The key players in the Western reliability coordinator transition said Wednesday they’re largely on track to take over from Peak Reliability on a staggered timeline from July to December.
“Overall, our project is on schedule, and we’re making changes needed to be ready in August,” Bruce Rew, SPP’s vice president of operations, told the Western Electricity Coordinating Council’s RC Forum in a web-only meeting.
SPP and CAISO will be the main RCs for the Western states, while BC Hydro will assume responsibility for most of British Columbia. Gridforce will serve several small balancing areas in Arizona, Oregon and Washington. Alberta Electric Service Operator will continue performing the RC function in its province, rounding out the Western Interconnection.
CAISO and SPP are taking over RC responsibilties in most of the West this year. | CAISO
Each entity provided an update on its progress Wednesday, and Peak described its gradual wind down as it exits the RC business this year.
CAISO’s RC West will start the handoff when it takes over RC services for its California territory July 1. The ISO is awaiting final certification from NERC, which it expects to receive “any day now,” Tim Beach, RC West’s director of operations told the forum. (See RC West Moving Smoothly Toward July Handover.)
RC West staff members are in the second phase of shadowing Peak employees and have already been involved in problem situations, including a high-voltage event last weekend in California that required switching a transmission line out of service to mitigate the problem, Beach said.
After July 1, RC West will be preparing for Nov. 1, when it assumes the RC role for most of the West; 39 entities have contracted for its services from the Canadian border to northern Baja California and from the Pacific Ocean to the Rocky Mountains.
SPP has agreements with 13 customers, 11 of which have completed connecting with SPP, Rew said. The utility will start its certification process with WECC and NERC in August in anticipation of going live Dec. 3. (See SPP on Track for WECC RC Certification.)
Gridforce President C.J. Ingersoll said that as a relative newcomer, the company is in “catchup mode” but with its small footprint, things should work out fine.
“Our target go-live date is Dec. 3, and we feel like we’re on track there,” Ingersoll said.
Asher Steed, BC Hydro’s manager of provincial reliability coordination operations, said the company’s employees will start shadow operations with Peak on July 8 as it ramps up for its Sept. 2 start date.
Peak said all is going as planned on its end. Losing key staff members was a major concern earlier this year, but the company’s retention policies, including severance packages, appear to have worked, Chief Administrative Officer Rachel Sherrard said.
“We’ve had some unplanned attrition. Not a lot.” The company has shrunk from more than 160 employees in May 2018 to 119 today, she said.
Peak will start decertifying Dec. 4, vacate its offices in Vancouver, Wash., and Loveland, Colo., and cease to be a company by May 2020.
Eric Whitley, a grid expert from Folsom, Calif., who serves on WECC’s RC Transition Coordination Group, said “Peak will not be operational after the last transition on Dec. 3. There’s no going backwards,” he warned. Peak has posted a banner on its website showing the countdown to when it ceases operations.
The forums will continue every two or three months, as needed, Whitley said.
“It’s going to be a very active rest of the year,” he said.
FERC Chairman Neil Chatterjee’s suggestion that incentives may be needed to encourage investments in infrastructure security received mixed reaction in comments filed with the commission this week (AD19-12).
At a March 28 technical conference by FERC and the Department of Energy, Chatterjee said he wanted to learn whether incentives were needed to encourage security investments beyond those required by NERC reliability standards. (See TSA Defends Pipeline Security Practices Before FERC.)
In post-conference comments, the Edison Electric Institute and EEI members Dominion Energy, FirstEnergy and American Electric Power expressed support for some form of “resilience incentives,” along with the North American Generator Forum, Calpine and International Transmission Co. EEI asked for incentives for technologies such as “high-temperature superconductor, smart grid communications-enabled technology or resilient hardened substation designs.”
But EEI members Exelon and Alliant Energy opposed the idea, as did the Electric Power Supply Association, the American Public Power Association, transmission-dependent utilities (TDUs) and industrial consumers.
“An initiative to revise existing incentives or develop new ones may unintentionally distract resources from what is truly needed to continue making investments in the physical and cybersecurity of our assets: the regulatory certainty provided by timely and fair commission action on filings that involve cost recovery and price formation matters,” Exelon said.
The North American Generator Forum said deregulated generators have no federal or state cost recovery mechanisms for security spending and “have significant challenges justifying additional cybersecurity spending beyond the mandatory requirements.”
Small generators also cannot afford dedicated information and operational technology staff on site, it said. “A government-sponsored program to provide cyber forensic assistance for facilities with limited resources would be a welcome tool for those facilities to be able to rely upon in times of need,” it said.
It also said market mechanisms and tax incentives should be considered as ways to provide cost recovery, noting state property taxes act as a disincentive for maintaining spare transformers. “We should ensure that early adopters that have completed security projects beyond the required compliance have a method to recover costs.”
EPSA called for “continued observation and analysis” of incentives in the future but said competitive suppliers “are currently able to recover costs associated with cyber and physical security through a number of sources, whether through market-based rates collected in the organized electricity markets, retail revenues, provisions within power purchase agreements or other sources of revenue.”
But EPSA member Calpine said the commission should consider “maturity credits” for industry participants who meet or exceed security goals to encourage best practices.
The Electricity Consumers Resource Council (ELCON), which represents industrial users, countered that competitive generators already have incentive to adopt cost-effective security practices — the opportunity cost of foregone market revenues if they are idled. “Shifting a segment of competitive generators’ costs to cost-of-service would set a deeply problematic precedent,” it said. “Security is an easy justification for cost-of-service entities to expand rate base.”
