroyed the town of Paradise and led PG&E to file for Chapter 11 reorganization in January 2019. (See PG&E Sentenced; Bankruptcy Plan Approved.)

Catastrophic fires blamed on PG&E equipment also occurred in 2015, 2017, 2019, 2020 and 2021, killing more than 100 people and leveling thousands of homes.

During a conference call in February 2021, then-new PG&E CEO Patti Poppe promised the utility would deliver a “regionalized hometown experience for the communities and customers we serve” by establishing a number of semiautonomous management units around the state.

PG&E’s territory will be divided into five regions: North Coast, North Valley/Sierra, Bay Area, South Bay/Central Coast and Central Valley. Regional executive officers will manage each region and report directly to Poppe. Each region will also have its own risk officer and safety officer.

A regionalization stakeholder group will monitor PG&E’s progress in implementing the plan and report to the CPUC.

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SEEM’s Sellers Pushes Reliability, Continuity to SERC Board

CHARLOTTE, N.C. — A spokesman for the Southeast Energy Exchange Market (SEEM) told SERC Reliability’s Board of Directors Thursday that the market poses no challenges to the regional entity’s work on grid reliability.

“For everybody here in the room, responsibilities are not changing. Everybody still has the same reliability responsibilities,” said Corey Sellers, general manager of transmission policy and services at Southern Company, one of SEEM’s founding utilities. “Because we’re not doing a centralized dispatch, all of those … remain as they do today.”

SEEM is slated to enter operation later this year, after receiving FERC’s de facto approval last October (ER21-1111, et al.). (See SEEM to Move Ahead, Minus FERC Approval.) Currently the market includes 16 participants across 11 Southeastern states and nine balancing authorities, with more than 160 GW of collective capacity.

Many industry stakeholders continue to express skepticism about the ability of the new market to meet its claims of reducing friction in bilateral trading and spurring the integration of renewable energy better than alternatives such as  an RTO or energy imbalance market, debates that Sellers has participated in before. (See GCPA Panelists Go One on One Over SEEM Proposal.) In his presentation Thursday, Sellers focused on the image of SEEM as an enhancement, rather than a disruption, to the current market.

Corey Sellers 2022-06-23 (RTO Insider LLC) FI.jpgCorey Sellers, Southern Company | © RTO Insider LLC

“As we entered into this, we kind of went in with two key principles,” Sellers said. “One, let’s try to keep this simple, and build it upon the bilateral market that we’re already operating in the Southeast. And let’s try to get the most benefit for the least cost.”

Continuity was a constant theme in Sellers’ talk, as he sought to assuage SERC’s potential concerns by assuring attendees that “each balancing authority will continue to operate as it operates today” under SEEM. He portrayed the market as an attempt to smooth the business of electricity trading and allow greater use of the region’s wide array of resources.

“It’s really about scale and diversity … There’s time zone diversity, there’s definitely weather diversity, generation, load, all of those things are very helpful when you think about operating the system,” Sellers said. “That was a key component when we put this together … looking at that diversity, [and] at the diversity of resources, in particular around renewables. We have a lot of solar coming online … all across the Southeast.”

SERC’s board includes several representatives of SEEM utilities, who were asked by independent director Shirley Bloomfield to chime in with their thoughts on why their companies signed on to support the new market. The first to speak was Roger Clark of Associated Electric Cooperative; most of the following speakers said he expressed their views better than they could. Clark said the main attraction was the expansion of trading from hourly increments into 15-minute intervals, allowing more responsive scheduling.

“It was a low-cost project; it’s voluntary. We’re optimistic that something will come out of it, but we don’t have a lot of skin in the game,” Clark said. “As a BA, you lay in [resources] the best you can, but that’s what you’ve got, until you get to your next hour. … If I’ve got excess wind that we can put on and sell, [or] there’s excess solar, it’s that intra-hour variability that we’re hoping to get some efficiency out of.”