Page 1124 – RTO Insider

March 27, 2020

Supply Chain Team Seeks Consensus After Feedback

By Holden Mann

The standard drafting team updating NERC’s standards to address cybersecurity supply chain risks is seeking a way forward in the face of widespread opposition to its proposed changes.

Project 2019-03 was initiated in response to FERC Order 850, which directed NERC to modify standards to address electronic access control or monitoring systems (EACMS) for high- and medium-impact bulk electric cyber systems. (See FERC Finalizes Supply Chain Standards.)

Meeting via conference call this week, the SDT focused on the results of the initial ballot that concluded March 11. The weighted results indicated just over 50% acceptance of the proposal, short of the two-thirds majority required for approval. (See Commenters See Overreach in Supply Chain Standards.)

Push for PACS Removal

Many of the negative comments accompanying the ballot focused on the inclusion of physical access control systems (PACS) in the proposed modifications to CIP-005, CIP-010 and CIP-013. This was not part of the original FERC mandate but was added after NERC staff’s supply chain risks report last May recommended that standards include requirements for PACS on high- and medium-impact systems.

The addition of PACS had been a subject of disagreement during the drafting process, and some team members pointed to the opposition as justification for removing the term from the proposal altogether. (See Supply Chain Team Wary of Changing Access Control Terms.) Tony Hall of Louisville Gas & Electric and Kentucky Utilities cited a comment from Meaghan Connell of Chelan County Public Utility District that noted that protected cyber assets (PCAs) are excluded from the CIP-013 reliability standards because their risk is difficult to quantify, and recommended PACS be excluded on the same basis.

However, others pushed back against the idea that PACS had no place in the standards, arguing that they could still represent a security vulnerability and that overlooking such systems in earlier standards is no excuse for not recognizing their potential threat.

“The fact that NERC and FERC left PCAs out of the CIP-013 standards is not lost on me. … It seems that they should have both been included, but they were not,” said Jeffrey Sweet, manager of cybersecurity testing and assessments for American Electric Power, adding that he would have preferred to include PCAs in the supply chain standards if the order allowed it. “[We] only addressed the PACS because that was all we were told to address: PACS and EACMS.”

More Warnings of Scope Creep

Team members also responded to concerns about a perceived expansion in the definition of EACMS. Several commenters argued that FERC had only asked for modifications to address EACMS that pose a known risk to the bulk electric system, but the proposed standard would affect all EACMS. This wider scope could cause unintended confusion for utilities and disrupt their workflows, they said.

Hall urged the drafting team to take these warnings seriously and try to clarify its language in order to avoid “messing something up through a process, because there’s always a different way to follow the process.” He observed that an overly vague standard with difficult-to-parse language could quickly bog down both utilities and auditors in trying to verify whether compliance has been achieved.

“I personally don’t want to get into the situation of maintaining lists for the sake of maintaining lists,” Hall added. “Early on in these CIP standards, we had so many violations in CIP-004 because the list didn’t match who actually had access. … We ended up with violation after violation because the list was wrong.”

The SDT’s next meeting has not yet been scheduled. Currently all drafting teams are meeting via conference call in accordance with NERC’s business continuity plan, invoked in response to the COVID-19 coronavirus pandemic.

March 27, 2020

PJM Members OK Tighter Credit Rules

By Rich Heidorn Jr.

Stakeholders on Thursday overwhelmingly approved an overhaul of PJM’s rules for managing the credit risks of market participants.

PJM credit rules — PJM Chief Risk Officer Nigeria Poole Bloczynski | © *RTO Insider*

“I applaud the investment by stakeholders and members in their actions to protect our energy markets,” PJM Chief Risk Officer Nigeria Poole Bloczynski told the Members Committee after the final vote.

The new rules were developed by the Financial Risk Mitigation Senior Task Force (FRMSTF) in response to the GreenHat Energy default in the financial transmission rights market.

The Markets and Reliability Committee approved the Operating Agreement and Tariff revisions in a 4.5 to 0.5 (90%) sector-weighted vote after PJM officials agreed to accept three friendly amendments and members rejected a motion to delay the vote. The MC later endorsed the rules by acclamation with one vote in opposition and three abstentions.

Exelon’s Sharon Midgley called the changes a “significant leap forward in PJM’s credit and risk management program.”

What Changes

After the default of Tower Research Capital’s Power Edge hedge fund in 2007, FERC ordered an end to collateral-free trading with the issuance of Order 741. PJM and other RTOs tightened their credit rules as a result.

But the changes weren’t enough to protect PJM against GreenHat, which purchased a staggering 890 million MWh of FTRs — the largest FTR portfolio in PJM — before defaulting in June 2018. (See Doubling Down – with Other People’s Money.)

