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December 21, 2025

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ERCOT Board of Directors Briefs: June 9, 2020

The COVID-19 pandemic and the associated economic crash has forced ERCOT to lower its financial forecasts for this year and into 2025, but the Texas grid operator said it is still in a “sound financial position.”

“We’re feeling comfortable with where we’re getting to in 2020 and 2021,” CEO Bill Magness told his Board of Directors during a June 9 videoconference.

ERCOT is facing a $29.3 million budgetary shortfall this year, primarily because of a $16.2 million drop in interest income that is part of a 10% unfavorable variance in net available revenues. Expenses are up $4.5 million as a result of “timing differences” related to a data center refresh and major software projects.

The ISO’s system administration fee collections are down $8.5 million through April, forcing staff to revise its expectations for the year. Based on revised weather forecasts and economic conditions, ERCOT now expects to bring in $218 million in administrative fees and interest income, down from original projections of $242.6 million.

“That’s similar to historical performance,” CFO Sean Taylor said as he detailed future expectations for the board. “There’s not yet a reason for large concerns.”

Taylor said ERCOT’s administrative fee of $0.55/MWh still seems “appropriate, given current projections.”

There were no questions from board members after Taylor’s presentation. Director Peter Cramton did urge Magness to continue moving forward with the data center refresh and “innovative” software solutions.

“I don’t want to slow down at all,” Cramton said.

Demand Down, but Record Peak Expected

Staff said it still expects a record demand peak this summer, albeit about 1.5 GW lower than earlier forecasts. ERCOT’s final seasonal resource adequacy assessment reduced its projected peak demand to 75.2 GW, still above last year’s record of 74.8 GW. (See ERCOT’s Summer Reserve Margin up to 12.6%.)

The grid operator will begin the summer with a 12.6% reserve margin. ERCOT survived last summer with an 8.6% reserve margin, calling two emergency alerts when wind resources unexpectedly dropped during the early afternoon amid above-average forced outages.

“We’re still in the range where we could call energy emergency alerts because of higher-than-expected demand, a larger number of forced outages or lower-than-expected wind, but we don’t expect any reliability concerns,” said Dan Woodfin, ERCOT’s senior director of system operations.

Woodfin said that while the ISO has seen lower demand in the early-morning hours while Texans sheltered at home, it hasn’t experienced much of a shift from normal peak demand. “That’s largely driven by air conditioning load,” he said.

Consumer demand, down 3 to 4% during the early weeks of the pandemic, is now down 1 to 2%.

Mark Ruane, ERCOT’s director of settlements, retail and credit, reminded the board that the market’s operating reserve demand curve will operate with a 0.25 standard deviation shift this summer, the second of two such shifts directed by the Texas Public Utility Commission in 2018. That will result in higher and more frequent price adders, he said.

ERCOT’s daily average August forward prices on the Intercontinental Exchange have dropped from almost $100/MWh in mid-March to just above $80/MWh by mid-May.

Michigan PSC’s Talberg Among Director Nominees

The directors unanimously approved a special meeting of ERCOT’s corporate members to consider three nominees for the ERCOT board, including Michigan Public Service Commission Chair Sally Talberg and retired ISO–NE General Counsel Ray Hepper.

Talberg and Hepper have been put forward by the board’s Nominating Committee to serve three-year terms as unaffiliated directors. The COVID-19 pandemic has hampered the committee’s ability to complete interviews for the third nominee.

Assuming their approval by corporate members followed by that of Texas’ Public Utility Commission, the nominees will replace Board Chair Craven Crowell, Vice Chair Judy Walsh and Karl Pfirrmann, whose terms all expire on Dec. 31. The meeting has been scheduled for July 10.

The Nominating Committee also recommended unaffiliated director Terry Bulger receive a second term after his current term expires March 30, 2021.

Talberg was appointed to the Michigan commission in 2013 by former Governor Rick Snyder and became chair in 2016. Her term ends in July 2021, but Talberg said she would step down from the PSC should she be appointed to the ERCOT board. She has previously worked in an advisory capacity with Texas’ Public Utility Commission, served on the Organization of MISO States’ board (and as its president) and holds a master’s degree in Public Affairs from the University of Texas’ Lyndon B. Johnson School of Public Affairs.

Hepper retired from ISO-NE in 2018 and serves on the Board of Trustees for the Perkins School for the Blind in Watertown, Mass. He spent time with the U.S. Department of Justice during part of his career.

Walker Reminds MPs of PUC’s Role

PUC Chair DeAnn Walker again brought up her concerns that commission staff’s anonymous comments on an ERCOT change request are not being considered by some market participants, a repeat of her comments during a May 14 open meeting. (See “Commissioners Defend PUC Staff,” Texas Public Utility Commission Briefs: May 14, 2020.)

Walker said she had since talked to one of the market participants involved and received further information on the May 13 Protocol Revision Subcommittee meeting, where stakeholders discussed a Nodal Protocol Revision Request (NPRR) seeking to clarify battery-storage technologies’ interconnection and operations.

She said a meeting summary she had read showed a market participant had asked for the names of the commission staff that provided comments on the change request. Walker added that the market participant indicated staff’s comments “hold little bearing” and that the NPRR would not be considered until they heard from the commissioners.

“I find it totally unacceptable that a market participant or multiple market participants believe they can demand action from this commission prior to the ERCOT market participants doing their duty as market participants,” she said. “I wanted to address this here so people are clear that ERCOT market participants don’t dictate to this commission what this commission does.”

Walker suggested ERCOT stakeholders read the Texas Public Utility Regulatory Act to correct their “basic misunderstanding” of the commission’s — and its staff’s — role in ERCOT proceedings and the PUC’s “exact authority over ERCOT in any market matters.” She said in reviewing the grid operator’s Protocols, she found language indicating commission staff may comment on revision requests.

“That’s exactly what this staff did, was comment on a revision request,” Walker said. “I could get into trouble if I keep going.”

