FOLSOM, Calif. — CAISO’s 2019 revenue requirement will be less than this year’s, despite hiring and costs associated with its planned new role as reliability coordinator for most of the West, staff members told the ISO’s Board of Governors on Thursday.
The ISO’s proposed revenue requirement for 2019 is $193.5 million — $3.7 million less than in 2019. That’s within “the tight range that the ISO has maintained over the past 13 budget cycles and beneath the FERC-approved cap of $202 million,” CFO Ryan Seghesio wrote in a memo to the board.
Total outlays will grow to $230.9 million from $217.4 million in 2018, but new revenues from the RC business as well as increased gains from the Western Energy Imbalance Market and other increased revenues will offset that spending rise by $7.2 million. A $13.5 million operating cost reserve adjustment for overcollection this year will provide an additional offset.
Operations and maintenance costs will rise by $10.5 million, April Gordon, director of financial planning and procurement, said at the board meeting. CAISO CEO Stephen Berberich added that the additional spending was primarily from “adding headcount” for the ISO’s new RC component.
The ISO is set to take over RC services from Peak Reliability for the bulk of Western Interconnection states, starting in California in July. (See RC Transition Fraught With Pitfalls, WECC Hears.)
CAISO’s telecommunication, outsourcing and contract costs also will increase in 2019 because of the RC transition, Gordon told the board.
Another cost driver is the expansion of the EIM, with new entities joining the market and increasing administrative expenses, Gordon said. Powerex and Idaho Power began trading in the EIM this year, and the Sacramento Municipal Utility District will join in April 2019, she noted. (See Idaho, Powerex Began Trading in Western EIM.)
The board unanimously passed the ISO’s 2019 budget proposal. It also heard about 2019’s policy initiatives from Greg Cook, CAISO’s director of market and infrastructure policy. A major effort involves proposed changes to the day-ahead market, including 15-minute scheduling and flexible ramping.
“We’re looking at significant enhancements to our day-ahead markets,” Cook said.
CAISO Governor Angelina Galiteva asked Cook whether ISO staff were aligning their policy initiatives with outside developments, particularly California’s adoption of a rule requiring all new homes to have rooftop solar panels starting in 2020. The state Building Standards Commission approved the rule, the first of its kind in the U.S., on Dec. 5.
“It may catch up with us before we even know what’s going on,” Galiteva said.
In addition to solar panels, many households will eventually get in-home electricity storage units, she said. “My sense is people are going to start installing storage and a lot of it,” she said.
Berberich responded, “Governor, I think you’re probably appropriately worried.” He said behind-the-meter storage, linked to home solar panels, would complicate CAISO’s forecasting.
“Storage is going to be the biggest issue for us to sort out,” the CEO said. Policies may be needed to govern the charging and discharging of storage units, including financial incentives for homeowners, he said.
“I’m not suggesting we send real-time prices to retail customers,” he said. “I’m not sure that works.”
But policymakers may need to “signal to the retail level as best we can,” he said. “Then you can shape the behavior and usage.”
The California Public Utilities Commission (CPUC) on Thursday voted to examine its rules allowing the state’s investor-owned utilities to de-energize power lines in cases of dangerous wildfire conditions “that threaten life or property.”
The practice of de-energization will get a dedicated proceeding, separate from another rulemaking effort set out in Senate Bill 901 to address utility wildfire mitigation. De-energization will be discussed in the SB901 proceeding as one of a broader set of fire prevention measures.
Carla Peterman
“We can’t not act” on the de-energization issue, Commissioner Carla Peterman said during the Thursday voting meeting, her last with the commission. De-energization “is an option we don’t want to exercise often, but we do want the option to exercise.”
Cliff Rechtschaffen
Commissioner Cliff Rechtschaffen said the issue was “worthy” of its own proceeding because de-energizing a line is a “significant event [with] significant consequences.”
“I support having this as a separate proceeding. … It is a requirement as part of the wildfire mitigation plans that the utilities now have to submit yearly that they include their de-energization protocols,” Rechtschaffen said. “[CPUC] President [Michael] Picker and I are the assigned commissioners partnered on the wildfire safety plans, and we’re committed to making sure that this proceeding is closely coordinated with that proceeding as we go forward.”
Proactive
The CPUC adopted the de-energization rules in July in response to the growing threat of wildfires throughout the state, especially in the expansive Pacific Gas and Electric and Southern California Edison service areas. Regulations around “proactive” shutoffs had previously applied only to San Diego Gas & Electric, which serves a historically highly fire-prone area.
