‘Grid Transformation Day’ Highlights ISO-NE Challenges

WESTBOROUGH, Mass. — More than 150 people attended ISO-NE’s first-ever Grid Transformation Day last week to hear about the speed of the change overtaking the power industry — and the breadth of resources needed to accommodate it.

Here’s some of what we heard.

Dealing with Outdated Data

Stephen Rourke, ISO-NE vice president for system planning, said the industry is changing so fast that some of the RTO’s statistics for last month are already significantly misleading.

One example: The figure of 1,381 MW of battery storage in the interconnection queue as of April 1 is already out of date, with the number now topping 2,500 MW.

Information is still key, he said about the RTO’s response to growth of distributed energy resources.

“So every night at around 10 or 10:30, we get five-minute snapshot data from 10,000 different solar sites around the region,” Rourke said. “Thanks to working with the utilities and the states, we have actually mapped every single solar panel in New England to the town or city that it’s in.”

However, getting that data in real time would significantly increase costs, “so we have not gone down that path yet,” he said.

Steve Widergren, principal engineer at Pacific Northwest National Laboratory, said that our modern, data-driven society requires a much more flexible and resilient transmission system, which must transition to meet the challenges of changing demand characteristics, he said.

“We’re asking the grid to do a lot more than it was originally designed to do, which I think has been the mantra for electricity through its entire life,” he said. “We have already seen what extreme weather events are doing and can do, so the mission is how to mitigate the damage and recover quickly. The grid is increasingly a critical national asset.”

The policy environment is changing as “corporates and municipalities are demanding more clean energy, and this clean energy operates in a different way from traditional power plants, so that’s a challenge for the system,” said Janet Gail Besser, managing director of regulatory innovation at the Smart Electric Power Alliance.

She listed various legislative initiatives around the region, including a bill on solar siting in Rhode Island (House Bill 5789).

“As we see more of these resources, we see more of the challenges in siting even distributed energy resources, and that’s not going to go away,” Besser said.

Technical Challenges

Aidan Tuohy, principal project manager at the Electric Power Research Institute (EPRI), spoke of the challenges of integrating DER into grid operations, such as ramping to compensate for both short- and long-term intermittency of wind and solar.

In his native Ireland, for example, the grid operator is “buying 14 different kinds of ancillary services to deal with all this,” Tuohy said.

Hosting capacity — the volume of DERs that the distribution system can handle at a given time and place — is important from a bulk services perspective and comes up when trying to get distributed battery storage to provide some service that can’t actually be accessed because the system is starting to hit some limit, Tuohy said.

“EPRI has been exploring the use of technologies to better understand where and how much DERs you can put on your system so that you can then plan around that … and flag where upgrades are needed,” he said.

Barry Mather, manager for integrated devices and systems at the National Renewable Energy Laboratory, said grid operators have “a lot of tools in the toolbox” and that the large number of options is in itself a challenge.

In sharing NREL research on the Hawaii grid, Mather said it is “a very interesting system with lots of PV; mostly distributed, not transmission-scale,” which results in steady-state over-voltage issues.

What smart inverter function should actually be used?

“Obviously, frequency ride-through is a big deal on an island system such as in Maui, where you have relatively large frequency transience, just because the system is not very large,” Mather said. “But even [with] things like the volt/[volt-ampere reactive] settings [on inverters], how specific do you need to be?”

“Another important step in this planning matrix is to understand where you are going to go, because these DER assets, even though they’re small systems … are designed relative to a utility-scale lifetime, maybe 25 or 30 years,” Mather said.

The smart inverter setting you set today may not be the same setting that will be needed when DERs reach their ultimate penetration level, he said.

“The biggest game-changer is demand response,” said Debra Lew, senior technical director at GE Energy Consulting. “I can’t convey to you the importance of this … think of it as demand response on steroids. This is going to be way bigger than what you think of today because, first of all, we’re electrifying all these new loads,” from transportation to space heating to water heating and cooling.

“These loads are inherently flexible; we can extract a lot of flexibility out of them, so a significant amount of our demand in the future is going to be price-responsive or controllable,” Lew said. “This demand is going to compete directly with storage, and that’s something to think about as you make investments for the future.”

Lew said she participated in a meeting the previous week in which a Californian said their state currently had a half-million electric vehicles and plans for 7 million.

“We did a back-of-the-envelope for 7 million electric vehicles: 420 GWh of storage. That’s huge,” Lew said. “Even if you can access only a tiny bit of that, that’s a huge amount of storage.”

Utility Perspective

“Vermont is the Hawaii of the East, but our mountains don’t blow off their tops,” said Chris Root, COO of Vermont Electric Co.

Vermont is leading the way in New England in terms of overall renewable energy on its system, but because of the intermittent nature of wind and solar, its grid is increasingly weather-dependent as more renewables come on, Root said.

For example, he said the load in the middle of an overcast day is 2.5 times that of a sunny day, and that when snow covers a solar panel, its energy production drops to zero — which drew the comment that Hawaii probably had the edge in weather.

“I do believe storage is going to be critical in the future, because we have loads that change, we have generation that changes, and the only thing that’s going to be able to equate that is going to have to be storage,” Root said.

He said Vermont utility Green Mountain Power has installed 1,900 Tesla Power Walls and “can’t install them fast enough.” He noted the state has two utility-scale energy storage facilities of 4 MW and 1 MW — but he likes to remind people that storage is not an energy source.

“You have to put energy in; then you can take it out.

“Sometimes when policy gets way ahead of engineering, that can be a little scary,” Root said. “We’re still solving the problems that are happening today, so it gets a little scary when you’re trying to play catch-up from an engineering perspective.”

National Grid has seen its average solar interconnection request in Massachusetts triple in size over the last few years and double in Rhode Island, said Brian Gemmell, the company’s vice president for asset management and planning.

“For those that know the transmission system well, there’s a lot of ripple effect with getting all these megawatts. … We don’t have a lot of transmission in central and western Massachusetts and, indeed, some of the areas in Rhode Island,” Gemmell said. “We’re grappling with a dramatic uptick in [distributed generation].”

