SACRAMENTO, Calif. — One of the biggest energy-related bills of the year in California shot through the State Legislature earlier this summer, well ahead of lawmakers’ Sept. 13 deadline to pass legislation, but other noteworthy electricity bills landed on the desk of Gov. Gavin Newsom in recent days.
Among them was SB 520, which reworks the notion of the provider of last resort (POLR) in the face of the state’s fast-changing electricity landscape. Traditionally, California’s three big investor-owned utilities have filled that role. But with the emergence of community-choice aggregators (CCAs), lawmakers decided the old rules needed updating. (See Calif. Lawmakers Reveal Growing Divisions over CCAs.)
The bill would let CCAs be the POLRs in their service territory, contingent on approval by the California Public Utilities Commission. State Sen. Bob Hertzberg (D) authored the bill.
One bill sent to California Gov. Gavin Newsom could affect the potential purchase by San Francisco of PG&E’s electric grid there.
Another measure, SB 550, conceivably could help shepherd the sale of PG&E Corp.’s assets in bankruptcy to the city of San Francisco or other public entities hoping to buy. San Francisco on Sept. 6 offered the bankrupt utility $2.5 billion to sell its wires and poles. (See PG&E Ends Bond Bid as SF Makes Wires Offer.)
PG&E has made public statements appearing to reject the offer but leaving the door ajar. It said selling its San Francisco wires wasn’t in the best interests of the company and its shareholders but that it remained open to discussing the matter with the city.
Under current law, the CPUC must evaluate the sale or merger of utility assets based on the net benefit to ratepayers. SB 550 would require the commission to also review the acquisition of an IOU’s assets based on safety criteria. It also specifies that the commission’s review would apply even if the sale is to a public entity, such as a city.
But the bill would also let the CPUC delay its implementation until July 2021, meaning SB 550 may not apply to PG&E if it becomes law — and the utility decides to accept the city’s offer. PG&E must conclude its bankruptcy reorganization by June 30, 2020, to access a $21 billion wildfire recovery fund.
Two measures authored by Sen. Steven Bradford (D) — a former public affairs manager for Southern California Edison and member of the Energy, Utilities and Communication Committee — bear on the state’s long-term clean-energy goals.
SB 676 seeks to ensure that adding millions of electric vehicles in coming years won’t overtax the grid and lead to greater need for fossil-fuel generation. It would instruct the CPUC to establish strategies and metrics to integrate EVs, including time-of-use rates that encourage charging during the “belly” of the state’s so-called duck curve, when there’s a glut of cheap solar power in the middle of the day.
Bradford’s SB 155 would require the CPUC to monitor the renewable portfolio standards of load-serving entities to make sure they’re meeting their goals. The larger goal is for the state to rely on zero-carbon energy sources by 2045, as required by last year’s SB 100.
Newsom has yet to sign the four bills, as of press time. The governor has until Oct. 13 to approve or veto measures sent to him this legislative session. Of the 2,600 bills introduced this year, more than 100 dealt with electricity, but only about a quarter of those measures passed.
State regulators and other PJM stakeholders last week expressed dismay over the announcement last week that PJM Vice President Denise Foster, head of the RTO’s State and Member Services Division, was resigning and that her unit would be “realign[ed].”
The decision was announced Sept. 9 in a letter to members from interim PJM CEO Susan Riley, who said Foster will resign effective Oct. 31 and that her unit will be reorganized under Associate General Counsel Jen Tribulski.
“With Denise’s decision to step down, we have decided to realign the State and Member Services Division to further demonstrate the organization’s willingness to listen to key stakeholders and provide a more direct line of communication between the executive team, the states and members,” Riley said.
The news was greeted with surprise and sadness.
“I love Denise. Everyone loves Denise,” said Greg Poulos, executive director of Consumer Advocates of the PJM States (CAPS), calling Foster’s departure “very much a surprise.”
“I thought everyone thought highly of Denise. I would say it’s definitely a loss for advocate relations,” Poulos said.
“No, I didn’t see it coming,” said Glen Thomas, a former Pennsylvania regulator and president of the PJM Power Providers Group (P3 Group). “I generally had very good experiences” with Foster’s division, he said. “There are a lot of things we were complaining about and focused on — and this was not one of them.”
“If Denise leaving is the answer, I’d like to know what the question is,” West Virginia Consumer Advocate Jackie Roberts said. “She created PJM’s outreach to members, especially advocates and the states. … There are very few lawyers with a combination of creative interpersonal skills and an understanding of the technical nature of PJM’s business. It’s a really hard thing to do for lawyers. Most of them are not wired that way.”
“I think she’s incredibly intelligent. I think she’s an effective communicator,” said Maryland Public Service Commissioner Michael T. Richard, president of the Organization of PJM States Inc. (OPSI). “PJM and the states were very well served by Denise Foster’s work. … I don’t think we’ve ever felt we’ve not been heard.”
Diminished Voice for Stakeholders?
PJM declined to say who initiated the discussion about Foster’s departure and whether it was voluntary. Foster also declined to comment.