Elizaveta Malashenko
“Since then, the topic of proactive power shutoff has reached a lot of people and has become a [hot] point of discussion,” CPUC Director of Safety and Enforcement Elizaveta Malashenko told the commission.
Among other mandates, the July rules require all IOUs to notify customers before de-energizing facilities and report to the commission after the fact (Res ERSB-8).
But Malashenko noted that industry stakeholders and members of the public have raised “a range of concerns” about the program, and that utilities are increasingly “proactively de-energizing” their lines. (See Fire Season Becomes Blackout Time in California.)
“In my mind, the type of issues that would come up in [this] rulemaking as related to de-energization is how much the utilities should be using that as a tool, as opposed to mitigating wildfires in other ways, such as introducing coated conductors or undergrounding lines, or increasing their ability to detect faults faster, and things like that,” she said.
A CPUC staff report on the new rulemaking indicates the proceeding will focus on:
Examining conditions under which planned de‑energization is practiced;
Developing best practices and ensuring an orderly and effective set of criteria for evaluating de‑energization programs;
Ensuring electric utilities coordinate with state and local level first responders, and align their systems with the Standardized Emergency Management System framework;
Reducing the impact of de‑energization on vulnerable populations;
Examining ways to reduce the need for de‑energization;
Ensuring effective notice to affected stakeholders of possible de‑energization and follow‑up notice of actual de‑energization; and
Ensuring consistency in notices of and reporting of de-energization events.
Digitize the Landscape
During the meeting, Picker emphasized the importance of learning from SDG&E’s experience from de-energization — without leaning too heavily on it.
Michael Picker
“Utilities have always de-energized,” Picker said. “We have so far required them to plan a little ahead and to provide notification, but what could we learn from San Diego? What should be applied elsewhere? And how do we know what will work in other parts of the state?”
Picker pointed out that in order to avoid de-energizing lines, SDG&E “digitized the landscape” in its service territory.
“They put sensors in a number of places,” he continued. “They put weather monitors, wind monitors, moisture monitors and cameras in places you wouldn’t expect to see that. They began to collect information. They began to look carefully at very granular conditions in specific parts of their service territory at a much finer level than has ever been modeled before.”
Picker said SDG&E over time developed “a much finer sense of where and when to de-energize, and what were the consequences.” But he also acknowledged that SDG&E has a much smaller service territory than either PG&E and SCE.
“When you begin to look at the service territories of the other regulated utilities … we may be able to expedite their processes, but they’re still going to have to go through that data-monitoring, data collection, analysis, modeling and eventual testing process,” Picker said.
“I want to be honest about what we’ll be able to achieve. I don’t think we’ll have a perfect set of rules right away.”
FOLSOM, Calif. — CAISO’s efforts to rein in congestion revenue rights insufficiencies seemed to show progress this summer and early fall but fell short in the last months of 2018, the ISO reported Tuesday during its quarterly Market Performance and Planning Forum.
Historically CRR revenues have been inadequate to meet payouts, Guillermo Bautista Alderete, CAISO’s director of market analysis and forecasting, told meeting attendees at ISO headquarters.
That changed in the middle of this year because of high levels of summer congestion, he said.
“From July to October we actually flipped the condition, especially in July and August,” when there were significant surpluses, Bautista Alderete said. A graph he displayed showed a surplus in July of about $15 million and close to $40 million in August, which amounted to about 140% of revenue adequacy. Those figures did not include auction revenues.
The good news turned grim in November, when “we had insufficiency in the range of 80%,” he said. “Even if we account for auction revenues, we were still marginally short.”
The chronic shortfall in CRR revenues, leaving ratepayers footing the bill, has been an ongoing problem for CAISO. This year the ISO sought FERC’s approval for changes it hoped would help in 2019, but the commission was loath to give it everything it wanted.
In September, FERC rejected a CAISO plan to eliminate full funding of CRRs and instead scale payouts to align with revenue collected through the day-ahead market and congestion charges. (See FERC Rejects CAISO Congestion Revenue Scaling Plan.)
The congestion revenue rights market saw an inadequacy in November compared to surpluses this summer, CAISO said. | CAISO
CAISO noted in its filing that CRR revenue shortfalls have continued into this year, and it urged the commission to quickly approve the revised plan to relieve ratepayers from paying costs for fully funding CRRs in 2019.
