PJM’s Planning Committee postponed a vote by one month on “quick-fix” manual revisions to implement the RTO’s plans to expand the use of synchrophasors and make them a requirement for certain projects under the Regional Transmission Expansion Plan (RTEP).
Stakeholders were scheduled to vote on the issue charge and endorse the proposed manual language at the June 2 PC meeting to require synchrophasors — also known as phasor measurement units (PMUs) — in all new substations and major construction projects to monitor bus voltage and line flows.
Some members said they were concerned about using the quick-fix process to endorse the changes and questioned PJM staff about missing Tariff language in the proposal.
Dave Souder, PJM’s senior director of system planning, said the PMU expansion will improve reliability and give operations staff the tools they need for the increasingly dynamic monitoring needs of the grid. Souder said he recognized some stakeholders may have issues with the quick-fix method, so he requested that members express their concerns about the proposed manual language in advance of the July PC meeting.
“I really don’t want to force a quick-fix solution down the stakeholders’ throats,” Souder said.
Types of projects under the PMU Placement Strategy | PJM
Shaun Murphy of PJM reviewed the PMU problem statement, issue charge and proposed solution at the meeting. In his presentation, Murphy said language is being proposed for section 1.4.1.3 of Manual 14B to add a PMU Placement Strategy (PPS) to identify the synchrophasor device coverage needed to support the RTO’s real-time synchrophasor applications. The PPS, which includes placement targets and required operational dates, would make mandatory a program that is currently voluntary.
Making each substation “PMU ready” costs as much as $120,000, he said, and each substation would have two or three PMUs that cost about $10,000 each. As many as 889 projects could be created over a 12-year span if a voltage threshold of 100 kV for each unit is accepted, according to PJM. The PMU requirement would be effective for projects presented to the Transmission Expansion Advisory Committee after June 1, 2021.
Murphy said about 80 PMUs will be added each year at a cost of about $8 million annually.
PJM identified nearly 900 possible projects under its proposed PMU Placement Strategy. | PJM
Tom Hyzinski of GT Power Group said the yearly price tag seemed reasonable compared to the value of the information that could identify costly problems on the system. Hyzinski asked if there was any discussion by PJM on ways the cost could be allocated across stakeholders so that no one would be greatly impacted by the expense.
Souder said PJM was open to discussing cost allocation among stakeholders, but he said the RTO felt PMUs have to be expanded across the system to be effective. Souder said the technology would be required for both baseline and supplemental projects to spread the technology.
Dave Mabry of the PJM Industrial Customer Coalition (ICC) said he was thankful for the educational session PJM held on May 26 on PMUs and their benefits to the system. He asked if there were any Tariff changes considered in the PJM proposal, noting that the Tariff makes references to PMUs in generation interconnection.
Souder said PJM’s legal review concluded the manual language was sufficient.
| PJM
Mabry said the ICC opposed using the quick-fix solution and thinks the issue would benefit from further consideration by stakeholders regarding the implementation strategy and cost allocation. He said the education session convinced the ICC to support the problem statement but that the group still has reservations about the PJM proposed solution and is concerned that it will increase the justification of supplemental projects, which are reserved for incumbent transmission owners and not subject to competitive bidding.
“We don’t want to implicitly approve supplemental projects we have questions about,” he said. “Our concern is whether PMUs are going to become a nexus for trying to justify supplemental projects.”
Souder said he understood that stakeholders have concerns about supplemental projects but said if PJM only requires PMUs in baseline projects, it will limit the ability to propagate the technology across the system.
“It truly is a catch-22,” Souder said. “We need the data across the systems so we can fully utilize the tools.”
The PJM Planning Committee on June 2 unanimously endorsed the 2020 Reserve Requirement Study assumptions, which reset the installed reserve margin (IRM) and forecast pool requirement (FPR) for 2021/22 through 2023/24 and establish the initial levels for 2024/25.
Jason Quevada of PJM presented the assumptions, which were developed in the Resource Adequacy Analysis Subcommittee (RAAS). The 2020 assumptions are similar to those in 2019 except for the modeling of wind and solar, Quevada said during the PC’s meeting.
Previously, capacity values for wind and solar generators with three or more years of operating data were set based on their actual performance, with values for newer wind units set based on a combination of actual performance and class average capacity factors. The new Capacity Capability Senior Task Force will be meeting this year to develop a method for calculating wind and solar capacity values using effective load-carrying capability (ELCC), a measure of the additional load that a group of generators can supply without a reduction in reliability. (See AWEA Balks at PJM Plan on Wind, Solar Capacity.)
The ELCC approach, which is intended to address the underestimation of wind and solar output variability, is expected to have a minimal impact on the FPR.
The reserve requirement values will be based on a capacity benefit margin — the amount of transmission import capability reserved for emergency import sales — of 3,500 MW, the same as 2019. PJM will also continue using a load forecast error factor of 1%.
Staff will use the PRISM model to develop a cumulative capacity outage probability table for each week of the year except the winter peak. For the winter peak week, staff will create a table based on RTO-aggregate outage data collected between 2007/08 and 2019/20 to account for the risk caused by the large volume of concurrent outages observed during that time frame.
The final report is planned to be presented to the RAAS and the PC in September, with final approval in October.
Load Impact and Forecast Update
Andrew Gledhill of PJM’s resource adequacy planning unit presented the estimated COVID-19 impacts on load. Gledhill said that since March 24, weekday peaks have averaged 10.4% less (9,300 MW) than projected before the coronavirus pandemic. The weekday peak impacts have ranged from 0.6 to 15%, and the biggest impact to load forecasting came in the first week of May.
While impacts in May were generally larger than April, Gledhill said PJM believes some of the impact is because of increased “weather sensitivity” — increased cooling loads with summer’s arrival.