“I couldn’t agree more with your comments,” Crowell said, noting he was unaware of what Walker planned to say. “I’m assuming your comments will serve to correct the situation going forward.”

Crowell opened the phone call to further comments, but there were none.

Parakkuth Approved as ERCOT’s New CIO

The board approved Jayapal “JP” Parakkuth as vice president and chief information officer, effective with his May 11 start date.

According to his LinkedIn profile, Parakkuth, a power engineer, has more than 24 years of experience in “successfully visualizing, designing and implementing software solutions” for the grid. He has spent more than 20 years with Siemens, specializing in the digital grid and delivering major projects to PJM and CAISO.

Parakkuth has a master’s degree in power systems and electronics from the Indian Institute of Technology in Bombay and an MBA in information systems and finance from the University of Minnesota. He replaces Jerry Dreyer, who left ERCOT on May 1.

Parakkuth “hit the ground running here,” Magness said.

Corpus Christi Tx Project Gets OK

The directors approved the Regional Planning Group’s (RPG) $219 million Corpus Christi North Shore Project, which addresses more than 1 GW of future industrial load growth expected by 2024 on the north shore of Corpus Christi Bay. (See “Corpus Christi Tx Project Gets OK,” ERCOT Technical Advisory Committee Briefs: May 27, 2020.)

The RPG classified the project as a Tier 1 project because its price tag exceeds the $100 million threshold. Previously endorsed by the Technical Advisory Committee, the project is comprised of 36 miles of 345-kV lines, 8 miles of new and upgraded 138-kV lines, two new 345-kV substations and three 345/138-kV transformers.

An independent staff review found multiple NERC and ERCOT reliability planning criteria violations in the area. Staff identified several options that supported voltage needs but was unable to analyze the dynamic characteristics of the coming load. ERCOT and American Electric Power, the project’s owner, agreed to re-visit reactive compensation needs as short lead-time projects, once the load dynamic characteristics information becomes available.

Board Approves Bylaw Amendments, 13 Changes

During their July 10 special meeting, corporate members will consider bylaw amendments that widen the definition of “urgent matters” to allow virtual board and committee meetings by various electronic means. The board approved the amendments, along with other voting items, through a series of roll call votes.

ERCOT’s legal staff has approved the use of electronic votes by stakeholders during the national emergency, asking only that such meetings use communications equipment that allows attendees to hear each other. If necessary, votes can be validated after the meeting, staff said.

The directors also approved a consent agenda that included nine NPRRs, a change to the Nodal Operating Guide (NOGRR), another binding document revision request (OBDRR) and two system change requests (SCRs):

      • NPRR933: Adds specific timing requirements for retail electric providers and non-opt-in entities to notify ERCOT of the demand response and price-response programs they offer to customers, the level of participation in those programs and the deployment events associated with those programs.
      • NPRR975: Clarifies that load forecast models will be used to select the seven-day load forecast based on expected weather and requires ERCOT operations to explain its selection, improving transparency for market participants.
      • NPRR987: Includes the contribution of energy storage resources (ESRs) to physical responsive capability and real-time online reserve capacity in the ancillary service imbalance calculation.
      • NPRR989: Establishes ESRs’ technical requirements for voltage support service (including reactive power capability) and primary frequency response.
      • NPRR1006: Returns ERS resources in a linear curve over a four-and-a-half-hour period following recall, instead of 10 hours, and changes the process for annually updating the parameter.
      • NPRR1018: Clarifies several provisions regarding the termination and suspension of a qualified scheduling entity (QSE) and the ability of a load-serving entity or resource entity to act as a “virtual” or “emergency” QSE.
      • NPRR1019: Addresses switchable generation resources (SWGRs) moving from a non-ERCOT control area to the ERCOT control area by creating a proxy energy offer curve with a price floor of $4,500/MWh for each RUC-committed SWGR and including a lost revenue cost component to the switchable generation cost guarantee.
      • NPRR1021: Shortens the default uplift invoice’s issuance timeline from 180 days to 90 days and allows ERCOT to use the best available settlement data when calculating each counterparty’s share of the default uplift.
      • NPRR1022: Modifies how QSEs and congestion revenue right account holders (CRRAHs) submit banking information changes to ERCOT by removing the ability to submit the information with a Notice of Change of Information via email or fax. Creates a new form, Notice of Change of Banking Information, that a QSE/CRRAH must execute and submit through the market information system’s certified area.
      • NOGRR204: Together with NPRR989, codifies concepts described in the Battery Energy Storage Task Force key topics and concepts No. 4 (KTC 4) and establishes ESR technical requirements.
      • OBDRR017: Aligns language within the operating reserve demand curve’s methodology for calculating the real-time reserve price adder with protocol revisions under NPRR987 and changes the real-time operating reserve calculation to consider an ESR’s state of charge when calculating the resource’s contribution to the online operating reserves.
      • SCR807: Increases the CRRAHs’ total CRR transaction limit by 33% to 400,000 market transactions during CRR auctions.
      • SCR809: Updates the validation rules imposed on ERCOT’s external telemetry and used in the resource limit calculator.
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Exelon Challenges ISO-NE RFP in Bid to Extend Mystic

Seeking to extend Mystic Generating Station’s cost-of-service contract for an additional year, Exelon on Wednesday accused ISO-NE of violating its Tariff by shortcutting its transmission security review and prematurely culling bids received in response to its Boston competitive transmission solicitation.

In a complaint filed with FERC Wednesday, Exelon alleged that the RTO is putting the reliability of the Boston area at risk “by prematurely substituting the uncertain outcome” of its transmission request for proposals “for the certainty provided by Mystic” (EL20-52).

The filing came two days after ISO-NE surprised many by announcing it had narrowed 36 responses to its first competitive RFP under FERC Order 1000 to a single finalist, a $49 million project by incumbent utilities National Grid and Eversource Energy. (See National Grid, Eversource Finalist for Boston Tx Plan.)