The ISO’s Department of Market Monitoring has estimated that CRR revenue shortfalls, which are allocated based on power consumption, cost California ratepayers about $100 million a year.
“We agree with CAISO that the proposal reasonably distributes the burden resulting from congestion revenue insufficiency and will help improve the revenue insufficiency and auction revenue shortfall,” FERC said. “Rather than relying solely on [load-serving entities] to make whole CRR holders in the event those obligations are revenue insufficient, CAISO’s proposal distributes the burden to all CRR holders.”
EIM prices were stable in the fourth quarter after spikes over the summer. | CAISO
Other results reported at Tuesday’s meeting included a stabilization in Western Energy Imbalance Market prices after a big spike at the end of July caused by high summer demand.
“As we have passed those summer months, the prices are generally stable,” Rahul Kalaskar, CAISO manager of market validation analysis, told those gathered and on the phone.
FERC on Monday denied SPP’s request for waivers from regulations guiding the confidential treatment of information in its explanation of how it allocated costs related to a NERC fine, the amount of which has not been publicly disclosed because of grid security concerns (ER19-97).
SPP filed the Section 205 request in October with an explanation of its allocation of costs from a NERC fine for violating reliability standards. The heavily redacted public version of the request shows the RTO asked for waivers from the requirement to include a protective agreement and from the regulations authorizing release of the filing’s confidential version to entities signing a nondisclosure agreement. SPP claimed that disclosing the information could jeopardize its system’s security.
But FERC ruled that “SPP has neither adequately supported its concerns nor justified the adverse effect that its waiver request would have on participants in this proceeding.” As the cost allocation plan did not include a proposed protective agreement, the commission dismissed it. It did so without prejudice, meaning SPP can refile its proposal for covering the penalty without the waiver request.
FERC noted intervenors would be willing to sign a protective agreement to review SPP’s filing and evaluate its proposed cost allocation.
SPP’s headquarters in Little Rock, Ark. | WER Architects
In the cost allocation filing, SPP said it paid the penalty costs using surplus funds, although a Tariff provision allows the recovery of such costs by direct assignment or cost allocations to members or market participants. The RTO’s Board of Directors approved offsetting the costs with employee compensation funds for 2018, an approach SPP said it adopted from FERC Order 693, which it said suggested RTOs and ISOs could tie employee compensation to compliance with reliability standards as a means of reducing repeat incurrences of penalties. The order also declined to provide grid operators blanket authority to recover penalty costs from members on a generic basis.
Under the board’s recommendation, the reduction in compensation would be reflected as a surplus in the administrative fee’s true-up for 2018, which would reduce the fee for 2019.
The West Texas Municipal Power Agency (WTMPA), created by the cities of Lubbock, Brownfield, Floydada and Tulia to increase their negotiating strength, intervened in the docket. While it did not protest the cost allocation plan or waiver request, it urged FERC to “strictly and expressly limit such findings to this case” if it approved them. The agency asked that interested parties be allowed access to information about the penalties and cost allocation, contending that it would be otherwise impossible for ratepayers to determine whether the penalty’s allocation was just, reasonable and not unduly discriminatory.
FERC regulations provide that any participant in a proceeding can make a written request to the filer for a copy of the document’s complete, nonpublic version. The request must include a signed copy of the filer’s protective agreement and a statement of the person’s “right to party or participant status or a copy of their motion to intervene or notice of intervention.”
SPP members Evergy, Oklahoma Gas & Electric and Western Farmers Electric Cooperative also intervened in the docket.
FERC on Tuesday ordered a closer look into whether We Energies accurately estimated customer savings stemming from the retirement of the Pleasant Prairie coal plant in southeastern Wisconsin.
The commission’s Dec. 11 ruling accepted, then suspended, We Energies subsidiary Wisconsin Electric Power Co.’s new wholesale tariff that includes the remaining costs on the plant, setting the rate for hearing and settlement judge procedures over the company’s claims of ratepayer savings related to the shutdown (ER19-103).
We Energies in April permanently closed the 1,190-MW coal plant, which entered service in 1980.
Pleasant Prairie Power Plant | We Energies
At retirement, Pleasant Prairie had an unamortized plant balance of approximately $665 million, which We Energies sought to amortize over about 23 years through an adjustment to its rate base. The company contended the recovery is just and reasonable, citing FERC’s 1996 decision to allow Yankee Atomic Electric Co. to recover from ratepayers 100% of its remaining unamortized investment in its nuclear plant after a study showed the plant’s operating costs exceeded the value of the its energy output.