PJM formed the FRMSTF to implement recommendations made by an independent investigation of the debacle, which led to the departure of the RTO’s CEO, CFO and general counsel and the hiring of Bloczynski. (See Report: ‘Naive’ PJM Underestimated GreenHat Risks.)

The new rules require companies wanting to become a market participant to provide PJM with financial records, corporate information and details of any prior defaults in energy markets or involvement in market manipulation.

To allow PJM to conduct ongoing risk evaluation, companies also must make annual officer certifications and notify the RTO of any “material adverse change in the financial condition of the participant or its guarantor.”

PJM will determine whether a company presents an “unreasonable credit risk” based on factors including “a history of market manipulation based upon a final adjudication of regulatory and/or legal proceedings, a history of financial defaults, a history of bankruptcy or insolvency within the past five years, or a combination of current market and financial risk factors such as low capitalization, a reasonably likely future material financial liability, a low internal credit score … and/or a low externally derived credit score.”

Unbeknown to PJM, GreenHat’s principals, Andrew Kittell and John Bartholomew, had come to FERC’s attention for their roles in J.P. Morgan Ventures Energy Corp.’s scheme to manipulate the CAISO and MISO markets between 2010 and 2012.

The new rules also seek to prevent applicants who have defaulted from participating in PJM markets under a different name. Factors for determining whether an organization should be treated as the same market participant that experienced a default include “the interconnectedness of the business relationships, overlap in relevant personnel, similarity of business activities, overlap of customer base and the business engaged in prior to the attempted re-entry.”

After GreenHat’s default, Kittell continued trading in PJM for a time under a new corporate name, Orange Avenue.

Amendments

PJM officials made several changes to the language Thursday in response to stakeholder comments at a second “page turn” on the proposals March 13. In addition, PJM accepted three “friendly” amendments to the proposal it had negotiated with stakeholders in the days before the MRC vote.

Bloczynski acknowledged before the votes that some members were concerned the new rules would result in “unintended consequences.”

“We do not believe this is the case,” she said. “However … I commit to you that we’ll continue to review and reform the language to ensure that what the Tariff contains is what we all intended.”

One amendment, sponsored by attorney Steve Huntoon, representing H-P Energy Resources, modified the definition of the term “market participant.”

Huntoon’s amendment eliminated the phrase “or any other PJM member whose application to participate in the PJM markets has been approved by PJM.”

As amended, the definition is “a market buyer, a market seller, an economic load response participant, an FTR participant, a capacity market buyer or a capacity market seller.”

“The problem is the definition of ‘PJM markets’ is very, very broad,” Huntoon said.

As originally written, Huntoon said, it could have inadvertently included generators that provide ancillary services directly, rather than through a wholesale affiliate, as well as transmission owners and customers, including hundreds of municipals and cooperatives that participate in PJM markets through wholesale entities like American Municipal Power and Old Dominion Electric Cooperative. It was an issue Huntoon had raised at the first “page turn” session in February. (See PJM Stakeholders Debate Credit Rule Changes.)

Gary Greiner, director of market policy for Public Service Enterprise Group, won two amendments, including one that makes the judgments of rating agencies such as Standard & Poor’s, Moody’s Investors Service and Fitch Ratings, if available, “the source” for calculating the unsecured credit allowance of market participants. If no external ratings are available, PJM’s internal credit score will apply. If there is difference of opinion among rating agencies, the lowest rating will apply.

“It’s a metric that’s monitored by members, consistently applied and transparent,” Greiner said. “It’s what investors use to buy our stock and bonds.”

Bloczynski supported the change, saying, “We do not believe that this takes anything away from us.”

The rules include a scale ranging from “very low risk” (S&P/Fitch: AAA to AA-; Moody’s: Aaa to Aa3) to “high risk” (S&P/Fitch: BB- and below; Moody’s: Ba3 and below).

PSEG also won a change that PJM only “consider” rather than “apply” any changes to best practices or principles by third-party industry associations relating to risk management in the North American electricity, natural gas or electricity-related commodity markets.

PJM will “bring [the new policies] into the equation, but it won’t be applied it in a hard way that … members would be forced to put into their policies,” Greiner said.

Paul Sotkiewicz of E-Cubed Policy Associates, representing Elwood Energy, moved to delay the MRC vote to give other members time to submit friendly amendments.

But Bloczynski said the “amendments do not change the substance of anything that’s been put in front of you since December” and cautioned that a delay would prevent PJM from winning FERC approval of the changes in time to apply them for FTR auctions in June.

“We do not believe that more time to review the package is necessary or advisable,” she said.

Members voted almost 4 to 1 (80%) against a delay.

March 27, 2020

CPUC Approves Big Boost in Storage, Solar Targets

By Hudson Sangree

The California Public Utilities Commission approved historic increases in the state’s clean energy targets Thursday, calling for almost 25 GW of renewable energy and storage by 2030 at an estimated cost of $45 billion (16-02-007).