ELCON criticized ISO-NE’s proposal to recover generators’ costs for meeting critical infrastructure protection (CIP) standards via cost-based rates, saying such costs should be collected via energy and capacity markets. (See Eversource Balks at ISO-NE Plan on CIP Costs.)
“The costs of compliance with new regulations — CIP or otherwise — is an investment risk that should be internalized by competitive generators, not socialized through a new charge on transmission customers.”
If market power mitigation rules do not allow the collection of such costs, they should be changed, ELCON said.
Dominion, however, said generators subject to CIP standards in organized markets may be at a disadvantage without “tailored cost recovery mechanisms in RTOs.”
“Under current market rules, developers may favor only building new generation resources that are not subject to NERC CIP standards, resulting in incremental generation on the system that is not optimally located for reliability and system stability.”
Transmission Incentives
ITC said the commission should ensure cost recovery for transmission owners that go beyond NERC standards “consistent with Order No. 679 and associated commission policy.”
But Alliant rejected the idea of a “resilience incentive,” saying it would “provide a financial windfall to transmission owners without providing commensurate benefit to transmission customers. As stated at the technical conference, transmission owners currently do not have difficulty securing financing for transmission projects.”
“Given that utilities with cost-of-service rates are able to recover the costs of any prudent security investments, it is neither necessary nor appropriate to grant them financial incentives for such investments,” agreed the Transmission Access Policy Study Group, which represents TDUs.
APPA said “unjustified incentives could be particularly problematic for its” TDU members. “The costs of incentives paid by public power utilities in their transmission rates might be on top of infrastructure security costs incurred by public power utilities on their own systems,” it said.
FirstEnergy said FERC should ensure black start resources are “appropriately valued” as transmission assets. It also called for funding for information sharing programs such as the Cybersecurity Risk Information Sharing Program (CRISP) managed by NERC’s Electricity Information Sharing and Analysis Center. “The costs for participation in CRISP can be prohibitively expensive for smaller companies or municipalities. While companies participating in CRISP cover over 75% of U.S. customers, the goal should be 100%. Given the interconnected nature of the grid, the lack of participation by smaller entities could pose a significant threat to the reliability of the Bulk Power System.”
Gas: Incentives Yes, Standards No
The American Gas Association, which represents local distribution companies, said it supports tax credits to reduce the costs of cybersecurity investments and certification processes that can be used to obtain lower insurance rates.
It also said state regulators should provide cost recovery for physical and cybersecurity measures, including cyber mutual assistance programs, video surveillance, sensor technology, physical barriers and lighting. Only some states allow security riders to recover investments outside of a full rate case, AGA said.
It said the gas industry should continue following voluntary guidelines and best practices rather than being subject to the kind of mandatory standards that cover electric utilities.
“Allowing for riders based on, for example, the [Transportation Security Administration] Pipeline Security Guidelines, [the National Institute of Standards and Technology’s] Framework for Improving Critical Infrastructure Cybersecurity or [DOE’s Cybersecurity Capability Maturity Model] could accelerate the adoption of enhanced security practices and tools,” it said. “Cost recovery that is limited to mandatory guidelines or standards for high-risk or critical energy facilities penalizes forward-thinking operators that are being proactive voluntarily and looking ahead to the next challenge.”
Bandwidth
The Utilities Technology Council — a trade group for electric, gas and water utilities’ telecommunications and IT functions — called on FERC to join it in fighting the Federal Communications Commission’s proposal to allow others access to the 6-GHz frequency band, a communications channel used by electric utilities and other critical-infrastructure industries (CII).
“While UTC recognizes FERC has no authority over the FCC or spectrum, it nonetheless has a distinct interest in this proceeding. As the agency responsible for assuring the reliability of our nation’s Bulk Electric System, FERC should amplify the significant concerns raised by the entire electric utility and the oil and natural gas industries that are in opposition to the FCC’s 6-GHz plan and urge the FCC to protect utilities and other CII from interference in the band.”
Public Citizen criticized FERC’s reliance on “industry self-reporting” and said it should do more to protect whistleblowers. It also called for public identification of utilities that violate NERC standards and said NERC is not independent of the electric utility industry.
Delta Star, a Virginia-based provider of substation equipment, used its comments to make a sales pitch for trailer-mounted mobile substations, calling them “the only product that can be remotely secured from terrorist, cyber and physical threats and still be dispatched and installed within a matter of hours.”
Delta Star, a Virginia-based provider of substation equipment, said FERC should encourage the use of trailer-mounted mobile substations. | Delta Star
Beyond Standards
The National Association of Regulatory Utility Commissioners did not say whether it supported incentives. Instead, it suggested states would benefit from improved information sharing by FERC’s Office of Electricity and Infrastructure Security and DOE’s Office of Cybersecurity, Energy Security and Emergency Response.
ELCON called for less emphasis on mandatory NERC standards and more information sharing on emerging threats and best practices for defense. “The rapid rate of change in computing technology is outpacing the ability of standards development processes,” it said.
On that, EEI appeared to agree. “The commission’s current approach of addressing new threats with new requirements is pushing the CIP standards into areas beyond the electric industry and electric company control,” it said. “We encourage the commission to take a more comprehensive approach to security than simply directing the development of modified or new industry security requirements.”
Texas regulators last week delayed action on a proposed transmission project in the oil-rich Permian Basin, allowing the parties involved to make modifications in the proposed order (Docket 48785).
“Two weeks won’t hurt us,” PUC Chair DeAnn Walker said during Thursday’s open meeting. The commission meets next on June 13.
The Texas PUC’s May 23 open meeting
Oncor and AEP Texas filed an application last year to build a 345-kV double-circuit transmission line from Oncor’s Sand Lake switch station in Ward County to AEP Texas’ Solstice switch station in Pecos County. The potential routes range from 44 to 59 miles in length with estimated costs of $98 million to $127 million. The line is part of the $336 million Far West Texas transmission project, approved by ERCOT in 2017. (See ERCOT Board Approves West Texas Transmission Project.)