On May 26, for example, when the RTO’s weighted average daily temperature was above 70 degrees Fahrenheit, peak load was only 0.6% below expected.
“Essentially, PJM saw the impact of COVID-19 weaken a bit during the last half of May,” PJM spokeswoman Susan Buehler explained after the meeting. “It is likely some combination of increased economic activity and hotter weather driving up residential air conditioning usage as people continue telecommuting from home. We don’t yet have a full picture of which influence is greater.”
Overall energy consumption has been less affected by the pandemic, Gledhill said, with the average reduction since March 24 being 8%. Recent data suggest the reduced trend could be starting to change, he said, as a result of weather sensitivity and the lifting of stay-at-home orders across the country.
Moody’s Analytics’ forecast of U.S. real GDP | PJM
PJM last month asked FERC to approve a waiver allowing the RTO to post a revised peak load forecast for the second Incremental Auction for delivery year 2021/22.
The RTO posted its initial forecast for the auction before Feb. 1. The revised forecast reduces peak loads by 1.7% for 2020 and 1.6% for 2021, based on Moody’s Analytics’ April 2020 Economic Forecast, which predicts that third-quarter 2021 real GDP will be 7.1% lower than assumed in PJM’s posted load forecast.
PJM asked FERC to respond no later than June 15, three weeks before the start of the IA on July 6. PJM is publishing two sets of planning parameters for the auction, Gledhill said, with the first set based off the 2020 forecast and the second set based off the updated April forecast. If FERC approves the waiver, PJM will use the second set.
Competitive Planner Update
Ilyana Dropkin of PJM presented an update on the Competitive Planner, a web-based application for transmission owners and developers to participate in the RTO’s competitive planning process under Order 1000.
The current PJM process for proposal submission relies on an Excel template. Dropkin said that having a web-based application increases the speed and accuracy of the process and provides near-real-time tracking of submissions.
Beta testing was implemented May 6-20, Dropkin said, and volunteers suggested improvements and provided feedback about how the application compares to previous methods for submitting proposals.
Dropkin said registration for the new application is scheduled to begin June 22, and it will be opened for use about July 1.
Those looking to participate in the competitive planning process can get access to Competitive Planner by prequalifying through the critical energy/electric infrastructure information (CEII) process, Dropkin said.
Transmission Expansion Advisory Committee
Generation Deactivation Notification
Phil Yum of PJM provided the Transmission Expansion Advisory Committee an update on recent generation deactivation notifications, including a request received in May for Dickerson Units 1, 2 and 3. The coal-fired plant in Dickerson, Md., totals 545 MW.
Dominion transmission zone | PJM
According to a press release from plant owner GenOn Holdings, Units 1, 2 and 3 came online in 1959, 1960 and 1962, respectively. GenOn said the decision to deactivate the coal units was “driven by unfavorable economic conditions and increased costs associated with environmental compliance.”
GenOn requested a deactivation date of Aug. 13. The company will continue operating approximately 312 MW of natural gas- and oil-fired generating capacity at the site. Yum said a full result of the reliability analysis of the deactivation will be presented at the July TEAC meeting.
Yum also presented a second read of the deactivation of Chesterfield Units 5 and 6 (1,015 MW) in the Dominion zone, which are scheduled to retire on May 31, 2023. Yum said a generation deliverability problem was discovered at the Chickahominy 500/230-kV transformer, which would be overloaded with the loss of the Chickahominy-Surry 500-kV line.
PJM is recommending installing a second Chickahominy 500/230-kV transformer at an estimated cost of $22 million.
A second read was also presented on several transmission upgrade projects related to the reinstatement of the Shippingport, Pa.-based Beaver Valley nuclear plant in March. (See Beaver Valley Nuclear Plant to Stay Open.)
Massachusetts’ two U.S. senators on Friday urged ISO-NE to prioritize “state climate, energy and health goals” when evaluating responses to a request for proposals seeking transmission projects to address the 2024 retirement of the Mystic Generating Station near Boston.
Sens. Ed Markey and Elizabeth Warren, both Democrats, sent a letter criticizing the RTO’s Boston 2028 RFP planning process for listing “environmental impact” in the lowest priority category for evaluation, noting that “public health impacts are not called out at all.”
New England likely needs 1,500 MW+ of new offshore wind resources every year to achieve 80%-by-2050 decarbonization goals. | The Brattle Group
“In particular, the eventual retirement of this power plant, which is the largest fossil fuel plant in New England, presents an opportunity to continue cleaning up the New England power grid and safeguarding public health,” they said. “The six New England states have all committed to achieving at least a 75% reduction in their greenhouse gas emissions by 2050. The Carbon Free Boston initiative aims to reach a target of carbon neutrality for the city by 2050. As part of the Boston 2028 RFP, ISO-NE should consider and prioritize these targets.”
ISO-NE spokesman Matthew Kakley declined to comment Friday, saying the RTO had just received the letter and was still reviewing it.
The RTO received 36 phase one proposals in response to the request, with costs ranging from about $49 million to $745 million, and in-service dates ranging roughly from mid-2023 to 2026.
The RTO’s transmission planners will share their draft list of qualifying proposals at a Planning Advisory Committee meeting June 17.
Both Markey and Warren last November joined five of their fellow New England senators in sending a letter to the RTO accusing it of “preserving the status quo of a fossil fuel-centered resource mix” in its fuel security planning triggered by the Mystic retirement. (See Senators Ask ISO-NE to Heed States on Clean Energy.)
Side Pressure
“As Massachusetts and other New England states work to reach decarbonization targets and respond to the ongoing COVID-19 pandemic, it is more important than ever that regional transmission organizations consider these impacts as part of electric-grid planning,” the senators said.