The CPUC’s new reference system portfolio (RSP) targets adding 11 GW of utility-scale solar; 3.4 GW of wind; 1 GW of pumped storage; and 8.9 GW of battery storage — eight times the total installed battery capacity nationwide as of 2018, the commission said.

Load-serving entities — including the state’s three big investor-owned utilities and a growing number of community choice aggregators — must use the reference portfolio figures, which the CPUC describes as “optimal” outcomes, in their individual integrated resource plans in 2020. The RSP also is used by CAISO in its annual transmission planning process.

The goal of the effort is to help the state reach its goal of providing 100% “renewable and zero-carbon” energy to retail customers by 2045, as mandated by Senate Bill 100, passed in 2018.

CPUC President Marybel Batjer thanked fellow commissioners, staff and stakeholders before the unanimous vote.

“I think [this] is a very, very good decision, one that will double the clean energy capacity of the state over the next 10 years and one I do believe will keep us on track for the 2045 goals that we must meet … not only for the good of California, but really for the good of the world.”

GHG Reduction not Enough?

Not everyone was as thrilled as Batjer with the result.

The Natural Resources Defense Council issued a statement Thursday saying the CPUC’s order didn’t do enough to address climate change because it maintained a target of reaching a greenhouse gas emissions level of 46 million metric tons by 2030 — the same figure the CPUC adopted in its last two-year IRP cycle.

“Despite recommendations to the contrary from the entire environmental community, multiple electricity providers and even the CPUC’s own Public Advocates Office, the commission adopted a proposal with a relatively high emissions scenario as the state’s reference system plan to guide California’s electricity providers for the next two years,” the NRDC said.

However, the plan also requires retail electric providers to outline how they would reach a more ambitious target of 38 million metric tons, a concession to the chorus of those calling for greater GHG reductions.

Commissioner Clifford Rechtschaffen voted for the plan but expressed support for the stricter target in his comments.

Commissioner Liane Randolph, who headed the effort to draft the new reference portfolio, acknowledged not everyone was completely satisfied with the result but said there would be opportunities to revisit the GHG reduction target in the next two years.

“Having LSEs submit their plans toward the additional target of 38 MMT [million metric tons] will allow us to conduct a more practical and less theoretical analysis of what resources are needed to achieve that … target from the perspective of the individual LSEs doing the planning and procurement,” Randolph said.

The 46 MMT figure is 56% below 1990 levels and would exceed the state’s legislative mandate to reduce GHG by 40% below 1990 levels over the next decade, the CPUC said.

Renewables, Storage to Double

Randolph said the dramatic increase in renewable energy and storage statewide deserves praise.

“The decision adopted today provides guidance to load-serving entities to go out and procure approximately double the amount of renewable and storage capacity that is currently online in the electric system in California,” she said in a statement.

From 2020 to 2030, the reference portfolio projects a total increase in utility-scale solar from 16,310 MW to 25,905 MW and wind power from 7,367 MW to 10,293 MW, including 606 MW of wind power from new out-of-state transmission.

Natural gas generation would decrease by about 2.5 GW over the same period but remain as one of the state’s two main power sources, along with large-scale solar.

Commissioner Martha Guzman Aceves called for more effort to eliminate natural gas from the state’s resource mix. Methane, which accounts for about 12% of GHG emissions, has a more potent effect than carbon on global warming, she noted.

Wednesday’s vote was the culmination of a process that began with an administrative law judge seeking input in November 2018 and dozens of utilities, environmental groups, consumer advocates and others commenting on the plan’s iterations during the past 16 months.

The commissioners made their decision in a web conference because of the COVID-19 coronavirus pandemic. Technical problems with the phone company’s virtual setup plagued the commissioners, who also regulate the state’s telecommunications industry.

While obviously irritated, they didn’t threaten repercussions.

March 27, 2020

SPP, MISO Tweak Pseudo-Tie Practices in JOA

By Tom Kleckner

FERC last week approved SPP’s revisions to its joint operating agreement with MISO that improve pseudo-tie coordination requirements between the RTOs, effective Monday (ER20-904).

The March 19 letter order accepted revisions addressing definitions, requirements, modeling, interchange schedules and general pseudo-tie coordination. SPP said the changes would improve transmission system efficiency along its seam with MISO by including obligations already in pseudo-tie agreements where MISO is the external balancing authority.

The changes include:

adding certain definitions set forth in the NERC glossary of terms used in reliability standards;
incorporating language requiring the native BA and the attaining BA to coordinate the pseudo-tie’s modeling in accordance with the rules of the native BA and attaining BA, respectively;
adding new subsections to the JOA that outline authorities for pseudo-ties from one RTO into the other; and
revising the requirements with language that includes the impacts of pseudo-ties in the attaining BA’s market flow impacts for the purposes of congestion management procedures. “Neither MISO, nor SPP, nor the entity seeking to pseudo-tie shall tag or request to tag the energy flows from a pseudo-tie into the attaining BA,” the language says.