The Route 320 path recommended by Administrative Law Judge Steven Neinast runs through what the judge called a “densely packed” Occidental Petroleum oilfield. Occidental would like to see the line shifted at a cost of $18 million.
Walker added language to the order to give Oncor and AEP flexibility in deviating from the approved route, but only if the parties can receive consent from all affected landowners. Oncor and Occidental both said they were having trouble working with all the landowners.
“I understand the problems they’re talking about,” said Walker, a former landman. “I don’t mind giving utilities some leeway to relocate, but I don’t know that we can get as far without the consent of landowners. I was prepared to move [this] out, because we’ve got to get transmission in the Permian Basin, but I think $18 million is a large amount to add to the transmission cost.”
AEP, LCRA Get Their West Texas CCNs
The PUC awarded certificates of convenience and necessity (CCNs) to AEP and Lower Colorado River Authority Transmission Services for the Bakersfield-Solstice portion of the Far West Texas transmission project (Docket 48787).
The project will connect AEP’s Solstice station and LCRA’s Bakersfield station with a 71-mile, 345-kV double-circuit line. The preferred route was the fourth cheapest among 25 options at $156 million. Expansion work at the two substations will add $45 million to the project.
AEP and LCRA said the project will support the area’s load growth, address reliability violations and provide the infrastructure necessary to facilitate further expansions. The companies cited an eight-fold load increase on nearby transmission lines that were built in 2012 and 2017.
| ERCOT
PUC Grants SWEPCO $6.5M Recovery
In other actions, the PUC granted Southwestern Electric Power Co.’s request to recover nearly $6.5 million through its distribution cost recovery factor (Docket 49041).
The commission also approved a pair of settlements that resulted in $210,000 in administrative penalties:
Retail electric provider Ambit Energy was assessed $160,000 for moving numerous customers to a new, higher-priced plan without the customers’ consent (Docket 48859).
LCRA was hit with a $50,000 penalty for failing to reserve sufficient capacity to meet its response reserve service obligations (Docket 49466).
FERC on Wednesday rejected a contested offer of settlement on network service rates for a group of New England transmission owners (NETOs) (ER18-2235, EL16-19).
The settlement proposed new rates and a new rate design for regional network service (RNS), local network integration transmission service (LNS) and point-to-point (PTP) transmission service for all the TOs in the region. It would have replaced the existing RNS and LNS rates with new formula rate templates and associated protocols. The PTP rates fall under the same Tariff schedule as LNS.
FERC instituted the proceeding in December 2015, saying ISO-NE’s Tariff “lacks adequate transparency and challenge procedures” on the NETOs’ formula rates and that the network rates “lack sufficient detail” to determine how costs are derived and recovered.
| Central Maine Power
In responding to requests for rehearing of its December 2015 order that established hearing and settlement judge procedures over the matter, the commission noted that it would not be possible to ensure the justness and reasonableness of the transmission rates in the ISO-NE Transmission, Markets and Services Tariff unless the NETOs “were all considered together in a single proceeding due to the possibility of a mismatch in the synchronization of the rates, timing of true-ups, cost allocation or methodology for calculating the RNS rate and LNS rates.”
Last September, the New England States Committee on Electricity (NESCOE), New England Power Pool Participants Committee and the NETOs separately filed comments in support of the settlement, while municipal utilities individually submitted comments in opposition.
The municipals contended that the settlement disadvantaged them by imposing costs for local — or “non-pool” — transmission facilities that provide them with no material benefit. They also contested the settlement’s inclusion of a five-year moratorium prohibiting Federal Power Act Section 205 or Section 206 filings to change the settlement. They argued that it was “heavily lopsided” because it would have subjected non-settling parties to the “most stringent standard of review under applicable law” in challenges under Section 206 while its exceptions “essentially eliminate most constraints that a moratorium would otherwise impose on the Section 205 filing rights of a transmission-owning utility.”
FERC trial staff argued that the settlement was unfair because it contained unreasonable rates and “contains fundamental defects.” Staff cited the TOs’ ability to: conduct “extra-formulaic, ad hoc” ratemaking for all externally sourced inputs every year; over-recover certain plant costs; and recover a return greater than 50% of funding for construction work in progress.
In its order rejecting the settlement, FERC noted that under the approach outlined in its Trailblazer decision, the commission may approve a contested settlement if it determines that “the contesting party’s interest is sufficiently attenuated that the settlement can be analyzed under the fair and reasonable standard applicable to uncontested settlements” and that it makes an independent finding that the settlement benefits the “directly affected” settling parties.
“Here, there are two obstacles to this approach,” FERC wrote. “First, the record is insufficient to determine whether the settlement’s benefits outweigh the objections to it; in fact, contesting municipals present evidence that there is more harm than benefit. Second, the parties who are directly affected by the settlement’s RNS and LNS rate calculation provisions include both parties who support the settlement (NETOs) and those who oppose the settlement (contesting municipals).”
The commission said that based on “the overall lack of necessary detail and transparency,” it could not accept the settlement, and it remanded the proceeding to the chief judge to resume hearing or settlement procedures.
The next day, the chief judge issued a procedural order assigning a hearing judge, a procedural track for the hearing, and a dispute resolution specialist to serve as a settlement facilitator.
The NETOs are Central Maine Power; Emera Maine; Eversource Energy Service; Fitchburg Gas and Electric Light; Maine Electric Power; National Grid; Unitil Energy Systems; United Illuminating Co.; Vermont Electric Power Co.; and Vermont Transco.