The RFP was issued to address transmission violations expected after the shuttering of Exelon Mystic Units 8 and 9, whose retirement was extended to May 30, 2024, under a two-year, $400 million cost-of-service contract to preserve the region’s reliability. The project recommended by the RTO Monday has a projected in-service date of Oct. 1, 2023, eight months before the end of the contract.

Mystic Generating Station
Mystic Generating Station | Anbaric Development Partners

In its complaint, Exelon alleges that ISO-NE is violating its Tariff by prematurely rejecting the other bids and modifying its planning procedures to qualify the National Grid-Eversource project in time for Forward Capacity Auction 15 in February 2021, which will procure resources for capacity commitment period 2024/25.

“Twice in the last eight months, ISO-NE has sought permission from the commission to alter its Tariff to prevent the retention for reliability of … Mystic 8 and 9, and twice the commission has said that those efforts were premature,” Exelon said, referring to FERC rulings on Feb. 14 (ER20-645) and March 6 (ER20-89). (See FERC Rejects ISO-NE Fuel Security Tariff Revisions.) “Now ISO-NE has revised its planning procedures to do the same thing, but this time, without asking the commission.”

Exelon cited ISO-NE’s changes to Planning Procedure 10 (PP10) to modify the rules for determining whether planned transmission can be included in the network model for the studied capacity commitment period.

The new language said projects proposed in response to an RFP that “are reasonably likely to be in service prior to the relevant capacity commitment period … may be determined to be timely and sufficient to meet the reliability need.” It was approved by the New England Power Pool Participants Committee over Exelon’s opposition on June 4. (See “Order 1000 Questions on Tx Planning,” NEPOOL Participants Committee Briefs: June 4, 2020.)

Exelon said the change, which was not filed with FERC, violates the Tariff’s “strict rules” for determining whether planned transmission can be included in the network model. “Unless a transmission project has been certificated or executed a binding construction contract, and met important milestones, and been vetted and selected through an extensive process, the project cannot be included in the modelling,” Exelon said. It said the changes to PP10 will shorten the amount of time for project construction by as much as two years.

“We strongly disagree with Exelon’s complaint, and we look forward to addressing a number of inaccuracies contained therein,” ISO-NE spokesman Matt Kakley said Thursday. “Exelon requested to retire its Mystic plant, and we have worked diligently to accommodate their request while maintaining system reliability in the region. We are moving forward in solving the reliability issues caused by Mystic’s retirement in a timely and cost-effective manner.”

Expedited Ruling Sought

Exelon asked FERC to limit answers to its complaint to 14 days and issue an order by Aug. 4. “Expedition is crucial because ISO-NE will perform its transmission security review from June 11, 2020, through Aug. 18, 2020,” Exelon said. “Action by Aug. 4 will allow a reasonable amount of time (two weeks) for ISO-NE to correct its transmission security analysis by the Aug. 18 deadline.

“Whether ISO-NE follows the merchant approach or the incumbent approach, it is unlikely that the analysis will be completed, and a project selected and committed, before the FCA 15 auction is run in February of 2021,” it continued. “Put differently, because the transmission security analysis will be completed in August of 2020, ISO-NE will not have a vetted, approved and committed project in place in time to conduct that review. The revision to Planning Procedure No. 10, and likely the truncating of the RFP, are intended to circumvent this problem, but in taking these actions, ISO-NE runs afoul of the Federal Power Act, the ISO-NE Tariff and commission ‘rule of reason’ precedent.”

Exelon also claimed that ISO-NE “has unduly rushed” its RFP analysis, saying “its elimination of some projects based on project installed cost alone bypasses the detailed weighing of factors required for viable projects in Phase Two … and exceeds ISO-NE’s authority to cull the list of proposals in Phase One.”

The RTO said it cut the candidates down to one project on the basis of installed cost and the speed of completion.

“That is unwarranted,” said the complaint. “To be sure, the Phase One information that project sponsors are to submit includes cost information but only ‘estimated life-cycle and installed costs of the proposed solution, including a high-level itemization of the components of the cost estimate, a description of the financing being used and any cost containment or cost cap measures.’”

By contrast, Phase Two requires “detailed cost component itemization and life-cycle cost,” and permits “clarifications to cost containment or cost cap measures that were not included as part of the Phase One Proposal,” the complaint said in quoting the Tariff.

Long and Litigious

Exelon announced in 2018 that it would retire the 2,001-MW Mystic plant’s units 8 and 9, which began a long and litigious process of the RTO working to keep the plant running for “fuel security” reasons rather than for reliability, the only rationale then allowed under the Tariff.

Wednesday’s complaint is the latest move by Exelon to extend Mystic’s life after announcing in 2018 that it would retire the plant as uneconomical, citing its dependence on LNG, which is more expensive than natural gas from pipelines.

The “fuel security” cost-of-service agreement for Mystic Units 8 and 9 and the Exelon-owned LNG terminal that supplies them pays Exelon an annual fixed revenue requirement of almost $219 million for capacity commitment period 2022/23 and nearly $187 million for 2023/24, subject to true-ups for fuel costs.

In April, Exelon filed interconnection requests to keep the two combined cycle units running beyond 2024. asking the RTO to treat the units — with combined capacity of 1,600 MW in summer and 1,700 MW in winter — as “new” resources. (See Exelon Bid to Keep Mystic Units Running Provokes Outrage.)

Kakley emphasized Tuesday that the RTO has “not selected” the National Grid-Eversource project but is only proposing to advance it to further review under Phase 2. RTO staff will discuss their review of the proposals with stakeholders at the Planning Advisory Committee on June 17.

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Coal Groups Fear Accelerating Retirements

Coal industry groups have asked NERC to update its 2018 generation retirement scenario, saying declining power demand and low natural gas prices will likely force the shuttering of more than 30 GW of coal capacity in the next three years.