SPP borrowed from the MISO-PJM JOA to define pseudo-ties as involving the real-time transfer of a generating resource’s or load’s control from the native BA where resource or load is physically located to an attaining BA that is responsible for operating the grid in a different geographic location.

SPP MISO Pseudo-Tie — MISO’s control room in Carmel, Ind., where the RTO manages pseudo-tie connections. | *MISO*

Its pseudo-tie agreement permits load and generating resources external to the SPP BA to be served by SPP. It also allows load and generating resources internal to SPP to function as part of an external BA.

ESR Data Added to Interconnection Procedures

FERC on Tuesday accepted SPP’s Tariff revisions to include specific information related to energy storage resources (ESRs) in the grid operator’s generator interconnection procedures (ER20-918).

With the commission’s approval, the generator interconnection forms will now ask whether or not ESRs will take energy from the system when operating in charging mode and the maximum rate of charge capability.

SPP filed the request on Jan. 31, shortly after stakeholders agreed to form a steering committee charged with determining how best to integrate energy storage. (See SPP Planning Approach to Battery Storage.)

March 27, 2020

CAISO Board OKs $141.7M Tx Plan, RMR Contracts

By Robert Mullin

CAISO’s Board of Governors on Wednesday approved $141.7 million in transmission spending and reliability-must-run contracts covering three power plants in Central California.

The 2019/20 transmission plan covers nine projects CAISO says are needed to maintain reliability according to NERC and ISO planning standards. Seven of the projects (totaling $120.7 million) will be located in Pacific Gas and Electric’s service territory, one ($16 million) in Southern California Edison and another ($5 million) in the Valley Electric Association/GridLiance West area straddling the California-Nevada border.

In his presentation to the board, CAISO Vice President of Infrastructure Development Neil Millar characterized the plan as a “modest” capital program and pointed out that all the projects are reliability-driven.

“We did not identify the need for any policy-driven projects or economic-driven projects in this cycle. The one qualifier was that the economic-driven analysis did identify the benefit of advancing a reliability project, but the driver remains the reliability requirement for that project,” Millar said, referring to the $16 million, 230-kV Pardee-Sylmar line-rating-increase project in SCE’s territory.

Millar said CAISO’s analysis of potential policy-driven projects relied on assumptions gleaned from the California Public Utilities Commission’s 2017/18 integrated resource planning cycle. The CPUC’s IRP reference system plan assumes that California’s electricity sector will cap its annual greenhouse gas emissions at 42 million metric tons by 2030 through a generation portfolio consisting of at least 60% renewables. It includes a “generic” base portfolio concentrated in various parts of the state needed to meet that target (see graphic).

“I’m not an engineer, but as a matter of common sense, can you explain how we can go from a 33% to 60% renewable system” without spending on new policy projects? Governor Ashutosh Bhagwat asked.

Millar responded that, in past years, utilities developed renewable portfolios under the expectation that the resources must be deliverable as resource adequacy under CPUC rules. But those portfolios have “started to shift” where some of the output can be energy-only, he said.

“So with the upgrades that were already put in place, we saw that we had considerable capability to take advantage of filling out those areas where developments had already taken place, as well as capacity to meet energy-only requirements where resources would be providing energy and not necessarily resource adequacy capacity,” Millar said.

The scope of the past transmission buildout accounts for the lack of policy-driven needs today, he said.

But Millar pointed to one “qualifier.”

“When you move to these higher [renewable] goals, we’re also seeing a steady escalation in the amount of transmission-related curtailments that’s showing up in the model, and unless there’s a policy requirement to address that curtailment, that would transition over to being an economic requirement,” he said. “Those could drive considerable transmission to address economic-driven transmission needs.”

The board additionally approved CAISO management’s recommendation to put three previously approved projects on hold for further review. The projects are all located in PG&E’s territory and include the North of Mesa upgrades, the 115-kV Morage-Sobrante line reconductoring and the Wheeler Ridge Junction substation project.