The California Public Utilities Commission late Friday released an administrative law judge’s proposed ruling approving staff’s “stress test” methodology for determining rate recovery for 2017 wildfire costs, part of an effort to maintain the credit ratings of the state’s investor-owned utilities.
The methodology, mandated under last year’s SB 901, seeks to balance the IOUs’ financial health against the impact of rate increases on consumers. (See California Wildfire Bill Goes to Governor.)
The proposed ruling would not apply to Pacific Gas and Electric, however, because it exempts utilities that have filed for Chapter 11 bankruptcy reorganization. PG&E filed for bankruptcy Jan. 29, citing, in part, its liability for a series of 2017 blazes that tore through Northern California wine country and the Sierra Nevada foothills.
The California Public Utilities Commission released an administrative law judge’s proposed ruling approving staff’s “stress test” methodology for determining rate recovery for 2017 wildfire costs. | U.S. Forest Service
The 2018 Camp Fire, the deadliest and most destructive fire in state history, is not covered under the bill’s stress-test provision, though lawmakers may yet apply SB 901’s requirements to 2018 fires and future blazes. State investigators recently blamed the Camp Fire on PG&E equipment. (See Cal Fire Pins Deadly Camp Fire on PG&E.)
The most obvious application of the proposed ruling would be to Southern California Edison. State investigators determined SCE’s power lines sparked the Thomas Fire, a 280,000-acre blaze in Santa Barbara and Ventura counties that killed two people and later caused a mudflow that killed 21. (See Edison Takes Partial Blame for Wildfire in Earnings Call.)
The ALJ’s decision has no legal effect until the CPUC approves it. The commission may consider the ALJ’s proposed order as early as its June 27 meeting.
In the “normal course of regulation of investor-owned utilities, a utility seeks recovery of its anticipated costs of operations and a reasonable return on its investments from ratepayers and seeks equity and debt from public markets to fund those operations in advance of the recovery permitted from ratepayers,” Judge Robert W. Haga wrote.
“In the case of a utility exposed to extraordinary costs as a result of a catastrophic 2017 wildfire, however, Senate Bill 901 … adds an exception to the process of rate regulation of investor-owned utilities. Public Utilities Code Section 451.2(b) enacts a new limitation on recovery of such costs from ratepayers and requires the commission to determine the maximum amount, after assessing the financial status of the electrical corporation … that the corporation can pay without harming ratepayers because of an increased cost for access to capital markets, or materially impacting its ability to provide adequate and safe service from inadequate financial resources.”
The main driver of the stress test “is the implied maximum additional debt that a utility can take on and maintain a minimum investment grade issuer-level credit rating” based on the ratings of Moody’s Corp. and S&P Global, Haga wrote.
Earlier this year, investor services downgraded the credit ratings of PG&E, SCE and Sempra Energy, the parent company of San Diego Gas & Electric, to junk-bond or near-junk status because of wildfire liability worries. California holds utilities strictly liable for fires sparked by their equipment under a state constitutional doctrine known as inverse condemnation. (See Calif. Must Limit Wildfire Liability, Governor Says.)
“The stress test therefore focuses on maintaining an investment grade credit rating because this metric is a predictable indicator of a utility’s ability to access capital markets on reasonable, acceptable terms, which is critical to avoid materially impacting its ability to provide adequate and safe service. … In addition to materially impacting a utility’s ability to provide safe and adequate service, utility ratings below investment grade have negative impacts that harm ratepayers. … The stress-test model therefore looks at the utility’s ability to take on additional debt while maintaining an investment grade credit rating, in order to also minimize financial harm to ratepayers,” Haga wrote.
The proposed decision wouldn’t affect PG&E, he said, because “an electrical corporation that has filed for relief under Chapter 11 of the Bankruptcy Code may not access the stress test to recover costs in an application under Section 451.2(b), because the commission cannot determine the corporation’s ‘financial status,’ which includes, among other considerations, its capital structure, liquidity needs and liabilities, as required by Section 451.2(b), as well as its capacity to take on additional, and all cash or resources that are reasonably available to the utility.”
SACRAMENTO, Calif. — Utilities are bracing for another fire season as the state heads into summer, but officials say troubling questions remain about how to gauge their level of readiness.
Pacific Gas and Electric said widespread power shutdowns will be a key part of its strategy following two years of catastrophic fires fueled by high winds and dry vegetation. The Camp Fire, sparked by PG&E equipment Nov. 8, was the deadliest and most destructive in state history.
Wildfires have darkened the sky in Northern California, including the San Francisco Bay Area, for the past two summers, but utilities are vowing change. | USDA
The state’s two other large investor-owned utilities, San Diego Gas & Electric and Southern California Edison, have employed strategic shutdowns for years, but this could be the first season that tactics used in drier Southern California are regularly deployed in relatively rainy Northern California.
“We will only turn off power for public safety and only as a last resort to keep our customers and communities safe,” PG&E said in a news release, responding to controversy surrounding the program.
The Camp Fire and a rash of deadly fires in 2017 led PG&E to file for bankruptcy in January, shake up its leadership and boost fire-prevention practices. (See PG&E Names New CEO, Board Members.)
The utility’s Public Safety Power Shutoff program now includes roughly 25,000 miles of distribution lines, up from 7,000 last year, and about 5,500 miles of transmission lines, including 500-kV lines, an increase from 373 miles at 70 kV and below in 2018. The plan affects potentially millions of customers in areas of elevated and extreme fire risk in the state’s coastal regions, mountains and foothills.