Eight qualified transmission project sponsors submitted bids for the Boston RFP. Among them was Anbaric Development Partners, which in March announced details of its proposed 900- to 1,200-MW Mystic Reliability Wind Link transmission project, including an option for an additional 1,200 MW of transmission capacity. (See ISO-NE Planning Advisory Committee: March 18, 2020.)
“Additionally, as Massachusetts and other New England states continue efforts to limit and stop the spread of COVID-19, it is important to consider the public health effects of various kinds of electricity generation,” the senators said. “Research continues to show a link between air pollution and higher COVID-19 death rates, placing a premium on regional transmission organizations’ factoring air quality into their grid-planning decisions — particularly for communities that are disproportionately affected by COVID-19 and the historic burden of air pollution.”
Last June, about 300 people turned out in Springfield, Mass., to attend a Department of Energy Resources hearing on a proposal to alter the state’s renewable portfolio standard to include biomass plants. (See Residents Protest Biomass at Mass. DOER Hearing.)
Among the nearly 60 people testifying were a dozen biomass industry proponents and five members of the Springfield City Council opposing plans by Palmer Renewable Energy for a 35-MW wood-burning plant in East Springfield.
“Clean energy and clean air are both important policy objectives for Massachusetts and the broader New England region, and those priorities should be reflected appropriately among the evaluation criteria for the Boston 2028 RFP,” the senators said.
Last August, about 40 environmental activists marched in front of the headquarters of Connecticut’s Department of Energy and Environmental Protection to protest state regulators’ approval of a new gas-fired power plant in the town of Killingly. (See Connecticut Activists Protest Gas-fired Plant.)
The Connecticut Siting Council last June approved construction of the 650-MW Killingly Energy Center by Florida-based developer NTE Energy, permitting the plant to emit up to 2.2 million tons of carbon dioxide each year.
“Fossil fuel plants are increasingly uneconomic, particularly as the cost for new renewable electricity generation declines, and after factoring in the costs to public health from air pollution,” the senators said. “In pursuing transmission solutions to meet electricity demand and address reliability needs, ISO-NE can also strive to better integrate low- or no-carbon generation projects, with the added benefit of saving ratepayers money and avoiding the need to bail out uneconomic plants.”
Fire victims unhappy with Pacific Gas and Electric’s reorganization scheme urged U.S. Bankruptcy Judge Dennis Montali to reject it Thursday, while others asked him to appoint an examiner to look into allegations of voting problems.
The victims had most of Thursday to make their cases during the second day of arguments over whether Montali should confirm or deny PG&E’s Chapter 11 plan. (See Lawyers Argue PG&E Bankruptcy Plan.) The arguments are scheduled to continue at least through Friday, after which Montali will have to decide whether to accept PG&E’s proposal to exit bankruptcy.
The case began more than 16 months ago as PG&E faced billions of dollars in liabilities for years of devastating wildfires ignited by its transmission lines and other electrical equipment.
During the morning’s session, two lawyers and an individual fire victim contended that many victims hadn’t received ballots in time to vote on the reorganization plan by the May 15 deadline.
“The request for an appointment of an examiner is based on the very large amount of voting procedure irregularities that we’ve now seen,” attorney Bonnie Kane said. “Primarily it appears from the problem of the fire-victim creditors not receiving ballots or receiving them after the time in which they could vote.”
Montali disputed the idea that there were a large number of irregularities.
The Tubbs Fire in October 2017 wiped out part of Santa Rosa, Calif. | City of Santa Rosa
Of the approximately 80,000 fire victims sent ballots, about 50,000 responded, voting overwhelmingly for PG&E’s plan, Montali said. (See PG&E Bankruptcy Moves Toward Conclusion.) It isn’t unusual for many people not to vote in bankruptcy cases, as well as in presidential elections, he said.
“There are 50,000 people who voted, and by my count, less than 1,000 who may be, for whatever reason, in that category” of those who experienced voting difficulties, the judge said. “I don’t consider that large in relation to the 50,000 who voted.”
The vote by fire victims to approve the plan by a margin of approximately 85% wasn’t even close, he noted.
“This isn’t a city council election,” where the winner is decided by 15 votes, he said.
Montali gave more credence to fire victim Theresa Ann McDonald, who said she wanted to learn if voting problems occurred and why — just as she had wanted to know if PG&E started the Camp Fire, which burned down her home in Paradise, Calif., in November 2018.
The utility has acknowledged its equipment started the Camp Fire, the deadliest and most destructive in state history.
“Those are all pieces in putting the entire puzzle together,” McDonald said.
She said Montali could appoint an examiner after approving PG&E’s plan, allowing the bankruptcy case to move forward.
PG&E lead attorney Stephen Karotkin contended even that could jeopardize the funding the company needs to emerge from bankruptcy by casting a cloud of uncertainty over its plan.
“The debtors will be going out to the market to raise equity capital of $9 billion in the most efficient manner possible, and to have an overhang of a potential examiner here will impact the ability to effect that marketing effort on the best possible basis,” Karotkin said.
After hearing all the arguments, Montali said he would rule on the matter later.
‘Exposed to Risks of Fire’
Later in the day, fire victim William Abrams, a frequent self-represented litigant in the case, urged Montali to reject PG&E’s reorganization plan because, he said, it fails to ensure that a safe and financially stable utility emerges.
The Coffey Park neighborhood of Santa Rosa was largely destroyed by the Tubbs Fire.
“This plan put together is not in good faith,” Abrams said. “Its primary goal is to ensure that entrenched investors can cash out and exit the stock — to leave victims and the public living among the PG&E lines, exposed to risks of fire and risks associated with the fires that they cause.”