Nor would PJM explain the need to “further demonstrate the organization’s willingness to listen to key stakeholders” or why Riley is making the changes now, while the board is conducting a search for a new CEO.
Under the changes announced Sept. 9, Tribulski will become senior director of member services, with oversight of stakeholder affairs, member relations, and state and member training. Former Ohio regulator Asim Haque, who joined PJM in February, will continue as executive director of strategic policy and external affairs.
Haque and Tribulski will report to Vince Duane, general counsel and senior vice president of law, compliance and external relations. Under the old structure, Haque reported to Foster.
PJM also declined to explain how the changes would result in a “more direct line of communication between the executive team, the states and members.”
Poulos and Roberts said it does exactly the opposite.
“Why was Denise’s role diminished in this reorganization?” Roberts asked. “An important voice is now absent on the executive team. Everything now has to come through Vince. Before, she’d be sitting at the same table. That voice is gone because neither Asim nor Jen are on the executive team. So, I find the role being diminished as really upsetting.”
Poulos said that although CAPS has a “really good relationship” with Haque, Foster’s departure is a loss. “Denise was an executive. From a consumer perspective, we lost a voice on the executive team.”
Did She Jump or Was She Pushed?
PJM’s refusal to provide more details and the fact that Riley announced the organizational changes at the same time as Foster’s resignation led to speculation among stakeholders over whether Foster was being forced out.
“She had to be asked to leave,” one stakeholder said. “She’s committed to the organization, and she’s too young to retire.”
Among stakeholders and PJM staff there was discussion over whether she was leaving to care for her partner, who has a serious illness. There was also a rumor that former CEO Andy Ott is starting his own venture and wants to bring Foster on board.
Poulos said he would like PJM to offer more information on the reason for the changes. “When you don’t give us the information, people are trying to fill in the blanks,” he said.
Roberts acknowledged that it is not common for corporate boards to discuss the reasons behind their personnel decisions.
“However, in this specific case, where PJM has admitted that it needs changes to its culture and how it operates, it would be best to explain how this change is consistent with that,” she said. “Given how well-liked [Denise] is, it would behoove them to give us some explanation.”
Second Stint at PJM
A graduate of Dickinson Law School, Foster worked for three years as an assistant consumer advocate for Pennsylvania before joining PJM as senior counsel in 2000. After five years in that post, she moved to Exelon, where she spent another five years, rising to become director of policy development. She returned to PJM, taking her current post, in 2009.
Foster had been reporting to Andy Ott, then executive vice president of markets, in June 2015 when Ott was named CEO-elect to replace Terry Boston. Foster then began reporting to COO Mike Kormos. (See Boston Retirement Prompts Additional Promotions at PJM.)
When Kormos left PJM in March 2016, his position was not filled, and three months later, Ott announced Duane would head a newly formed Law, Compliance and External Relations Division, with Foster as a direct report.
OPSI President Richard said he was informed of the restructuring shortly before it was announced Sept. 9 but not given an explanation of why PJM was making the changes or how it would affect OPSI and state regulators.
Richard said he was contacted by Stu Widom, manager of regulatory and legislative affairs under Haque, who joined PJM from Calpine in July.
“They told me that Denise was resigning and that they’re making these changes. It seems like they’re moving people around.”
Richard said “there’s been a desire [by OPSI] to have better communication with the [PJM] board” and said he was “very encouraged” by Riley’s comments on the subject.
The OPSI board meets twice yearly with the PJM Board of Managers, Richard said, and will have an “extended meeting” at their next face-to-face in October.
The Real Source of the Friction
Asked whether he had any problems in his dealings with Foster, Richard said, “None whatsoever.”
Richard also said he had not suggested any changes to PJM’s structure. “Generally, they have a good shop in keeping states apprised of what’s happening. … How the organization works I don’t think is key to having a good relationship.”
New Jersey Board of Public Utilities President Joseph L. Fiordaliso, who has been highly critical of PJM for failing to communicate with his state, said he didn’t hold Foster responsible. And he said he knew of no other regulators who had difficulties with her. “Denise and I have always had a cordial relationship,” he said.
At the Mid-Atlantic Conference of Regulatory Utilities Commissioners annual meeting in July 2018, Fiordaliso threatened to pull the state from the RTO, saying “it’s not rocket science to make people feel a part of the process, … Pick up the phone. … That’s all we want.” (See NJ Regulator Threatens to Exit PJM Amid States’ Complaints.)
Regulators’ criticism was frequently directed at Ott.
“I think you would find a number of states that certainly would have the same concerns that [Fiordaliso] has,” Illinois Commerce Commissioner John Rosales, then president of OPSI, said at the same conference. “I’ve made this clear to Andy that the communication could be better.”
Former FERC Commissioner and Pennsylvania regulator Robert Powelson had similar criticism at a PJM issues workshop in D.C. last year. “You talk to certain state commissioners; you talk to consumer advocates; there’s a concern that voices are not being heard,” he said. “I think PJM — Andy has heard me say this — has to do a better job with their state outreach. … A lot of states right now are not happy.”
