The order represents a “fundamental and unlawful shift in transmission planning responsibility from the regional transmission organization, PJM, to the PJM Transmission Owners,” said consumer advocates for Delaware, D.C., Indiana, New Jersey, Ohio and West Virginia, who joined American Municipal Power, AMP Transmission, Blue Ridge Power Agency, LS Power, Old Dominion Electric Cooperative, the PJM Industrial Customer Coalition and the Public Power Association of New Jersey in filing one challenge.
They said the order is improper because it gives the TOs unilateral authority to propose revisions related to transmission planning, gives them veto authority over future planning methodologies, restricts PJM’s role as the regional planner and reduces transparency and the rights of other stakeholders.
“Not only is the order’s decision to accept the TO proposal not supported by substantial evidence, the TO proposal is contrary to the plain language of the governing documents upon which it is based,” they said. “The Aug. 11 order fails to reconcile the TO proposal’s conflicts with regional transmission planning protocols and procedures established in the PJM Operating Agreement.”
The New Jersey Board of Public Utilities also filed a challenge saying the order violates the transparency principles of Order 890 and ignores cost concerns over “unchecked transmission owner investment.”
“After transmission spending remained between approximately $1.7 billion and $3.7 billion from 2005 to 2009, it rose to approximately $8 billion in 2018. Transmission owners invested approximately $69.6 billion in baseline and supplemental projects from 2005 through 2019,” the BPU said. “New Jersey has been particularly hard hit. For example, over a third of PJM’s total $55.6 billion in transmission between 2015 and 2019 occurred in New Jersey.”
The TOs had proposed to identify and include asset-management projects within the existing planning procedures of Tariff Attachment M-3 and to include procedures for the identification and planning for EOL needs of transmission lines 100 kV and above. They voted in June to approve a Federal Power Act Section 205 filing of the proposed amendments.
Stakeholders challenging the filing asserted that the TOs do not have “exclusive filing rights” in regard to EOL projects and that PJM members maintain rights under the OA to also make filings related to EOL projects. A competing, joint stakeholder proposal is still pending before FERC (ER20-2308). (See PJM Files EOL Proposal over TO Protest.)
Below is a summary of the issues scheduled to be brought to a vote at the PJM Markets and Reliability and Members committees on Thursday. Each item is listed by agenda number, description and projected time of discussion, followed by a summary of the issue and links to prior coverage in RTO Insider.
RTO Insider will be covering the discussions and votes. See next Tuesday’s newsletter for a full report.
Markets and Reliability Committee
Endorsements/Approvals (9:10-11:00)
1. Cost Development Subcommittee (9:10-9:20)
Members will be asked to endorse a revised charter for the Cost Development Subcommittee, which has been dormant since 2013 but is being revived to address issues including the biennial review of Manual 15 and clarifications to variable operations and maintenance rules and the fuel-cost policy. The revised charter would have the subcommittee report to the Market Implementation Committee instead of the MRC.
2. Critical Infrastructure Stakeholder Oversight Senior Task Force (9:20-9:40)
Greg Poulos, executive director of the Consumer Advocates of the PJM States, and Erik Heinle of the D.C. Office of the People’s Counsel will ask members to revoke an existing issue charge for Planning Committee special sessions on critical infrastructure stakeholder oversight and approve a new issue charge creating the Critical Infrastructure Stakeholder Oversight Senior Task Force, which would report to the MRC.
3. PMU Placement in RTEP Planning Process (9:40-10:10)
Members will be asked to endorse changes to Manual 01: Control Center and Data Exchange Requirements and Manual 14B: PJM Region Transmission Planning Process to expand the use of synchrophasors and make them a requirement for certain projects under the Regional Transmission Expansion Plan. (See “Manual 1 Changes for PMUs,” PJM Operating Committee Briefs: Aug. 6, 2020
4. Capacity Capability Senior Task Force Proposed Solutions (10:10-11:00)
The MRC will be asked to endorse rules for using the effective load-carrying capability (ELCC) method to calculate the capability of limited-duration, intermittent and combination (limited-duration plus intermittent) resources, the results of which would be revised with changes to the resource mix or load shape.
The rules will govern the timing of annual ELCC analyses; the allocation of ELCC capability of a resource class to specific units; the simulated dispatch of energy storage and hybrid resources; and the determination of resource classes. The main motion, Package A, which does not include a transition plan, received 64% support of the task force. Package D, which includes a transition, won 57% support and may be considered if the main motion fails.
MC endorsement will be sought on the same day.
Members Committee
Consent Agenda (12:35-12:40)
B. The committee will be asked to approve Tariff clean-up provisions related to its credit and risk management revisions to the Tariff and Operating Agreement, which FERC accepted on May 30 (ER20-1451). The changes are needed to ensure consistency with other recent rule changes and to avoid confusion.