Between 2003 and 2007, We Energies invested $365 million worth of capital, environmental and reliability investments into Pleasant Prairie, all of which were approved by the Public Service Commission of Wisconsin.
“Although Pleasant Prairie has reliably served Wisconsin Electric’s customers for nearly 38 years, its value to customers began to decrease significantly after 2008 due to a significant loss of industrial load following the recession in 2007-2008 and improvements in energy efficiency; declining energy prices in MISO as a result of increased competition from natural gas and renewable energy resources; and a corresponding reduction in Pleasant Prairie’s dispatch in MISO markets,” the company told FERC.
We Energies says Pleasant Prairie’s retirement will save retail and wholesale customers anywhere from $2 billion to $3.2 billion.
But wholesale customer Great Lakes Utilities challenged the customer savings estimates, arguing that We Energies’ assumptions of a hypothetical carbon tax imposed in 2028 and other pricey environmental regulations on the coal plant are “not sufficiently supported.”
The commission agreed that the cost-savings assumptions could use more evaluation.
FERC said it “cannot determine on the record before us whether the third prong of the test set forth in Yankee Atomic has been satisfied such that there will be substantial savings for customers as a result of Pleasant Prairie’s retirement.”
In the Yankee Atomic decision, FERC said a 100% recovery of a prematurely retired plant’s unamortized balance is warranted when three criteria are met: the investment and retirement decisions are prudent, the plant has already provided years of beneficial service to customers and the retirement results in “substantial cost savings to customers.”
While FERC said We Energies demonstrated prudent investment and retirement decisions, and that Pleasant Prairie was beneficial to customers over its nearly four decades of reliable operation, it could not definitively answer without further proceedings whether the company would achieve substantial customer cost savings from retirement of the plant.
CARMEL, Ind. — MISO officials are still hashing out how they can best model and analyze energy storage-as-transmission in the RTO’s transmission planning process.
During a Dec. 10 Reliability Subcommittee meeting, MISO Senior Manager of Expansion Planning Edin Habibovic said planning for storage-as-transmission boils down to four key modeling factors:
Determining the voltage, thermal or stability need;
Asking if storage is the most effective, efficient and economical solution;
Examining what level of megawatt or mega volt amps of injection is needed to resolve the issue; and
Investigating how long the reliability issue usually lasts.
Habibovic said MISO also must study how frequently a storage asset would have to operate to resolve a reliability issue and how that cycling may impact the operational life of the asset. He also said MISO will need to look into seasonal load levels to estimate how often the asset may be dispatched in scenarios under the RTO’s annual Transmission Expansion Plan (MTEP).
Storage solutions would also be evaluated to make sure charging and discharging don’t cause harm either to the MISO transmission system or to generation projects in the definitive planning phase in the interconnection queue, Habibovic said.
“Just like any other reliability project, it can’t solve one problem and cause another,” he said.
But storage could be dispatched to minimize transmission system upgrade needs from generation projects in the definitive planning phase of the interconnection queue, he said. The result would be more flexibility in modeling the definitive planning phase.
WPPI Energy’s Steve Leovy asked if MISO would employ a storage-as-a-transmission-asset (SATA) study process on solutions submitted for MTEP 19. Habibovic said MISO would study storage projects and might provide additional MISO assessments and discussions about the study results and feasibility of such projects. MISO already has at least one proposed storage project lined up for study under Appendix A of MTEP 19.
So far, MISO is only proposing a model for storage to act as a transmission reliability solution, solving thermal, voltage or stability issues. The RTO is leaving more complex SATA issues for later rules. (See Few Clear Lines in MISO Storage as Tx Plan.)
MISO is accepting stakeholder comment on the challenges and benefits of incorporating transmission-level storage in reliability planning through Jan. 7.
Inverter Projects to Prove Stability
MISO has added an option for owners of inverter-based generation to prove the system won’t suffer degraded reliability because of their projects.
In October the RTO said it was mulling requiring owners of inverter-based resources to supply their short-circuit ratios at the point of interconnection before completing an application to enter the queue. (See MISO Moving to Head off Inverter-based Instability.)
Interconnection customers with an inverter-based project can now demonstrate a stable interconnection later in the queue process using one of two demonstration methods.