“It’s a given that we’re going to need innovation … but the biggest thing we’ll need is collaboration,” said Vandan Divatia, Eversource Energy’s director of ISO-NE policy and interconnections. “We have a role in every sector of the grid, from a customer-facing angle to grid-type investments, to supply, and the key thing is going to be collaborating with the right folks.”

Highlighting the ambitious clean energy policies and greenhouse gas reduction targets of various states in the region, Divatia said, “This may mean, based on the numbers you run … one scenario is you need to have every single new vehicle by 2030 to be electric.

“Massachusetts has shown great leadership in this area by enabling a make-ready program to deploy $45 million to get about 18,500 EVs,” and the region needs about 80,000 charging stations to help people overcome their range anxieties regarding EVs, Divatia said.

“Again, if we want to go from here to there, we’re going to need a lot more electric infrastructure,” he said.

— Michael Kuser

May 27, 2019November 29, 2023

ERCOT Technical Advisory Committee Briefs: May 22, 2019

AUSTIN, Texas — Unable to reach a decision on a rare update to a key metric used to determine systemwide offer caps, the ERCOT Technical Advisory Committee last week delegated a staff proposal to the Wholesale Market Subcommittee for further discussion.

ERCOT has proposed lowering the peaker net margin (PNM) threshold from $315,000/MW-year to $273,600/MW-year, based on a revised 2018 report by The Brattle Group that set the cost of new entry (CONE) for generation plants — typically combustion turbines — at $91,200/MW-year. The PNM threshold is set at three times the CONE, which means the $315,000/MW-year threshold used in recent years implies a CONE of $105,000/MW-year.

The PNM threshold is used to determine the point at which the systemwide offer cap is reset from the high offer cap of $9,000/MWh to the low offer cap (the higher number between $2,000/MWh or 50 times the daily effective fuel index price).

During its Wednesday meeting, the committee rejected two separate motions in roll-call votes, both of which would have referred the issue to the WMS for further discussion on the study’s values. One motion would have tabled ERCOT’s proposal; the second would have approved it. The latter motion fell just short, by a 66-34 margin.

When the smoke cleared, TAC Vice Chair Diana Coleman, of the Texas Office of Public Utility Counsel, agreed with ERCOT to send the proposal to the WMS.

Brattle initially set the CONE for CTs at $88,500/MW-year but revised it in the final draft estimate of ERCOT’s market equilibrium and economically optimal reserve margins. The study, which “translated” an earlier version conducted for PJM to account for locational cost differences, adjusted assumed interest rates and corporate tax rates to come up with the new CONE.

The current CONE dates back to a 2012 Brattle study, which the Texas Public Utility Commission used to update its resource adequacy requirements earlier this year (Project 48721). (See “PUC Amends Resource Adequacy Rules,” Texas PUC Briefs: May 9, 2019.)

“We’re in a rising interest rate environment,” Reliant Energy Retail Services’ Bill Barnes said in advocating for the WMS’ further evaluation. “Let’s avoid a 10-year backward-looking number and use values that make sense.”

ERCOT staff said they would take time to bring in a consultant to review the Brattle analysis. They noted its Independent Market Monitor, Potomac Economics, has used a CONE of between $80,000 to 95,000/MW-year in recent reports and that the process used to change the CONE is “consistent with our current methodology.”

Luminant’s Ian Haley countered by bringing up PJM to Consider Revisions to Demand Curve Design.)

“This is so controversial in PJM that this is being litigated at FERC,” Haley said, objecting to making a “major market change” with seven days’ notice. “This is not something PJM instituted and everyone grabbed hands and sang ‘Kumbaya.’ These are some numbers with big issues in other markets. I have a lot of trouble with [ERCOT] describing them and running with them and showing slight differences [justifying] why they work here in six slides.”

Subcommittees to Review Emergency Procedures

The TAC also delegated to the WMS and its Reliability and Operations Subcommittee further discussions on the need to balance emergency procedures and system reliability.

ERCOT has already spent the last month working to resolve issues raised by a late-winter cold-weather event that resulted in generation resources being forced to adjust their outage schedules. (See ERCOT Generators Upset over Early March Weather Event.)

The grid operator has held two workshops on its procedures for issuing operating condition notices (OCNs) and conducted a webinar on a Nodal Protocol revision request (NPRR930) that would require it to use a weekly reliability unit commitment process to commit resources with an approved outage. The NPRR also sets an offer floor for the resource at the systemwide offer cap. (See “Changes Coming to ERCOT’s OCN Process,” ERCOT Briefs: Week of April 22, 2019.)

Two other NPRRs (934 and 935) addressing emergency procedures are going through the stakeholder process.

TAC members pushed to gain a clearer understanding of ERCOT’s OCN procedures and asked for greater accuracy in weather forecasts and planning assumptions.

“The range of possible outcomes of load [and] the range of possible forecasts for wind and icing are all very situationally dependent,” ERCOT COO Cheryl Mele said. “I’m not sure that is something we can hard code. We want to make that as transparent as possible and share that information with folks as soon as we can. I don’t think we can develop specific criteria around that because cold weather, hot weather [and] wet weather combined with cold all present very different types of risks to us.”

“We don’t expect hard coding, but we think we can get close to it,” Calpine’s Brandon Whittle said. “I think there’s a way to narrow that scope a little bit to where we have general consistency.”

“We don’t want an emergency declared days in advance, which is not what ERCOT wants to do,” Citigroup Energy’s Eric Goff said. “There are certainly other instances in the protocols worth finding and revising. At the same time, we can ensure we have communications around emergency conditions that are very clear and procedures that don’t have much guesswork.”

Barnes said his concern is that market participants are using ERCOT’s planning assumptions and the planning process to make operational decisions, “so we’re always going to overshoot.”

“That’s the nature of solving this problem,” he said. “Inherent in our market design is an acknowledgement we’re willing to accept a high level of reliability risk.”

Barnes referred to recent comments filed by Texas Competitive Power Advocates, a trade association representing ERCOT generators, wholesalers and retail providers. TCPA called for a holistic review of ERCOT’s reliability standards by the grid operator itself, along with Texas Reliability Entity and market participants.

“[TCPA] is concerned that this fundamental conflict between the reliability standards and required scarcity means that even lower reserve margins will be required before the economic signals are apparent and trusted to lead to a turnaround in supply,” the association said.

