WECC waded into California’s wildfire troubles Thursday in an effort to understand how catastrophic blazes could affect regional grid stability and what can be done to protect the bulk power system.
In the first in a series of webinars planned this month, major utilities and transmission operators, including Southern California Edison and Pacific Gas and Electric, briefed WECC stakeholders on fire-prevention planning.
The state’s summer and fall fire season has begun, with several large wildfires burning in Southern California. The largest, the Apple Fire, had burned more than 32,000 acres and was 40% contained as of Sunday afternoon, the California Department of Forestry and Fire Protection reported.
Massive fires sparked by utility equipment killed dozens of people and destroyed thousands of homes in Northern and Southern California during fire seasons in the past three years.
“The timing of this presentation is such that I don’t need to spend a lot of time explaining the risk or the severity,” said Tom Brady, senior manager of emergency response at SCE. “We know that California does have a serious wildfire problem, and it’s something that continues to get worse.
“I recall growing up and remembering a time when there was a start and an end to fire season,” Brady said. But “it seems with today’s current events, that window is extending, and it’s really difficult to say there’s a fire season anymore because there’s always a risk for ignition and spread.”
Ten of the state’s 20 most destructive wildfires have happened in the past five years, posing an “existential crisis” for investor-owned utilities, he said.
WECC should “prepare for and evaluate impacts on the bulk power system caused by extreme natural events,” such as wildfires, drought, flooding and earthquakes, it said, with an emphasis on sharing best practices and lessons learned from individual state and utility experiences across the Western Interconnection.
On Thursday, utility representatives described efforts to head off wildfires, starting this fall.
Brady said SCE had installed 650 miles of insulated wire in the areas at highest risk of fire in its sprawling service territory. The utility plans to install a total of 1,200 miles of covered conductor by the end of this year, he said.
A smoke plume from the Apple Fire, burning in Southern California, rises behind transmission towers. | U.S. Forest Service
SCE also placed 1,200 fuses and remote-controlled sectionalizing devices on its system to interrupt power more quickly and prevent ignitions.
Sectioning off its grid also allows SCE to limit the extent of public safety power shutoffs (PSPS) — the intentional blackouts California IOUs use to keep electrical equipment from starting fires during dry windy conditions.
“We’re able to minimalize, sectionalize and isolate the smallest footprint possible so that we’re not interrupting a lot of customers,” he said.
During a weather event the weekend of Aug. 1, SCE warned hundreds of customers in Kern County they might be subject to power shutoffs. Sectionalizing allowed the utility to limit the number of affected customers to 17, Brady said.
PG&E said it is following the lead of SCE and San Diego Gas & Electric by installing hundreds of weather stations and hilltop cameras in its high-risk fire zones, which make up about half the utility’s 70,000-square-mile service territory.
Matt Pender, director of PG&E’s community wildfire safety program, told the WECC audience that 70% of ignitions in its territory resulted from vegetation contacting power lines (48%) or equipment failure (22%).
The November 2018 Camp Fire, the deadliest in state history, started when a PG&E conductor fell, igniting dry vegetation below. Investigators determined a 100-year-old C-hook had broken after decades of wear, dropping the high-voltage line. (See Ancient C Hook, Financial Manipulation Caused Camp Fire.)
Pender said PG&E had inspected every asset in its high-risk fire areas during six months in 2019. The work, helped by drones and machine learning, might have taken five years under PG&E’s “old regime” of line inspections, he said.
Planes equipped with infrared sensors can now inspect lines at night, he said.
The utility also is using sectionalizing devices, as well as placing generators at substations, to limit the scope and duration of PSPS events this fall. Last year, PG&E blacked out hundreds of thousands of customers for up to a week at a time during multiple events. (See California PUC Approves Microgrids, Fire Plans.)
The company’s goal with PSPS is to “to make them smaller, shorter and smarter this year,” Pender said.
Upcoming Webinars
WECC said its next wildfire webinar, on Aug. 13, will be an in-depth “technical exploration into wildfire preparedness and the bulk power system, including system hardening, technology deployment, advanced weather modeling, weather stations, predictive fire spread modeling and high-definition camera installations.”
A third webinar Aug. 20 will examine the “mitigation, right-of-way and vegetation-management aspects of wildfire preparedness. The webinar will explore actions that entities may take to stay compliant and assist in the preparation and prevention of wildfires.”
A new study by The Brattle Group estimates New York would save $500 million through a planned transmission strategy for its next 7,200 MW of offshore wind versus the generator lead line (GLL) approach.
The new study for Anbaric Development Partners reaches similar conclusions to one Brattle did for the company in May on the potential benefits of planned and networked transmission development for southern New England. (See Brattle Study Highlights Benefits of Offshore Grid.)