According to MISO interconnection engineer Warren Hess, project owners can either submit an Electromagnetic Transients Program (EMTP) study report confirming stable operation or, by the first decision point about 120 days into the queue, submit a short-circuit ratio at the point of interconnection and a manufacturer’s letter stating the equipment operates reliably.
As with the first proposal, any project owner unable to prove stable operation must either add equipment to raise the short-circuit ratio or reduce the size of the project.
MISO is accepting another round of feedback on the proposal through Jan. 2.
NYISO said Tuesday it will have adequate capacity on hand to meet its forecasted peak demand of 24,269 MW for the 2018/19 winter season, well under last winter’s peak of 25,081 MW.
The ISO expects capacity resources, including imports and demand response, to total 43,943 MW this winter, ISO Vice President of Market Operations Emilie Nelson said in a review of the winter outlook.
Installed generation amounts to 41,539 MW, while the ISO has acquired external capacity of 1,519 MW for the winter. Projected demand response resources equal 884 MW, Nelson said.
NYISO long-term winter forecast for 2018 to 2025, including transmission and distribution losses. The low and high forecasts are at the 10th and 90th percentiles for extreme weather conditions, respectively. | NYISO
The ISO forecasts a capacity margin of 11,436 MW based on a 50/50 winter peak forecast with average winter weather conditions consisting of composite statewide temperatures of 15 degrees F. More extreme temperatures in the model (approximately 5 degrees statewide) result in a higher forecasted 90/10 peak load of 25,884 MW, with marginal capacity of 9,821 MW.
“Last winter’s peak [on Jan. 5] occurred during a two-week cold snap, and the all-time winter peak of 25,738 MW occurred in January 2014, during what was called the polar vortex,” Nelson said.
In response to the harsh winter five years ago, “we have fine-tuned many of the things we do in advance of the winter season,” Nelson said. The ISO enhanced its winter reliability planning by providing stronger incentives for generators to secure fuel for winter peak demand needs and improved its monitoring of the natural gas system and checking of generator fuel inventories.
“In preparing for the winter 2018/19, we start by conducting a generator fuel survey … and also we like to understand any arrangements they have in place for replacement fuel,” Nelson said. “This is particularly important in New York, because so many of our generators are located along waterways that allow replenishment of fuel storage through the winter.”
When considering resupply, the focus is on oil, which is typically used as a backup fuel in New York, prompting the ISO to differentiate between resources with fuel tanks that will be drawn down throughout the season and those that can resupply from barges as needed, Nelson said.
In the spirit of testing for extremes, the ISO forecast models a loss of natural gas scenario, which is less about replenishment than demand coming from both homes and power generators, she said.
FERC on Monday denied SPP’s request for waivers from regulations guiding the confidential treatment of information in its explanation of how it allocated costs related to a NERC fine, the amount of which has not been publicly disclosed because of grid security concerns (ER19-97).
SPP filed the Section 205 request in October with an explanation of its allocation of costs associated with a NERC fine for alleged violations of reliability standards. The heavily redacted public version of the request shows the RTO asked for waivers from the requirement to include a protective agreement and from the regulations authorizing release of the filing’s confidential version to entities signing a nondisclosure agreement. SPP claimed that disclosing the information could jeopardize its system’s security.
But FERC ruled that “SPP has neither adequately supported its concerns nor justified the adverse effect that its waiver request would have on participants in this proceeding.” As the cost allocation plan did not include a proposed protective agreement, the commission dismissed it. It did so without prejudice, meaning it did not rule on SPP’s approach to covering the penalty cost.
FERC noted intervenors would be willing to sign a protective agreement to review SPP’s filing and evaluate its proposed cost allocation.
SPP’s headquarters in Little Rock, Ark. | WER Architects
In the cost allocation filing, SPP said it paid the penalty costs using surplus funds, although a Tariff provision allows the recovery of such costs by direct assignment or cost allocations to members or market participants. The RTO’s Board of Directors approved offsetting the costs with employee compensation funds for 2018, an approach SPP said it adopted from FERC Order 693, which it said suggested RTOs and ISOs could tie employee compensation to compliance with reliability standards as a means of reducing repeat incurrences of penalties. The order also declined to provide grid operators blanket authority to recover penalty costs from members on a generic basis.
Under the board’s recommendation, the reduction in compensation would be reflected as a surplus in the administrative fee’s true-up for 2018, which would reduce the fee for 2019.