Ott declined to comment Monday.
Rosales and Pennsylvania Public Utility Commission Vice Chairman Andrew Place, who also spoke at the workshop, agreed with Powelson’s characterization.
“It becomes very frustrating for us because they’ll say they listen, they’ll tell us about the stakeholder process, they’ll tell us everything that they’ve done … and then they’ll just throw it out the door and say, ‘We’re going to go with this anyway,’” Rosales said.
Place was referring to PJM’s April 2018 “jump ball” filing that asked FERC to choose between RTO staff’s capacity repricing proposal or the Independent Market Monitor’s plan to extend the minimum offer price rule to existing resources in addition to new entries (ER18-1314). (See Glick Recusal May Mean No MOPR Ruling Before December.)
PJM further angered states with its energy price formation proposal, which the RTO filed unilaterally in March after a yearlong discussion with stakeholders produced no consensus. In a letter to stakeholders in December, PJM Chairman Ake Almgren had pledged that a “comprehensive” energy price formation proposal would include six elements, including a transitional offset in the capacity market to prevent ratepayers from being overcharged because of increased energy and ancillary services revenue.
But the proposal PJM ultimately filed lacked the transition, OPSI complained, meaning consumers would be overcharged for seven years, from implementation in June 2020 to completion of energy and operating reserve revenue increases being fully reflected in capacity prices in 2027.
OPSI also has repeatedly clashed with PJM’s management and board over the independence of the Monitor. The Monitor’s independence has been a recurring source of contention since IMM Joe Bowring accused then CEO Phil Harris at a FERC technical conference in 2007 of attempting to muzzle it, an allegation that ultimately led to Harris’ resignation.
Improvements Seen
In an interview on Friday, Fiordaliso said PJM’s communication with the state has improved with the addition of Haque in February and the July 1 appointment of Riley — a member of the board since 2005 — as interim CEO.
“I think they’re making a concerted effort to keep a line of communication open with the states,” he said. Riley is “a very outgoing person and a person who is more than willing to communicate and keep the member states up to date on things. My encounters with her thus far have been beyond pleasant.”
Haque was the chair of the Public Utilities Commission of Ohio when he took a newly created position as PJM’s executive director of strategic policy and external affairs. PJM said Haque would report to Foster, who in turn reported to Duane.
“It’s always encouraging when you have someone you know well being brought into the inner circle,” Maryland’s Richard said of Haque. “He’s a known entity and has a great deal of credibility [with the states]. He understands the issues of importance to the state. He’s very easy to reach.”
“I think everyone’s really happy with him. He’s a breath of fresh air,” West Virginia’s Roberts said. “He’s objective, and he’s openminded, and he’s willing to hear different views and try to understand those views. He seems open to new and novel solutions to the problems that PJM has had.
“I don’t see Asim coming in as any kind of force-out” of Foster, she added.
Culture Problem?
One stakeholder who declined to be identified said that Riley is attempting to address a “cultural problem” identified in the report on the GreenHat Energy default: “the idea that we’ve got it [under control], we don’t have to tell the stakeholders anything.”
A report by independent consultants on the fiasco concluded that “an unwarranted air of confidence facilitated GreenHat’s ability to grow” and recommended PJM “create a culture and environment that encourages staff to challenge internal assertions and test their own assumptions.”
The stakeholder said the culture stems from PJM’s early years as an RTO under Harris, who “controlled the board” and saw stakeholders as “an irritant and a hindrance.”
But under Ott, who was mentored by Harris, “it switched back to what it was under Phil,” the stakeholder said.
“These are the type of crux issues that lead to mistakes like GreenHat. Sue Riley is really committed to improving the culture.”
Riley has said little publicly since becoming interim CEO. Earlier this month, however, she took steps to defuse the latest clash between PJM and the Monitor. In January, PJM made a FERC filing arguing that the Monitor should not be permitted to file complaints under Federal Power Act Section 206 without a change in the RTO’s governance structure (EL19-27). On Sept. 5, PJM indicated it was abandoning that request, with Riley and Bowring issuing a statement that reaffirmed their “relationship of mutual respect.” (See PJM Content with IMM Role after Fuel-cost Policy Ruling.)
Threading the Needle
Some observers worry that PJM’s board is not attuned to the real reasons for the RTO’s often fractious relations with its stakeholders and wonder what that means for the search for a new CEO.
In July, state consumer advocates and regulators said the new CEO should support state environmental goals to address climate change and a stronger partnership with the Monitor. (See States, Regulators: Look Outside PJM for Next CEO.)
But East Kentucky Power Cooperative COO Don Mosier said the search committee should not overlook internal candidates and the “successes of the PJM leadership team.”
“The new CEO must have a vision for threading the needle between state and federal authority on market issues, while maintaining a strong rapport with both authorities, the Market Monitor and PJM members, taking into account what is best for the majority of market participants,” Mosier said.