‘Uncharted Waters’
At a legislative hearing last week, representatives of the IOUs and an official from the California Public Utilities Commission outlined additional measures and shortcomings in the state’s firefighting arsenal. The hearing of the Assembly Utilities and Energy Committee examined the IOU’s wildfire mitigation plans filed with the CPUC earlier this year. (See PG&E Lays out Billion-dollar Wildfire Plan.)
“We’re in uncharted waters,” committee Chairman Chris Holden said.
Sumeet Singh
Sumeet Singh, in charge of PG&E’s wildfire safety program, said the utility has installed 350 weather monitoring stations and plans to have 1,300 by 2020. It has installed 30 high-definition fire-detection cameras and is aiming for three times as many in 2019. The cameras allow firefighters to more quickly verify the location of a fire and monitor its progress before arriving on the scene.
“We’re looking to get to 100 cameras by the end of this year” and to establish remote visual coverage of 90% of PG&E’s high-risk fire areas in the next two to three years, he said.
PG&E said it is making a major push to inspect and harden its grid, which covers 70,000 square miles of Northern and Central California, or 42% of the state. A federal judge overseeing the utility’s criminal probation in the San Bruno gas pipeline explosion case has put pressure on the company to increase inspections and fix problems. (See Judge Postpones Strict Probation Conditions for PG&E.)
“We launched an aggressive inspection program [in] December of 2018, where we moved forward with inspecting all of our transmission infrastructure in the high-fire-risk areas, and we are near completion of doing the same for our distribution system,” Singh told lawmakers. “This really entails an unprecedented level of effort that we have undertaken within our service territory.”
Singh said PG&E has increased transmission line inspections by 130% this year and ramped up inspections of distribution lines by 400%, using a combination of drones, helicopters and workers. The company has turned to Silicon Valley to adopt machine learning to identify potential problems using powerline imaging, he said. (See Silicon Valley Tackles Wildfire Prevention.)
The company is boosting its vegetation management, including clearing branches that overhang bare wires even when its vegetation clearances meet regulatory standards, he said. Half of all ignitions occur when overhanging vegetation contacts power lines, Singh said.
Replacing wooden poles with composite ones and strategically burying some power lines are among other grid hardening strategies, he said. The utility recently said it would bury new power lines in Paradise, as the town is rebuilt.
Gaps in Expertise, Resources
PG&E’s moves mirror those undertaken by SDG&E in the last decade after a series of devastating wind-driven fires in San Diego County in the early 2000s. The combination of 175 weather stations, more than 100 cameras, de-energization and grid hardening has eliminated major wildfires sparked by power lines in the utility’s service territory, said Brian D’Agostino, director of fire science and climate adaptation at SDG&E.
“Since we’ve implemented this plan over a decade ago, we have not seen a catastrophic wildfire ignited by electrical equipment across our region,” D’Agostino told the committee.
The company has spent $1.4 billion in its effort and is continuing to improve, he said. Expanding the use of easements as firebreaks is a current focus, he said. So is tracking “every spark,” he said.
SCE has adopted similar techniques and is pursuing others along the same lines as SDG&E and PG&E.
“They build upon programs we’ve had for many years — things we’ve done in response to redline warnings,” said Phil Herrington, senior vice president of transmission and distribution for SCE.
About one in 10 wildfires in California are ignited by electrical equipment, but a higher proportion of those fires grow into destructive blazes, state fire officials said.
Elizaveta Malashenko
Elizaveta Malashenko, the CPUC’s deputy executive director of safety and enforcement, said the utilities’ efforts may be laudable, but their timelines for completion remain uncertain, and no industry-wide standards exist for wildfire prevention. Last year’s omnibus wildfire bill, SB 901, required mitigation plans to be filed with the CPUC, yet evaluation has proven difficult without longer-term data, she said.
“The PUC isn’t set up to top the expertise of utilities … so I think that’s a gap,” Malashenko said.
“I think we also lack a vision of where are we going with all of this,” she said. “There’s a lot of activity that’s being proposed as part of wildfire mitigation plans, and it looks like the right type of activity, but we don’t really have an articulated vision of what goals we are trying to hit in the future.
“We hear a lot of statements of, ‘This is going to take a long time. We shouldn’t expect that this first round of wildfire mitigation plans and these efforts that utilities are putting in place right now will address all wildfire problems this year.’ … But I think we need to unpack this a bit more and get more specific,” she told the committee.
“What does this mean? How long of a roadmap are we talking about? Are we talking about being able to see measurable results in five years, in three years, in 10 years, in 50 years? How are we going to track that, and what does the system of the future look like?”
Regarding wildfire compliance, there are no black-and-white rules like a building code, she said. And the CPUC was never designed to inspect power lines. “That capability is nonexistent,” Malashenko said.
Every foot of rail line in the state is regularly inspected by CPUC personnel. Doing the same with power lines would require 1,300 to 1,500 additional workers and an annual budget of $125 million, she told lawmakers.
“To me, the question here isn’t which agency does it, but that this gap exists, and we need to recognize it,” she said.
MISO’s Steering Committee last week routed eight new market improvement proposals to stakeholders for debate and prioritization by voting.
During a Wednesday conference call, the Steering Committee said eight of the 11 ideas submitted met the criteria to be considered in the Integrated Roadmap list of market improvements due later this year. They will be ranked by staff and stakeholders alongside existing Roadmap ideas from previous years.
The Steering Committee does not debate the merits of Roadmap candidates, leaving that instead to the Market Subcommittee and the Resource Adequacy Subcommittee.
MISO control room | MISO
Main Line Ideas
The package contains three ideas from Main Line Generation, including a suggestion that MISO include energy efficiency measurements in its load forecasting method.
“At present, there is no clear articulation of the process by which energy efficiency measures are included in the demand side of the MISO Planning Resource Auction,” Main Line said.