The West Texas Municipal Power Agency (WTMPA), created by the cities of Lubbock, Brownfield, Floydada and Tulia to increase their negotiating strength, intervened in the docket. While it did not protest the cost allocation plan or waiver request, it urged FERC to “strictly and expressly limit such findings to this case” if it approved them. The agency asked that interested parties be allowed access to information about the penalties and cost allocation, contending that it would be otherwise impossible for ratepayers to determine whether the penalty’s allocation was just, reasonable and not unduly discriminatory.
FERC regulations provide that any participant in a proceeding — or that has filed a motion to intervene or notice of intervention — can make a written request to the filer for a copy of the document’s complete, nonpublic version. The request must include a signed copy of the filer’s protective agreement and a statement of the person’s “right to party or participant status or a copy of their motion to intervene or notice of intervention.”
SPP members Evergy, Oklahoma Gas & Electric and Western Farmers Electric Cooperative also intervened in the docket.
Commissioner Kevin McIntyre, who has been battling health issues, did not vote on the order.
WASHINGTON — Experts in cybersecurity last week painted a somewhat dire picture when detailing the threats to the electricity industry posed by countries such as Russia, Iran, North Korea and China.
Perhaps the only thing they described that was more worrying than hackers’ persistence and the inevitably of a major attack on the U.S. grid was the No. 1 cyber risk: lack of common sense.
Eight out of 10 cyberattacks are caused by people making very poor decisions, said Jerome Farquharson, a cybersecurity consultant at Burns & McDonnell. “One of the biggest things, and I always say this when I sit down and start talking about cybersecurity and trying to close the gaps, is that cybersecurity [requires] a common-sense approach,” he said. “If we just did some very simple things, we can start making ourselves secure.
“Human nature by itself is very trusting. But when we start training people, for an example, not to use USBs [thumb drives] or not to click on email links [when] you know you’re not winning the lottery any time soon, [they] still click on them! … We go to vendor shows, and guess what vendors give out? USBs.”
Farquharson told several stories to illustrate his point. In one, an employee allowed his children to play on his laptop — the same one he used to perform system maintenance at a substation. The laptop became infected with malware at home, then went on to infect the substation’s system and his colleagues’ computers, leading to a control center outage.
In another example, Farquharson’s team sent phishing emails to a company’s 200 employees to test them after it had trained them in cybersecurity awareness for a week. More than 90 employees clicked on the links in the emails. After retraining those employees, it conducted another test a week later. More than 50 of those employees still clicked on the links.
In a different training exercise for another company, Farquharson’s team scattered USB thumb drives infected with malware throughout the company’s building and parking lot. Twenty employees picked them up; 10 plugged them in.
“The biggest threat sometimes is the human factor,” he said. “And so that’s where you have to really [spend] a lot of time on training and awareness.” The most secure companies are those with consistent, regular training, he said.
On another panel at the summit, Jim Cunningham, executive director of nonprofit Protect Our Power, said he sees similarities between the pre-9/11 airline industry and the electricity industry’s defenses against cybersecurity today. He recounted his experience witnessing the explosion caused by United Airlines Flight 175 crashing into the South Tower of the World Trade Center on Sept. 11, 2001. He recalled that television media at the time were calling the attack “sophisticated.”
“I thought, ‘Oh my God, that’s wrong.’ It was 19 guys with boxcutters; it was an unprepared airline industry; and it was an unprepared security industry,” he said. “We were paying people at the airports $10/hour to keep bad people off the planes. And we didn’t spend a few extra bucks to take those thin doors that were in front of the cockpit and make them stronger.”
Cunningham’s organization recently published a report focusing on the solar inverter supply chain. It found that about 47% of the world’s inverters come from Huawei, “a company that is banned by the U.S. government from the telecommunications business,” he said. The report says evidence is mounting that Huawei regularly flouts U.S. and international laws. “A threat actor with access to the inverter supply chain allows the manipulation of massive quantities of inverters, the ability to embed malware into the operating system away from the end-consumer and to operate under the veil of a reputable manufacturer,” it says, and makes several recommendations to mitigate the risk.
Still, preventing a catastrophic cyberattack on the grid “is the equivalent of a modern-day moonshot,” he said. “We’ve got to get everybody together, we need to get all the money we need and we have to get the smartest people on this issue to come up with a solution now.”
Ronald Keen, senior energy adviser at the Department of Homeland Security’s National Risk Management Center, said the days of companies independently defending themselves “are pretty much gone. We need to begin looking at cohesive defense: defense where we’re working together. We need to be able to start working together to design multilayered defenses that work with each other.”