PJM spokeswoman Susan Buehler said Monday that the RTO’s search committee is scheduling interviews with both internal and external candidates. “To my knowledge, [Riley] is not” a candidate, Buehler said.
One stakeholder who thinks Riley could end up the permanent CEO said she will “either be the best CEO or the worst CEO.”
“Frankly, I think the board in its ignorance thought the commissioners’ and advocates’ and other stakeholders’ objections to what PJM’s doing [was because of] a lack of a relationship with them. The real problem was Andy wouldn’t do it any other way than his way, and Vince was driving the car for him,” the stakeholder said. “The board’s culpable in all this GreenHat stuff they’re trying to fix now. They believed senior management and didn’t ask questions.
“I’m really concerned that the PJM board has mistaken a problem with their relationship with certain stakeholders with Denise’s oversight of that. Because they’re two different things. … As engaging as she is, that’s not going to stop people from being disappointed in what PJM is doing.”
PJM generators seeking must-offer exceptions will lose their capacity interconnection rights (CIRs) unless they meet Capacity Performance requirements within five years under Tariff changes approved by FERC on Monday (ER19-2417).
Rejecting arguments from some of PJM’s largest utilities, the commission said the joint PJM-Independent Market Monitor proposal was needed to mitigate market power and hoarding of CIRs.
Exelon, Duke Energy and Public Service Enterprise Group had contended the revocation of CIRs was overly punitive and that CIRs are a contractual right resulting from investments and not granted on a “use it or lose it” basis.
The commission disagreed. “The interconnection service agreement or wholesale market participation agreement, which is signed by the seller, explicitly provides that CIRs are subject to the terms of the Tariff, which may change over time. … We agree with PJM that sellers that are neither meeting nor attempting to meet the Capacity Performance resource requirements should not be able to retain capacity resource status and CIRs indefinitely through must-offer exceptions.
FERC approved a joint PJM-IMM proposal to revoke CIRs from generators seeking must-offer exceptions without a plan to meet their CP commitments within five years. | PJM
“We do not agree with the protesters’ arguments regarding the types of hardships sellers could face if they lose their CIRs,” FERC continued. “The proposed procedures for removal of CIRs because of a resource status change are the same Tariff procedures used for removal of CIRs after a resource deactivates. After a resource loses its capacity resource status, the seller is able for one year to transfer the CIRs or submit a new generation interconnection request that contemplates the use of the same CIRs. Sellers also may choose to continue to participate in the PJM markets as an energy resource.”
Sellers will have up to five years to develop and complete necessary upgrades to achieve CP status, which FERC noted “is consistent with the time frames for new resources to complete upgrades and reach commercial operation.”
The changes, endorsed at the Markets and Reliability Committee in April, will require existing capacity resources not offered in three consecutive auctions to change to energy-only status. A resource receiving a must-offer exception must also file a plan showing how it will become able to satisfy CP requirements or forfeit its CIRs. Resources would be granted exceptions for no more than two auctions. (See Load Interests Endorse PJM-IMM Must-offer Proposal.)
The commission approved the proposal, effective Sept. 23, with the new provisions first affecting the 2023/24 delivery year.
“The main motion would permit hoarding of CIRs inappropriately,” Monitor Joe Bowring said at the time. “We continue to believe the compromise we worked out with PJM makes the most sense.”
FERC shot down arguments from Exelon, Duke, PSEG and FirstEnergy that PJM has exaggerated the potential for capacity sellers to exercise market power and that the change would encourage unit retirements.
“The underlying purpose of the must-offer requirement is to ensure that sellers do not withhold capacity resources from [Reliability Pricing Model] auctions and potentially exert market power,” the commission wrote. “We concur with the IMM that the historical frequency of exception requests is irrelevant and that a small number of units in constrained locations in the market could have significant impact on prices. We find that the proposed revisions to the must-offer exception procedures and limitations on the number of exceptions are consistent with the purpose of preventing sellers from physically withholding capacity. We also agree that these provisions will prevent hoarding of CIRs by resources that are not performing as a capacity resource.”
FERC was also unmoved by arguments the proposal could result in generators making hasty investment decisions. “PJM has concluded a multiyear transitional period to the Capacity Performance resource requirements, and through that process, sellers have had opportunities to determine if upgrades were necessary for existing resources to meet those requirements,” it said.
The commission directed PJM to submit a compliance filing to add some clarifying language and correct a ministerial error in one of its Tariff citations.
ISO-NE Load Forecasting Manager Jonathan Black provided the New England Power Pool Reliability Committee last week with more details on the forecasting changes that contributed to a reduction in the installed capacity requirement (ICR) in the 2019 capacity, energy, loads and transmission (CELT) summer demand forecast.
Participants at last month’s Power Supply Planning Committee and the RC meetings requested more information on the load forecast changes, which produced a 1,250-MW reduction in net ICR for delivery year 2023/24.
The forecast cycle change (using macroeconomic assumptions from 2019 data vs. 2018) produced a reduction of 300 MW, while the use of a second weather variable (adding cooling degree days, in addition to the weighted temperature-humidity index previously used) caused an additional 855-MW drop.