C. Members will vote on proposed OA revisions to grant transmission owners access to the Dispatch Interactive Map Application. (See “DIMA Quick Fix Endorsed,” PJM OC Briefs: July 9, 2020.)
D. The committee will vote on OA revisions to clarify when capacity benefits of market efficiency projects are calculated, removing obsolete language from the Tariff that conflicted with the OA. (See “Market Efficiency Proposals,” PJM MRC Briefs: Aug. 20, 2020.)
Endorsements/Approvals (12:40-1:10)
1. Capacity Capability Senior Task Force Proposed Solutions (12:40-1:10)
Executives from Volvo and FedEx told the Edison Electric Institute last week they are fully committed to transitioning to electric trucks but need utilities’ help on rate structures and charging infrastructure.
For “what we do, which is last-mile delivery … electricity is the most efficient energy source for a vehicle fuel,” said Russell Musgrove, managing director of global vehicles for FedEx Express, which is adding 1,000 electric trucks in California.
Keith Brandis, Volvo | Edison Electric Institute
“I know a couple years ago there were startups and other companies that predicted that electric trucks were going to be right around the corner, and then they … didn’t come through,” said Keith Brandis, vice president of partnerships and strategic solutions for Volvo Group, which will begin production of electric heavy-duty trucks in North America later this year. “If I could speak to your audience of CEOs, I’d like for them to know that the future is happening now.”
Patti Poppe, CEO of CMS Energy and Consumers Energy, moderated the discussion with Musgrove and Brandis during EEI’s Virtual Leadership Summit on Wednesday.
Based on current battery range and charging infrastructure, Volvo’s trucks will initially be used for local and regional deliveries. “We’re not talking a nationwide corridor yet. But it’s happening. And we’re saying: Now is the time for having these real plans for grid upgrades, for charging infrastructure.”
Production of Volvo’s VNR Electric trucks follows the company’s earlier forays into hybrid transit buses and medium-duty trucks. The company also is participating in the Low Impact Green Heavy Transport Solutions project, a collaboration among 15 public and private partners, including the ports of Long Beach and Los Angeles, to demonstrate the viability of all-electric freight hauling.
Brandis said the project is starting with 23 pilot trucks at four sites. “It includes everything in a complete ecosystem. So, we are able to go in and replace all of the propane forklifts with electric forklifts. We’re adding electric yard tractors as well as the Volvo heavy-duty battery electric trucks and tractors. We’re adding solar [generation] on some of the customer sites as well as all the charging infrastructure for these to run in daily operations. … We have two community colleges putting together technician training, because this is not the same as working on a diesel unit.”
Volvo will begin producing its VNR Electric heavy-duty truck in North America this year. | Volvo
FedEx Seeking ‘Scale’
Musgrove said FedEx, which has been investigating electricity as a vehicle fuel since 2010, now intends to electrify its fleet — more than 180,000 motorized vehicles — globally where it can.
Russell Musgrove, FedEx | Edison Electric Institute
In what Musgrove called its first “scaled project,” FedEx is purchasing 100 electric delivery vehicles from Chanje Energy and leasing 900 more through Ryder System for deployment in California. Chanje says its V8100 panel van, being produced in Hangzhou, China, can carry 2,000 pounds of payload for a range of 150 miles on a single charge.
FedEx must accelerate its transition, Musgrove said. “I don’t want to do 1,000 trucks a year. I can’t make real inroads into potential savings from a business perspective — and the environmental, carbon-neutrality goals we have as a company — unless we can truly get to scale. And to get to scale, we’re going to need everyone to build these ecosystems, aligning on what we can align on and finding workarounds on those things we can’t.”
After initially focusing on finding the right vehicle, Musgrove said he has shifted his attention to the charging infrastructure inside FedEx’s facilities. “The majority of our facilities are built in warehousing areas. … A lot of time, there’s just not enough energy [available for] putting 150 electric vehicles inside a building. So right now, we’re actually scaling down the number of electric vehicles in the facility until we can get the appropriate utility upgrades, or microgrids, to allow us to have an entire facility using electricity as a vehicle fuel.”
EV ‘Ecosystem’
Brandis said Volvo is listening to its customers to determine what they need from electric trucks and charging infrastructure.
“What we’re finding is that it’s not [enough] to put a bigger transformer on the site because you’re drawing more power. It’s how can you look at that entire site and optimize it based on the daily routines as trucks are ready to leave in the morning and come back in the evening; [it’s] the overall energy usage, and maybe energy offsets with solar or wind in order to look at the entire eco-cycle.”
Musgrove said truck manufacturers, fleet operators and utilities need to have a “true ecosystem discussion, where the stakeholders get in the room and people truly understand the customers’ need. Understand … that there are going to be some locations where we’re going to put in some microgrid technology, where we’re using solar. We’re going to have to use battery storage to … ensure we have the necessary energy to launch those vehicles every day.”