Not a Trend — Yet

The board also approved the designation of three Central California power plants as RMR resources for the summer peak season. The approvals are conditional because they will be revoked for any resource that obtains a resource adequacy contract by that time. The facilities include:

Starwood Energy Group’s Greenleaf II Cogen, which is required to help meet the 734-MW local capacity requirement (LCR) for the Drum-Rio Oso subarea within the Sierra local area. The 49.5-MW unit is not currently active in the CAISO market following termination of its Public Utility Regulatory Policies Act contract and is going through a qualifying facilities conversion process to become an ISO participating generator. The 230/115-kV Rio Oso transformer replacement project, which will mitigate the subarea’s reliability need, is not scheduled to be in service until June 2022.
California State University Channel Islands’ Channel Islands Power, which is required to help meet the 288-MW LCR requirement in the Santa Clara subarea of the Big Creek/Ventura local area. The 27.5-MW unit is currently under a resource adequacy contract set to expire on March 30. While 195 MW of new energy storage resources have been procured to meet the expected LCR shortfall in the subarea, they won’t become available until June 2021.
Atlantic Power’s E.F. Oxnard, which is also needed for the Santa Clara subarea. The 48.5-MW plant is currently under a resource adequacy contract that expires May 24. The unit will need to convert from a QF participant arrangement to a conventional market participant arrangement.

Governor Severin Borenstein noted that last year saw just one CAISO unit secure an RMR designation for the summer.

“Are we seeing an increase, or should I not think this is a trend?” Borenstein asked.

“From a local capacity perspective, we wouldn’t expect to see this being indicative of a trend,” Millar said. “Two of these units are qualifying facilities as opposed to being conventional market participants, and there’s a relatively small number of those. The other issue we’re dealing with is that we do have reinforcement projects under way generally to backfill for a number of these items, so there are individual cases that we’re going to have to deal with from a local perspective. So we don’t see this as a trend — at least yet.”

CAISO CEO Steve Berberich interjected: “I think the operative word being used is ‘yet.’ With the fragmentation of the load-serving entities in California, we expect that this could very well be the case. I agree with Neil that this doesn’t necessarily indicate a trend, but we’re going to continue to be vigilant about this issue.”

March 27, 2020

NYISO Management Committee Briefs: March 25, 2020

NYISO has sequestered approximately two-thirds of its operations staff on site at its two control centers to prevent possible infection by the COVID-19 coronavirus from interfering with reliable grid operations, CEO Rich Dewey told the Management Committee on Wednesday.

“First and foremost, from a reliability standpoint, we do not feel at this juncture that we have any reliability concerns specific to the pandemic or the readiness of any market participants, whether generators or utilities, to comply with what we need to do,” Dewey said.

The regular staff are working almost 100% from home, and there have been no reports of infection, he said.

“We have moved two full operational crews on site, provided trailers for sleeping [and] separate food facilities, and have walled off access to any of the individuals participating in that program,” Dewey said. “We’ve got a rotation that will help us maintain grid operations for the foreseeable future.”

The ISO also has been in regular contact with generators and transmission owners, and some of them are also beginning to implement on-site sequestration for staff, he said.

“Similarly, we’ve also been in touch with all the other RTOs and ISOs around the country … and everyone is thinking along the same lines,” Dewey said.

“We’ve also initiated, at the request of the [New York] Public Service Commission, some outreach to the generation community to try to get an understanding — for each of the generation plants — what level of readiness or preparedness exists, and to get a sense if we’re going to have any concerns with respect to their ability to perform.”

2019/20 Winter 5th Mildest in 200 Years

Vice President of Operations Wes Yeomans delivered the Winter 2019/20 Cold Weather Operations report, which showed a seasonal peak load of 23,253 MW on Dec. 19, compared with a seasonal 50/50 forecast of 24,123 MW. NYISO’s all-time winter peak load was 25,738 MW on Jan. 7, 2014.

NYISO 2019/20 winter daily peak loads in perspective | *NYISO*

Yeomans said there were no “critical issues” to report to stakeholders after a season without “critical operating conditions.”

“It feels strange to give a winter report when the winter was so mild,” he said. “Just how mild was this? Relative to the top 10 mildest winters … dating all the way back to 1820, this one tied with 1906 as the fifth-warmest January in the last 200 years.”

Transmission performance was also excellent, he said.

Yeomans also delivered the monthly operations report, highlighting the mild weather in February that saw natural gas and distillate prices lower compared to the previous month, and natural gas prices down 32.2% year-over-year.

ESR Tariff Revisions Approved

The MC also approved Tariff modifications related to energy storage resource (ESR) participation, as recommended by the Business Issues Committee earlier this month. (See NYISO BIC Briefs: March 19, 2020.)

Energy Market Design Manager Zachary Stines presented the background material for the discussion and vote on proposed Tariff language, which spells out details regarding day-ahead margin assurance payments; the method for setting feasible day-ahead and real-time schedules; generator offer caps, mitigation and reference levels; and installed capacity supplier bidding requirements.

If approved by the Board of Directors in April, the ISO will file the changes with FERC and anticipates making them effective simultaneously with the rest of its ESR participation model.

CIO Doug Chapman said the ISO wants to activate the new software in June and would delay the rollout until September if unable to do so to avoid implementing new software in summer conditions, because it represents a significant change to the system.

“If the summer was mild enough, our operations teams might elect to go ahead, but our default decision would be to avoid the summer and its tight operating conditions,” Chapman said.