Brattle found a planned approach in New York could save $1.5 billion in onshore upgrades compared to a GLL approach. | The Brattle Group
In the New York study, Brattle estimated onshore upgrade costs of $500 million under a planned approach, compared to $2 billion for GLLs, a savings of $1.5 billion. That would be partially offset by increased offshore transmission costs for the planned approach — $6.1 billion vs. $5.1 billion for GLLs — primarily because of the use of HVDC technology.
Brattle said there could be additional savings of 20 to 30% from increased competition under the planned strategy.
The study, buttressed with engineering, cost and seabed analyses by Pterra, PSC Consulting and Intertek, was presented and discussed in a webinar Thursday. The New York League of Conservation Voters Education Fund, Anbaric and the Sabin Center for Climate Change Law at Columbia University hosted the virtual event, which Consolidated Edison sponsored.
Clockwise from top left: Joe Martens, NYOWA; Kevin Knobloch, Anbaric; Girish Behal, NYPA; and Kirsty Townsend, Ørsted. | Sabin Center
Following is some of what we heard at the event.
Hurry Up and Wait
Joe Martens, director of the New York Offshore Wind Alliance and former commissioner of the state’s Department of Environmental Conservation, referred to the Accelerated Renewables Growth and Community Benefit Act enacted in April as part of a budget bill that aimed to speed up the state’s clean energy transition.
Joe Martens, NYOWA | Sabin Center
“In addition to completely rewriting the way renewable energy is sited in New York, and establishing very strict timetables, [the act] was an acknowledgement that we were really good at entering into contracts, but not so good siting and getting projects built,” Martens said. “We’re at about a 27% renewable penetration in the electricity sector today in New York, and 20% of that is legacy hydro projects upstate, so we have a long way to go.”
The siting law also called for a study by year-end of the transmission system, both onshore and offshore, he said.
The Public Service Commission in May approved such a study to identify distribution upgrades, local transmission upgrades and bulk transmission investments needed to meet the state’s clean energy goals of 70% renewable electricity by 2030 (20-E-0197). (See NYPSC Launches Grid Study, Extends Solar Funding.)
The PSC and the New York State Energy Research and Development Authority also issued a white paper in June, and one question in it regarded the second OSW solicitation for up to 2,500 MW, Martens said.
Brattle’s study shows likely offshore transmission buildout under a planned approach. Phase 1 is already contracted using HVAC cables. Planned approach would use HVDC cables for Phases 2 and 3. | The Brattle Group
“One of the big questions was how to approach transmission in this second solicitation,” Martens said. “In the first solicitation, it was decided that a so-called radial system, where the developer designs and builds the transmission just to accommodate their project, was the right approach because we don’t have any commercial-scale offshore wind projects to date, and we wanted to get the program up and running as quickly as possible.”
However, even during the phase one solicitation, people raised the question about looking at a network system, as the state anticipates “multiple projects being built, not just off New York, but across our sister states to the north and south,” he said.
The white paper proposed that for the second solicitation, developers build radial transmission lines because “the potential for a backbone network remains speculative, primarily because there is still a lot of uncertainty about where new wind energy areas would be located and how soon they would be leased in the New York Bight,” Martens said. “However, the white paper acknowledged that this is still a very important issue and needed to continue to be studied.”
The PSC’s grid study includes investment plans for both the bulk and local transmission systems. “And of course, a key component of that study is the offshore wind transmission analysis, and part of that analysis is consideration of offshore network configurations,” said Tammy Mitchell, chief of bulk electric systems for the state’s Department of Public Service. “The final results of that study are due at the end of the year, and preliminary results will be available in the fall.”
Many projects are moving through the Article VII transmission siting process, and the DPS should soon be proposing rules for a nine-month process, Mitchell said.
Rules and Need
States along the East Coast cooperating on the issue would bring more opportunities for bringing OSW energy ashore where it makes sense, perhaps at shorter distances, said Kevin Knobloch, president of Anbaric subsidiary New York OceanGrid.
“Ultimately, what we’re looking for is an open-access transmission system, where there’s maximum competition among not just generators, but transmission developers, which can also be generators,” Knobloch said. “Robust competition is what will ultimately bring costs down and get this power to shore.”
New York has the greatest need for shared transmission and is in the lead to deal with it, said Kirsty Townsend, head of special projects at Ørsted.
“The IEEE standards for offshore don’t exist in the U.S., so it would be great to establish that so we can actually connect multiple wind farms into these shared infrastructures,” Townsend said. “I think some of the ISO’s market rules could [use] improving, or finding another way round in order to achieve the public policy goals. It’s something we as developers, both transmission and generation, are already struggling with, and I can see this kind of shared transmission system only exacerbating those issues, interconnection queue process rules, for example.”