Utilities’ Role
Another challenge, Musgrove said, is dealing with the “very complicated” utility industry, with its variety of regulatory schemes and rate structures.
“Working with energy management companies and utilities is going to be the key globally for us to be able to make a meaningful transition between now and 2030 — 2025 even.”
While some utilities have been good partners, he said, others have a “take it or leave it” attitude that suggests they’re not interested in responding to the increased power demands that vehicle electrification will produce.
FedEx is adding 1,000 Chanje electric-powered panel vans in California in its first “scaled” EV project. | Chanje Energy
Brandis said fleet operators need utilities to designate a single account manager to help them navigate the transition and upgrade the infrastructure in their properties.
“We can’t have the typical, ‘Well you’re not talking to the right department. You’ve got to talk to another department.’”
Musgrove agreed, saying utilities should create dedicated fleet EV programs: “A group of people that understand our business, understand us as a customer … [and] help us get the information and do the things that you need us to do.”
FedEx also wants help from utilities in developing rate structures that “stabilize” its costs.
“Maybe some out-of-the-box thinking, where we talk about a fixed, contracted kilowatt rate including some of the infrastructure we need to put in there,” he said.
“I do think our willingness to work with others is essential to getting this ecosystem up and running,” agreed Poppe. “And there’s a huge … potential for our industry to have growth that we haven’t experienced in decades. It is an exciting time if we can all figure out how to swim together.”
Regulators’ Role
CMS Energy CEO Patti Poppe | Edison Electric Institute
Musgrove said Volvo is lobbying California officials to revise a rule that prohibits public charging stations for heavy-duty trucks. “So, we’re going the California Public Utilities Commission to say, ‘Look this is not going to take off; this is not going to go anywhere, unless we [have private and] public charging stations.’”
Poppe said utilities will need their customers’ help also.
“There will be times when your voice in a regulatory proceeding … is very influential. Our regulators have to be objective, and they may not always do everything we say needs to be done. But when they hear a FedEx say, ‘This is what we need to be done,’ that can be very helpful in us advocating for the right policies.”
Rapid advances in digital technology can provide utilities with much needed assistance in wildfire response, panelists said during Edison Electric Institute’s 2020 Virtual Leadership Summit.
In the “Harnessing Technology to Fight Wildfires” panel, attendees including Caroline Winn, CEO of San Diego Gas & Electric, discussed the potential of emerging technologies such as drones and cloud computing to record and correlate information at speeds far beyond that of human operators. This can be especially important in California, where the increasingly warm and dry climate means that wildfires have been a major threat to the power grid. (See WECC Tackles Wildfires as Reliability Threat.)
SDG&E CEO Caroline Winn | EEI
“Drones are giving us a different viewpoint of our infrastructure and really provide us a higher level of granularity than inspections done on the ground or [from a] helicopter,” Winn said. “We’re now implementing machine-learning models to automatically detect images coming in from our drone program, and that’s complementing and additive to our weather prediction models.”
Beyond preventing and detecting wildfires, technology also plays a vital role in SDG&E’s strategy for mitigating the impact of fire-related public safety power shutoffs (PSPS). One aspect of this strategy is the creation of microgrids in designated areas, using small solar generation resources in conjunction with battery storage to keep electrical equipment in these regions operating in the event of a larger grid failure. SDG&E has four microgrids: two in low-income communities, one for a major medical care facility and one for an air traffic hub used by firefighters in Southern California.
Caroline Narich, Accenture | EEI
Caroline Narich, managing director at Accenture — a professional services company that partnered with SDG&E to implement its cloud analytics platform, as well as other technology-enabled services — said the company’s system optimization software presents further possibilities for mitigation of harm. System optimization in this sense refers to the representation of every physical asset in cyberspace via a “digital twin” that can be used to train automated grid management software via machine learning.
“If we apply this to wildfire management, we can envision a world where we’re better able to manage the system as we go into these wildfire events,” Narich said, “for example, by communicating directly to the microgrids or to the local batteries, telling them to preserve power and then actually leveraging that capacity to minimize the impact of the PSPS event.”
Everette C. Rochon Jr., FAA | EEI
Another potential application of cloud technology suggested by Narich is in customer engagement. Utilities may already use mobile apps to communicate with customers during wildfire events; these can be expanded to include targeted notifications to those in the highest-risk regions, as well as through visualizations of outage data and real-time photographic imagery of affected areas.
Panelists acknowledged that making full use of these emerging technologies will require careful tuning to ensure safe implementation. Responding to Winn’s comments on drones, Everette C. Rochon Jr., acting manager of the Federal Aviation Administration’s General Aviation and Commercial Division, pointed out that rules regarding unmanned aerial vehicles are still in the very early stages and warned that utilities should be conservative as they move forward with their introduction.