Abrams and his family had to flee their home in Santa Rosa, Calif., in October 2017, as the Tubbs Fire roared through the city. State fire investigators said PG&E equipment didn’t start the fire, but the company agreed to settle with victims as part of its restructuring.
Abrams repeated the argument that fire victims are the only large group of creditors being asked to accept PG&E stock as part of their settlement agreement. (See Skeptics Get Last Chance to Sound off on PG&E Plan.) Half of a $13.5 billion victims’ trust is expected to be funded with the utility’s stock, which could diminish in value or become worthless, he said.
PG&E said it hopes to attract “traditional utility investors” after bankruptcy, but the utility won’t pay dividends for years, he said.
“I don’t see how that is possible,” Abrams said.
The state and the California Public Utilities Commission will have to solve PG&E’s safety and financial problems within months after it leaves bankruptcy, including by raising rates, he argued.
FERC last week accepted a settlement between ReliabilityFirst and an unnamed entity in the Eastern Interconnection for violations of NERC reliability standards (NP20-15). In a notice on Friday, the commission said it would not review the settlement, leaving the $450,000 penalty intact.
In a Notice of Penalty submitted April 30, ReliabilityFirst described 34 separate violations of NERC’s critical infrastructure protection (CIP) standards. The standards at issue were:
CIP-002-5.1 — BES cyber system categorization (one violation);
CIP-004-6 — Cybersecurity personnel and training (five);
Many details of the violations were redacted on the grounds that they “could be useful to a person planning an attack on critical electric infrastructure” by helping such a person identify the entity and its cybersecurity vulnerabilities, which could in turn jeopardize security of the wider bulk power system.
The time frame covered by the violations was also not disclosed, but the regional entity said many of them were “relatively short in duration.” In addition, most of the issues posed a minimal risk to BPS reliability. Only two violations were assessed as serious; of the remaining infringements, 11 were classed as moderate risk, including three violations of CIP-007-6, four of CIP-010-2, and one each of CIP-004-6, CIP-005-5, CIP-006-6 and CIP-007-3a.
ReliabilityFirst’s coverage area includes all or portions of Delaware, New Jersey, Pennsylvania, Maryland, Virginia, Illinois, Wisconsin, Indiana, Ohio, Michigan, Kentucky, West Virginia, Tennessee and D.C. | ReliabilityFirst
The first serious risk violation involved CIP-007-3a, with the entity failing to evaluate and install necessary patches for certain programs. ReliabilityFirst attributed the issue to insufficient workforce management, leading to a mistaken assumption on the part of the entity that the vendor for the programs would track patches; however, this was not part of the vendor support agreement.
In the second serious violation, ReliabilityFirst determined that the entity had violated CIP-007-6 R4 in three instances. The first case involved improperly configured cyber assets; in the second case, server logs were not being properly reviewed; and in the third instance, cyber assets were not being monitored for security incidents. ReliabilityFirst blamed the lapses on insufficient asset and configuration management, coupled with insufficient process and workforce management.
All of the issues were self-reported by the entity and mitigated at the time of submission. ReliabilityFirst determined that a number of causes contributed to the minor violations, including issues implementing new assets, tools and processes; inadequate training; unclear or overlapping responsibilities of staff; inadequate planning; and gaps in existing processes, procedures and work instructions.
The RE acknowledged that the minor risk infringements could have been handled as compliance exceptions under different circumstances, but it said it wanted to “consider and evaluate the full scope” of the violations. It emphasized that the violations resolved in the settlement “are not indicative of” systemic issues in the entity’s CIP compliance program and predicted that many of the issues would occur less frequently as the compliance program matures.
The monetary penalty was “largely” based on the serious and moderate risk violations. In addition, a repeat noncompliance with CIP-006-6 was cited in aggravating the amount. Mitigating factors included the fact that the entity admitted to and accepted responsibility for the violations, most of which had been self-identified, and was cooperative throughout the enforcement process. The NERC Board of Trustees’ Compliance Committee approved the penalty as “appropriate for the violations and circumstances” and “consistent with NERC’s goal to promote and ensure reliability of the BPS.”
NERC has submitted the first of two compliance filings directed by FERC earlier this year, providing information about its oversight of regional entities, the development process for reliability guidelines and the role of the Electricity Information Sharing and Analysis Center (E-ISAC) in developing reliability standards (RR19-7).
NERC’s Rules of Procedures (ROP) and the delegation agreements it signed with REs in 2007 require it to perform “comprehensive” audits of their compliance monitoring and enforcement programs (CMEP) at least once every five years.
However, FERC noted in January that NERC’s performance assessments for both 2014 and 2019 failed to mention whether it had actually performed any such audits in the relevant period. The commission required NERC to produce any RE audits it had performed or provide a plan to perform them within the next 18 months.
In its filing, NERC disclosed that it had “conducted two [CMEP] audits of the regional entities” since 2014 that examined confidential information and conflict-of-interest procedures, as well as internal controls evaluations. NERC also performed two “non-CMEP audits” during the period to examine REs’ implementation of the event analysis process and of Section 215 of the Federal Power Act.
The audit reports were not provided in the public filing; NERC requested that the commission treat the information as privileged material because it “reflects confidential business information as well as NERC’s investigative audit process.”
Along with information on its audit history, NERC outlined a proposal to enhance RE audits by expanding the scope of its internal audit program — which currently focuses on CMEPs, the Organization Registration and Certification Program (ORCP) and its bulk electric system exception activities — to encompass such functions performed by the entire ERO Enterprise. These audits, dubbed “regulatory programs audits” in the proposal, would be carried out at least once every three years, either by NERC or an outside auditor.
Under the proposal, the organization would also conduct a separate “nonregulatory programs” audit every year with participation by observers from FERC. The nonregulatory programs audit would cover other delegated functions performed by the REs outside of the CMEP, ORCP and BES exception activities.