The use of separate July and August peak load models rather than a combined July/August case was the only change to increase the ICR, responsible for a 45-MW boost.
Shortening the weather history period to 25 years from 40 years subtracted 140 MW. ISO-NE said it made the change primarily because wind speed data needed for the new winter demand model used for CELT 2019 was unavailable for all the years of the former 40-year period. The shorter history allows the RTO to keep a consistent historical weather period for both summer and winter monthly forecasts.
It is also more consistent with the practices of other grid operators such as NYISO (20 years) and PJM (25 years).
Black also discussed the reduction in the region’s energy intensity over the last two decades, largely caused by increased end-use efficiency driven by federal standards. Since 2005, he noted 45 mandatory Department of Energy efficiency standards have gone into effect.
The electric energy intensity of the New England regional economy has been declining for the past few decades. | ISO-NE
The relationship between annual electric gigawatt-hours and regional gross state product has dropped by almost 25% since 1991 on a gross energy basis and 35% on a net energy basis, including the impact of behind-the-meter solar.
Evolving ICAP Requirements
Peter Wong, ISO-NE manager of resource studies and assessments, presented a review of the schedule for developing the “ICR-related values” for Forward Capacity Auction 14 (capacity commitment period 2023/24).
These values include the ICR; local resource adequacy requirement; transmission security analysis; and local sourcing requirement for import-constrained Southeast New England. Also included are the maximum capacity limit for the export-constrained capacity zones of Maine and Northern New England and the marginal reliability impact demand curves.
Proposed ICR-related values for capacity commitment period 2023-2024, FCA 14, *including Mystic Units 8 and 9 | ISO-NE
Including Mystic Units 8 and 9, the RTO has proposed an ICR of 33,431 MW and a net ICR of 32,490 MW after a 941-MW reduction for Hydro-Québec interconnection capability credits. That is a 1,260-MW reduction from the net ICR for FCA 13. (See “ICAP Requirements and Tie Benefits,” NEPOOL Reliability Committee Briefs: Aug. 20, 2019.)
If the RC approves the values Sept. 25 and the Participants Committee does on Oct. 4, the RTO plans to file the ICR-related values with FERC by Nov. 5 both including and excluding Mystic Units 8 and 9.
WASHINGTON — FERC staff last week held a technical conference to receive input from RTO officials and stakeholders on dynamic and ambient-adjusted line ratings, including whether and how the commission should require transmission owners to implement them (AD19-15).
Much of the two-day conference held at FERC headquarters focused on the current limited use of the practices on the grid, the different kinds of devices and how RTOs accommodate them. But staff — and Commissioner Richard Glick, who attended parts of the conference each day — received plenty of advice, with some urging a requirement for TOs to use ambient-adjusted ratings (AARs), and others stressing caution against a one-size-fits-all approach. Others urged the commission to force TOs to disclose how they calculate their ratings.
All seemed to agree, however, about the potential benefits of dynamic line rating (DLR) technology.
“If this country is going to meet its numerous clean energy targets established by numerous states and corporations, we’re going to need a more vibrant transmission system,” Glick said in opening the conference Sept. 10. “And part of that is we’re going to need more transmission capacity. But it also means using our existing system more efficiently. … Certainly, this commission needs to consider whether there are alternative mechanisms for establishing line ratings … that can squeeze more out of the transmission system without impairing reliability.”
| FERC
A transmission line’s rating determines how much electricity can flow through it. TOs provide their line ratings to their RTOs/ISOs. Most are static — rarely changing throughout the line’s lifetime — and very conservative, often based on worst-case scenarios: high temperatures, cloudless days and minimal wind.
Some TOs use seasonal ratings, allowing for more power flow in the winter months — though a TO’s definition of “winter” can vary, with some increasing the rating beginning in October and maintaining it all the way into April. As one panelist noted, April temperatures are quite different from those in January.
AARs, which change every so often (the frequency can vary from as high as every 15 minutes to daily) based on temperature forecasts, are widely used in PJM and ERCOT, and see limited use in MISO and SPP. Rarer still are dynamic line rating (DLR) devices, some of which can take into account not only temperature, but humidity, wind speed, sunlight and precipitation; others simply measure the sag of a line and adjust its rating accordingly.
Many TO representatives who spoke at the conference were positive about the technology, pointing to specific experiences their companies have had in using certain devices. But they cautioned against a hard rule from FERC for widespread implementation.
“At a high level, the concept of AARs sounds appealing and relatively simple: adjust line ratings based upon current or near-term environmental conditions (ambient temperature and sometimes wind velocity) to increase the efficiency of energy flow on the bulk electric system,” Dennis Kramer, senior director of transmission policy for Ameren, said on behalf of MISO’s TOs. “The broad implementation of AARs, however, is not simple and could be very complex with impacts on multiple existing processes and procedures, as well as requiring creation of entirely new policies, requirements, obligations and capabilities.”