NERC’s December 2018 special reliability assessment report warned that “significant reliability problems could occur” if retirements occurred faster than the grid could respond to with replacement generation and needed transmission.
The report, which NERC called a “stress test,” used data from NERC’s 2017 Long-Term Reliability Assessment (LTRA), which identified 18 GW of confirmed coal retirements from 2017 through 2022. (See NERC Releases ‘Stress Test’ Analysis of Gen Retirements.)

The National Mining Association, Lignite Energy Council and ACCCE (formerly the American Coalition for Clean Coal Electricity) told NERC in a letter June 2 that a study by Energy Ventures Analysis (EVA) indicates that 38.5 to 83 GW of coal-fired generation is at risk of retirement by January 2023 because of falling coal capacity factors resulting from low gas prices, increasing renewable penetration and reduced power demand from the coronavirus pandemic.

The Sierra Club’s Beyond Coal campaign told ERO Insider it agrees that coal retirements are likely to accelerate due to the pressures cited by EVA. “However, we have not modeled these effects on our targets — nor do we have enough data over the past three months to assess a solid trend,” said Beyond Coal spokeswoman Marta Stoepker.

The coal groups told NERC that coal-fired generation in PJM, MISO and SPP — which represents 60% of the remaining coal fleet — fell by 45% in March and April, compared to the same two-month period in prior years. “Low capacity factors mean the fixed costs of operating coal-fueled units are spread over fewer megawatt-hours, making it even more challenging for coal units to recover their costs in the electricity markets and continue operating,” they said.

The groups cited Energy Information Administration data that show coal’s share of electricity generation dropped to 24% in 2019 from 31% in 2017, while natural gas’ share increased from 31% to 37% and wind and solar grew from 8% to almost 9.5%.

“The share of electricity supplied by coal is likely to fall even more during 2020, to be replaced primarily by natural gas,” the groups said. “This trend has left the grid even more vulnerable to problems associated with natural gas than it was during the 2014 polar vortex and the 2017/18 bomb cyclone, when coal was called on to meet increased load and replace power from natural gas units that experienced fuel shortages. (Coal provided more than 60% of the increased demand for power during the Bomb Cyclone.) The natural gas system is unlikely to be significantly more reliable now than it was when the SRA expressed concerns about electric sector dependence on natural gas.”

NERC Assessments

Asked whether NERC had plans to update the 2018 Special Reliability Assessment or if the data provided by the coal groups was causing it to consider an update, spokeswoman Kimberly Mielcarek told ERO Insider that NERC’s 2018 assessment was based on information available at the time, including projected retirements.

“As we do other assessments, we take any new information into account,” she said. ” … Our 2020 Long-Term Reliability Assessment, done annually and expected to be released in December, will have a ten-year outlook on expected generation retirements.”

NERC’s 2019 LTRA projected the elimination of 19 GW of coal by 2029 — just half the 38 GW forecast by EVA by 2023 in its “low retirement” scenario — dropping coal’s generation market share from 20% to 16%. The NERC report noted, however, that its projections “are based on committed retirements known to date and [are] expected to increase as the time horizon progresses.”

EVA’s April 2020 study noted that while coal plant retirements have averaged more than 14 GW annually from 2014 to 2019, only about 14.7 GW of retirements have been announced for the three years ending in January 2023.

coal retirements
Energy Ventures Analysis estimates that 38.5 to 83 GW of coal-fired generation is at risk of retirement by Jan. 2023 because of falling coal capacity factors resulting from low gas prices, increasing renewable penetration and reduced power demand from the coronavirus pandemic. | Energy Ventures Analysis

But it said retirements are likely to increase because of “intensified … pressure” on coal plants. “In the first quarter of 2020, coal generation across the lower 48 states fell by about 31% from the prior year,” EVA said.

Two Scenarios

EVA looked at two scenarios, a low retirement case that could more than double announced retirements to almost 38.5 GW and a high retirement case that would more than quintuple retirements to 83 GW. “The acceleration of coal retirements is more likely in the merchant power markets of PJM and ERCOT where coal capacity could fall by 50% or more,” EVA said.

The low retirement case assumed the following plants to be at risk for early retirement:

  • Utility plants with announced retirement dates from 2023 to 2026, which EVA said are likely to be accelerated due worsening conditions in 2020;
  • Utility plants listed for retirement under the “final scenarios” of the most recent integrated resource plans (IRP) but for which no final decision has been reached; and
  • Merchant and utility plants with capacity factors below 20% in 2019.

The high retirement case assumed the following plants at risk:

  • Utility plants with announced retirement dates in the period from 2026 to 2028, which EVA said could be accelerated due worsening conditions;
  • Utility and merchant plants with capacity factors below 40% in 2019;
  • Merchant plants in Pennsylvania, which have an increased risk of early retirement after PJM’s 2022 capacity auction because the state may join the Regional Greenhouse Gas Initiative (RGGI), increasing coal plants’ dispatch costs; and
  • Merchant plants in ERCOT with capacity factors below 60%, which are at an increased risk due to the lack of a capacity market and high fixed costs.

‘Aggressive, but not Impossible’

The Sierra Club’s Beyond Coal campaign is projecting 21 GW of retirements between January 2020 and January 2023 based on announced retirements, with an additional 30 GW expected to retire by January 2031.

Stoepker said EVA’s retirement projections are “an aggressive, but not impossible, outcome.”

“2015 is when we saw the greatest drop in coal energy generation (21 GW). If we matched that rate in 2020/22, we’d have 63 GW retire (i.e., 42 GW beyond currently announced retirements).”

EVA projects PJM’s coal fleet would be reduced from the current 52.7 GW to 37 GW in its low retirement scenario (–30%) and to 19 GW (–64%) in its high retirement scenario.

PJM offered no comment in response to EVA’s estimates but pointed to its 2018 Fuel Security Study, which found that under two “escalated” retirement scenarios, combined with extreme winter load, “the system may be at risk for emergency procedures and load loss.”