“There’s a lot of subjectivity in interpreting the standards,” Barnes said. “Not just ERCOT, but every power market has this tension between the need to preserve reliability and the need to let markets solve those problems. I know we probably have a reluctant partner in ERCOT to review the standards to see if there’s more room for relaxation of those, but that’s worth continuing to discuss.”

Wind, Solar Energy Set New Marks in April

Mele’s revamped operations report revealed ERCOT in April set new monthly generation records for its wind and solar fleets, producing 7,148 GWh and 408 GWh, respectively. That bettered the previous marks of 7,060 GWh of wind in May 2018 and 368 GWh of solar last June.

Wind energy accounted for 26.7% of ERCOT’s production during April, besting coal (19%) and nuclear (12.3%), while gas accounted for 39.9%.

April’s peak demand of 51.6 GW was a 3.7% increase over April 2018’s peak (47.9 GW) but below the April 2017 record of 53.5 GW.

Mele said she wants to retire the previous operations report’s format but agreed to add real-time revenue neutrality allocation (RENA) metrics to the deck. RENA measures the amount of leftover market revenue paid to qualified scheduling entities on a load-ratio share to keep the grid operator revenue neutral.

TAC Tables One Change, but OKs 17 Others

Committee members tabled an NPPR (917) that would set a 20-year grandfathering period to assist settlement-only distribution and transmission generators (SODGs and SOTGs) in their transition from zonal to nodal energy pricing.

NPRR917 currently allows existing SODGs and SOTGs to apply for continued zonal pricing until they opt in for nodal pricing or Jan. 1, 2030, whichever comes first. The proposed rule would grandfather distributed generation resources that have entered into interconnection agreements or power purchase agreements before Jan. 1, 2019.

In objecting to the request, solar developer Cypress Creek Renewables called for allowing existing SODGs and SOTGs to opt out of nodal pricing and continue to receive zonal prices for five years, with the option of extending the treatment for additional five-year increments for up to 40 years.

Cypress Creek is supported by Lower Colorado River Authority, which prefers a longer grandfathering period rather than a shorter one. The two entities will work together over the next month on joint comments.

Ralph Daigneault, legal counsel for Potomac Economics, said the Monitor is concerned with any grandfathering clause, but even more so when the term extends to 40 years.

“We think it’s bad precedent and bad market design. Any exception to that perpetuates the bad market design,” he said. “I think the comments by Cypress Creek are a step backwards. The smaller we get with that number, the more comfortable the IMM is going to be.”

“The big motivation for doing this zonally is if you have a load entity in that zone, and your generation is in that zone, you get a natural hedge,” said Walter Reid of the Advanced Power Alliance. “That is the business model that was expected, but unfortunately, we’re changing that.”

ERCOT says the change would better align its operations with the overall nodal market design and reliability needs and would increase economic efficiency.

The TAC did approve seven other NPRRs, three revisions to the Nodal Operating Guide (NOGRRs), four other binding document changes (OBDRRs), two modifications to the Planning Guide (PGRRs) and a system change request (SCR):

- - NPRR885: Adds new language to address the solicitation and operation of must-run alternatives, as directed by the Texas PUC (Project 46369). The commission ruled that a resource entity must file a notification of suspension of operations at least 150 days prior to the date on which it intends to cease or suspend operations; within the 150-day notice period, ERCOT must determine whether the resource is needed for reliability.
  - NPRR896: Outlines the process to evaluate the cost-effectiveness of procuring reliability-must-run service or one or more must-run alternatives.
  - NPRR921: Replaces all instances of the “all-inclusive generation resource” and “all-inclusive resource” terms with “generation resource and settlement-only generator (SOG)” and “generation resource, settlement-only generator and load resource,” respectively. Eliminating the all-inclusive generation resource enables ERCOT to more narrowly tailor the requirement’s applicability to a reasonable scope.
  - NPRR923: Updates the weather-sensitivity process by allowing transmission and/or distribution service providers an additional 30 days to complete the investigation and execution of requests to revise electric service identifier (ESI ID) load profiles.
  - NPRR924: Moves the Independent Market Information System Registered Entity Application for Registration form into a section of the Nodal Protocols that houses similar forms.
  - NPRR926: Removes the 90-day period between subsynchronous resonance (SSR) study approval and initial synchronization, clarifies that the SSR mitigation plan is part of the SSR study, and adds an ERCOT review process that gives the grid operator 30 days to review the SSR study. The change also gives ERCOT 45 days to implement any required SSR monitoring after the study’s approval.
  - NPRR929: Adds new criteria for determining whether a point-to-point (PTP) obligation with links to an option bid is eligible to be awarded based on the resource’s current operating plan (COP) status at the node where the bid sources. Bids will not be eligible for awards if they source at a resource with a COP status of “OUT” or “OFF” and the resource is not offered into the day-ahead market.
  - NOGRR185: Uses the terms created in NPRR889 (RTF-1 Replace Non-Modeled Generator with Settlement Only Generator) to replace the terms “all-inclusive generation resource” and “all-inclusive resource” in the Nodal Operating Guide.
  - NOGRR188: Aligns the guide’s language with ERCOT’s wide area network refresh project to allow implementation of Voice over Internet Protocol.
  - NOGRR189: Aligns the NOGs with NERC Reliability Standard PRC-002-2 (Disturbance Monitoring and Reporting Requirements).
  - OBDRR009: Revises the online and offline capacity reserves to prevent price reversal and price distortion during DC tie out-of-market actions.
  - OBDRR013: Changes the current single-value voltage categories of 345, 138 and 69 kV used to define generic transmission shadow price caps for N-1 constraint violations to accommodate Lubbock Power & Light’s transmission equipment, which does not fall into the three existing categories. The ranges are: greater than 200 kV ($4,500/MW), 100 to 200 kV ($3,500/MW) and less than 100 kV ($2,800/MW).
  - OBDRR014: Changes the location where resource nodes with disallowed energy-only offers, energy bids and point-to-point bids will be posted, and clarifies that the congestion revenue rights team will use the most recent list when building the auction model. The OBDRR also modifies its approval process to better account for revisions that may require a project and a separate SCR.
  - OBDRR015: Sets the value of lost load (VOLL) equal to the systemwide offer cap, which changes the high systemwide offer cap to the low systemwide offer cap should the PNM exceed its threshold within an annual resource adequacy cycle.
  - PGRR069: Uses terms created by NPRR889 to replace the terms “all-inclusive generation resource” and “all-inclusive resource” in the Planning Guide. The PGRR also clarifies the applicability of the generation interconnection or change request process to different generators, based on NPRR889.
  - PGRR070: Aligns the Planning Guide with NERC Reliability Standard TPL-007-2 (Transmission System Planned Performance for Geomagnetic Disturbance Events) by identifying responsibilities for performing studies needed to complete benchmark and supplemental geomagnetic disturbance vulnerability assessments.
  - SCR799: Enables ERCOT to provide transmission service providers its current month, 60-day and 90-day outage study cases in the system operations test environment on a monthly basis.