“Individual transmission owners should be given an opportunity to determine whether implementing AAR on a particular transmission line would be beneficial to the transmission system in either alleviating congestion or enhancing the reliability of the transmission system,” said Rikin Shah, principal engineer for PacifiCorp. “Requiring the transmission owners to implement AARs on every single transmission line may result in unnecessary capital investment without the return that was expected and put additional burden on consumer rates.”
Carlos Casablanca, director of advanced transmission studies and technology for American Electric Power — which he said has been using AARs for more than 10 years in several RTOs — encouraged FERC to require TOs to use the technology on most of their lines, as they “can increase the value of a robust transmission system to the benefit of our customers and bring flexibility to the transmission operations environment.”
But even he said that not all lines would benefit from their use. “We have some assets that are over 100 years old in some regions. … We don’t think it may be safe or prudent to apply [AARs] to those facilities.”
Joe Bowring, PJM’s Independent Market Monitor, said not requiring TOs to use AARs “is akin to saying, ‘You have your ratings wrong most of the time.’ … PJM real-time prices are calculated every five minutes. The system operates in real time. There’s no reason for line ratings to be the same [every] season, at all hours of the day.”
Transparency Concerns
But regardless of the TO and their position on AARs or DLRs, line rating practices vary dramatically. As multiple speakers pointed out, for example, there is no uniform methodology for calculating static line ratings — and no requirement for TOs to explain how they calculate them.
Advocates for FERC stepping in seized upon those differences in making their case.
“The same facilities should have the same ratings under the same operating conditions regardless of the transmission owner,” Bowring said. “Transmission owner discretion should be minimized or eliminated in line ratings.”
Speaking about MISO, Michael Chaisson of Potomac Economics, the RTO’s Monitor, echoed Bowring’s sentiments. He presented a histogram showing how many TOs used certain ratings in the winter for their 115-kV lines. “You can see it’s all over the map … but this isn’t even the worst of it,” he said. “This histogram actually proceeds several more pages off to the right with outliers. … You can’t effectively monitor without knowing the basis for the ratings.”
Michael Chaisson of Potomac Economics, MISO’s Market Monitor, displayed this histogram to demonstrate how many different ratings TOs use for their 115-kV lines. The graph actually extends “several more pages off to the right with outliers,” he said. | Potomac Economics
Michelle Pivach Bourg of Entergy Services pushed back, pointing to NERC Reliability Standard FAC-008-3’s requirement that TOs make their methodologies for calculating ratings available to their RTOs and reliability coordinators upon request.
But RTOs don’t review the line ratings that TOs submit for accuracy, the Monitors said. Both Bowring and Chaisson said their respective RTOs monitor for abnormal ratings and only then request information from the TOs.
Bowring said to Bourg, “I never said that the information was not available to the RTOs. I said they don’t actually do the review. There’s a difference.”
“I think the key phrase is ‘upon request,’” Chaisson said. “What we’re seeing in practice at MISO is that they don’t have a comprehensive folder with all these methodologies stored, and they don’t have a comprehensive database with the limiting elements. … All they have are the ratings the TOs gave them and the ability to ask about particular ones, which they do from time to time.”
Bowring also recommended that the commission require TOs to “at least engage in” pilot programs for DLR technology, not necessarily to permanently install the devices, “but to get the data.”
“There’s been a lot of talk about ‘smart grids,’” he said. “This seems to me one of the basic elements of what a smart grid would be. You can’t be smart without information.”
The first panel of the conference on Sept. 10 served as an introduction to line rating methodologies and technologies. | FERC
Adam Rousselle Sr., president of Alternative Transmission Inc., agreed. “What we’re seeing is the advent of great new information, and we’re asking questions about how to integrate it with a system designed not to have it. … I think we have to have the data, and after we have it, we’ll have better opportunities to steer.”
Rousselle advocated for “a broad, systemwide and immediate evaluation of every bulk electric transmission circuit’s facility rating. … If you put a blood-pressure cuff on every circuit … there would be no doubt at what the rating was.”
Mike Kormos, senior vice president of transmission and compliance for Exelon, balked at these suggestions. “I’d be happy for that rate base,” he joked. “I think it’s a real waste of money.
“Please recognize that the vast amount of line ratings on the system have no impact. Those lines are not overloaded; those lines do not go into congestion,” said Kormos, a former PJM executive. “For those lines that are in routine congestion or extreme congestion, even for a short period of time, I can assure you that the first question asked is, ‘Are the ratings right?’ … When I was at PJM, I asked, and now that I’m with Exelon, I will provide.”
CARMEL, Ind. — MISO has softened a proposal to crack down on long-term outages from capacity resources, granting some wiggle room for outages taken June through August and removing a replace-or-pay requirement.
The RTO last month introduced a provisional solution that would limit extended planned outages to fewer than 90 days to qualify for participation in the Planning Resource Auction. Additionally, resources expected to be unavailable for the first 90 days of the planning year would not qualify. (See MISO to Limit Capacity Resource Extended Outages.)