“[We call it] the three A’s: airmen, aircraft and airspace,” Rochon said. “Manned aircraft operations have established standards and processes in all three areas, [but] these are not well established in the unmanned world, and they have to be considered concurrently and at the speed of innovation.”
NYISO stakeholders at the Business Issues Committee on Wednesday recommended the Management Committee approve increasing by 10 MW the exemption from real-time generation penalties for units that supply the New York City steam distribution system.
Chris Hargett of Consolidated Edison presented the rationale for increasing the exemption, currently at 523 MW, for the company’s East River Units 1, 2 and 6, specifically a number of projects completed over the past several years that have increased the efficiency of Unit 6.
Hargett said that while Con Ed does not sell excess or unneeded electricity from the winter-peaking steam system on the wholesale market, the power is nonetheless available to NYISO for reliability reasons. Under normal conditions, the utility only dispatches the units to meet steam demands, given their operating characteristics.
If the MC approves the Tariff revision at its Sept. 23 meeting, and the Board of Directors does so in October, NYISO will make a Federal Power Act Section 205 filing with FERC.
Con Edison won approval from the NYISO BIC of a proposal to increase the exemption from real-time generation penalties for units that supply steam to New York City. | Con Edison
Committee Approves ESR Capacity Bidding Rules
The BIC also recommended MC approval of proposed energy storage resource (ESR) bidding rules for installed capacity suppliers with an energy-duration limitation.
Market Design Specialist Sarah Carkner presented the ISO’s proposal for Tariff revisions specifying that such ESRs bid or schedule a bilateral transaction for their full injection range for all hours during the peak load window and to bid their full withdrawal range for all hours outside of the peak load window, or notify the ISO of a derate.
Given MC support and board approval, the ISO will later this year or in early 2021 submit the proposed Tariff revisions to FERC and update the ICAP Manual to accommodate the expanding capacity eligibility rules, at which time changes to the availability calculation for ESRs will be incorporated, Carkner said.
Incorporating Wholesale Market Solar in Dispatch, LBMP
The BIC recommended the MC approve revising market rules applied to wind energy resources to also encompass solar resources.
In the calculation of the locational-based marginal prices for wind and solar resources, the lower dispatch limit would be zero, and the upper dispatch limit would be the supply forecast, NYISO analyst Cameron McPherson said. The dispatch definitions would apply to both the day-ahead and real-time markets.
Solar resources would submit flexible offers indicating their willingness to generate at various price levels and would also receive, and be expected to respond to, NYISO economic dispatch instructions (down only) when prices are below their offer.
The proposed revisions leverage a set of existing rules and processes that require only incremental changes in order to accommodate solar, which is a prerequisite to deploying the co-located storage resource (CSR) market design within the hybrid storage model, McPherson said.
Additional resource flexibility will improve the ISO’s ability to accommodate increased levels of intermittent resources, and solar resources will be able to signal their economic willingness to generate, minimizing the need for out-of-market curtailments and self-directed curtailments.
If the MC and board approve, the ISO will file the proposed Tariff revisions at FERC in November/December and look to implement them in 2021.
Credit Policy Enhancements
The BIC recommended, with several abstentions, that the MC approve changes to NYISO’s policy on extending unsecured credit to public power providers and other government entities.
The proposed Tariff revisions would stipulate that government entities are eligible for up to $1 million in unsecured credit, as public power entities currently are, and require that a public power or government entity be an investment-grade customer to be eligible for $1 million in unsecured credit.
FERC in April granted the ISO a nine-month waiver allowing it to grant up to $1 million in unsecured credit to government entities that do not meet the current Tariff definition of a public power entity.
The ISO’s manager of corporate credit, Sheri Prevratil, said that NYISO recognizes there is some inherent risk associated with extending unsecured credit as a general matter, and that the proposed changes were consistent with all other customers who qualify for unsecured credit under the Tariff.
Investment-grade customers are those with a senior long-term unsecured debt rating of BBB- or higher by Standard & Poor’s or Fitch, or Baa3 or higher by Moody’s Investors Service. A customer without a rating may request a NYISO equivalency rating using its audited financial statements.
If the MC and NYISO board approve, the ISO will make a Section 205 filing in October.
The BIC also recommended MC approval of proposed enhancements to the ISO’s current transmission congestion contracts (TCC) auction practices and credit policy.
Currently, the second year of a two-year TCC is the only one for which the ISO solely holds a margin to cover declines in value relative to auction-determined market-clearing prices. Market participants support the ISO holding as collateral the higher of the payment obligation or holding requirement until the second year is paid, rather than paying for both years in advance, Prevratil said. The ISO also proposes using auction prices to calculate requirements for TCCs subject to only the historical congestion rent credit requirement.