WILMINGTON, Del. — Ten Consumer Advocates of the PJM States (CAPS) members signed onto a letter urging PJM’s Board of Managers to let “that process play out” concerning analysis of the RTO’s financial transmission rights market and any subsequent rule changes, CAPS Executive Director Greg Poulos told stakeholders and staff at Thursday’s Markets and Reliability Committee meeting.
While the other five manual revisions on the agenda were approved by group acclamation, Poulos asked that the revisions to Manual 06: Financial Transmission Rights, developed as part of the manual’s annual review, be voted separately. They were approved with one objection and seven abstentions.
PRD Review for Capacity Performance Requirements
Stakeholders endorsed revisions that would align PJM’s price-responsive demand (PRD) rules with the Capacity Performance construct. While three proposals developed by the Demand Response Subcommittee were potentially under consideration, the voting didn’t get past the main motion, which received 3.72 in favor in a sector-weighted vote with a 3.34 threshold. The MRC vote was accepted in the subsequent Members Committee meeting, moving it on to the board.
The main proposal requires PRD to reduce load in winter like other CP resources and will leverage existing load reduction and capacity nomination rules already approved by FERC for demand response. The status quo does not require winter load reduction, similar to PJM’s rules for DR prior to CP. (See “Summer-only Demand Response,” PJM MRC/MC Briefs: Oct. 25, 2018.)
An alternative initially developed by Calpine proposed using performance assessment intervals (PAIs) to trigger performance assessments, bonuses and penalties instead of using them only when appropriate real-time LMPs are greater than the PRD energy price, which the endorsed proposal uses.
Susan Bruce, representing the PJM Industrial Customer Coalition, voiced support for a proposal from the Independent Market Monitor because it allows PRD to be based on summer load-reduction capability rather than year-round. The Monitor’s proposal would not require PRD to reduce load in the winter if the customer’s load is already low and would use the old DR measurement and verification method to meet the CP annual requirements, which was updated based on CP and subsequently approved by FERC.
Surety Bonds
Exelon representatives, who had initially introduced one of the proposals to use surety bonds as a form of credit, called for deferring a committee endorsement on two proposals until a special PJM board committee reports on its investigation of the historic GreenHat Energy FTR default. The proposals were developed at the Credit Subcommittee. (See “Surety Bond Use,” PJM Market Implementation Committee Briefs: Oct. 10, 2018.)
The main motion would allow surety bonds as collateral for all market purposes, except FTRs, with a $10 million cap per issuer for each member and a $50 million aggregate cap per issuer. Exelon’s alternative proposal would allow surety bonds as collateral for all market purposes, with a $20 million cap per issuer for each member and a $100 million aggregate cap per issuer.
Some members were concerned about considering the proposals while the board’s investigation continues and because insurance companies can investigate claims against surety bonds prior to paying on the claims. PJM staff echoed previous assurances that the surety bond agreement language is designed to require immediate payment of claims, identical to the requirements of letters of credit, which are already approved forms of credit. While some of the language came from other RTOs/ISOs, it remains untested legally, staff said.
Both proposals will be reconsidered at the Dec. 20 MRC meeting. PJM CEO Andy Ott said representatives of the special committee will call in to provide an update on the investigation.
Gas Pipeline Contingencies
Load-side preference won the day for an alternative developed by the D.C. Office of the People’s Counsel to PJM’s proposed rules and compensation plan for handling supply-constraint contingencies on gas pipelines.
The main motion endorsed by the Market Implementation Committee, which was originally developed by Calpine, would have allowed units switching fuels at PJM’s direction to recover specific costs through a formula rate to be developed and filed with FERC. It would have been based on costs associated with fuel switching, exemptions from PJM performance charges during the fuel switch, and procedures for seeking cost recovery. (See “Gas Pipeline Contingencies,” PJM Market Implementation Committee Briefs: Nov. 7, 2018.)
Calpine’s David “Scarp” Scarpignato offered an amendment to remove gas pipeline penalties from the rate, which was accepted as friendly. He said it would be “untenable” for generators to potentially incur tens of millions of dollars in costs during an emergency and not be able to recover them.
The OPC’s alternative allows for cost recovery to be filed at FERC by the generation owner. Bruce supported this proposal, noting concerns about what could be included in rates developed through the main motion and how they would be audited. She said her members agree on the fundamental ideas behind the main motion but would be “behind the blocks” in having to file complaints about recovery charges rather than the generator having to seek recovery.