Massachusetts also is interested in exploring the benefits of multistate cooperation on offshore transmission. Patrick Woodcock, commissioner of the state Department of Energy Resources, said last month that a network transmission “initiative could be achieved more effectively at a larger scale of offshore wind build-out and with regional coordination among New England states … than through a single-state procurement with limited size.” (See Mass. Nixes Separate Offshore Tx RFP.)
Mid-century economy-wide GHG emission reduction targets in New England | E3/EFI
NEPOOL’s Participants Committee on Thursday began taking a new look at how it can adapt market rules to reach New England states’ decarbonization goals with educational presentations on two potential “pathways”: carbon pricing and a forward clean energy market (FCEM).
The pathways discussion — and planning for a parallel “Future Grid” study — resulted from requests by the New England Power Generators Association (NEPGA), New England States Committee on Electricity (NESCOE) and other stakeholders for the region to plot a path toward reaching states’ 2050 decarbonization goals. (See NEPOOL Reviews ‘Future Grid’ Study Requests.)
At the March PC meeting, NESCOE Executive Director Heather Hunt said the organization’s request was intended “to initiate proactive and actionable discussion on the future grid and potential market changes to achieve states’ goals other than through the reactionary changes that have been directed by the FERC and driven the region’s efforts in past years,” according to NEPOOL meeting minutes.
IMAPP Redux?
Carbon pricing and the FCEM were among four long-term proposals considered in detail by stakeholders in the Integrating Markets and Public Policy (IMAPP) initiative in 2016. Carbon pricing foundered because of differing ambitions among the states, with New Hampshire balking at the more ambitious goals of Massachusetts and Connecticut. (See ISO-NE Two-Tier Auction Proposal Gets FERC Airing.)
ISO-NE ultimately adopted a two-tiered capacity construct, the Competitive Auctions with Sponsored Policy Resources (CASPR) to prevent consumers from paying twice for the same capacity through both the Forward Capacity Market (FCM) and subsidies for new, state-mandated supply resources.
CASPR is intended to allow state-sponsored resources to enter the FCM while maintaining competitive prices in the Forward Capacity Auction (FCA). In a substitution auction after the primary FCA, existing capacity resources may transfer their obligations to new resources that did not clear in that first stage because of the minimum offer price rule.
The CASPR substitution auction cleared 54 MW in 2019 and none in 2020. That led some observers to label CASPR a failure, with others calling for it to be redesigned. (See NEPOOL Markets Committee Briefs: May 12, 2020.)
ISO-NE CEO Gordon van Welie has urged patience, telling the PC in March that CASPR is the “next best solution” if the region can’t adopt effective carbon pricing.
“Resource substitution via CASPR will depend on the build-up of economic pressures over time,” he said. He acknowledged CASPR’s performance thus far “has caused concern among some stakeholders that the transition may not occur swiftly enough, or that the lack of substitution may lead to a costly overbuild, leading to a discussion about alternative market designs or structures.”
Forward Clean Energy Market
Kathleen Spees, Brattle Group | The Brattle Group
At Thursday’s PC meeting, Kathleen Spees of The Brattle Group briefed members on its FCEM proposal, which she said could help states achieve their goals without demanding that those goals be uniform. “We developed the Forward Clean Energy Market as one tool that states could use for mobilizing private investment to meet their goals through a competitive market,” Brattle said.
The Brattle proposal resulted from a study funded by the Conservation Law Foundation, Brookfield Renewable Partners, NextEra Energy Resources and National Grid, and one funded by NRG Energy, Spees said.
The proposal acknowledges states’ desire to move from a wholesale market that delivers “reliable, low-cost electricity” to one in which the power is also carbon-free, Spees said.
[Note: Although NEPOOL rules prohibit quoting speakers at meetings, those quoted in this article approved their remarks afterward to clarify their presentations.]
The FCEM would be a centralized, three-year forward auction in which buyers and sellers could voluntarily exchange clean energy attribute credits (CEACs) — a product Spees likened to a renewable energy credit.
Brattle’s proposed Forward Clean Energy Market would be a centralized auction in which buyers and sellers could voluntarily exchange clean energy attribute credits (CEACs). | The Brattle Group
There are two optional variations: One for a “dynamic” CEAC would award more credits to resources that displace more carbon emissions, which would benefit batteries “and focus incentives toward achieving more carbon abatement faster,” Brattle said.
A second option would allow buyers to register a preference for “targeted” resource types to meet carve-outs for preferred technologies such as storage or offshore wind.
The FCEM would assign most fundamentals-based and asset-specific risks to sellers, with features to mitigate regulatory risks and support financeability:
a multiyear commitment period of about seven to 12 years to lock in prices for new resources;
a multiyear forward period to support development and financing of new resources;
a sloped demand curve to reduce year-to-year price volatility and improve revenue certainty; and
the ability for states to make commitments to rely on the market for a minimum time frame and quantity to ensure confidence in the construct.