Clarity on Reliability Guideline Development
NERC’s proposed risk monitoring flowchart | NERC
FERC also ordered NERC to explain its guidance development process, how it determines if guidance documents are addressing the risk they are designed to, and “how and at what interval NERC will evaluate whether components of the guidance document should be incorporated into the reliability standards.” The mandate was prompted by concern that unlike reliability standards, which have a transparent development process, guidelines may be “based on the input of a limited number of interested participants.”
In response, NERC explained the difference between reliability standards — which set requirements for operation of the bulk power system — and reliability guidelines, which “[outline] approaches for managing potential risks to reliability.” While it emphasized that it “carefully considers” whether a guideline or a standard is best suited for a particular circumstance, the organization also acknowledged that it lacked a formal framework for addressing known and emerging reliability risks.
NERC has already begun the process of formalizing its existing process. At February’s meeting of the Member Representatives Committee, Chief Engineer Mark Lauby outlined a proposed risk management framework. (See NERC Developing Risk Mitigation Framework.) The framework, which NERC included in the compliance filing, comprises six steps:
Identifying risks and creating a risk registry;
Prioritizing risks;
Identifying and evaluating mitigation strategies;
Deploying mitigation strategies;
Measuring the strategies’ success; and
Monitoring the residual risk.
Reliability guidelines may be selected in the third step as the best method for addressing moderate- or low-impact sustained risks, or risks in areas that fall outside NERC’s jurisdiction. Responsibility for guideline development previously fell within the charters of the Operating, Planning and Critical Infrastructure Protection committees; these procedures will be consolidated under the new Reliability and Security Technical Committee (RSTC) after its first meeting next week.
The RSTC will also be responsible for evaluating the effectiveness of guidelines after they are posted. Under the RSTC charter, comments are accepted on an ongoing basis and must be reviewed every quarter. At any time, the committee may update a guideline, and every third year the guideline must be reviewed for continued applicability, usefulness and effectiveness. Metrics for evaluation of guidelines include:
performance of the BPS before and after the guideline’s introduction;
use and effectiveness of the guideline as reported by industry via survey;
industry assessment of the extent to which the guideline addresses risks; and
additional metrics specific to each guideline as determined by the RSTC.
E-ISAC Information Sharing Detailed
The final section of NERC’s filing details how the E-ISAC shares industry information with the ERO and the role that its data play in developing reliability standards. FERC requested the material because of concern that while E-ISAC’s code of conduct prohibits sharing information received from registered entities with enforcement staff, it may be permitted to share such information for the purposes of developing standards.
NERC said in its filing that the E-ISAC operates under “broad information-sharing restrictions” that generally restrict personnel from sharing any voluntarily reported information with non-ISAC staff at NERC. Limited exceptions are allowed. Specifically, such information may be shared only with:
NERC’s president and CEO for providing oversight of the E-ISAC;
NERC’s general counsel for providing legal advice to the ERO;
other persons or entities to whom the submitting entity has provided permission for such sharing; and
persons or entities authorized to review such information by the Electric Subsector Coordinating Council (ESCC).
In spite of these restrictions, NERC acknowledged that some E-ISAC data may be used to inform development of reliability standards. This is generally limited to information provided through the E-ISAC but also publicly available through other avenues. The E-ISAC may also share nonpublic reports that anonymize and aggregate otherwise protected information. Such reports might include trending analysis or analysis of a specific threat, vulnerability or risk, as long as no specific entities are implicated.
NERC plans to enhance the coordination between the E-ISAC and the Standards Department with quarterly meetings between relevant personnel so that relevant information may be exchanged more smoothly and frequently, in hopes of establishing a “regular feedback loop” to help strengthen standards development.
The E-ISAC also features prominently in the second compliance filing ordered by FERC, which is due on Sept. 28 (extended from the original deadline of July 21). NERC last week posted the draft filing for comment. It details proposed revisions to the E-ISAC’s relationship with the ESCC, along with changes to NERC’s sanction guidelines to clarify how the ERO Enterprise applies monetary and nonmonetary penalties to registered entities. The comment period runs through July 10. (See NERC Seeks Comments on Proposed ROP Changes.)
Attorneys began debating the merits of Pacific Gas and Electric’s reorganization proposal Wednesday during the final days of the utility’s 16-monthlong bankruptcy case before Judge Dennis Montali in San Francisco.
“I’m prepared to shut up and listen for your argument,” Montali told the lawyers participating in the hearing via Zoom video. Dozens of attorneys were scheduled to deliver statements Wednesday through Friday.
Stephen Karotkin | Weil, Gotshal & Manges
PG&E’s lead attorney Stephen Karotkin made the first argument. He said PG&E’s plan resulted from months of “hard-fought, good-faith” negotiations that led to agreements with all the major parties in the case, including creditors, insurance companies and the victims of major wildfires sparked by utility equipment in 2015, 2017 and 2018.
An estimated $30 billion in liabilities from those fires — including the November 2018 Camp Fire, the deadliest in state history — caused PG&E to file for bankruptcy in January 2019.
“The plan before you today has the overwhelming support of the fire victims in addition, your honor, to the support of the governor’s office [and the California Public Utilities Commission],” Karotkin told Montali. “All those approvals and support serve to ensure expedited distributions to fire victims, and that, your honor, is the principal goal that these debtors have expressed since these cases were commenced last January.” (See CPUC Approves PG&E Bankruptcy Plan.)
Karotkin warned the judge that if he doesn’t approve the plan, it could delay payments to fire victims for years. It would also prevent PG&E from taking part in a state fund to insure it against future wildfire liabilities. PG&E must exit bankruptcy by June 30 to participate in the wildfire fund established last year by Assembly Bill 1054.