— Tom Kleckner

May 24, 2019

Va. Group Seeks End to Dominion Monopoly

By Christen Smith

A newly minted energy policy group in Virginia has set its sights on busting up the commonwealth’s dominant utility companies — Dominion Energy and Appalachian Power — in favor of a deregulated electricity market.

The Virginia Energy Reform Coalition (VERC) features policy experts from across the ideological spectrum united against what it considers wasteful infrastructure spending funded by ever-increasing electricity rates.

“Moving from Virginia’s 100-year-old government-regulated electricity market to a 21st-century free market will finally put families and businesses in control of their electricity-buying decisions so they can lower their own prices simply by shopping around,” said former Virginia Attorney General Ken Cuccinelli, director of the Regulatory Action Center of the libertarian FreedomWorks Foundation, one of VERC’s nine member organizations. “Shrinking the control of the government-imposed electricity monopoly means more citizens’ control, more choices, more innovation and lower prices.”

RTO Insider contacted each of Virginia’s legislative caucuses to gauge lawmakers’ appetite for electricity deregulation but received no response. Staffers for the respective Commerce and Labor committees declined to comment.

“For too long we have allowed the energy industry and those masquerading as electric utilities to chart our energy future,” said Dan Holmes, director of state policy for the Piedmont Environmental Council, during VERC’s May 7 press conference. “They have crafted the legislation and relied on their campaign contributions and lobbying prowess to ensure it is signed into law. The net result is a system that works for them alone, holding the commonwealth captive, all at the expense of the ratepayer.”

Dominion contributed more than $452,000 to state candidates and committees last year, according to the Virginia Public Access Project, making it the commonwealth’s largest campaign donor within the energy sector.

“Yes, the utilities are quite influential,” said Jim Presswood, executive director of the Earth Stewardship Alliance, another VERC member. “But our coalition represents consumers and groups across the ideological spectrum who plan to let their elected officials know that the time for reforms is now.”

IDSO

VERC argues it’s time for lawmakers to decouple utility companies from power generation — allowing for smaller, cheaper and cleaner resources to enter into the marketplace. The coalition looks to ERCOT’s structure as inspiration, noting Texas’ decision to “quarantine” utilities to owning transmission and distribution lines. Such a policy in Virginia could pave the way for more distributed energy resources, including solar and storage, to come online, the group says.

But the group does not want Virginia to create its own ISO. Instead, it supports the establishment of streamlined interconnection standards implemented by an independent distribution grid operator (IDSO).

“An IDSO would be similar to an RTO, but at the distribution level,” Presswood said. “The IDSO would operate and plan the distribution grid. The utilities would own and maintain the grid. There is not a conflict with PJM because the IDSO would not run any markets.”

An IDSO would also ensure an “all-cost-effective” energy efficiency standard by issuing private sector bid solicitations to remedy “significant” discrepancies that may require system upgrades.

“Competitive markets may not deploy energy efficiency resources even though they may be a cheaper way to meet system needs than other methods such as building new power plants or transmission and distribution infrastructure,” Presswood said. “If a competitive market were already deploying most or all cost-effective energy efficiency resources, there would be no need for IDSO intervention.”

The coalition also says the proliferation of DERs means there is no need for a capacity market, calling it an outdated structure that causes overinvestment, excess costs and unequal treatment of energy resources. It says it wants to “phase out” the capacity market and move to an ERCOT-like resource adequacy model, though it does not say how exactly it would accomplish that.

Costly Move?

Both Dominion and Appalachian Power doubt the proposed reforms make sense for Virginia, citing higher electricity prices in neighboring deregulated states. The legislature established a competitive model in 1999, but a failure to gain traction with customers and suppliers led to its undoing just eight years later.

“By owning and operating a diverse, clean generation fleet within PJM, our customers are protected from price volatility and market changes,” said Julie Mills Taylor, spokesperson for Dominion. “Being a member of PJM does provide a level of integrated transmission and generation planning that provides reliability assurances across a regional footprint.”

John Shepelwich, spokesperson for Appalachian Power, said Edison Electric Institute data published in April showed industrial customers paid rates 78% higher during the last winter in deregulated states. Residential rates were likewise 37% more expensive, according to EEI.

“We would expect that if Virginia were to deregulate generation services, it would probably result in the need to collect many millions of dollars in our plant investments made to meet longstanding obligations to serve our customers here,” he said. “That would be in addition to paying market-based generation service costs under a new regime.”

VERC also wants to change the way electricity rates are structured, said Travis Kavulla, director of energy policy for the R Street Institute. Instead of collecting revenues based on cost inputs and a desired return — the cost-of-service model — the coalition prefers basing rates on utility performance.

“The coalition’s agenda strikes a fair-minded balance between customer empowerment and customer protection,” he said. “Both of which are things Virginia energy policy has needed more of for years.”

Presswood said he expects legislation fleshing out VERC’s platform will be introduced next year.

May 24, 2019

ISO-NE on Track with GMD Standard

By Rich Heidorn Jr.

ISO-NE has completed its work on the first two requirements to take effect under NERC’s revised geomagnetic disturbance (GMD) standard and will be fully compliant by the end of the year with requirements effective in July 2020, the RTO told the New England Power Pool’s Reliability Committee on Wednesday.