One of the scenarios modeled retirements of 32.2 GW by 2023, with 16.8 GW of replacement capacity added to meet the installed reserve margin requirement of 15.8%. A second one assumed 15.6 GW of retirements, with no replacements.

Public Service Company of Oklahoma notified ERCOT in January it will retire the 650-MW coal-fired Oklaunion Power Station in the Texas Panhandle by Oct. 1. | AEP

Combining the extreme load, escalated retirements and pipeline outages resulted in numerous scenarios with voltage reductions, reserve shortages and load sheds of as much as 83 hours — about 3.5 days.

PJM described the analysis as a “stress test … intended to discover the tipping point when the PJM system begins to be impacted.” Some critics said the escalated retirement scenarios were unrealistic because they assumed no more than half of such retired capacity would be replaced. (See PJM Begins Campaign for ‘Fuel Security’ Payments.)

EVA sees ERCOT’s fleet dropping from the current 14.2 GW to 11.2 GW under the low retirement scenario (–21%) and 7.5 GW in the high retirement model (–47%).

Asked to comment on the projections, ERCOT spokeswoman Lindsey Hughes said the latest Capacity, Demand and Reserves report issued in May listed only one planned coal retirement, the 650-MW Oklaunion Unit 1 plant, which is expected to be shuttered by Oct. 1. The report said a “reliability analysis study determined the unit is not required to support ERCOT system reliability.” (See PSO Officially Retires Oklaunion Coal Plant.)

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FERC Rejects Challenge to CIP Standards

FERC on Tuesday rejected a complaint by security gadfly Michael Mabee alleging that NERC’s physical security standard is ineffectual and unenforced (EL20-21).

Mabee’s complaint alleged that reliability standard CIP-014-2 is “inadequate” and that enforcement “seems nonexistent” because few violations have been cited since it took effect in 2015.

The standard, prompted by the 2013 sniper attack on Pacific Gas and Electric’s Metcalf substation, requires the protection of transmission stations, substations and control centers that “if rendered inoperable or damaged as a result of a physical attack could result in instability, uncontrolled separation or cascading within an interconnection.”

The commission said it had already rejected many of the arguments Mabee made in Order 802, its 2014 ruling approving the first version of the physical security standard (CIP-014-1) and in its 2015 order denying rehearing. The complaint’s new arguments “are either unsupported or misapprehend the requirements” of the standard, FERC said.

Few Violations

Mabee contended that there had been only four violations cited while 245 physical attacks have been reported to the Department of Energy through its Form OE-417 Electric Emergency Incident and Disturbance Reports since the standard took effect.

The commission denied that the small number of violations is proof the standard is not being enforced, saying “it is equally plausible that the small number of violations could be attributed to industry compliance.”

It said the higher number of Form OE-417 filings was not persuasive because “there is no evidence how many of these attacks, if any, were against critical facilities” subject to the standard.

“NERC’s comments also indicate that, as of January 31, 2020, there have been 16 (not four) instances of noncompliance … and that NERC and the regional entities are currently reviewing other instances.”

Coordinated Attacks, Generation

Mabee said the standard is lacking because it does not require registered entities to identify critical facilities based on a coordinated attack of multiple facilities and does not apply to generator owners and operators or smaller transmission lines.

In its order denying rehearing, the commission said by “protecting individual critical facilities, responsible entities will necessarily protect critical facilities against simultaneous attacks.”

Regarding suggestions to expand the scope of covered facilities to include those not individually critical, FERC said, “We are not prepared to do so at this early stage of industry experience with the new requirements.”

The commission said Mabee’s complaint “does not provide any new basis for expanding the scope.”

cip standards
Transmission line near Calvert Cliffs nuclear power plant | © ERO Insider

FERC previously had rejected calls to include generator owners and operators under the standard, saying “a generation facility does not have the same critical functionality as certain transmission stations and transmission substations due to the limited size of generating plants, the availability of other generation capacity connected to the grid and planned resilience of the transmission system to react to the loss of a generation facility.”

Mabee said the standard’s requirement that registered entities obtain third-party verification of their protections could allow collusion. A transmission owner performing a third-party review could “go easy” on another TO in return for reciprocal treatment, he alleged.

“But the complaint offers no evidence that registered entities have engaged, or intend to engage, in bad faith,” FERC said. “We find no reason to conclude that registered entities will abuse this process. Moreover, a sham verification would not benefit the registered entity because … even if a registered entity’s list of critical facilities is verified by a third-party,” the entities could face penalties from NERC for noncompliance.

“While registered entities must address third-party recommendations, Order No. 802 made clear that regional entities, NERC and the commission retain regulatory oversight.”

Effectiveness of Protections

Mabee’s complaint contended that the standard does not require that physical security plans be effective or spell out what the plans should include. The commission said the claim ignores Requirement R5, “which identifies mandatory attributes that must be present in physical security plans” and says that physical security plans must have “[r]esiliency or security measures designed collectively to deter, detect, delay, assess, communicate and respond to potential physical threats and vulnerabilities identified” by the entity’s security evaluation.

He also contended that it does not require updates to vulnerability evaluations and security plans. FERC said although the standard doesn’t require updates to the threat and vulnerability evaluations on a periodic basis, it does require entities “to evaluate evolving physical threats.”

The Edison Electric Institute, National Rural Electric Cooperative Association (NRECA), American Public Power Association (APPA), Transmission Access Policy Study Group (TAPS) and Large Public Power Council (LPPC) were among those who opposed the complaint.

Mabee was supported by several individuals, the Secure the Grid Coalition, the Task Force on National and Homeland Security, the Town of Mount Vernon and the Foundation for Resilient Societies.

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Public Policy Challenges Top NYISO Grid Plans

NYISO on Wednesday released its annual Power Trends report, this year focusing on how the grid is being shaped by public policy – amid a global pandemic in which New York was the epicenter for COVID-19 cases in the United States.

“Obviously, the COVID-19 pandemic has altered significantly the way that people work and live their lives, and as a result the challenges and changes to the electric sector,” CEO Rich Dewey said in a press conference.