Until Wednesday, a dispute between PG&E and the case’s official Tort Claimants Committee had threatened to derail the case. But the TCC and PG&E filed court papers before the hearing saying they had resolved the committee’s objections to provisions in the Chapter 11 plan, which the committee had argued could have hampered lawsuits against the utility for post-bankruptcy activities. PG&E contended the provisions were commonplace in bankruptcy cases but agreed to remove them.
One creditor group, consisting of state public employee retirement systems that bought PG&E shares, continues to oppose the reorganization proposal. It is pressing a securities fraud action against PG&E, saying it was deceived about potential fire liabilities and the resulting devaluation in PG&E stock.
Karotkin told Montali the opponents are subordinate shareholders whose opposition is outweighed by the support of the majority of PG&E’s creditors.
Some fire victims still oppose the plan. They argue victims could be shortchanged because PG&E plans to fund a $13.5 billion victims’ trust with $6.75 billion in company stock, which could end up being worth less when the utility emerges from bankruptcy. Some of the self-represented fire victims are among those scheduled to argue before Montali. (See Skeptics Get Last Chance to Sound off on PG&E Plan.)
The New York State Board on Electric Generation Siting and the Environment on Wednesday overrode local opposition to approve the 340-MW Alle-Catt Wind Farm south of Buffalo, the largest wind farm to pass Article 10 siting review in the state (17-F-0282).
| Invenergy
The order authorized the developer, Invenergy subsidiary Alle-Catt Wind Energy, to build and operate up to 116 wind turbines with associated infrastructure on approximately 30,000 acres spread across Allegany, Cattaraugus and Wyoming counties. The project had been under review since December 2017.
“In keeping with Gov. Andrew M. Cuomo’s ambitious goals for carbon reduction and for a clean-energy economy, we must develop the clean energy resources in New York state needed to help all New Yorkers,” said Siting Board Chair John B. Rhodes, who also serves as chair of the state’s Public Service Commission.
New York’s Climate Leadership and Community Protection Act (A8429), signed into law last July, mandates that 70% of electricity come from renewable resources by 2030 and that electricity generation be 100% carbon-free by 2040. (See Cuomo Sets New York’s Green Goals for 2020.)
Amish Outreach
Former PSC Commissioner Gregg Sayre, now serving as administrative law judge for the Department of Public Service, presented to the Siting Board “three hotly contested issues in this case: the outreach to the Amish community, whether the project is a beneficial addition to the state’s generation capacity and compliance with local laws.”
The towns of Freedom and Farmersville took the position that the project should be rejected because there was ineffective outreach to the Amish community in Farmersville.
“There is a separate Amish community in another town, some members of which signed participating leases, but no one in the Farmersville community signed,” Sayre said. “The draft order before you notes that in addition to the usual meetings, mailings and newspaper notices, Alle-Catt met face-to-face with members of the Farmersville community at one of their residences and discussed the project and took concerns raised by the Amish representatives.”
Another argument was that every Amish household is effectively a church, as they regularly host worship services, but DPS examiners rejected that as unpersuasive, because a home would only host such a service, on average, once in 10 months, Sayre said.
The Concerned Citizens Coalition (CCC) argued that the project will not be a beneficial addition to the state’s energy profile because transmission bottlenecks between upstate and downstate will, if not resolved in the future, constrain its capacity and cause its output to merely displace the output of other upstate wind projects.
The Siting Board rejected that position.
An Amish family bales hay on their farm in western New York | Joed Viera
The order “acknowledges there are transmission constraints that will need to be addressed in the future but determines that the need to add transmission in the future is not a reason to reject new renewable energy projects now,” Sayre said. “Requiring transmission to be built before a generation project is approved would be putting the cart before the horse.”
Those constraints are being addressed in compliance with the recently enacted Accelerated Renewable Energy Growth and Community Protection Act, which provides for expedited transmission upgrades, Sayre said. (See NY Renewable Supporters Push for New Siting Agency.)
State Power and Symbols
“One of the most hotly contested issues in this proceeding is the application of the local laws … because it’s very complicated,” Sayre said.
“Under the statute, the Siting Board applies substantive local laws to projects but may decline to apply any local law provisions that it finds to be unreasonably burdensome, with the applicant bearing the burden of proof,” Sayre said. “In this case, the local laws in the towns of Freedom and Farmersville have changed a number of times, complicating the situation.”
The Siting Board in effect sided with the developer, which responded to CCC’s opposition to exceptions by arguing that the towns in question had misinterpreted the statute as “an open-ended authority in municipal legislative bodies to adopt laws that become applicable to projects when and as adopted.”
DPS Chief Administrative Law Judge Dakin Lecakes presented the environmental review, which detailed the impacts of the project on various wildlife over its 30-year lifespan, as well as impacts on people using the state forest lands abutting the project.
For example, a setback of 1.1 times tip height will result in compliance with the 45-decibel sound limit for public lands; General Electric’s 3.6-137 turbine has a tip height of 585 feet, which makes for a setback of 643.5 feet.
Following definitions set by the U.S. Fish and Wildlife Service and the state Department of Environmental Conservation, the order approved various curtailment strategies and mitigation plans for endangered species such as the bald eagle and the northern long-eared bat.
Austin Energy has officially notified ERCOT that it plans to permanently retire one of the two original gas-fired steam units at its Decker Lake generating facility, effective Oct. 31. The municipal utility filed a notification of suspension of operations on Monday.
The 315-MW Decker 1 unit began commercial operation in 1971 and is the oldest generating unit in Austin Energy’s fleet. Decker 2 went into service seven years later and has 420 MW of capacity.
According to the utility’s latest resource plan, approved in late March by the Austin City Council, Decker 2 will be retired following the 2021 summer peak. An Austin Energy spokesperson said both units are nearing the end of their normal life expectancies.