TPL-007-3 (Transmission System Planned Performance for Geomagnetic Disturbance Events) replaces TPL-007-1, effective July 1. TPL-007-3 added a regional variance for Canadian jurisdictions to TPL-007-2, which FERC approved in Order 851 in November (RM18-8, RM15-11-003). (See Revised NERC GMD Standard Approved.)

NERC developed the new standard in response to FERC’s directives to improve how its initial GMD rules, approved in 2016, addressed the risks from “locally enhanced” events. It broadens the definition of GMDs, requires grid operators to collect certain data and imposes deadlines for corrective actions.

The standard applies to planning coordinators (PCs), transmission planners (TPs) and transmission owners (TOs)/generator owners (GOs) with power transformer(s) with a high side, wye-grounded winding with terminal voltage greater than 200 kV.

NERC’s original standard required applicable entities to assess the vulnerability of their transmission systems to a “benchmark” GMD event — defined as a one-in-100-year event. The new standard addresses FERC’s directive to revise the benchmark GMD event definition so that it is not based solely on the averaging of magnetometer readings over a geographic area. NERC defined the “supplemental” GMD event using individual station measurements rather than spatially averaged measurements, acknowledging that geomagnetic fields during severe GMD events can be “spatially non‐uniform” with localized peaks that could affect reliability.

5 New Requirements

The standard adds five new requirements. R8, R9 and R10 require responsible entities to assess the potential implications of the supplemental GMD event on their equipment and systems. R8 requires the completion of a supplemental GMD vulnerability assessment at least once every five years. If the analysis finds the supplemental GMD event would cause cascading outages, the responsible entity must evaluate ways to reduce the likelihood or mitigate the impact of the event. NERC said its standard drafting team concluded that an evaluation was more appropriate than a formal corrective action plan “in light of the limitations of currently available tools for modeling localized GMD effects.”

R9 requires responsible entities to provide geomagnetically induced current (GIC) flow information based on the supplemental GMD event to owners of applicable bulk electric system power transformers in the planning area. R10 requires TOs and GOs to conduct a supplemental thermal impact assessment for BES power transformers where the maximum effective GIC value resulting from R9 is above a threshold (85 A per phase or greater).

Under R11 and R12, PCs and TPs must obtain GIC monitors and geomagnetic field data for their planning areas or system model areas. They must have at least one GIC monitor in their regions.

The new standard also made conforming changes to other requirements and revised the deadlines in R7 for corrective action plans required to address system performance issues identified in the benchmark vulnerability assessment.

ISO-NE’s Alex Rost said the RTO is already compliant with R1, which concerns the definition of PCs’ and TPs’ roles and responsibilities, and R2, maintaining system GIC models.

He said the RTO will be compliant by Dec. 1 with R5 (“Provide benchmark GIC flow information to applicable TOs and lead market participants [MPs] for applicable GOs”) and R9 (“Provide supplemental GIC flow information to applicable TOs and lead MPs for applicable GOs”), which take effect in January.

Rost said the analyses required by the standard can be “iterative” — results obtained in later stages of the study cycle may prompt the rerun of early-stage work.

He said most of the GIC modeling data required is already included in the New England system GIC model but that the RTO will notify applicable entities if modeling updates are needed.

May 24, 2019

OGE Acquires 2 Oklahoma Plants

Oklahoma Gas and Electric said Wednesday it has completed the acquisition of two Oklahoma generators from which it had previously bought power to meet its capacity needs.

OG&E said FERC’s approval of the transactions (EC19-49) was the final regulatory OK it needed to complete its purchases. Financial terms were not disclosed, but OG&E said last year it would spend $53 million to acquire the plants.

AES Shady Point is a 360-MW, coal-fired facility in Eastern Oklahoma; privately owned Oklahoma Cogeneration is a 146-MW combined cycle plant in Oklahoma City.

OG&E — Shady Point facility | *AES Shady Point*

OG&E, a subsidiary of Oklahoma City-based OGE Energy, had contracts with both resources under the Public Utility Regulatory Policies Act of 1978. The legislation requires utilities to buy power from cogeneration plants built by non-utility power producers when the costs for that power are equal to or less than what the utility would spend to produce that power from a facility it would build and own.

Shady Point qualified for the cogeneration requirement by using some of its carbon dioxide emissions as a liquid and solid food-grade refrigerant for the poultry industry. However, OG&E said last year it was ending a five-year power purchase agreement with the plant, leading AES to announce it would close the facility.

OGE Energy CEO Sean Trauschke has said he expects “operational changes” to reduce Shady Point’s coal usage by more than 50%. The plant came online in 1991.

OG&E — Oklahoma Cogeneration plant | *Oklahoma Cogeneration*

Spokesman Brian Alford said the acquisitions will save OG&E customers “tens of millions of dollars” annually and keep “good-paying jobs in Oklahoma.”

OG&E received approval from Arkansas and Oklahoma regulators earlier this month.

— Tom Kleckner

May 24, 2019

NERC Panel Delays Action on BAL Standard Request

What to Do When ACE Conflicts with Interconnection Frequency?

By Rich Heidorn Jr.

The NERC Standards Committee on Wednesday postponed action on Arizona Public Service’s request to amend BAL-002-3 (Disturbance Control Standard — Contingency reserve for recovery from a balancing contingency event) after several members said they wanted to add the technical justification for its rejection to the record.

APS’ standards authorization request (SAR) proposed that compliance with BAL-002-2 requirement R1 would be reached once interconnection frequency has recovered, saying the change was needed to prevent the recovery of one event from contributing to the creation of another event.

Asked by the SC to provide a technical review, the Operating Committee in March recommended rejection of the SAR, citing advice from its the Resources Subcommittee (RS). “The recommended modification of R1.1 of this standard to include interconnection frequency assessment will modify the original intent of [the] standard, which is the demonstration of the deployment of reserves to recover from reportable balancing contingency events (RBCEs),” the OC said, adding, “The concerns raised in this SAR can be addressed by other means.”

Sean Bodkin, NERC compliance policy manager for Dominion Resources Services, asked for the delay, saying the technical reasons for the rejection should be added to the record. Other committee members also sought additional information on the “other means” cited by the OC.

“I’m not a BAL expert, but it looked like [APS] had a legitimate concern,” said Steve Rueckert, director of standards for the Western Electricity Coordinating Council.