Committee Chair Jane Quin, vice president of energy policy and regulatory affairs for Consolidated Edison, announced that the MC will hold a special meeting April 15 to act on buyer-side mitigation rules.

— Michael Kuser

March 26, 2020

CAISO Protecting Control Room Staff

By Hudson Sangree

CAISO is focused on keeping its control room running and isolating key employees from those who might be carrying the COVID-19 coronavirus, CEO Steve Berberich told the ISO’s Board of Governors Wednesday.

Some employees are working off site, Berberich said. Others have shifted to CAISO’s secondary control room at a 35,000-square-foot backup facility in Lincoln, Calif., about 20 miles north of the ISO’s Folsom headquarters near Sacramento.

“We’re doing our best to particularly make sure we protect our control room personnel and leveraging our backup site to make sure we have separation between them,” Berberich said. “Our focus though right now is to make sure we protect our staff but also ensure our primary missions of running the reliable grid and credible markets remains intact.”

Like other regions, CAISO has seen shifts in demand as a result of the coronavirus threat. The ISO has experienced a 3 to 5% load reduction, with Californians under a statewide stay-at-home order, he said. Mild weather and other factors may be disguising more pronounced effects on the state’s demand curve, he noted.

“We’re tracking that,” Berberich said. “I know [Vice President of Market Quality and California Regulatory Affairs] Mark Rothleder’s group is focused on making sure we take that into consideration as we make our forecasts.”

CAISO Wholesale Prices — CAISO’s control room in Folsom, Calif. | *CAISO*

CAISO has had a pandemic plan in place since 2015 as part of its business continuity plan and has put it into effect, the CEO said.

The ISO is continuing with business as usual in other ways too, he said.

CAISO is continuing to perform its role as reliability coordinator for much of the West and running the Western Energy Imbalance Market, so far without significant disruption, he said.

However, Berberich acknowledged that some of RC West’s “advanced tools continue to be challenged.” CAISO’s advanced computer applications run contingency analyses based on a system model that is changing, he said.

“We’re working through some of the issues getting that system model completely correct,” he said.

“We do expect to move forward on all our policy initiatives,” Berberich said. “The stakeholder processes will continue to go forward on a telephonic basis. We’ll continue to manage the interconnection queue, transmission planning and all the other efforts we have to support California, but also the region and its decarbonization goals.”

He said developers have asked not to postpone projects, so CAISO won’t meddle with interconnection timelines.

“We are mindful that there are a lot of strains out there on the system — local regulatory authorities, the permitting agencies, financing and all those things,” Berberich said. “We are in a position where we will do what’s right to try to make sure that people can move through the queue, [that] they can successfully bring in projects and they can add to California’s goals of decarbonizing the grid.

“To the extent that we need to work with FERC and the stakeholders to find ways through that, we will. We have explored changing the queue dates and the schedules. After consulting with the industry, we got resounding feedback that they would like to keep those dates and requirements as is, so that will be our plan.”

Berberich plans to retire this summer, and a nationwide search has commenced for his successor.

Board Chair David Olsen took time at the start of Wednesday’s meeting to tell stakeholders that the ISO’s policy goals, including the expansion of the Western Energy Imbalance Market across the West and to a day-ahead market, won’t change during the CEO transition.

“That will not change any of our current commitments and forward-looking policies,” Olsen said. “The board wanted to communicate that unambiguously.”

March 26, 2020

MISO Loads Down as Region Faces COVID-19 Threat

By Amanda Durish Cook

MISO’s weekday loads are looking more like weekends as social distancing measures to lessen COVID-19 cases take hold in more states in the footprint.

“We are starting to notice a few impacts,” Vice President of System Planning Jennifer Curran reported during the Markets Committee of the Board of Directors’ Tuesday meeting, conducted via WebEx and teleconference. (See Virus Fear Sends MISO Board Week to the Web.)

Director Tripp Doggett asked if MISO is experiencing more load shapes on par with weekend usage as more people stay home across the footprint.

“In general, it’s going in that direction; the peaks aren’t as prominent,” Executive Director of Market Operations Shawn McFarlane said.

MISO COVID-19 — MISO’s March 2019 Board of Directors meeting in New Orleans | © *RTO Insider*

For instance, McFarlane said, morning peaks are flattened absent the usual flurry of activity to get schoolchildren and workers out the door. In its place is a more dispersed demand over the morning hours, he said.

McFarlane said MISO hasn’t yet quantified how much load has declined across the footprint.

“Things have been evolving. Last week, it was only schools closed. Now we have shutdowns in the industrial sector. It’s very fluid at this time. It’s certainly greater than 5% — now it could be even 10%” year-over-year, he said.

Complicating matters, MISO’s load forecasting relies on historical information. “During this unprecedented time, we don’t have historical data,” Curran explained.