Now, MISO has relaxed the proposal so that resources unavailable for 90 of the first 120 days of the planning year will be disqualified from participation. Tim Bachus, MISO capacity market administration analyst, told the Resource Adequacy Subcommittee on Wednesday that the new proposal recognizes that September is becoming more summer-like in terms of hot weather-related demand.
Bachus said the rules will apply to both full and partial outages. Had the rules been in place during the last PRA, about 254 MW would have been impacted, he added. Currently, the RTO doesn’t impose any penalties for capacity resources that take extended outages.
“We don’t have any mechanisms in place to address this, and that’s what we’re hoping to do today,” Bachus said.
MISO has also scrapped its original provision to make cleared resources on 90-day-plus planned outages replace their capacity or be penalized at its approximate $240/MW-day cost of new entry.
Bachus said that while stakeholders were generally supportive of the 90-day planned outage limit, they criticized the CONE payment penalty as too extreme.
“We realize that not all resources will be in a position to replace,” he said.
Bachus stressed that the new rule is meant to be provisional. “This proposal is really only meant to cover a year or two, and then we’ll have a more robust construct in place,” he said.
VALLEY FORGE, Pa. — After a one-month delay, the PJM Market Implementation Committee on Wednesday endorsed two packages to update the RTO’s opportunity cost calculator.
The latest plan from Dominion Energy and Panda Power Funds would make what the sponsors called “modest improvements” to the calculator and include Manual 15 revisions so that it more closely resembles the Independent Market Monitor’s calculator that most stakeholders prefer using. Just under 84% of members voted in favor of the new package.
When polled on PJM’s package — which maintains the status quo but also makes minor clarifications in Manual 15 — 51% of stakeholders also approved. Both plans will advance to the Markets and Reliability Committee for consideration, with the Dominion/Panda proposal considered first.
Critically, Panda and Dominion withdrew three other proposals that were discussed at the August MIC meeting, including one that eliminated PJM’s calculator altogether. (See “Opportunity Cost Calculator Vote Delayed,” PJM MIC Briefs: Aug. 7, 2019.)
“We thought that this would be a good compromise,” Dominion’s Jim Davis said. “We worked with PJM to see what they would be willing to change in a timely fashion.”
Monitoring Analytics, however, disagreed that the latest changes made PJM’s calculator any more similar to its own and said that Manual 15 changes were unnecessary.
“We think these are modest changes, we agree with that, but this brings us a little closer to the IMM calculator and lets us just focus on further documentation of the IMM calculator,” Davis said.
Monitor: Review ARR/FTRs to Improve the Allocation of Congestion Rights
The Monitor told the MIC that the existing constructs for auction revenue rights and financial transmission rights leaves some load zones unable to sufficiently offset their congestion costs.
“There is a significant misalignment between congestion as it has been allocated and congestion as it has occurred,” said Howard Haas, chief economist for Monitoring Analytics. “Even if you were to claim all the rights made available to you, you cannot offset all off the congestion assigned to you.”
Zonal ARR and FTR total congestion offset (in millions) for ARR holders for the 2018/2019 planning period | Monitoring Analytics
Existing rules generated a 91.8% rate of congestion offset recovery across all of PJM last year, but the rate varies wildly from zone to zone, Haas said. For example, Dayton Power & Light only offset 27.2% of its congestion costs, while Baltimore Gas and Electric offset 367.3% of its costs, despite producing significantly different amounts of congestion, according to the Monitor’s table.
Both PJM and stakeholders said they were generally supportive of exploring the issue, but some worried the problem statement and issue charge as presented were “too narrow.”
“I believe the GreenHat [Energy] report said we should take a comprehensive look at the FTR/ARR design,” said Exelon’s Sharon Midgley, noting that the Financial Risk Mitigation Senior Task Force is instead focusing on other credit and risk policies post-default. “This issue charge is leading towards a solution that is perhaps a little too narrow.”
Haas said that the key work activities listed in the issue charge provide appropriate room for that discussion. The deliverables would require stakeholders to identify the causes of congestion misalignment and decide whether changes to the market design could fix the problem.
“I would like to keep this more broad,” Midgley insisted. “All stakeholders might not necessarily share the same exact view on your description of the problem to be solved here.”
Other stakeholders agreed. Vitol’s Joe Wadsworth said he would like to see the rolling monthly auction option that PJM has presented at prior task force meetings added into the scope of the Monitor’s proposed review. The issue charge will be up for approval at the October MIC meeting.
Regulation Historic Performance Score
PJM presented revised Manual 11 language that would address a gap in missing historical performance scores used for regulation market clearing.
The MIC endorsed the manual changes in August, but at the MRC on Aug. 22, stakeholders took issue with the proposed value PJM would use when a system failure or other issue prevents the transfer of timely data.
The latest revisions will note that “if no historic performance scores are available from the last three days, then the latest available regulation qualification or regulation requalification test score for each resource by signal type is used.” A previous version indicated PJM would use a default value of 1 instead.