Duke Energy Carolinas’ Tom Pruitt, chair of the RS, said there are simpler and more effective solutions to the situation identified by APS.

“There is an option to go through compliance guidance and develop a compliance guidance document. … There is an option for a BA [balancing authority] with the existing standard to simply execute an emergency assistance agreement with one of its neighbors for this situation. No modification of the standard at all is needed…

“The bottom line is, [under the SAR,] the BA would be exempt from balancing his BA area and that goes right to the heart of the job of a balancing authority,” Pruitt continued. “If he’s not required to balance his BA, we’re missing the boat here.”

Gary Nolan, an APS regulatory compliance adviser who wrote the SAR, told the SC there were “some differences of opinion and some misunderstandings” of his company’s concerns.

APS was not seeking to have a BA shirk its responsibilities, he said, but attempting to draw attention to a situation in which a BA’s area control error (ACE) is low while the interconnection frequency is high.

“BAL-001 R2 has a balancing authority … responding to what the interconnection needs as opposed to what the balancing authority needs. … When [interconnection] frequency is high, a balancing authority is asked not to correct their ACE and make frequency worse but rather to — if their ACE is low, it’s okay for them to remain low if [interconnection] frequency is high,” he explained.

Nolan said BAL-002 could be read to direct a BA in that situation to “increase their generation — or possibly, if it gets to a point where they’re very near to the deadline, they may need to shed load in order to recover their ACE in time. … Shedding load should be something we would be abhorrent to and not want to do. … That’s not going to help the interconnection … when frequency is high.”

“I get it, and I can see where there’s an issue,” Rueckert responded. “But we need to remember that the Standards Committee is not a technical committee; we’re kind of a process committee, and I don’t know that we should be making a decision on this SAR on technical terms. I think that is the RS and the OC.”

Bodkin agreed. “I know I am completely unqualified to make any technical justification on the BAL standards and that’s the reason I actually wanted to see the technical information from the RS in the record.”

Revised Standards Grading Tool Approved

The SC also approved a revised Standards G rading Spreadsheet for the Periodic Review Standing Review Team to use in evaluating standards’ requirements.

A working group formed last September revised ambiguous questions; eliminated duplicate questions; converted multipart questions into single questions; and added a reference section linking to source documents. It is the first update of the tool since its development in 2016.

However, the tool won’t get used immediately because of the decision to suspend the review team’s work until next year to avoid conflicts with the Standards Efficiency Review. (See “Standards Grading Process on ‘Pause,’” NERC Standards Committee Briefs: March 20, 2019.)

May 24, 2019

Outside Parties Slow MISO-PJM Freeze Date Thaw

By Amanda Durish Cook

After five years of discussion, MISO and PJM are still slogging through development of an alternative to their “freeze date” used to grandfather permissible unscheduled transmission flows that predated their seam.

And while the RTOs promise progress on the issue, they acknowledge that outside entities with a stake in any changes are still resistant to a proposed solution, stakeholders learned Tuesday.

The RTOs rely on the April 1, 2004, “freeze date” to determine firm rights on flowgates based on historical firm flows that occurred before creation of the seam between their markets. That date is used to establish acceptable flows in both the market-to-market (M2M) process and transmission loading relief.

Andy Witmeier, of MISO’s seams administration team, said the RTOs still agree that the freeze date needs updating.

“We’re more than 15 years away from it now, and issues with the date have become prominent,” Witmeier told stakeholders during a MISO-PJM Joint and Common Market conference call. Those issues primarily have to do with how designated network resources are dispatched and determining eligibility for transmission service requests.

But five years on, the RTOs are still facing opposition from parties to their congestion management process (CMP), which includes MISO, PJM, SPP, the Tennessee Valley Authority, Manitoba Hydro, the Minnkota Power Cooperative and Associated Electric Cooperative Inc. The CMP was established to minimize unscheduled market — or loop — flows among neighboring balancing areas.

All CMP parties stand to be affected by a change in the freeze date, MISO staff have said.

In November, MISO and PJM announced that their original goal of a full freeze date replacement by June 2019 was too optimistic. Now, the RTOs say they will continue talks on a possible replacement throughout the year and hope to implement a solution in 2020.

FFE vs. FFL

In M2M procedures between RTOs, an RTO’s entitled firm usage is classified as a firm flow entitlement (FFE). In the transmission loading relief process utilized for nonmarket entities in the CMP, an RTO’s entitled firm usage is classified as a firm flow limit (FFL).

Witmeier said MISO and PJM were close to a solution last year, but that nonmarket entities party to the CMP had issues with how the proposal might impact FFLs.

The RTOs’ proposal would divide flowgate allocation — or FFEs — among four separate “buckets” to prioritize access to the flowgates. (See “Freeze Date Update,” MISO-PJM Markets Meeting Addresses Seams Issues.)

The first bucket — which would get primary consideration for flowgate needs — would consist of active designated network resources predating the freeze date and historic transmission service requests.

A second bucket would consist of active designated network resources dating after the freeze date, while a third would be used for transfers from local balancing authorities with excess generation to LBAs short on generation.

The fourth, lowest-priority bucket would be for market-wide transfers based on RTO transmission planning.

MISO and PJM last summer changed their policies to make post-freeze date designated network resources with a defined dispatch order eligible to receive FFE allocations — a small piece of the RTOs’ broader proposed solution.

Witmeier said most CMP entities favor completing an FFE solution by mid-2020 while continuing to work on how FFLs would be handled. However, some want any solution delayed until both FFEs and FFLs can be addressed.

“Obviously, we have to have a unanimous agreement from all parties. … We’re not there yet,” Witmeier said.

‘A Long Time’

MISO, PJM and CMP entities have been working for about five years on a freeze date alternative through their Congestion Management Process Working Group.

Witmeier also said the two RTOs are specifically working on how to account for FFE allocation priorities and in what order they would curtail the overallocation of rights on a particular flowgate.

A joint white paper on the matter that would detail an alternative way to calculate the freeze date is still in the works, Witmeier added.

Customized Energy Solutions’ David Sapper asked if MISO and PJM could move to a FERC filing on a freeze date alternative without all nonmarket entities signing on.