Spees indicated a willingness to discuss a forward period shorter than three years, which could benefit some renewable developers. But she noted that some clean resources such as offshore wind may also have longer development time frames. She recommended that the FCM and FCEM both be conducted at the same forward period to minimize clearing risks for new resources that seek financing.
Brattle said its simulations estimated that FCEM could save customers $3.60/MWh — or $4.5 billion over 10 years — compared to states’ current practices for bringing clean resources and storage online, including competitive solicitations.
Spees said the FCEM offers several benefits over carbon pricing and traditional RECs.
Carbon pricing maximizes benefits if implemented regionally and economy-wide, which may not be politically feasible in the near term; carbon prices acceptable to all states would likely be too low to achieve the carbon-reduction goals. The FCEM, by contrast, would not require states, cities or companies to agree on a common price or policy goal: States and customers pay to meet their own goals with no cost-shifting to nonparticipants.
Brattle says traditional RECs offer flat incentives over every hour and incentives to offer at negative energy prices during excess energy hours when displacing other clean supply.
“Dynamic” CEACs would scale payments in proportion to marginal CO2 displacement by time and location, incenting the production of clean energy when and where it is most effective in reducing emissions, Spees said. There would be no incentive to offer at negative prices.
Spees said she was uncertain whether the plan would be subject to FERC jurisdiction or outside it like the REC market and the Regional Greenhouse Gas Initiative. Either way, she said, “it’s critical that states have control over their participation. States were very clear when we went through the IMAPP that they want that flexibility.”
Carbon Pricing
Joe Cavicchi of Analysis Group also gave a presentation on the NEPGA-funded carbon pricing study it released in June.
Joe Cavicchi, Analysis Group | Analysis Group
Cavicchi began his presentation with a look at Western Europe, where carbon spot prices, which he said had been ineffectual at about 5 euros/metric ton in 2017 ($5.89), have generally traded between 20 and 25 euros since 2018 ($23.57 to $29.47).
Analysis Group’s study concluded that New England needs a CO2 price of $25 to $35/short ton by 2025, rising to $55 to $70 by 2030, to meet states’ carbon emissions goals. (See Study: $25 Carbon Price Needed to Meet Goals.)
The Analysis Group’s study concluded that New England needs a carbon price of $25 to $35/short ton by 2025, rising to $55 to $70 by 2030, to meet New England states’ carbon emissions goals. | Analysis Group
Cavicchi said a multisector price on carbon could help the transformation to electrification, allowing “a more accurate assessment of the trade-offs when assessing electricity as a fuel for transportation and heating as opposed to fossil fuels.”
It also would allow technology-neutral competition among existing and new zero-emission resources in the electric sector, incentivizing cost reductions and innovation while reducing the need for future state-directed investments. It would additionally reduce the risk of stranded investments that can result when the costs of power from new technologies drop below long-term contract prices.
The study assumed light-duty electric vehicle penetration of 25% in 2025, 60% in 2030 and 90% in 2035. Similarly, it assumed 25% of homes heating with oil, propane or natural gas would switch to electric by 2025, rising to 50% by 2030 and 75% in 2035.
Although a carbon price would increase wholesale power prices, it would not increase consumer costs materially if states rebate the carbon revenues, the study said.
Next Steps
The PC next month will receive education on energy-only markets, such as ERCOT, and alternative approaches to the region’s existing reliance on the FCM for resource adequacy.
The committee expects to begin discussing the pros and cons of the potential solutions in October.
Consent Agenda
Earlier in the meeting, the PC approved the following on the consent agenda:
The amended and restated Services Agreement between NEPOOL and ISO-NE reflecting the evolution in the roles of ISO-NE, NEPOOL and the NEPOOL Generation Information System Administrator, as recommended by the Markets Committee at its July 14-15 meeting.
Revisions to metering requirements for DC-coupled assets: Manual M-28 (Market Rule 1 Accounting) and Manual M-RPA (Registration and Performance Auditing), as recommended by the MC in July.
Revisions to OP-18 (Metering and Telemetering Criteria), which adds requirements for DC-coupled assets, as recommended by the Reliability Committee at its June 16 meeting.
Revisions to Planning Procedure No. 5-1 (Procedure for Review of Market Participant’s or Transmission Owner’s Proposed Plans) in response to the significant increase of proposed plan applications and generator notification forms being processed monthly. Submittals will be required 10 business days before the monthly RC meeting date. Generator application forms have been updated to enable bulk review and summarization, and information regarding the storage component of co-located facilities will be collected to enable improved summarization. The change was recommended by the RC in June.
Experts last week said it’s mostly policy — not technology — holding back widespread adoption of distributed energy resources supported by smart technology.