Some Steering Committee members argued that the proposal was a waste of time because energy efficiency only accounts for about 312 MW of capacity in the footprint and that stakeholders have already spent enough time on the matter. Nevertheless, the item was moved for Roadmap consideration.
Main Line also recommended that MISO develop a way to verify the accuracy of coincident peak load forecasts provided by load-serving entities. While the RTO conducts a random sampling to check load forecasts, Main Line called the current method an “opaque process where stakeholders and MISO are not provided with a detailed understanding of the key drivers of the large majority of the load forecasts provided.”
Finally, Main Line asked that MISO adopt a sloped demand curve in its capacity auction. This is the first time the oft repeated call for a sloped demand curve has ever made it to the Roadmap process.
Monitor Recommendations
The committee advanced two ideas from Independent Market Monitor David Patton, who recommended the RTO use a lower generator shift factor (GSF) cutoff for transmission constraints with limited relief. MISO currently employs a 1.5% GSF cutoff to identify which generators to optimize in its dispatch when managing the flows on a constraint, but the Monitor said that policy “eliminates most or all of the economic relief available” for some constraints.
Patton also said MISO should reduce the unpredictability of its emergency pricing by implementing fixed default floors. Emergency pricing default floors are currently set by a supplier’s offer, which can result in them being either too high or too low under different circumstances, Patton said. He also said the RTO should better calculate megawatt limits on its North-South contract path during emergency pricing events.
Other Recommendations
Among the remaining ideas was a recommendation by Indianapolis Power & Light that MISO introduce a financial incentive for market participants providing primary frequency response, in line with the company’s unsuccessful 2016 FERC complaint. MISO had placed the item in its Roadmap “parking lot” in 2018, putting discussion on hold.
Clean Grid Alliance asked MISO to begin preparations to move to a “universal participation model” that would “eliminate the need for technology-specific generator models.” The group said the removal of standard generator models would allow any technically capable resource to participate in the RTO’s markets. CGA’s Natalie McIntire clarified that the group is only proposing that MISO scope the system changes required to forgo differing models sometime in the future.
Finally, MISO Market Strategy Adviser Lakisha Johnson said the RTO should focus on improving its scarcity pricing and price formation so it can meet needs across all hours and during scarcity pricing in nonemergency events. “Continuously improving scarcity pricing provides incentives for resources to follow MISO’s dispatch,” Johnson said. Some Steering Committee members criticized the idea as too broad.
Direct Path to Stakeholders
Three ideas from Patton were not included in the Roadmap package, instead going directly before other committees for discussion or because they were already being considered as part of the ongoing Resource Availability and Need (RAN) effort. Those ideas include:
A recommendation that MISO improve capacity accreditation in the long term by establishing accreditation on resource availability “during high-load or tight supply periods.” Steering Committee members said the idea was best included in the RAN project, which already aims to evaluate the overall process of capacity accreditation.
A recommendation that MISO improve outage data for capacity calculations by treating unreported outages and derates as forced outages and accounting for the fact that “forced outages may occur when a resource would not have been dispatched.” The Steering Committee said the issue is already being considered in RAN discussions.
A suggestion that MISO improve the calculation of capacity requirements by factoring in the obligation to serve behind-the meter load and accounting for the lead times of load-modifying resources and other emergency resources in the loss-of-load expectation (LOLE) study. Patton said MISO’s LOLE studies “essentially assume that [LMRs and emergency resources] provide more reliability value to the system than they do in reality.”
Meanwhile, the eight forwarded ideas will go before stakeholders for ranking next month. MISO has planned an Aug. 8 stakeholder workshop to review the prioritization of improvements. A final report on how it will order the improvements in the Roadmap won’t be complete until November.
CARMEL, Ind. — MISO is still pondering whether to amend its Order 841 compliance filing, after FERC earlier this month rejected multiple requests to alter the landmark order requiring RTOs to provide storage resources access to their markets.
As part of its May 16 ruling (Order 841-A), the commission rejected MISO’s requests to reconsider compliance deadlines and consider a phase-in for minimum size requirements for storage participation. (See FERC Upholds Electric Storage Order.)
“MISO is still reviewing Order 841-A,” Kevin Vannoy, the RTO’s director of market design, said at an Energy Storage Task Force (ESTF) meeting Thursday. “To the extent in our review of the order that we need to review our compliance filing, or amend it, we may or may not do that. We’re still deciding.”
In the meantime, MISO is waiting on FERC to act on its compliance filing, which includes both a request to delay a storage participation model until 2021 and limit the participation of storage resources 1 MW and smaller to 50 in the first year of compliance and 150 in the second year. (See MISO Requests Storage Compliance Delay into 2021.) MISO has said it will gradually increase the number of small storage devices in its market as it “improves its software’s capability to manage them.”
RTO staff have said they expect a response from the commission in July, and Vannoy reminded stakeholders that MISO’s filing is still open for comments.
“FERC has time to review and folks can comment,” he said.
MISO has said its phased approach is a “reasonable precaution to proactively address the potential for large numbers of small electric storage resources, rather than waiting to react to adverse impacts of future high volumes of small electric storage resources.”
But FERC maintains that benefits of increased competition will outweigh complexity and implementation costs.
In Order 841-A, the commission said the 100-kW minimum size requirement is a “balance between the benefits of increased competition fostered by the opportunity for smaller resources to participate in the RTO/ISO markets … and the potential need to update RTO/ISO market clearing software to effectively model and dispatch these smaller resources.”