“Five years is a long time,” Sapper observed.

PJM Director of Energy Market Operations Tim Horger said the two RTOs are considering substitutes to unanimous accord and may consider a filing that not all parties have signed on to. He also said parties to the CMP are “frustrated” that talks on a potential solution have taken this long.

“There is going to be a path forward shortly,” Horger promised stakeholders.

MISO and PJM staff promised to return to the Aug. 27 JCM meeting with an update.

May 24, 2019

ISO-NE Planning Advisory Committee Briefs: May 21, 2019

WESTBOROUGH, Mass. — ISO-NE told the Planning Advisory Committee on Tuesday that it plans to conduct all three economic studies requested by stakeholders last month.

Marianne Perben, ISO-NE manager of technical studies and resource adequacy, presented the 2019 Economic Study Draft Scope of Work and High Level Assumptions to the PAC. (See “Economic Study Requests Focus on Wind,” ISO-NE Planning Advisory Committee Briefs: April 25, 2019.)

The studies will cover:

A New England States Committee on Electricity (NESCOE) request to analyze various scenarios for integrating offshore wind by 2030, focusing on the impact on the transmission system and wholesale market. The study will examine a range of 2,000 to 8,000 MW of OSW resources, Perben said.
A request by transmission developer Anbaric Development Partners to review the impacts of OSW on energy market prices, emissions and regional fuel security in 2030. The study will look at an 8,000- to 12,000-MW range of OSW.
A RENEW Northeast request to evaluate transmission upgrades that would increase the hourly operating limits of the Orrington South interface in Maine.

The three studies will rely on a number of common assumptions, including: modeling Forward Capacity Market and energy-only generators at their seasonal claimed capability; using the most recent U.S. Energy Information Administration forecasts for New England coal, oil and natural gas prices; and reflecting CO2, SO2 and NOx prices in fossil fuel generation. Michael Henderson, the RTO’s director of regional planning and coordination, cautioned participants that “these are economic studies, not detailed transmission studies.”

In response to a question about why the RENEW study would exclude the western Maine cluster of resources in the interconnection queue, Perben said the cluster was not part of the request.

Asked about varying threshold prices in the analysis, Perben said ISO-NE uses them to facilitate analysis of load levels where the amount of $0/MWh resources exceeds the system load. They “are really just a way to know when to curtail those resources,” she said.

New Hampshire 2029 Needs Assessment Outlined

Jinlin Zhang, the RTO’s lead engineer for transmission planning, gave the committee a briefing on the New Hampshire 2029 Needs Assessment.

In February, ISO-NE suspended its New Hampshire 2027 Solutions Study process in order to incorporate changes in the draft 2019 Capacity, Energy, Loads and Transmission (CELT) forecast data, which showed the regional net load figure the RTO was using was too high.

The RTO used the draft 2019 forecasts to update the models to reflect the change in load, energy efficiency and solar PV volumes from the 2018 CELT, Zhang said.

She highlighted the “very important date” of June 10 as the deadline to notify the RTO of any resources it should consider including in the Needs Assessments.

Resources to be included are those that have cleared a Forward Capacity Auction, have signed contracts from state-sponsored requests for proposals, or are otherwise obligated by contract.

Two projects that received capacity supply obligations (CSOs) in FCA 13 have been added to the 2029 cases, she said. A 632-MW combined cycle plant in Connecticut is far from the study area and therefore modeled offline, while a 123-MW solar farm connecting into the Albion Road 115-kV substation in Maine is modeled at about 32 MW, or 26% of nameplate.

In addition, four generators have been set as out-of-service in the 2029 cases, with one generator in New Hampshire (Schiller 4 at about 48 MW) fully delisted for the second consecutive FCA, which is the cutoff for considering the resource unavailable for dispatch when performing a Needs Assessment. If a resource does not operate for three calendar years in a row, it is deemed to be retired.

The New Hampshire 2029 Needs Assessment will consider sensitivity study scenarios of the unavailability of all major generators in Central New Hampshire, as well as the addition of the 1,090-MW New England Clean Energy Connect (NECEC) project that would deliver Canadian hydropower and wind energy to the Larrabee Road 115-kV substation in Maine. NECEC was proposed in response to a solicitation by Massachusetts utilities.

Although NECEC does not yet have an approved contract from Massachusetts regulators, ISO-NE recognizes the project may be approved prior to or soon after the completion of the Needs Assessment, Zhang said.

In addition, the RTO will examine the unavailability of one Comerford and one Moore hydro generator.

The study models photovoltaic generation based on the draft 2019 CELT forecast.

“And when we studied generation unavailable, we studied generation unavailable in the neighboring area,” Zhang said. “All interface transfers are within their limits, demonstrating that the established reserves are acceptable.”

The RTO plans to post the updated 2029 Needs Assessment intermediate study files in Q3 2019. The assessment is expected to be completed by Q3 or Q4 2019, she said.

Emergency Actions Eyed to Address Potential Shortfall in Operable Capacity

ISO-NE projects the region’s net installed capacity requirements (ICRs) will increase by 480 MW by 2028 and that operating procedures could be needed to overcome a shortage of “operable” capacity.

Those were some of the highlights of a presentation the RTO gave the PAC on resource adequacy studies to be included in the 2019 Regional System Plan.

Peter Wong, the RTO’s manager of studies and assessment, said net ICR — 33,390 MW this year — is projected to increase to 33,870 MW by 2028.

Wong said the 34,839 MW of “known resources,” based on CSOs from FCA 13, are sufficient to meet the net ICR values through the 2028/29 capacity commitment period.

A comparison of the representative net ICRs with the FCA 13 resources plus the energy efficiency forecast shows a surplus of 2,291 MW in 2029, assuming no resource retirements, he said.

However, the RTO’s analysis of “operable” capacity — which deducts unplanned generator outages and gas-fired generation that may not be able to obtain fuel during peak winter periods — indicates the region may have to rely on load or capacity relief measures under Operating Procedure 4 (OP-4) to avoid shortfalls.

The analysis deducted 2,100 MW from the summer capacity based on historical unplanned outages, and 8,600 MW in winter based on the highest planned and unplanned generator outages during 2014-2018 and the highest amount of gas-fired generation at risk during the three-week winter peak.