Poulos said his members also supported the OPC proposal and expressed “a lot of frustration” that discussion of the proposals received “short shrift” at the upper committees, as it was scheduled for first reads and votes at both the MRC and MC on the same day.
“I think that the risk of putting forward an inadequate proposal is greater than the risk of going one more winter without it,” said Panda Power Funds’ Bob O’Connell, announcing that he planned to oppose all the proposals.
The main motion failed, receiving 3.13 in favor in a sector-weighted vote with a 3.34 threshold. The OPC alternative was endorsed, receiving 3.77 in favor. It received 4.26 in favor in a subsequent endorsement vote at the MC.
In the MC, attendees agreed to move proposed credit-related Tariff revisions to the consent agenda, where they were endorsed with no objections. The revisions remove an apparent overlapping credit reduction provision for qualified transmission upgrades in order to clarify milestone documentation requirements for internally financed projects and that capacity market sellers should submit requests for reductions.
Committee Elections
Attendees also elected nominees to the Finance Committee, sector whips and American Municipal Power’s Steve Lieberman, representing the Electric Distributor sector, as vice chair of the MC for 2019.
Elections to the Finance Committee were:
The D.C. OPC’s Erik Heinle, from the End-Use Customer sector;
Jeff Whitehead, representing Eastern Generation, from the Generation Owner sector;
Credit Suisse’s Marguerite Miller, from the Other Supplier sector; and
Virginia Electric and Power Co.’s Jim Davis, from the Transmission Owner sector.
The tenures will all expire at the end of 2021. Tenures for the current representative from each sector on the committee expire either next year or in 2020, including the tenures for both representatives from the Electric Distributor sector.
The sector whips were Old Dominion Electric Cooperative’s Adrien Ford, from the Electric Distributor sector; the PJM ICC’s Bruce, from the End-Use Customer sector; Gabel Associates’ Michael Borgatti, from the Generation Owner sector; Direct Energy’s Marji Philips, from the Other Supplier sector; and Exelon’s Sharon Midgley, from the Transmission Owner sector.
Bilateral FTR Retraction
PJM CFO Suzanne Daugherty announced PJM’s plans not to follow up on additional information requested by FERC in a recent FTR-related filing and instead pushed to have it withdrawn. The MC voted in favor of showing its agreement with PJM’s plan, but not without Shell Energy voicing its disagreement. The acclamation vote passed with six objections and 11 abstentions.
In the previous week, FERC approved two of four filings — and rendered moot a third — that PJM made in response to the GreenHat default. On the fourth filing related to bilateral FTR transactions, the commission issued a deficiency letter requesting more information. Shell and several financial traders protested the filings. (See FERC OKs Key PJM Changes to Address GreenHat Default.)
Shell’s Matt Picardi said his company protested to raise the issue of the underlying indemnification and that addressing the deficiency letter is important for hashing out those issues.
Daugherty responded that “Shell has been very straightforward” with its opinion, but that its interpretation of the indemnity provision differs from PJM’s. Staff would prefer to pull that back to discuss it in the stakeholder process because it was never addressed there, rather than hash it out at FERC.
“There was some discussion around the edges” of the indemnification issues during the GreenHat talks earlier this year, Picardi said. He said Shell would engage in any stakeholder processes on the topic but would not be “foreclosing” on its “other options” to push the issue.
Daugherty confirmed that PJM has no expectation of submitting another filing on the issue other than to have the discussion.
Stakeholders Approve Variety of Actions
Stakeholders endorsed by acclamation several manual revisions and other operational changes:
Manual 03: Transmission Operations. Revisions developed to update the generator voltage schedule with new processes that require transmission owners to verify and submit voltage schedules via eDART, generation owners to review the schedules and the eDART contact to acknowledge the schedule. This will all need to be done annually. (See “Generator Voltage Schedule,” PJM Operating Committee Briefs: Nov. 6, 2018.)
Manual 10: Pre-Scheduling Operations. Revisions developed as part of a periodic cover-to-cover review.
Revisions to the day-ahead scheduling reserve for 2019. The 2019 calculation of 5.29% is a 0.01-point increase from the 2018 requirement. Endorsed with seven abstentions and one objection. (See “Day-ahead Scheduling Reserve Recommendation,” PJM Operating Committee Briefs: Nov. 6, 2018.)