MISO Director Theresa Wise called the forecast challenges “completely understandable.”

Independent Market Monitor David Patton said MISO load in the first three weeks of March was about 8% lower than it was a year ago, reflecting the closure of schools and business. “We’ve noticed a significant impact,” he said.

“We expect that load effect to increase, and we’re talking to MISO about the impact. … We do think the learning of their models will improve the forecast,” Patton said, adding that in the meantime, RTO staff have manually adjusted short-term load forecasts.

MISO Director Baljit Dail asked if generators were scheduling maintenance outages to take advantage of the dip in demand as the economy slows.

“Actually, we’re seeing the opposite. We’re starting to see deferrals of planned outages,” Curran said. She said the root cause is likely that utilities are making do with fewer personnel.

Directors asked if MISO anticipates other impacts related to the pandemic.

“It’s early days yet, so we’ll be in constant communication with our members,” Curran said.

The RTO has convened incident response teams focusing on COVID-19 that meet daily and have escalation plans at the ready to protect grid operations, if necessary, Curran said.

“MISO’s top priority is to ensure the safety of its staff and stakeholders and reliability of the bulk electric system,” she said.

Although most MISO employees are working from home, Curran noted that the RTO has operations in four sites in three states: the headquarters and Central Region Operations Center in Carmel, Ind.; the North Region Operations Center in Eagan, Minn.; and the South Region Operations Center in Little Rock, Ark. “So, we have a built-in social distancing,” she said.

Curran said MISO is also working with law enforcement to make sure the RTO’s control room operators can get to and from work as more states order their residents to shelter in place. She also said control rooms are being disinfected more frequently, and MISO has limited access to control rooms to essential personnel only. MISO facilities continue to be closed to visitors through May 1.

“This situation seems to change daily so keep in mind these actions can change or be extended,” Curran said.

Patton also reported Potomac Economics staff are all working remotely.

“We’ve seen no real problems in the functioning of the IMM or the software. Our software is run from a third-party data center, so we didn’t anticipate any impacts there,” Patton said.

March 26, 2020

Appeals Court Sets Dates in Texas ROFR Challenge

By Tom Kleckner

The Texas Public Utility Commission has won extra time to respond to NextEra Energy’s efforts to void a Texas law giving incumbent transmission companies the right of first refusal to build new transmission lines.

The 5th U.S. Circuit Court of Appeals in New Orleans on Friday granted the PUC’s request for a 14-day extension to file response briefs, giving the commission until April 22. NextEra will have seven days to file a reply brief (20-50160).

NextEra Energy Capital Holdings and four other NextEra transmission owner/developer entities appealed to the 5th Circuit after the U.S. District Court for the Western District of Texas in February refused their motion to overturn Texas Senate Bill 1938. (See District Court Dismisses Texas ROFR Repeal.)

On March 13, the district court also rejected NextEra’s request for an injunction delaying the court’s decision, saying NextEra is unlikely to prevail on appeal (1:19-cv-00626).

The Texas law grants certificates of convenience and necessity to the owners of a new transmission line’s endpoints, essentially allowing only incumbent transmission companies to build new power lines in the state.

“The court concludes that plaintiffs have failed to make a sufficient showing to warrant an injunction pending appeal,” District Judge Lee Yeakel wrote.

The judge said an injunction would substantially harm the PUCT, the defendants in NextEra’s lawsuit, because it would be unable to “plan and facilitate” new transmission projects.

At issue is NextEra Energy Transmission (NEET) Midwest’s ability to build the $115 million Hartburg-Sabine Junction transmission project in MISO’s East Texas footprint. NEET Midwest won the project’s rights in 2018 through a competitive bidding process. (See NextEra Wins Bid to Build MISO’s 2nd Competitive Project.)

NextEra has said it expects MISO to make a decision reassigning or canceling the project by March 31.

Southwestern Public Service and East Texas Electric Cooperative have both appealed to the 5th Circuit to have their rejected intervention requests overturned. The district court denied both requests when it rejected NextEra’s motion in February.

March 25, 2020

Stakeholders Seek TO `Engagement’ on End-of-Life Tx

By Rich Heidorn Jr.

PJM stakeholders seeking to improve the transparency of transmission owners’ spending on end-of-life (EOL) projects urged the RTO Tuesday to swiftly conclude work on proposals that can be brought to a vote.

End-of-Life transmission — Ed Tatum, AMP | © *RTO Insider*

Over four special Markets and Reliability Committee meetings on transparency and end-of-life planning, American Municipal Power, Old Dominion Electric Cooperative and LS Power have proposed rule changes that would require TOs to share how they make EOL determinations, create a new category for EOLs within the Regional Transmission Expansion Plan (RTEP) and open them to competition.