Under 90/10 peak load conditions, the region could have operable capacity shortfalls of -1,150 to -2,500 MW during the summer and -1,370 to -2,500 MW during the winter.

Assuming 50/50 peak load conditions, New England could fall short of operable capacity during the winter peak for the entire study period and during the summer starting with delivery year 2024/25. Operable capacity shortfalls range from -310 to -470 MW during the summer and -160 to -1,200 MW during the winter.

The RTO said OP-4 actions of up to Action 6 (a 5% voltage reduction) could be needed to meet 50/50 loads and up to Action 9 (requests of all generation not contractually available to market participants and voluntary load curtailments by large industrial and commercial customers) to serve 90/10 loads.

Other operating procedures anticipated include depleting 10- and 30-minute operating reserves and importing power from other regions.

Wong said the RTO is anticipating a possible change in what has historically been a summer-peaking region.

“We are reviewing the growth in demand-side resources and the penetration of PV both behind the meter and in front of the meter, and the penetration of heat pumps,” Wong said. “Penetration of PV is not only shifting the time of the daily peak; it is possible that the system will shift to dual-peaking and then to a winter-peaking system.”

The Power Supply Planning Committee will conduct a final review of all assumptions on June 20 and July 25 and will review ISO-NE recommendation of ICR values Aug. 9 and Aug. 29 ahead of a Reliability Committee review and vote on ICR values on Aug. 20 and Sept. 25.

The Participants Committee will review and vote on the recommended ICR values Oct. 4, which will be filed with FERC by Nov. 5.

— Michael Kuser

May 23, 2019

PGE Gets More Time to File Bankruptcy Plan

By Hudson Sangree

The federal judge overseeing PG&E Corp.’s bankruptcy case gave the company four more months to come up with a Chapter 11 reorganization plan at a hearing Wednesday.

Judge Dennis Montali, of the U.S. Bankruptcy Court in San Francisco, extended the 120-day period under which PG&E and its utility subsidiary Pacific Gas and Electric have exclusive rights to file a reorganization plan with the court.

Montali gave the companies through September to come up with a proposal, though he said he could shorten that time if he chose.

The companies filed for bankruptcy Jan. 29, citing at least $30 billion in liabilities for wildfires sparked by transmission and distribution lines. (See PG&E Files for Bankruptcy.) The 120-day exclusivity period was set to run out next week.

PG&E — Tulips bloomed this spring in a neighborhood of Paradise, Calif., leveled by the Camp Fire last November. | © *RTO Insider*

Montali’s extension was a compromise. PG&E had asked for six more months in the hopes that California Gov. Gavin Newsom and the State Legislature might offer the state’s investor-owned utilities wildfire liability relief later this year.

Lawyers representing wildfire victims had urged Montali to deny the extension, while creditors had recommended a four-month reprieve. The judge said he was inclined to grant PG&E’s motion, but after hearing from the parties, he decided to accept the recommendation of the creditors’ committee.

“This judge has never been a fan of exclusivity but is a fan of practical consequences,” Montali said. He explained he did not want to deal with competing reorganization plans that might be unworkable.

Montali also approved PG&E’s creation of a $100 million fund to aid wildfire victims who lack housing or have other urgent needs. Many of those displaced by the November 2018 Camp Fire, the deadliest and most destructive in state history, are still living in tents and recreational vehicles in the destroyed town of Paradise.

One victims’ lawyer said the fund was a ploy by PG&E to generate good will with the governor and lawmakers. PG&E and the state’s other two large IOUs — Southern California Edison and San Diego Gas & Electric — want policymakers to lessen their wildfire liability under the state’s strict liability standard, known as inverse condemnation.

PG&E is a “pariah in Sacramento” and needs help winning reforms, the plaintiffs’ lawyer Robert Julian told the judge.

PG&E — Mailboxes were often all that remained after the Camp Fire tore through Paradise, Calif., in November 2018. | © *RTO Insider*

Julian said that in the same courthouse, Judge William Alsup is overseeing PG&E’s criminal probation related to the 2010 San Bruno gas pipeline explosion and has ordered the company’s new leaders to tour the devastation in Paradise. (See PG&E Probed by Plaintiffs’ Lawyers, SEC.)

The California Department of Forestry and Fire Protection recently concluded PG&E’s equipment had started the Camp Fire, which killed at least 85 people and destroyed nearly 19,000 structures. PG&E admitted weeks ago that a tower on its 100-year-old Caribou-Palermo line near Paradise had likely sparked the massive blaze. (See Cal Fire Pins Deadly Camp Fire on PG&E.)

“The only question is whether it’s homicide or manslaughter in the Camp Fire because they knew that tower was going to fail,” Julian said.

Montali said that as a bankruptcy judge, he could only approve or deny PG&E’s request to establish the aid fund, and that he had no cause to deny it.

“You’re saying, ‘You get brownie points with the governor and Judge Alsup,’” Montali told Julian. “I don’t care about that.”

May 23, 2019

ISO-NE on Track with GMD Standard

By Rich Heidorn Jr.

NERC’s original standard required applicable entities to assess the vulnerability of their transmission systems to a “benchmark” GMD event — defined as a one-in-100-year event. The new standard addresses FERC’s directive to revise the benchmark GMD event definition so that it is not based solely on the averaging of magnetometer readings over a geographic area. NERC defined the “supplemental” GMD event using individual station measurements rather than spatially averaged measurements, acknowledging that geomagnetic fields during severe GMD events can be “spatially non‐uniform“ with localized peaks that could affect reliability.

5 New Requirements

Under R11 and R12, PCs and TPs must obtain GIC monitors and geomagnetic field data for their planning areas or system model areas. They must have at least one GIC monitor in their regions.

ISO-NE’s Alex Rost said the RTO is already compliant with R1, which concerns the definition of PCs’ and TPs’ roles and responsibilities, and R2, maintaining system GIC models.

Rost said the analyses required by the standard can be “iterative” — results obtained in later stages of the study cycle may prompt the rerun of early-stage work.

He said most of the GIC modeling data required is already included in the New England system GIC model but that the RTO will notify applicable entities if modeling updates are needed.