“We continue to believe that, given the record showing that all RTOs/ISOs are already accommodating the participation of smaller resources in their markets and the commission’s willingness to consider requests to increase the minimum size requirement in the future, we are providing the RTOs/ISOs with adequate time to develop the requisite tariff language and update their modeling and dispatch software to comply,” FERC said.
The commission repeated its position that any RTO experiencing difficulty calculating the market after an influx of storage participation could file a request to increase the minimum size requirement. It also pointed out that its compliance directives don’t include any of the distributed energy resource aggregation rules that were first considered in its original Notice of Proposed Rulemaking, making compliance less burdensome.
“We continue to find that the timeline for compliance and implementation is reasonable,” FERC said, adding that it will not allow individual RTOs to propose their own compliance timelines.
Vannoy said MISO’s request for delay had lined up with the early delivery of its new market system platform by a third-party vendor in 2021.
Next up: Hybrid Resources
The Thursday meeting was the last in-person meet-up of the ESTF before it sunsets next month after a year and a half of service. The group will provide a final report of potential storage topics to the Steering Committee, which will route the items to the appropriate stakeholder committees for possible policy development.
Entergy’s Yarrow Etheredge asked if MISO should consider extending the life of the ESTF because of the uncertainty surrounding the Order 841 compliance filing and a decision is not expected until July.
Task force Chair John Fernandes said stakeholders might consider ad hoc meetings focusing on energy storage, but monthly meetings of the ESTF were no longer necessary.
“Where there is interest in discussing this further, it would be on an as-needed basis,” Fernandes said.
The ESTF’s topic list focuses heavily on how MISO might facilitate market participation for hybrid resources that include both generation and energy storage devices. The group said the RTO should work out how modeling, forecasting and offer data submittals will work for those resources. MISO must also determine allowable capacity factors for the purposes of its Planning Resource Auction. It currently lacks historical data on the charging patterns and behavior of hybrid resources, making capacity factors difficult to determine.
Some stakeholders agreed that hybrid resources are a more pressing matter than storage-as-transmission assets (SATA) because they believe multiple hybrid resources will be built before a SATA project is realized. Others added that if MISO wants to incorporate hybrid resources soon, it needs to rethink its postponement on combined cycle modeling until mid-2023. (See “At Least 1 Market Project Delay,” New MISO Platform Headed to the Cloud.) Multiple stakeholders said better combined cycle modeling and hybrid resource modeling are inextricably linked.
Below is a summary of the issues scheduled to be brought to a vote at the PJM Markets and Reliability Committee on Thursday, along with highlights of first readings and discussion issues. 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 in Valley Forge, Pa., covering the discussions and votes. See next Tuesday’s newsletter for a full report.
Consent Agenda (9:15-9:25)
B. Endorse proposed revisions to Manual 01: Control Center and Data Exchange Requirements as a part of the cover-to-cover review.
C. Endorse proposed revisions to Manual 03: Transmission Operations as a part of a cover-to-cover review.
D. Endorse proposed revisions to Manual 07: PJM Protection Standards to update applicability references and an Institute of Electrical and Electronics Engineers standard reference.
E. Endorse proposed revisions to Manual 11: Energy & Ancillary Services Market Operations and Manual 13: Emergency Operations to clarify the impact of operationalizing gas contingencies on reserve requirements and reserve market eligibility.
F. Endorse proposed revisions to Manual 13: Emergency Operations as part of a cover-to-cover review.
G. Endorse proposed revisions to Manual 36: System Restoration as a part of a cover-to-cover review.
The draft charter fleshes out the details of the compromise problem statement and issue charge stakeholders spent more than two hours haggling over at the March MRC meeting, including an open-ended timeline that doesn’t commit stakeholders to action by the end of the year. PJM will seek endorsement at the June MRC meeting.
4. FERC Order Related to Hourly Cost Offers
PJM will present an update on fuel cost policies after FERC accepted the RTO’s March compliance filing that clarifies:
Clearly specifying when a penalty for noncompliance with a fuel-cost policy would be terminated by PJM.
Allowing a new resource a 90-day time period before it submits its fuel-cost policy.
Specifying that a market seller may only update its minimum run time for the uncommitted hours in real time and that a market seller’s make-whole payment be based on the minimum run time specified at the time of commitment.
WESTBOROUGH, Mass. — More than 150 people attended ISO-NE’s first-ever Grid Transformation Day last week to hear about the speed of the change overtaking the power industry — and the breadth of resources needed to accommodate it.
Here’s some of what we heard.
Dealing with Outdated Data
Stephen Rourke, ISO-NE vice president for system planning, said the industry is changing so fast that some of the RTO’s statistics for last month are already significantly misleading.
One example: The figure of 1,381 MW of battery storage in the interconnection queue as of April 1 is already out of date, with the number now topping 2,500 MW.
Information is still key, he said about the RTO’s response to growth of distributed energy resources.
“So every night at around 10 or 10:30, we get five-minute snapshot data from 10,000 different solar sites around the region,” Rourke said. “Thanks to working with the utilities and the states, we have actually mapped every single solar panel in New England to the town or city that it’s in.”
| ISO-NE
However, getting that data in real time would significantly increase costs, “so we have not gone down that path yet,” he said.
Steve Widergren, principal engineer at Pacific Northwest National Laboratory, said that our modern, data-driven society requires a much more flexible and resilient transmission system, which must transition to meet the challenges of changing demand characteristics, he said.
“We’re asking the grid to do a lot more than it was originally designed to do, which I think has been the mantra for electricity through its entire life,” he said. “We have already seen what extreme weather events are doing and can do, so the mission is how to mitigate the damage and recover quickly. The grid is increasingly a critical national asset.”