The economic shutdown has reduced load levels statewide by an average of 8%, and a return to pre-pandemic demand will depend on how quickly the economy rebounds, he said.

2020 Gold Book Baseline Summer and Winter Peak Forecasts. | NYISO

The ISO will continue “to keep our eyes on some of those demand patterns and how they might influence the way markets work,” Dewey said.

Though the study found that increasing electrification will likely flip the peak from summer to winter by 2050, the ISO still plans for reliability based on the current summer peak, when air-conditioning use spikes demand, he said.

“The electrification of transportation and building heating systems will certainly change the demand patterns that we need to manage,” said Executive Vice President Emilie Nelson.

Studying these trends “will allow us to develop the market design and further the planning processes necessary to support this transition,” Nelson said. “The ISO hopes to integrate renewable resources like wind and solar not only operationally but also in terms of planning.”

The ISO in December published a 122-page “Grid in Transition” report and in January decided to devote at least one day a month in 2020 to discussing how to meet the clean energy goals set by last year’s Climate Leadership and Community Protection Act (A8429). The law mandates that the state get 70% of electricity from renewable energy resources by 2030 and reach 100% carbon-free electricity by 2040. (See NYISO Focus Turns to Grid ‘Transition’.)

Transmission Buildout

“New technologies are impacting the industry at large, so it’s a very exciting time in the utility industry, whether it’s new renewable projects, whether it’s wind or solar, distributed energy resources, it’s really changing the way energy is produced and how it’s moved and used,” Dewey said.

New York State proposed generation by fuel type in (MW) as of March 1, 2020. | NYISO

The state’s Siting Board earlier in June approved a 340-MW wind project south of Buffalo, to date the largest wind farm to pass Article 10 review in New York (17-F-0282). (See NY Regulators Approve 340-MW Alle-Catt Wind Farm.)

In addition to the increasing influence of public policy decisions on the ISO, infrastructure is becoming more important, he said.

“Specific to the infrastructure of transmission, we remain very, very bullish on the need to build out the infrastructure, and transmission is going to be a very important part,” Dewey said. “We continue to study and promote the notion that we need additional infrastructure.”

The state’s recently enacted Accelerated Renewable Energy Growth and Community Protection Act addresses transmission constraints directly by providing for expedited transmission upgrades. (See NY Renewable Supporters Push for New Siting Agency.)

The ISO is mindful of the economic impact from the pandemic and as always is “committed to looking at the most cost-effective way of being able to both hit the goals and to deliver power to consumers,” Dewey said.

The study also considers the transmission implications of developing 9 GW of offshore wind in New York by 2035. The New York Public Service Commission in April granted a state agency permission to solicit up to 2,500 MW of offshore wind energy this year. (See NYPSC Greenlights 2,500-MW Offshore Wind RFP.)

New York Control Area Summer 2020 Installed Capacity (MW) by fuel source, upstate and downstate. | NYISO

Dewey was asked why the ISO includes the controversial 1,000-MW Champlain Hudson Power Express (CHPE) project in its trend forecasts. FEFERC OKs Negotiated Rates for Champlain Hudson Project.)

Dewey said that the project is in the interconnection queue and that the ISO’s use of it in planning does not signify endorsement of it.

Nonetheless, he added, “the project that can deliver low-carbon power down to New York City, that’s something that’s probably got to be seriously considered from a policy standpoint.”

Carbon Pricing Still Tops

“First and foremost of the ISO’s initiatives is our proposal to implement carbon pricing,” Dewey said. “We look at this as the most effective, viable means to attract the right kind of investment for renewables that is going to be so important for New York State to achieve its clean energy goals.”

Additions, uprates and deactivations (Nameplate Capacity). | NYISO

Speaking at an industry forum in March, NYISO Principal Economist Nicole Bouchez said the ISO determined its carbon price should be incorporated into the energy rather than capacity market because of transmission constraints that prevent upstate New York, which has 87% zero-emission generation, from delivering it to downstate, where only 27% of the mix is renewable. (See Carbon Pricing Gains Popularity — and Doubts.)

“We remain committed to promoting carbon pricing,” Dewey said. “We think using a social cost of carbon embedded in the markets is going to be the most effective and cost-efficient means to be able to hit those goals.”

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PG&E Names New Board of Directors

PG&E Corp. named a nearly new board of directors Wednesday to guide the troubled utility after it emerges from bankruptcy, probably later this month.

Eleven new board members will join three current members. The boards of parent PG&E Corp. and utility subsidiary Pacific Gas and Electric will be largely the same, PG&E said in a news release.

PG&E Board of Directors
PG&E is headquartered in San Francisco’s downtown financial district.

The new board members include Mike Niggli, a 13-year veteran of Sempra Energy, who served as president of San Diego Gas & Electric from 2010 to 2013; Craig Fugate, the administrator of the Federal Emergency Management Agency (FEMA) from 2009 to 2017; and retired Admiral Mark Ferguson, former commander of U.S. Navy forces in Europe and Africa.

Former FERC Commissioner and PG&E Corp. Chair Nora Mead Brownell is among those who will leave the board. | PG&E

Among those departing will be PG&E Chair Nora Mead Brownell, a former FERC commissioner and Pennsylvania utility regulator. Kristine Schmidt, a former member of CAISO’s Western Energy Imbalance Market Governing Body, who was an adviser to Brownell at FERC, will also be leaving.

The board shakeup is intended to meet the demands of Gov. Gavin Newsom and California Public Utilities Commission President Marybel Batjer to appoint a board of directors with more Californians and greater safety expertise. (See PG&E Tries to Appease Governor with New Plan.)

“Putting in place a new board is a critical component of PG&E’s plan to emerge from bankruptcy as a reimagined utility — one that is in touch with its customers and communities and is safe, reliable, financially stable and capable of helping California meet its energy goals,” Brownell said in a statement.