Those opinions were on display during Austin, Texas-based electricity data research organization Pecan Street’s “Smart DERs — The Missing Link” webinar Friday.
Eaton Research Lab Engineering Specialist Hossein Ghassempour Aghamolki said there’s still a long way to go in smart DER adoption and that the lack of clear, uniform rules is partly to blame.
“We don’t have a universal strategy. … Every market, region [and] state has its own policy,” he said. Part of the problem is that utilities see DERs as a barrier rather than a tool that can be leveraged through smart meters and load forecasting, he said.
“If the business model is there, the technology can catch up,” Ghassempour Aghamolki said.
| Pecan Street
Arnela Smajlovic, manager of Siemens’ Microgrid Management System, said microgrids are already able to bid into markets for dispatch instructions on behalf of the DERs they manage. She said that scenario can be realized today, but it lacks a business model for commercial use and monetized incentives.
“This concept is all well ahead of its time technology-wise. … We need to get over this limited use of microgrids,” Smajlovic said. “We’re waiting for the business model to catch up. … It’s the [state] commissions that have to agree on how we use this technology.”
Shashank Pande, a Siemens product manager, said smart DER controllers have improved drastically over the last seven years but are still somewhat limited in their capabilities.
“There’s a lot of room to grow in the future,” he said, noting that while inverters improve continuously, constraints involving data sharing and a lack of real-time control still hinder widespread DER systems.
In the meantime, Pande said utilities could do more to expand demand response and time-of-use programs.
Bandera Electric Cooperative CEO William Hetherington said his co-op near San Antonio is focused on incorporating DERs in a rural setting, a completely different challenge.
Hetherington said the co-op began offering rooftop solar installations and programs after getting tired of third-party solar companies hoodwinking members by overcharging and underperforming on generation programs.
The result is Tesla Powerwall solar batteries “scattered throughout the hills of Texas,” he said. Hetherington said Bandera uses the Apolloware DER management system to analyze energy use and avoid overloading inverters.
The co-op has installed about 200 Apolloware systems and hopes to add another 1,000 by the end of 2021, he said. So far, the co-op simply monitors and provides pricing signals and doesn’t perform load control. Hetherington said the idea is that customers get to choose when to respond to price incentives.
“For some reason, people get really upset when you turn their AC off,” he joked.
MISO is once again evaluating the effectiveness of the rules behind its scarcity pricing just three years after shelving a similar effort.
Market Design Adviser Michaela Flagg said the RTO will analyze whether to up its value of lost load (VOLL) and change the shape of the operating reserve demand curve. It would likely file revisions in the second quarter of 2021.
“Shortage conditions are not appropriately priced,” she told stakeholders at during a Market Subcommittee teleconference Thursday.
MISO has said it needs to re-evaluate its scarcity and emergency pricing and is exploring a different cost structure under its yearslong resource availability and need (RAN) project. Shortage and emergency pricing has generally been inefficiently low, the grid operator says. (See MISO Exploring Emergency Pricing, Forward Market.)
The current $3,500/MWh VOLL could be understating the value of involuntary load shedding, and the administratively set price doesn’t account for congestion, generation losses or other reserve shortages, MISO contends.
Principal Adviser of Market Design Michael Robinson said MISO first set the VOLL in 2009 based on the class of customers who value uninterrupted electrical service the least and consider shedding load at that price.
“It’s a little bit dated here,” he said. “We established the price that people weren’t willing to pay, and that’s $3.50/kWh. Now, they’re not going to shed hospitals; they’re not going to shed entities that value uninterrupted electric energy service. They’re going to shed customers that value it less … and prefer interruption to those rates. That was the thinking back then.”
MISO’s Independent Market Monitor recommended it ratchet up the VOLL three years ago when it was implementing MISO, IMM Differ over Scarcity Pricing Changes.) Ultimately, MISO didn’t pursue a higher VOLL.
The RTO must consider the consequences to different market segments when adjusting the VOLL, Robinson said, whether that be inconvenience or ruining leisure, to property damage or spoilage of food and other perishables. He said residential and light industrial customers typically suffer the least from load shedding.
Robinson said MISO has never shed firm load because of a capacity emergency since the rollout of the wholesale markets, although it has experienced local load shedding because of transmission outages.
MISO could use a price index or economic research to update the VOLL, Robinson said. “There are a lot of potential approaches.”
However, while MISO could perform its own analysis of end-use customers to establish a price, it would likely be prohibitively expensive and too labor-intensive, he said.
WPPI Energy economist Valy Goepfrich suggested MISO research the retail rates of customers getting paid to interrupt their load. “It might be interesting what you find,” she said.
Monitor David Patton said the understated VOLL means MISO generation still exports to neighboring PJM during shortage conditions. “It creates a mess when you have two [RTOs] valuing electricity at very different levels. … We view this as the No. 1 item for achieving MISO’s RAN initiative,” he said.