NYISO currently does not recalculate the credit requirement for the second year until approximately one year after the initial award. The ISO recommends administering a one-year round for TCCs covering the same period as the second year five to six months earlier, which will ensure more current pricing is used.
If the MC and board approve, the ISO will submit the changes to FERC in the fourth quarter.
An advocacy group representing California’s community choice aggregators (CCAs) on Wednesday called on Gov. Gavin Newsom to appoint an independent panel to review a pending joint agency report on the causes of the rolling blackouts that rocked the state in mid-August, leaving millions of residents without power during a record heat wave.
The request came the same day that WECC told its stakeholders of plans to produce its own analysis of the circumstances leading to the Aug. 14-15 blackouts and subsequent emergency events occurring in the days that followed.
During a voting meeting Thursday, California Public Utilities Commission President Marybel Batjer thanked residents and businesses for their efforts in heading off additional blackouts during another heat wave last week and assured them that the CPUC is working with CAISO and the state’s Energy Commission “on a joint investigation into the root causes of the events … that we intend to deliver to the governor later this month.” (In a meeting Tuesday, CAISO said the report could be finished as soon as early next week.)
But advocacy group CalCCA’s letter to Newsom expressed implicit skepticism over the impartiality of that effort.
“While the joint agencies are no doubt motivated to prevent future shortages, an objective eye will ensure that natural biases do not affect the characterization of the root cause or proposed mitigation measures,” wrote Beth Vaughan, executive director of CalCCA, which has 24 members and four affiliates.
CalCCA said its proposed review panel should consist of “former agency experts,” “non-market participants” selected by load-serving entities (including CCAs, investor-owned utilities and electric service providers) and “other key stakeholders.”
Like other industry participants, CalCCA pointed to declining resource adequacy as being a key factor in the rolling blackouts, saying the emergencies revealed an “urgent need” to reform the existing RA rules administered by the CPUC and CAISO “and focus the CPUC’s integrated resource planning process more rigorously on supply reliability.”
The letter also called on state officials to consider a new set of policy initiatives:
Use of the CPUC’s procurement track of its 2021 integrated resource planning proceeding to “refine our understanding of near- and midterm reliability needs in the 2024-2026 time frame.” This would entail identifying specific technical needs for requirements such as capacity, energy and evening ramp; establishing a “fair process” for allocating those needs to LSEs for procurement; and providing “appropriate market incentive and regulations” for behind-the-meter resources to act as energy and capacity resources. CalCCA also wants the commission to develop “a deeper understanding of import resource availability and institutional barriers to securing firm import resources.” (See Theories Abound over California Blackouts Cause.)
Legislative action to create a Central Reliability Authority responsible for coordinating the state’s RA with CAISO and potentially procuring backstop RA. (See Calif. Participants Float ‘Central Buyer’ RA Plan.)
Collaboration between the governor’s office and California’s congressional delegation to extend the federal investment tax credit to cover standalone storage resources.
WECC to Take Wider View
Additional analysis of the blackouts was a topic of discussion during a virtual meeting of WECC’s Class 4/5 members (end users/state representatives) Wednesday, where an official said the regional entity aims to issue its own report on the emergency events by the end of the year.
Vic Howell, WECC director of reliability risk management, recounted to stakeholders that the organization followed every stage of the heat wave events and communicated developments to NERC as they unfolded. He noted that the RE tracked each CAISO energy emergency alert (EEA), all shedding of firm and non-firm interruptible load, and demand response usage.
“We also tracked transmission capacity and transmission limitations,” Howell said. “Although transmission wasn’t noted as being an issue during that event, the imports from outside California’s footprint were difficult to find because the neighboring entities were experiencing the same heat wave.”
Howell pointed out that CAISO issued 14 Level 1, six Level 2 and seven Level 3 EEAs over Aug. 14-19, equating to 62% of all EEAs issued in the Western Interconnection last year.
He said WECC’s report would examine the blackouts through the framework of NERC’s event analysis process but with a twist, “because we’re forming a larger internal team that includes folks from planning and from the resource adequacy group, in addition to the typical analysis staff.”
“We’re going to look into those conditions more broadly as a heat wave event, not a California load-shed event, to identify any other indicators of reliability issues,” Howell said. “The goal is to work really hard to produce a public report later this year with its findings, and there may be subsequent work that needs to happen after that.”
Asked whether it would support — or even participate in — the kind of independent review being sought by CalCCA, WECC told RTO Insider that while it doesn’t oppose such an independent analysis, its primary focus will be to conduct its own work through the NERC process.
“This process allows WECC to work with the entities involved to analyze what happened [and] why and identify lessons learned,” the RE said. “As part of the process, WECC will seek input from NERC [subject matter experts] and industry (via WECC’s Events Performance Analysis Subcommittee). WECC will look into the conditions on the system more broadly during the event to identify any additional indicators of reliability issues.”