Four other gas turbines at the facility, with a combined capacity of 192 MW, will continue to operate.
ERCOT has projected reserve margins of 17.3% and 19.7% in 2021 and 2022, respectively. Those figures include Decker 2’s capacity.
2 Market Participants File Appeals with PUC
Two ERCOT market participants have filed appeals with the Public Utility Commission regarding last year’s resettlement of 21 operating days, necessitated by a series of software errors.
Monterey TX, a qualified scheduling entity (QSE), said it is seeking “financial and injunctive relief” over what it says are “improper” charges for point-to-point (PTP) congestion revenue rights obligations in excess of its not-to-exceed bid prices in September 2019. Monterey is asking that the PUC direct ERCOT to halt its “unlawful behaviors” and is seeking more than $89,400 and accrued interest in compensation (50881).
Independent power marketer DC Energy appealed ERCOT’s resettlement of certain PTP obligations at prices more than 1 cent/MWh above the company’s not-to-exceed bid prices. DC Energy is seeking “redress of the economic penalty” it suffered from resettlement “that would put it in the same position economically” if ERCOT had honored the terms of its not-to-exceed bid prices when it resettled the day-ahead market (50871).
Both companies said they attempted to resolve their disputes with ERCOT, eventually submitting requests for alternative dispute resolution proceedings. Those requests were dismissed in April.
ERCOT’s Board of Directors in December approved the price corrections for 21 operating days, dating back to September, after it determined that real-time prices were “significantly affected” by the software error. (See “Directors Approve Price Corrections for 21 Operating Days,” ERCOT Board of Directors Briefs: Dec. 10, 2019.)
ERCOT Adjusts to DG, DR Resources
ERCOT has published a backgrounder and an accompanying video on how distributed generation and demand response are used in its footprint. Both can be found on the grid operator’s Distributed Generation webpage.
A slide from ERCOT’s backgrounder on how DG and DR are used in the grid operator’s footprint | ERCOT
Staff have been working to catalogue the various forms of DG and DR in the region, primarily utility-scale solar, commercial solar and batteries. ERCOT only has 2 MW of operational DG but has another 374 MW in its interconnection queue.
“All generation resources provide great value to the grid, and our goal is to ensure these newer resources can participate in the ERCOT market and help provide reliable electric service to Texans,” ERCOT Director of Grid Coordination Bill Blevins said in a statement.
ERCOT defines distributed generation as electrical generating facilities located at a customer’s point of delivery, of 10 MW or less and connected at a voltage less than or equal to 60 kV, which may be connected in parallel operation to the utility system.
DG that intends to be dispatched by ERCOT or provide ancillary services must register as a DG resource and undergo qualification testing. DG with installed capacity of more than 1 MW and capable of providing a net export of energy into the distribution system is required to be registered as a settlement-only distribution generator.
TAC Passes Revised ERS Change
The Technical Advisory Committee on Tuesday unanimously approved a change to how emergency response service resources return following recall.
The Nodal Protocol revision request (NPRR1006) returns ERS resources in a linear curve over a four-and-a-half-hour period following recall, instead of 10 hours. It also changes the process for annually updating the parameter so that the TAC does not have to file an NPRR.
The vote was conducted by email after a previous version was rejected on May 27 in a similar email vote. Direct Energy offered revisions that removed a real-time deployment price adder from the original language. (See “Members Disagree over Change to ERS’ Return,” ERCOT Technical Advisory Committee Briefs: May 27, 2020.)
NPRR1006 passed by a 26-0 margin and now goes before the board during its June 9 teleconference. The measure failed 4-20, with two abstentions, the week before.
NPRR1066’s implementation is expected to cost between $140,000 and $180,000 and take up to nine months.
Stakeholders challenged a proposal by transmission owners to amend the PJM Tariff regarding end-of-life (EOL) projects, accusing them of attempting to take power away from the RTO in the Regional Transmission Expansion Plan (RTEP) process.
The two-hour debate at the Transmission Owners Agreement-Administrative Committee (TOA-AC) on Monday came on the heels of a contentious vote at the Markets and Reliability Committee meeting May 28 in which a “joint stakeholders” proposal from American Municipal Power (AMP), Old Dominion Electric Cooperative (ODEC) and others was narrowly defeated. (See PJM End-of-life Proposals Fail at MRC.)
Financial Traders Joined TOs in Opposition
The joint stakeholders proposal won 64% support in a sector-weighted vote in the MRC, just short of the two-thirds threshold required to send it to a final vote of the Members Committee.
Ruta Skučas | Pierce Atwood
A review of voting records indicates the TOs were aided in their opposition by financial traders within the Other Supplier (OS) sector. The OS voted 22-15 against the stakeholders’ proposal at the MRC, with eight members abstaining.
When supporters of the proposal sought to suspend PJM rules to bring the issue to a vote of the MC despite falling short in the MRC, the OS voted 21-14 against the move, with three abstentions.
The MC reported that 13 of 15 financial traders in the sector opposed suspending the rules, with one abstention. Ten of the companies that voted against the suspension are represented by attorney Ruta Skučas of Pierce Atwood. Had the joint stakeholders been able to flip four OS votes at the MRC, the measure would have passed.
In an interview, Skučas acknowledged casting the votes on her clients’ behalf but declined to say why the traders opposed the proposal or how the EOL issue affects them.
Thirteen of 15 financial traders voted against considering the joint stakeholders’ end-of-life proposal at the Members Committee meeting May 28. Ten of those that voted “no” are represented by attorney Ruta Skučas. | PJM
“Part of this is being a member of a stakeholder body and working in coalitions and working in groups regardless of whether you’re directly affected,” she said.