MISO’s operating reserve demand curve stays at $2,100/MWh for most scarcity conditions. | MISO
Additionally, MISO’s operating reserve demand curve (ORDC) isn’t nuanced enough to “differentiate shortage severities, especially above minimum requirements,” Flagg said. “A very large portion of the curve is flat.”
The ORDC curve, based on the VOLL, begins at $3,300/MWh, dropping to $2,100/MWh when the RTO clears 8% of its requirement level. At 89%, the level falls to the original $1,100, remaining there until 96% or more of the requirement is cleared, when the curve flattens at $200.
MISO is also reassessing a five-year-old Monitor recommendation that the RTO stop allowing offline resources to set prices. Currently, offline fast-start resources can set extended LMPs during a shortage. The Monitor contends that allowing offline units to set prices artificially suppresses scarcity prices.
Emergency Pricing Fixes on the Way
MISO Research and Development Adviser Yonghong Chen said the RTO will most likely file with FERC before the end of the year to improve its emergency pricing. Chen said that for now, MISO is pursuing a few “simple” fixes that have high impact:
expanding extended LMP eligibility to allow online units with start-up times of four hours or less to set prices during emergencies and emergency alerts;
taking the Monitor’s advice to set an administrative emergency offer floor for emergency resources that respond without an offer; and
updating the emergency pricing structure to reflect the costs of managing congestion on the regional directional transfer limit linking MISO Midwest and South.
Chen said MISO will work on a conceptual design and a benefits evaluation in the fall.
Restoration Energy Pricing Approved
Meanwhile, FERC last month authorized MISO’s new plan to compensate generators that re-energize the grid following a blackout (ER20-1673).
MISO’s compensation for restoration energy relies on last-submitted offers before a blackout as a starting point for pricing, resulting in unique costs based on resource. The RTO will allow for the recovery of start-up costs, emergency purchases and resource-specific energy costs. It would also include recovery for any unusual costs incurred during operation, provided they can be verified by the Monitor. It would also accept after-the-fact updates of offers. (See “Restoration Energy Design Nears Completion,” MISO Market Subcommittee Briefs: Dec. 3, 2019.)
FERC Commissioner Bernard McNamee announced Wednesday he will leave the commission on Sept. 4, reducing the current four-member panel to three pending the confirmation of his replacement, Virginia State Corporation Commission Chair Mark Christie.
President Trump last month nominated Christie, a Republican, and clean energy activist Allison Clements, a Democrat, to the commission. Clements would fill the seat left vacant by Cheryl LaFleur, who departed nearly a year ago. (See Trump to Nominate Christie, Clements to FERC.)
McNamee, whose term expired on June 30, announced in January that he would not seek a second term but agreed to remain on the commission pending his replacement. He is allowed to remain until the end of the current Congress at the end of the year. (See McNamee Declines to Seek Reappointment.)
“I intend for Sept. 4, 2020, to be my last day serving on the commission,” he said in a statement Wednesday. “Since I announced at our January meeting that I would not be seeking another term, I have continued to work diligently and tirelessly on the important work of the commission. After I leave, I will take some time off and search for a job. Serving as a commissioner has been an incredible honor and an experience for which I am extremely grateful. I thank President Trump for having nominated me and the Senate for having confirmed me. I will have more to say before I leave, but needless to say, I thank the chairman, my fellow commissioners, my advisers and staff, the staff of the commission and all of the FERC community for their support and friendship.”
McNamee was confirmed by the Senate in December 2018. The commissioner, who has been commuting weekly to D.C. from his home near Richmond, Va., has said he is eager to spend more time with his wife and teenage son.
Sen. Joe Manchin (D-W.Va.), ranking member on the Senate Energy and Natural Resources Committee, said the panel has not received the paperwork to hold confirmation hearings on the FERC nominees.
“Commissioner McNamee’s announcement that he will be stepping down in a month’s time means FERC will be operating with only three commissioners as opposed to five. This was not the intention of Congress when the commission was created,” Manchin said in a statement. “I am hopeful the committee will act quickly to restore a fully seated FERC once we have the necessary paperwork.”
The commission will maintain its quorum after McNamee’s departure with Chair Neil Chatterjee and Commissioner James Danly, both Republicans, and Democrat Richard Glick.
The MISO stakeholder community appears to support the RTO’s plan to extend the current arrangement on transmission flows between its Midwest and South regions.
Jeremiah Doner, MISO’s director of seams coordination, told stakeholders during a Market Subcommittee teleconference Thursday that the grid operator will file by Nov. 1 to add two years to a cost allocation agreement with SPP and six other parties. MISO agreed to a settlement, which manages the regional directional flows over SPP’s system to connect the Midwest and South regions, with the seven parties in 2016.