The policy environment is changing as “corporates and municipalities are demanding more clean energy, and this clean energy operates in a different way from traditional power plants, so that’s a challenge for the system,” said Janet Gail Besser, managing director of regulatory innovation at the Smart Electric Power Alliance.
She listed various legislative initiatives around the region, including a bill on solar siting in Rhode Island (House Bill 5789).
“As we see more of these resources, we see more of the challenges in siting even distributed energy resources, and that’s not going to go away,” Besser said.
Potential New England 2050 load profiles by end use | EPRI
Technical Challenges
Aidan Tuohy, principal project manager at the Electric Power Research Institute (EPRI), spoke of the challenges of integrating DER into grid operations, such as ramping to compensate for both short- and long-term intermittency of wind and solar.
In his native Ireland, for example, the grid operator is “buying 14 different kinds of ancillary services to deal with all this,” Tuohy said.
Hosting capacity — the volume of DERs that the distribution system can handle at a given time and place — is important from a bulk services perspective and comes up when trying to get distributed battery storage to provide some service that can’t actually be accessed because the system is starting to hit some limit, Tuohy said.
“EPRI has been exploring the use of technologies to better understand where and how much DERs you can put on your system so that you can then plan around that … and flag where upgrades are needed,” he said.
Barry Mather, manager for integrated devices and systems at the National Renewable Energy Laboratory, said grid operators have “a lot of tools in the toolbox” and that the large number of options is in itself a challenge.
Mass CEC CO2 Projections | Mass. CEC
In sharing NREL research on the Hawaii grid, Mather said it is “a very interesting system with lots of PV; mostly distributed, not transmission-scale,” which results in steady-state over-voltage issues.
What smart inverter function should actually be used?
“Obviously, frequency ride-through is a big deal on an island system such as in Maui, where you have relatively large frequency transience, just because the system is not very large,” Mather said. “But even [with] things like the volt/[volt-ampere reactive] settings [on inverters], how specific do you need to be?”
“Another important step in this planning matrix is to understand where you are going to go, because these DER assets, even though they’re small systems … are designed relative to a utility-scale lifetime, maybe 25 or 30 years,” Mather said.
The smart inverter setting you set today may not be the same setting that will be needed when DERs reach their ultimate penetration level, he said.
“The biggest game-changer is demand response,” said Debra Lew, senior technical director at GE Energy Consulting. “I can’t convey to you the importance of this … think of it as demand response on steroids. This is going to be way bigger than what you think of today because, first of all, we’re electrifying all these new loads,” from transportation to space heating to water heating and cooling.
“These loads are inherently flexible; we can extract a lot of flexibility out of them, so a significant amount of our demand in the future is going to be price-responsive or controllable,” Lew said. “This demand is going to compete directly with storage, and that’s something to think about as you make investments for the future.”
Lew said she participated in a meeting the previous week in which a Californian said their state currently had a half-million electric vehicles and plans for 7 million.
“We did a back-of-the-envelope for 7 million electric vehicles: 420 GWh of storage. That’s huge,” Lew said. “Even if you can access only a tiny bit of that, that’s a huge amount of storage.”
Utility Perspective
“Vermont is the Hawaii of the East, but our mountains don’t blow off their tops,” said Chris Root, COO of Vermont Electric Co.
Vermont is leading the way in New England in terms of overall renewable energy on its system, but because of the intermittent nature of wind and solar, its grid is increasingly weather-dependent as more renewables come on, Root said.
For example, he said the load in the middle of an overcast day is 2.5 times that of a sunny day, and that when snow covers a solar panel, its energy production drops to zero — which drew the comment that Hawaii probably had the edge in weather.
Renewables are only 5% of New England’s installed generating capacity today, but wind and solar are on the rise. | ISO-NE
“I do believe storage is going to be critical in the future, because we have loads that change, we have generation that changes, and the only thing that’s going to be able to equate that is going to have to be storage,” Root said.
He said Vermont utility Green Mountain Power has installed 1,900 Tesla Power Walls and “can’t install them fast enough.” He noted the state has two utility-scale energy storage facilities of 4 MW and 1 MW — but he likes to remind people that storage is not an energy source.
“You have to put energy in; then you can take it out.
“Sometimes when policy gets way ahead of engineering, that can be a little scary,” Root said. “We’re still solving the problems that are happening today, so it gets a little scary when you’re trying to play catch-up from an engineering perspective.”
National Grid has seen its average solar interconnection request in Massachusetts triple in size over the last few years and double in Rhode Island, said Brian Gemmell, the company’s vice president for asset management and planning.
“For those that know the transmission system well, there’s a lot of ripple effect with getting all these megawatts. … We don’t have a lot of transmission in central and western Massachusetts and, indeed, some of the areas in Rhode Island,” Gemmell said. “We’re grappling with a dramatic uptick in [distributed generation].”
Massachusetts has approved $45 million to support the sale of approximately 18,500 EVs over five years. | Eversource
“It’s a given that we’re going to need innovation … but the biggest thing we’ll need is collaboration,” said Vandan Divatia, Eversource Energy’s director of ISO-NE policy and interconnections. “We have a role in every sector of the grid, from a customer-facing angle to grid-type investments, to supply, and the key thing is going to be collaborating with the right folks.”
Highlighting the ambitious clean energy policies and greenhouse gas reduction targets of various states in the region, Divatia said, “This may mean, based on the numbers you run … one scenario is you need to have every single new vehicle by 2030 to be electric.
“Massachusetts has shown great leadership in this area by enabling a make-ready program to deploy $45 million to get about 18,500 EVs,” and the region needs about 80,000 charging stations to help people overcome their range anxieties regarding EVs, Divatia said.
“Again, if we want to go from here to there, we’re going to need a lot more electric infrastructure,” he said.