“I just wanted to note I’ve only heard a solution from AMP, ODEC and LS Power. I’m aware that PJM is working on a solution. But … I’m not seeing a whole hell of a lot of engagement from others,” said Ed Tatum, AMP’s vice president for transmission, during Tuesday’s meeting, held via WebEx because of the coronavirus pandemic. “I appreciate that we’re in times that no one has ever lived through before. [But] there’s not a whole lot of new stuff coming here … . We are to a point in this process that we are very close to being able to finish it up.”

Proposals

The proposals would require TOs to have a transparent process for making EOL determinations based on industry averages, manufacturers’ recommendations and “good utility practice.” Once a TO has made a determination that a facility had reached the end of its life, that information would become part of the RTEP baseline planning process.

Currently, EOL projects developed under Tariff Attachment M-3 are designed based on assumptions and needs presented in local transmission planning meetings. For TOs that include EOL projects in FERC Form 715 planning criteria, the needs are presented in Transmission Expansion Advisory Committee and Subregional RTEP meetings.

The proposals would require all TOs to have a minimum 10-year look-ahead EOL program and to present their program’s criteria and guidelines to stakeholders at least annually.

TOs would have to present the methodology of their programs “in sufficient detail that stakeholders … can understand and, to the extent feasible, replicate the results for individual facilities determined to be EOL.”

Mark Ringhausen, vice president of engineering for ODEC, said this would apply to “bright line criteria” such as triggering new infrastructure based on the volume of outages. “I don’t think there’s going to be a lot of these, but we haven’t seen the TO criteria behind the scenes that are used for end-of-life determinations,” Ringhausen said.

EOL needs solutions developed by PJM would be subject to competitive bidding and would not be considered supplemental projects assigned to the incumbent TO.

PJM would conduct planning for all TO EOL replacements and retirements to ensure they don’t compromise reliability or create new critical facilities under FERC reliability standard CIP-014.

Timing Differences

The AMP/ODEC proposal would require TOs to notify PJM and stakeholders of any EOL conditions at least six years before the EOL date so that the project could be included in five-year planning models and opened to competitive bidding. The LS Power package would require six years’ notice for lower voltage facilities and at least eight years’ notice for facilities 230 kV and above.

Tatum and others have been attempting to gain more input on EOL spending since at least 2016. (See PJM TOs Oppose Proposal to Develop End-of-Life Criteria.)

Ringhausen said he believed the AMP-ODEC proposal complied with FERC precedent and existing rules and agreements.

But Exelon’s Robert Taylor said “we don’t share the same view that there’s no legal or contractual problems with” the proposal. “We want to see what PJM will say,” he added.

“These exact issues have recently been ruled on by FERC in the M-3 order, and some stakeholders want to go back to FERC and take it further,” Taylor said later via email. “We supported the changes in M-3 and are engaged in conversations to further improve transparency and address stakeholder needs, but to say we have been working on this for three years and done nothing is not accurate.” (See FERC Upholds PJM TOs’ Supplemental Project Rules.)

PJM Vice President of Planning Ken Seiler said RTO staff were “really looking hard at the three issues our board has asked us to work with the stakeholders on: … transparency, authority, as well as competition.”

And the authority to make the EOL determination, Seiler said, is with the TOs. “We’ve been very consistent about that message from day one: We are not in a position to make EOL decisions on transmission assets.”

He said any package backed by PJM must be consistent with FERC precedent and “be supported from a process and staffing viewpoint.”

He noted the new rules could have impacts on the planning process, the interconnection queue and cost allocation. “Does the load pay or does the generation interconnection customer pay?” he asked. “We have to be very careful and very surgical.”

In a letter to members Oct. 4, Dean Oskvig, chair of the Board’s Reliability Committee, pledged the RTO would continue efforts to improve transparency.

“PJM does not have the authority or expertise to assume responsibility for asset management decisions or to determine when a facility is at the end of its useful life or otherwise needs to be replaced. Those decisions are the sole responsibility of the Transmission Owner,” Oskvig said. He added, however, that in developing the RTEP, “in some circumstances, PJM may be in the best position to determine the more cost-effective regional solution to replace a retired facility.”

No Rush?

Exelon’s Taylor also pushed back on Tatum’s urgency.

“It is not the time to rush. Let’s get this right,” he said. “There [are] so many interlocking pieces.”

“We’re still anxiously waiting to hear from your organization as to what [Exelon’s proposal] would look like,” responded Tatum. “And so far, we’ve heard nothing. Part of the stakeholder process is to engage and to try to be part of a consensus solution.”

Taylor said the pandemic was occupying the minds of “a lot of folks who make these decisions for us.”

The project’s work plan is to target a vote on proposed packages at the May 28 MRC meeting, following a first read on April 30.

The MRC is scheduled to return to the issue in a special meeting April 17, but PJM staff said it may seek an earlier meeting date.