MISO Midwest and South | MISO
Doner said the agreement’s extension was generally well received by stakeholders.
But not all were happy.
MidAmerican Energy’s Greg Schaefer said he was disappointed because his company’s location in Iowa means it is shouldering a heavy financial burden for MISO’s use of SPP’s system above its 1,000-MW contract path.
“All the costs are being loaded onto a relatively small number of parties,” Schaefer said. “It’s not surprising that there is a consensus here.”
MISO’s payments to the other parties for regional flows above the contract path are recovered from its market participants using a special rate schedule, which increasingly has put emphasis on a flow-based beneficiary allocation over a load ratio calculation. The current calculation is 90% flow-based and 10% load-based, which will continue into 2023. (See MISO Seeks Extension on Midwest-South Tx Limit.)
The 2016 agreement can be terminated by any party with a year’s notice beginning Jan. 31, 2021. Without an extension or alternative solution, MISO’s flows would be limited to its original 1,000-MW contract path in either direction. The agreement limits MISO to 3,000 MW of flows in the north-to-south direction and 2,500 MW in the other direction.
MISO has said a two-year extension of the original terms will buy time for it, SPP and the other parties to explore eventually reopening the agreement’s terms. MISO has also said it may revisit the idea of constructing new transmission capacity to supplant the agreement. (See “No Midwest-South Tx Solution this Year,” Price Tag Rising for MTEP 20.)
MISO last week said it will begin hunting for solutions to mitigate “significant gaps” between load-modifying resources (LMRs) that clear capacity auctions and what actually shows up to help mitigate emergencies.
The RTO acknowledged during a Resource Adequacy Subcommittee teleconference Wednesday that it had a problem with the amount of LMR-accredited values and what is listed as available to allay demand during summer peak times.
Market Design Adviser Dustin Grethen said that when MISO hit its summer peak in July 2019, 6 GW of LMRs were listed as available, though 11.5 GW cleared the Planning Resource Auction a few months earlier.
Grethen said some of the availability issues result from LMR outages, fear of penalties by overstating load-reducing capability, overly generous LMRs accreditation, voluntary self-deployment or difficulties using the RTO’s availability reporting tool, the MISO Communication System (MCS). Some LMRs that double as emergency demand response enter availability through a separate RTO tool and not the MCS, he said.
Even those reasons cannot explain all the widespread unavailability, Grethen said. He promised MISO would investigate why some LMRs are no-shows after clearing the capacity auction.
Customized Energy Solutions’ Ted Kuhn suggested the grid operator start by checking the MCS’ availability against the metered data LMRs are required to provide.
The LMR availability gap is part of MISO’s ongoing resource availability and need suite of market improvements. The RTO is still gauging which combination of new resource adequacy and capacity market rules it might adopt to reduce the number of maximum-generation emergency events it declares. (See MISO Closer to Seasonal Capacity, Reliability Reqs.)
As part of that, the grid operator will now scrutinize the actual availability of conventional generators and for what they’re accredited. Planning Adviser Davey Lopez said MISO’s planning reserve margin requirement is likely understated because it doesn’t model real-world generation outage scenarios.
Executive Director of Market Operations Shawn McFarlane said MISO didn’t have to resort to LMRs that day. He said the peak would have been higher had not thunderstorms popped up in the northern part of the footprint.
McFarlane also said the pandemic continues to complicate load forecasting, as air conditioning load is likely skewed to more residential use this year than in others because of customers working from home.
“We think there’s some offsetting things that made it very hard to predict summer peak,” he said.
Despite that, McFarlane called the event “one of the most orderly max gens I’ve seen,” as MISO responded quickly and committed more resources appropriately.
MISO President Clair Moeller said not much has changed in the RTO’s modus operandi after the pandemic’s announcement.
“The risk profile doesn’t seem to be changing much,” Moeller said during an Informational Forum on July 21. “The good news is the operational impacts of the pandemic are manageable … and we don’t expect that to change.”
Moeller said load “crept back up” in July and is now about 5% less than its normal load average.
“We’re still learning how to forecast in this new environment,” he said.
Consolidated Edison said Thursday that the COVID-19 pandemic had negatively impacted its first-half earnings by $52 million — a report that came as the utility struggled to restore power to its more than 500,000 customers in and around New York City after Tropical Storm Isaias hit two days earlier.
The negative impact primarily reflects foregone revenues from the suspension of customer late payment charges and certain other fees associated with the pandemic, as well as higher depreciation and amortization expense, offset in part by the Employee Retention Tax Credit under the CARES Act, the company said.
Despite the effects of the pandemic, net income for the first six months of 2020 was $565 million ($1.69/share), only a 2% drop from the $576 million ($1.77/share) in the first half of last year. Con Ed also reported second-quarter net income of $190 million ($0.57/share), compared to $152 million ($0.46/share) during the same period in 2019.