Asked whether the traders had formed an alliance with the TOs, Skučas said, “I don’t want to go into specifics,” adding, “There are a number of TOs who engage in [financial transmission rights] trading.”
The traders could be calling in their chits soon, as PJM is planning to hire a consultant to recommend whether the RTO’s FTR and auction revenue rights (ARRs) markets should be changed to ensure more of the benefits go to load-serving entities rather than financial traders.
PJM’s draft of the proposed scope of work poses nine issues for the consultant to address, one-third of which question the current market’s balance between LSEs and other market players. Among the questions is whether “aspects of the current mechanism … result in profits to non-load-serving participants without commensurate or associated benefit to load.” (See PJM ARR/FTR Review Could Pit LSEs vs. Financial Traders.) The ARR/FTR Market Task Force is scheduled to meet June 17 to discuss the work scope.
M-3 Presentation
During the TOA-AC webinar Monday, Chad Heitmeyer, director of RTO policy for American Electric Power, gave a presentation on the TOs’ proposal to amend Attachment M-3 of the Tariff. Comments on the TOs’ proposal are due June 8, with the TOA-AC set to vote on it at its meeting June 10.
Heitmeyer’s presentation was similar to one he gave at a special meeting of the MRC on May 15. (See TOs Back PJM End-of-life Proposal.) He said PJM’s grid faces degraded performance and a heightened risk of failure as it nears obsolescence. The RTO has said two-thirds of all system assets are more than 40 years old, and more than one-third are more than 50 years old.
“It’s clear the system vital to our daily lives is aging,” Heitmeyer said.
The current M-3 process provides significant transparency, requiring stakeholder review of supplemental projects a minimum of three times prior to inclusion in the PJM plan, Heitmeyer said. He said the new language will increase transparency and improve planning coordination with PJM while honoring the TOs’ rights and responsibilities over asset management.
Baseline and supplemental projects since 2005 (adjusted by peak load) | PJM
On May 7, the TOs gave notice that they were supporting the principles of a PJM EOL package and considering a Federal Power Act Section 205 filing to revise the Tariff to implement it. PJM’s proposal would require TOs to have a formal program for EOL determinations and to identify potential EOL projects five years in advance. Projects that “overlap” with RTEP violations would be included in a competitive window seeking regional solutions. The RTO’s proposal also failed to win consensus, with a sector-weighted vote of 1.77 (36%) at the May 28 MRC meeting.
Heitmeyer’s presentation included the red line changes proposed by the TOs in the Tariff, which include new sections on procedures for identifying and planning EOL needs and the coordination of EOL planning with PJM.
Process Challenged
Before Heitmeyer started his presentation, Ed Tatum of AMP questioned the process by which the TOs decided to announce the potential Section 205 filing, saying he didn’t recall a vote at the TOA-AC. Tatum is a member of the TOA-AC through AMP Transmission.
Takis Laios of AEP, the outgoing chair of the TOA-AC, said a “supermajority” of the TOs had approached him and said they had the votes necessary for a Section 205 filing they wanted to take before stakeholders.
“It’s not the proper manner of acting for a select number of TOs to make unilateral decisions and couch it on behalf of the TOA-AC,” Tatum said.
Sharon Segner, vice president of LS Power, said the TOs’ proposed Tariff amendments could lead to “fairly significant” changes in the RTEP process and were “significantly more expansive” than the language in PJM’s proposal. She asked the TOs for a page-turn review of the proposed amendments.
FirstEnergy’s Jeff Stuchell, the incoming chair of the TOA-AC, said a page-turn of the amendments had not been planned because of the scheduled length of the meeting and the time involved in a full review.
Segner asked to review the first page of proposed definitions as an “interesting place to start,” pointing to the definition of an “Asset Management Project,” which is “any modification or replacement of a transmission owner’s transmission facilities that results in no more than an incidental increase in transmission capacity undertaken to perform maintenance, repair and replacement work, to address an EOL need, or to effect infrastructure security, system reliability and automation projects the transmission owner undertakes to maintain its existing electric transmission system and meet regulatory compliance requirements.”
Segner said the definition seemed similar to language contained in two CAISO orders FERC issued in September 2018 (EL17-45 and ER18-370), which she said did not define “asset management” or “incidental increase.”
The TOs would define “incidental increase” as “an increase in transmission capacity achieved by advancements in technology and/or replacements … which is not reasonably severable from an asset management project.”
Attorney Don Kaplan, representing the TOs, said the definitions were included in the proposed amendments because of stakeholder input and that the crafted language “broadly” defines asset management and incidental increase to comply with the California orders.
Kaplan said amending Attachment M-3 is permitted for the TOs if approved by FERC and that definitions can be codified given that they are consistent with applicable law.
“This is an expansion of stakeholder consultation and opportunity for input, which is not required by Order 890, and is beneficial to the planning process,” Kaplan said.
Segner asked Kaplan why the EOL projects wouldn’t be handled in the RTEP process versus Attachment M-3.
Kaplan said projects would be handled in the RTEP if they were expansions or enhancements and they were needed to address PJM planning criteria. He said the TOs’ focus was projects that are not needed to address PJM planning criteria.
Segner cited language giving the TOs responsibility for planning and constructing “any other transmission expansion or enhancement of transmission facilities that is not planned by PJM to address … planning criteria,” including NERC reliability standards, individual TO planning criteria, criteria to address economic constraints, “state agreement” projects or RTEP projects.
Segner said the proposed language seemed to reduce the types of projects that are regionally planned. “It looks like a [power] grab to me,” she said.
Kaplan said the first four categories are the only planning responsibilities that have already been transferred from the TOs to PJM. Kaplan said the last clause expands the coverage of Attachment M-3 to projects not delegated to PJM.