ISO-NE will proceed with its proposal to eliminate capacity performance payments for energy efficiency resources, despite its failure to win endorsement by the New England Power Pool Markets Committee.
The proposal won 55.57% in a sector-weighted vote of the MC on Tuesday, falling short of the 60% threshold for endorsement. The Supplier and Transmission sectors were unanimous in support of the proposal, which also was backed by most members of the Generation sector. It was opposed by a majority of the Alternative Resources and all of the End User members voting. All 49 Publicly Owned Entity members abstained.
In a memo to stakeholders, Henry Yoshimura, the RTO’s director of demand resource strategy, said the change is a recognition that EE resources “permanently reduce energy consumption [and] create a reduction of demand across all conditions and prices.”
Capacity performance payments, which are intended to provide resources with incentives to provide energy or reserves in real time, should be limited “to those resources whose performance could be at risk,” Yoshimura said, citing generators, imports, batteries and demand response. In contrast, EE has no real-time performance and thus can’t trip offline, he said.
Abigail Krich of Boreas Renewables spoke against the proposal, calling it “real slippery slope logic for Pay-for-Performance.”
[Note: Although NEPOOL rules prohibit quoting speakers at meetings, those quoted in this article approved their remarks afterward to explain their positions.]
She said settlement-only generation, most variable generation and all non-dispatchable generation are similar to EE in that “they’re really not able to increase output in response to a scarcity condition,” such as the one that occurred on Sept. 3, 2018.
ISO-NE’s Internal Market Monitor and External Market Monitor backed the change.
“The capacity provided by EE resources during a scarcity condition is not measured,” said David Naughton, manager of surveillance and analysis for the RTO. “It’s also not clear to me that EE resources have the ability to alleviate capacity shortage conditions in real time.”
Projected annual energy use with and without EE and PV savings | ISO-NE
Pallas LeeVanSchaick of EMM Potomac Economics agreed with Naughton, saying PfP rules are intended to incentivize good performance that is verifiable.
“The nature of energy efficiency is that it’s not really possible to assess performance in the kind of time frame that you need to make PfP work,” he said. “It’s really not a mechanism that’s appropriate for something like energy efficiency.”
LeeVanSchaick also rejected concerns that the loss of the revenue would stifle investment in EE.
Mark Spencer of LS Power urged stakeholders to “take a look at the merits of the argument rather than the emotional issues,” noting the Monitors’ endorsement. “It’s a better market design.”
Spencer also said it was a mischaracterization to suggest the change abrogated a compromise that emerged in the Demand Resources Working Group (DRWG) report after 18 months of stakeholder work. (See “Assessing EE Resource Performance,” NEPOOL Markets Committee Briefs: Sept. 18, 2019.) The MC approved a proposal by the New England States Committee on Electricity with a 94% vote. The proposal, which effectively removed EE from balancing ratio calculations for scarcity events during off-peak hours when EE is not measured, was approved by FERC in July (ER20-1967).
The discussions were prompted by the Sept. 3, 2018, scarcity event during off peak hours, which resulted in capacity performance payment credits exceeding charges by $7.8 million because EE had been eliminated from the numerator of the balancing ratio but not the denominator.
Spencer said the DRWG solution “was not a compromise.” He said stakeholders were faced with the choice of the lesser of two evils, and “that doesn’t result in a durable market design.”
The change left EE with the ability to earn PfP bonuses, or be charged penalties, during peak hours.
Synapse Energy’s Doug Hurley, the leader of the AR sector, did not respond to requests for comment on the MC debate.
Hurley had presented the DRWG solution to the committee in March on behalf of his client, EE aggregator Vermont Energy Investment Corp. “I understand that some participants are frustrated that EE resources are subject to PfP only during DR on-peak and seasonal-peak hours,” he had said. “Our proposal is separate from addressing that issue.”
Calpine’s Brett Kruse said he supported eliminating PfP payments to EE but also agreed with Krich on the need for a broader examination to limit PfP payments to only those resources with “production risk.”
“If something breaks during one of these PfP events, then they’re paying the guys that are there picking up the slack. There are probably some other [resources] that fit much like EE, and those resources should be excluded from the pool as well.”
Yoshimura said ISO-NE will ask FERC to approve the change effective 60 days after the filing is made.
Illinois Gov. J.B. Pritzker told a virtual gathering of PJM stakeholders Wednesday that his state’s transition to cleaner energy is “non-negotiable,” but he emphasized the need for collaboration with the RTO.
Pritzker delivered the keynote address for PJM’s General Session stakeholder meeting, headlining a group of diverse speakers on the topic of resource adequacy and the RTO’s capacity market.
Throughout his speech, the governor stressed the “urgent need” to address climate change and pointed out that it is a common goal among many states in PJM.