Con Edison reported the pandemic had a negative impact on net revenues of $52 million in the first half of 2020. | Con Edison
“We are facing today’s unprecedented challenges by providing essential and reliable service during the pandemic,” CEO John McAvoy said in a statement. “We understand the hardship that Tropical Storm Isaias has had on our customers, and we are working around the clock to restore service.”
McAvoy said crews were restoring power to approximately 300,000 Consolidated Edison Company of New York (CECONY) and 225,000 Orange & Rockland Utilities (O&R) electric customers affected and called Isaias “the second-worst storm in our company’s history.”
Con Edison’s long-range plan forecasts EV-related usage will reach 7.2% of system peak, or 107 MW, in 2038. | Con Edison
The company highlighted the New York Public Service Commission’s decision in July to establish a light-duty electric vehicle “make-ready” program, which includes budgets of $290 million and $24 million for CECONY and O&R, respectively, through 2025, for fast-charger stations and other services. (See NYPSC Approves $700 Million for EV Chargers.)
NERC opened 45-day comment periods last week for proposed reliability guidelines on winter weather readiness and supply chain procurement, as well as on planned changes to its Critical Infrastructure Protection (CIP) standards.
Comments will be accepted on the reliability guidelines through 5 p.m. Sept. 21 and through 8 p.m. Sept. 21 for the CIP standards. In addition, ballots for the standards and implementation plan, along with nonbinding polls for associated violation risk factors and severity levels, will be conducted Sept. 11 to 21.
NERC Adds Detail to Winter Guideline
The proposed changes to the winter weather guideline were developed during the regular three-year review process for NERC reliability guidelines. The guideline is currently in its second version, approved in July 2017.
Updates in the most recent draft guideline include replacing references to the Operating, Planning and Critical Infrastructure Protection committees with the new Reliability and Security Technical Committee (RSTC), along with adding detail to the existing guideline’s recommendations for evaluating the readiness of critical components.
New to the recommendations is a clear deadline for finishing winter-related inspections, repairs and upgrades by the local first frost date as set by the National Oceanic and Atmospheric Administration. The guideline also adds lubricants, batteries, uninterruptible power supply systems, and heat tracing and ventilation systems to the list of components that utilities should check for winter readiness.
The winter reliability guideline is separate from the proposed cold weather standard currently under development by NERC (Project 2019-06). Some industry stakeholders have questioned the need for mandatory standards on the grounds that the existing guidelines should be sufficient, but NERC representatives have pointed to ongoing issues with cold weather as a reason for continuing the project. (See Cold Weather SDT Planning February Posting.)
“Out of the past 12 years, there have been six blackouts [from extreme cold] — that is a problem. … Obviously, the NERC guidelines may not be enough,” NERC Senior Standards Developer Jordan Mallory said at a meeting of the SAR drafting team in January.
Draft Supply Chain Guidelines Use Broad Strokes
NERC’s proposed supply chain procurement language guideline was developed under the Critical Infrastructure Protection Committee but moved to the RSTC following the merger of the technical committees. The guideline focuses on helping organizations implement effective controls in procurement agreements to prevent exposing themselves to cyberattacks through equipment purchases.
“Regulators have challenged the levels of rigor regarding risk management practices that organizations claim to have attained,” the guideline says. “Remedies applied through the inclusion of targeted controls in the procurement of cyber systems, components, maintenance and related services can assist in the development of a ‘risk-based’ approach to cybersecurity.”
Currently the guideline is in its first draft, so it lacks specific measures for entities to adopt. Instead, the document focuses on broader principles that utilities can follow in their contracts with suppliers, such as identifying cybersecurity risks that might be in play with a particular vendor and specifying audit mechanisms and metrics to ensure vendors are complying with needed changes.
The comment and balloting period for reliability standards CIP-004-7 and CIP-011-3 are hoped to be the last for Project 2019-02, which is focused on clarifying requirements to access bulk electric system cyber system information (BCSI) and establishing guidelines for encryption or other methods to protect such information.
Both standards saw relatively few changes from the last posting: In the case of CIP-004-7, the only significant change is the addition of a new requirement that responsible entities “implement one or more documented access management program(s) for [BCSI]” along with a table defining what such programs must consist of. Changes to CIP-011-3 include clarifying requirements for the reuse and disposal of BES cyber assets and for the components of entities’ information protection programs.
The latest posting also incorporates language previously agreed between the teams for Project 2019-02 and Project 2019-03 to address concern about potential overlaps between their projects. The conflict centered on risk assessments for cloud storage providers, which both groups saw as their domain; however, earlier this year the team for Project 2019-02 agreed to leave specific risk assessment language to the other team and keep its focus on broader questions of risk management. (See CIP Teams Compromise on Cloud Risk Assessment.)