Bill Smith will remain on the board and serve as interim CEO after Bill Johnson’s departure on June 30. | PG&E

PG&E CEO Bill Johnson previously announced he’ll retire June 30 — the deadline for PG&E to exit bankruptcy and participate in a state wildfire insurance fund. Remaining board member Bill Smith will serve as acting CEO until Johnson’s replacement is named.

Liabilities from two years of massive wildfires sparked by its equipment drove PG&E to seek bankruptcy protection in January 2019.

The utility’s lawyers made their closing arguments in the bankruptcy case Monday, and U.S. Bankruptcy Judge Dennis Montali is expected soon to rule on whether to accept or reject PG&E’s Chapter 11 reorganization plan. (See Lawyers Close PG&E Bankruptcy Case.)

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Calif. Energy Commission OKs Electrification Rules

Two San Francisco Bay Area cities will join a growing list of communities in California with building electrification ordinances, following the California Energy Commission’s approval Wednesday.

The CEC unanimously accepted ordinances passed by the city councils of Richmond and Hayward, Calif. The new rules needed commission approval because they exceed the efficiency requirements of the state’s 2019 energy code.

Richmond’s ordinance requires new residential buildings to be mainly electric with gas allowed for cooking and fireplaces. It requires new high-rise buildings, both residential and nonresidential, to be all-electric.

electrification
Richmond, Calif., home to a Chevron refinery, will join the growing list of cities with building electrification requirements.

In Hayward, new low-rise housing must be all-electric.

“The city of Hayward was one of the first California cities to adopt a climate action plan in 2009, and sustainability remains a top priority,” the city’s mayor, Barbara Halliday, told the commissioners. The city, popular with Silicon Valley workers, is expected to add 2,000 housing units in the next ten years, she said.

There are now 25 cities with CEC-approved electrification ordinances, according to commission staff, including San Jose, Santa Rosa and Berkeley. Some require types of new construction to be fully electrified while others have less-stringent rules. The city of Los Altos Hills, for example, requires new homes to have electric space and water heating.

The CEC and the California Public Utilities Commission have prioritized the switch to electric appliances, including heat-pump water heaters and HVAC units, and away from methane-emitting gas appliances. The state legislature devoted $200 million to jump-start the electrification effort in 2018, with grants administered by the CEC. (See California Travels down Electrification Road.)

electrification
California energy commissioners, meeting here in February, held their business meeting Wednesday via Zoom. | © RTO Insider

On Wednesday, the CEC awarded more than $4.3 million in grants to the Association for Energy Affordability, a group that advocates for energy efficient buildings. The grants were for two programs to advance “next-generation heating, cooling and water heating systems,” including a pilot project to install central heat-pump water-heating systems in apartment buildings in low-income communities.

The CEC also awarded more than $8 million in grants to lower greenhouse gas emissions from healthcare facilities and large commercial buildings. The awards to five entities included nearly $1.5 million to Southern California Gas Co. (SoCalGas) to demonstrate “an emerging and replicable gas heat pump technology that can reduce natural gas consumption for hot water heating by at least 35% in large commercial buildings.”

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TOs Vote to File End-of-life Rules with FERC

PJM Transmission Owners voted Wednesday to seek FERC approval for Tariff amendments governing end-of-life (EOL) projects.

Jeff Stuchell, manager of FERC & transmission technical support for FirstEnergy and chairman of the PJM Transmission Owners Agreement-Administrative Committee (TOA-AC), said the committee approved a Federal Power Act Section 205 filing of the Attachment M-3 amendments following the consultation and voting procedures detailed in the Consolidated Transmission Owners Agreement (CTOA).

[UPDATE: The amendments were filed with FERC on Friday (ER20-2046).]

| © RTO Insider

Wednesday’s vote came a little more than a week after stakeholders challenged the TOs’ amendments during a special session of the TOA-AC on June 1 and two weeks after a vote at the May 28 Markets and Reliability Committee meeting in which a “joint stakeholders” proposal from American Municipal Power (AMP), Old Dominion Electric Cooperative (ODEC) and others regarding EOL projects was narrowly defeated. (See PJM TOs Outline End-of-life Tariff Amendments.)

The joint stakeholders will try again to win approval of their plan at the June 18 Members Committee meeting.

Concern Addressed

One revision was made to the TOs’ amendments after a stakeholder raised a concern that EOL projects could potentially remove FERC Form 715 planning criteria from PJM planning under Schedule 6 of the Operating Agreement and cause them to be planned by the TOs under Attachment M-3.

To address those concerns, TOs added to the definition of “Attachment M-3 Project,” revising it with the following clause: “‘Attachment M-3 Project’ does not include a project to address Form No. 715 EOL Planning Criteria.”

“This addition should put to rest the concern that the proposed Attachment M-3 amendments change the responsibility for planning Form No. 715 transmission projects,” the TOs wrote.

Stakeholder Responses

Leading up to Wednesday’s vote, the TOs solicited stakeholders’ comments on the proposed amendments.

The Organization of PJM States (OPSI) proposed several edits, including requiring the TOs to provide annual EOL project lists to OPSI and PJM.

The Joint Consumer Advocates wrote that the proposed amendments are “unjust, unreasonable and otherwise not permissible on procedural and substantive grounds,” saying a May 8 notice filed by the TOs did not comply with provisions of the CTOA. The advocates took exception to new definitions in the amendments and what they said was an improper “expansion and reliance on inapplicable FERC precedent regarding asset management.”

“The PJM TOs, and PJM, have a responsibility to work constructively with all stakeholders to endeavor to develop proposals that are broadly supported and meet FERC standards for an open and transparent planning process,” the advocates wrote.

In joint comments, Old Dominion Electric Cooperative (ODEC), American Municipal Power (AMP), LS Power and the PJM Industrial Customer Coalition (ICC) echoed the Advocates’ remarks, saying the proposed revisions are not supported by a majority of PJM members. The stakeholders encouraged the TOs to continue discussions with members to ensure that EOL planning is conducted by PJM.