Illinois Gov. J.B. Pritzker | PJM
“We all know well that systems transform faster when all their players and parts are willing to move,” Pritzker said. “So, it’s important that we work together to move toward an ethical, affordable, clean and renewable energy economy as soon as we can.”
Pritzker said he hopes PJM and MISO will work with Illinois and other states in allowing capacity markets to reflect their desire for clean energy.
“Beyond addressing capacity market issues, we’re interested in working with PJM to make further progress toward rules that recognize and enhance clean energy to advance the clean energy economy,” he said. “With a commitment to doing what’s right, we can pave the way to a clean and renewable economy, not just for Illinois, but for all of PJM’s member states and, in turn, the nation.”
“Bold action,” he said, is needed to tackle climate issues in the Midwest as the region sees record-breaking flooding and extreme droughts. He said that his energy plan, released last month, prioritizes both consumers and climate change. He said he welcomes the help of PJM and its stakeholders to achieve its goals. (See Exelon to Close Ill. Nukes as Gov. Touts Clean Energy Plan.)
“I know this group that eats, sleeps and breathes the details on how we get there and is going to dive right in,” Pritzker said.
The governor also said there is a need to strengthen utility company transparency and ethics requirements. Utility companies “can no longer write the state’s energy policies behind closed doors,” he said, pointing to the recent bribery scandal with Commonwealth Edison and its parent company, Exelon. Pritzker said Exelon must open its books for a “transparent, independent and expert review of finances” to do a proper investigation. (See ComEd to Pay $200 Million in Bribery Scheme.)
He also called for changes to state laws to incentivize rapid development of renewable energy, including putting a price on carbon emissions. State policies must be developed in an open setting with engagement from stakeholders impacted by energy policy, including utility ratepayers, he said.
CEO’s Perspective
Speaking earlier in the session, PJM CEO Manu Asthana said it’s “imperative” that the RTO resume a schedule of regularly occurring capacity auctions as soon as possible.
Asthana said PJM’s markets add between $3.2 billion and $4 billion of value annually through the benefits of scale, efficient operations and the power of competition. He said competition in the markets has led to reductions in wholesale power prices and a 34% reduction in carbon emissions since 2005.
“These auctions and PJM’s other markets add significant value, and that value can’t be taken for granted,” Asthana said.
The pace of change in the energy industry is accelerating, Asthana said, and is driven by a change in technology, including batteries, offshore wind and smart grid technologies.
The RTO is also seeing changes in consumer preferences towards decarbonization, Asthana said, along with changes in public policy, as Illinois and some other PJM states take “aggressive steps” to decarbonize their generation.
Asthana said PJM stakeholders have said they are open to starting a conversation about a long-term solutions to resource adequacy challenges. He pointed out that of the 107,000 MW of generation currently in PJM’s interconnection queue, about 86% is either solar, wind, or batteries.
“This is not some distant theoretical change that we’re talking about,” Asthana said. “This change is here now.”
The New Jersey Board of Public Utilities voted Wednesday to seek 1,200 to 2,400 MW in its second solicitation for offshore wind, continuing efforts to meet a goal of 7,500 MW by 2035 despite doubts about the resource’s ability to win revenues through PJM’s capacity market.
The Bureau of Ocean Energy Management has designated 17 lease areas with potential capacity of more than 21 GW along the East Coast. Ørsted’s 1,100-MW Ocean Wind project, expected to begin operations in 2024, will be built in lease area OCS-A 0498. | N.J. BPU
Responses to the solicitation will be accepted between Sept. 10 and Dec. 10, with an award expected in June 2021.
“This second solicitation not only reinforces our commitment to fighting climate change and achieving 100% clean energy by 2050, but it secures New Jersey’s foothold as a national leader in the growing U.S. offshore wind industry,” Gov. Phil Murphy said in a statement.
Under the proposed solicitation schedule, the BPU will consider a third solicitation in 2022 for at least 1,200 MW of OSW and hold additional solicitations every two years until 2028.
The BPU awarded its first OSW contract to Ørsted’s 1,100-MW Ocean Wind project last year. Ocean Wind, which will be built 15 miles from Atlantic City, is expected to begin operations in 2024. (See Orsted Wins Record Offshore Wind Bid in NJ.)
The board on Wednesday also gave final approval to the state’s Offshore Wind Strategic Plan, which provides recommendations to maximize the economic benefits of the projects while protecting the environment and fishing interests. (See NJ Releases Draft Offshore Wind Plan.)
Commitments by New Jersey and its neighbors, Maryland (1,200 MW) and New York (9,000 MW), account for about half of the East Coast’s 36-GW pipeline of offshore wind projects. | N.J. BPU
The East Coast’s OSW industry has grown from 30 MW in 2018 to a pipeline of more than 35 GW by 2035, according to the plan.