Ed Tatum of AMP said he was discouraged by Wednesday’s vote, saying it was a “subset” of the TOs in the TOA-AC who decided to draft the amendments. “I’m disappointed the TOs would take this action,” he said.

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MISO Solar Dispatch a Go, FERC Says

MISO can begin requiring new solar generation in its footprint to become dispatchable by early 2022, FERC ruled Tuesday.

The commission’s order approves a MISO Tariff change requiring all solar resources that achieve commercial operation on or after March 15, 2020, to register as dispatchable intermittent resources (DIRs) and become dispatchable by March 15, 2022 (ER20-595). The RTO is using a ruleset nearly identical to the one that brought wind resources under dispatch in 2011. (See “Solar Dispatch Imminent,” MISO Market Subcommittee Briefs: Dec. 3, 2019.)

MISO has about 46 GW of solar generation pending in its interconnection queue.

“We expect solar to grow 10 to 20 times. It’s small now; we’d like to get ahead of it,” MISO Executive Director of Market Strategy and Design Scott Wright said during the RTO’s December Board Week.

MISO solar dispatch
| Entergy New Orleans

In its ruling, FERC said MISO satisfactorily cleared up the commission’s earlier confusion about whether the generator interconnection agreement (GIA) or commercial operation date will determine the 2022 deadline to register. (See FERC Seeks Info on MISO Dispatchable Solar Push.)

MISO said it will exempt the DIR registration requirement for all solar resources in commercial operation prior to March 15, 2020. However, resources that have GIAs executed by March 15, 2020, but are not yet in commercial operation must plan to register and respond to MISO dispatch signals.

MISO said at least one solar developer with a project lined up to come online this summer will have to push back its commercial operation date in order to install the proper communication equipment needed to receive the RTO’s dispatch instructions.

Entergy opposed MISO’s grandfathering plan, saying solar projects that had a GIA executed by mid-March should also be exempted from the DIR registration requirement. The utility will soon either own or purchase output from six solar facilities currently under development. Entergy said the late-stage alterations needed for the solar facilities at their “advanced stage of development” would place an undue burden on the utility.

“MISO’s proposal would unfairly change a Tariff rule that Entergy and other generation developers may have relied upon when planning and making arrangements pertaining to such facilities,” Entergy said.

But FERC disagreed, concluding that facilities with GIAs are not the same as units already in service. The commission also said MISO’s two-year transition period is a reasonable amount of time to purchase and install communication equipment for the solar facilities.

“MISO states that, even if there were no imminent reliability threat, MISO’s proposal follows NERC’s suggestions for how MISO as a transmission provider should dispatch inverter-based resource,” FERC pointed out.

The commission also said MISO doesn’t need to be in the thick of a solar generation boom before it proposes new dispatch rules.

“We also find that it is reasonable for MISO to propose these revisions without waiting until solar penetration has reached a point when its lack of dispatchability may significantly affect reliability,” it said.

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‘Plan B’ for PG&E Takeover Moves Forward

SACRAMENTO, Calif. — California lawmakers advanced a measure Tuesday that would let the state appoint a receiver or take over Pacific Gas and Electric if the utility fails to provide safe and reliable service after it leaves bankruptcy.

Senate Bill 350, called the Golden State Energy Act, cleared the state Assembly’s Utilities and Energy Committee on Tuesday by a vote of 12-2.

PG&E takeover
Sen. Jerry Hill addressed the Assembly’s Utilities and Energy Committee on Tuesday. | California Assembly

In his remarks to the committee Tuesday, bill author Sen. Jerry Hill (D-San Mateo) said the measure is a “plan B” if PG&E doesn’t undergo the safety transformation it has promised.

“As much as we push forward with that change, we must also be prepared to step in should the company not meet its obligations or commitments in the future,” Hill said. “SB 350 is our preparation. I hope it’s unnecessary and that it’s never triggered. But we owe this preparation to the residents of San Bruno and Santa Rosa and Napa and Butte County and Paradise” — communities devastated by PG&E-caused catastrophes in the past decade.

It is unlikely the state will try to seize PG&E anytime soon, especially with its budget in shambles from the COVID-19 shutdown. The purchase of PG&E would cost tens of billions of dollars and saddle the state with the task of performing the estimated $40 billion in upgrades that PG&E’s aging infrastructure requires.

State investigators, for example, blamed a poorly maintained 100-year-old PG&E power line for starting the November 2018 Camp Fire, the state’s deadliest and most destructive wildland blaze. The Camp Fire and a series of conflagrations in 2017 caused PG&E to file for bankruptcy in January 2019. The utility is expected to emerge from its Chapter 11 reorganization later this month.

As PG&E has been trying to leave bankruptcy, state officials have been putting mechanisms in place to allow for a takeover of the utility if needed.

The California Public Utilities Commission recently approved PG&E’s reorganization plan, along with a process of enhanced oversight and escalating enforcement that could lead to the CPUC revoking PG&E’s certificate of public convenience and necessity (CPCN), its license to operate as a monopoly utility in central and Northern California. (See CPUC Approves PG&E Bankruptcy Plan.)

In a May 28 meeting, CPUC Commissioner Martha Guzman Aceves said her vote for PG&E’s bankruptcy plan was bolstered by the likely passage of SB 350. The bill would authorize the CPUC to ask a court to appoint a receiver for PG&E or to revoke its CPCN. The bill allows the governor to establish a nonprofit public-benefit corporation called Golden State Energy to take over PG&E’s assets and operations.

“This bill will give ratepayers a genuine alternative,” Guzman Aceves said. “If PG&E fails to provide safe, reliable and affordable energy service, then the commission could petition the court to appoint a receiver or revoke PG&E’s CPCN.”

The bill next faces a vote on the Assembly floor and a concurrence vote by the Senate on Assembly amendments. After that it could go to Newsom for his signature. The governor has indicated he supports the measure.