Commitments by New Jersey and its neighbors, Maryland (1,200 MW) and New York (9,000 MW) account for about half of the East Coast market. The Bureau of Ocean Energy Management has thus far designated 17 lease areas with potential capacity of more than 21 GW along the coast.
New Jersey’s strategic plan for OSW calls for the state to evaluate transmission costs based on several scenarios, including each project using its own radial line and a “backbone” of shared transmission. | N.J. BPU
The plan calls for the state to evaluate transmission costs based on several scenarios, including each project using its own radial line and a “backbone” of shared transmission. (See Coastal States Seek Balance on Offshore Wind.)
The BPU and the New Jersey Economic Development Authority (NJEDA) on Wednesday also approved two memoranda of understanding authorizing almost $6 million in spending to support OSW and other clean energy projects. New Jersey’s Clean Energy Program, which is run by the BPU, will provide $4.5 million to support NJEDA-led workforce development projects aimed at preparing workers in the state for OSW jobs and $1.25 million to support early-stage, New Jersey-based clean tech companies.
Trust and collaboration between the private and public sectors is more important than ever for guarding against cyberattacks on U.S. critical infrastructure, according to participants in Edison Electric Institute’s 2020 Virtual Leadership Summit.
Southern Co. CEO Tom Fanning, who participated in the government-sponsored Cyberspace Solarium Commission last year and moderated a panel Wednesday on its findings (See Solarium Team Urges Long-term Cybersecurity Focus.), observed that while the U.S. is “effectively at war in cyberspace,” mustering the necessary defense is challenging because the conflict is almost invisible to the average citizen.
“It’s almost like going to a beach and watching a submarine war,” Fanning said. “You really can’t see anything until something cataclysmic happens, and yet we know that the threat is ongoing and lethal.”
King: Cyberattacks Cheap, Low-risk
Also on the panel was Sen. Angus King (I-Maine), who served on the commission with Fanning. King predicted that cybersecurity is likely to remain a pressing issue because it represents a “cheap way to attack.” He speculated that Russia’s government could hire 800 hackers for the cost of one jet fighter.
Cyberattacks are cheap in an additional sense because foreign adversaries have not had to feel that “there’s some cost they’re going to have to bear if they attack us.” Another complicating factor is the asymmetric nature of the threat, with King echoing previous complaints by Fanning that utilities “don’t have the authority to go and punch North Korea on the nose.” (See NERC Planning Level 2 Supply Chain Alert.)
“This problem is not strictly a governmental problem; 85% of the cyber target space is in the private sector,” King said. “And so really, deepening the relationship between the federal government, which has some extraordinary capabilities, and the private sector is a huge opportunity and something that we really have to work on.”
Southern Co. CEO Tom Fanning (left) and Sen. Angus King (I-Maine) | EEI
King admitted that establishing the necessary trust between the public and private sectors will take consistent effort, particularly in the realm of information-sharing, where both sides have been historically reluctant to share information because of concerns for privacy on the part of industry and national security for the government. The senator insisted that this state of affairs has to change for the good of all.
“We’ve got to get over this [viewpoint] that the U.S. government … owns the information and doles it out reluctantly. I’m on a mission to make them think more broadly about who their customers are,” King said. “By the same token, [utilities] have to think of them as a resource [and] share the information that you have. … If Southern Co.’s getting attacked, and you tell [the government] that this is going on, they can then warn the other major utilities around the country.”
CISA Lauds Utilities for Collaboration
In a separate panel, Christopher Krebs — director of the U.S. Cybersecurity and Infrastructure Security Agency (CISA) — offered an upbeat assessment of the level of collaboration between public and private entities. Krebs held up his agency as a friendly middle ground where the intelligence community and utilities have come together to find a common purpose, leading each to redefine their roles in a manner that makes sense for a changing world.
CISA Director Christopher Krebs | EEI
“What we’ve been doing for the last couple of years [is] getting away from this almost monolithic approach to critical infrastructure, where you have a sector that’s defined by the companies,” Krebs said, referring to CISA’s National Critical Functions framework released in 2019. “Instead, we’re taking an approach where the critical infrastructure community is defined by the services and functions it provides.”
Krebs praised the electric industry in particular for setting a powerful example of public-private collaboration, citing the participation of utility CEOs — including Fanning — for their willingness to work with their peers and the federal government on solutions in both emergency situations and long-term planning. However, he warned that this is just the starting point, with “lesser-resourced organizations” in particular needing more help to ensure that the broader community is prepared for any threat.
“I really can’t think of a sector where we get this kind of CEO-level engagement and participation,” Krebs said. “Time is money, and to get this kind of CEO participation on operational activities, I can’t tell you that there’s another sector that engages at that level … [but] no organization, no sector is going to be able to stand on your own against a dedicated adversary with a nation-state capability. So we’ve all got to work together.”