ISO-NE COO Vamsi Chadalavada’s operations report to the New England Power Pool Participants Committee on Friday showed the region’s energy market value dropped to $321 million in August, down $93 million from July 2019 and down $240 million from August 2018.
August natural gas prices were 11% lower than the previous month’s average values, with average RT Hub LMPs ($23.58/MWh) down 19% from July. The average day-ahead Hub LMP was $25.69/MWh for the month, and average August 2019 natural gas prices and RT Hub LMPs were down 36% and 40%, respectively, from August 2018 averages.
The average day-ahead cleared physical energy during the peak hours as percent of forecasted load was 101.3% during August, up from 99.9% during July. Day-ahead cleared physical energy is the sum of generation and net imports cleared in the day-ahead energy market.
| ISO-NE
Chadalavada drew attention to slides showing that forecasting trends are shifting fast. He said the RTO is continuing efforts to improve load forecast models and tools to produce better day-ahead and long-term load forecasts.
Consent Agenda
The Participants Committee voted unanimously to approve the single item on the consent agenda, revisions to OP-14E to incorporate energy storage as a type of asset-related demand that can be selected on ISO-NE’s form NX-12E, which provides the RTO with details that are not included in bid information.
ISO-NE and NESCOE Budgets Update
Kenneth Dell Orto, chair of the Budget and Finance Subcommittee, presented an update of the RTO’s proposed 2020 operating and capital budgets, as well as the 2020 budget of the New England States Committee on Electricity.
The budgets are in the final stages of development and will be voted on at the Oct. 4 Participants Committee meeting in Boston.
A more detailed presentation was provided to the subcommittee last month.
ISO-NE’s budget presentations to the New England state agencies, with their questions and the RTO’s answers, can be found here.
Michigan regulators last week approved a settlement between Consumers Energy and solar developers, resolving arguments over the utility’s obligation to support small generation projects under the Public Utility Regulatory Policies Act.
The Public Service Commission’s approval of the agreement means that Consumers will interconnect new solar projects and is allowed to establish a new avoided-cost rate (ACR) for qualifying facilities (U-20615).
Consumers will now purchase power from an additional 584 MW worth of solar projects to be interconnected by 2023. About 170 MW of the projects will receive the current ACR, while the remaining 414 MW will be eligible to enter contracts at a rate based on MISO LMPs plus the capacity prices established in the RTO’s annual capacity auction. Solar developers Geronimo Energy, Cypress Creek Renewables and sPower stand to receive a cut of the first 170 MW of projects at higher rates.
The move will more than triple solar capacity in Michigan, which currently has more than 153 MW of solar. The settlement puts to rest five separate cases between Consumers and more than 40 entities. The settlement was signed by several QFs, Consumers, PSC staff and the Solar Energy Industries Association.
Solar panel construction | Consumers Energy
Under PURPA, utilities such as Consumers are obligated to purchase electricity from independently owned QFs at rates that reflect a utility’s own cost to build new generation. Consumers’ existing avoided costs generally range from about $95 to $110/MWh, but the company has alleged the figures are outdated and above-market.
While the settlement will put some QFs in operation, its leaves many awaiting approval and compensation from Consumers. The company’s current PURPA interconnection queue is jammed at 3.3 GW, and several QF owners complained that the first version of its integrated resource plan didn’t do enough to clear the backlog. Consumers has previously mounted an unsuccessful bid with its state regulators to waive deadlines on reviewing QF applications for approval. The utility claimed it was simply overwhelmed by the more than 1,700 QF applications in the pipeline.
A previous settlement in June modified Consumers’ IRP so that the utility will now conduct an annual competitive bidding supervised by a third party for adding new capacity (U-20165). Consumers can only own up to half of the new capacity it secures through competitive bidding; the rest must come from power purchase agreements with unaffiliated companies. Any remaining capacity needs after bidding is complete can be filled by QFs.
Consumers this fall will bid out about 1,200 MW of new solar energy for the 2019-2021 time frame. Although the bidding will focus on solar generation, the utility said QFs of all fuel types will be allowed to bid.
The June settlement also stipulates that Consumers will use a five-year horizon instead of the previous 10-year outlook to determine whether it has a capacity need. Consumers will also have to file new ACRs for regulatory approval within 30 days of each annual bidding process. Current QFs with a PURPA-based contract will continue to get new PPAs regardless of Consumers’ capacity needs. Additionally, QFs 150 kW or smaller will receive PPAs based on the full avoided cost, also regardless of Consumers’ capacity status.
Last year, Michigan regulators lifted a 10-month suspension on the state’s new avoided-cost calculation for Consumers. The utility argued it didn’t need any additional capacity over the next 10 years and had put about 700 MW of solar projects on hold. The PSC rejected the argument, saying the utility’s IRP would determine whether it needed new capacity.
PURPA in Flux
Michigan isn’t the only state in the MISO footprint where utilities have tried to alter or discontinue their obligation to pay independent developers under PURPA, arguing that rates exceed actual avoided costs for new generation.
The 9th U.S. Circuit Court of Appeals ruled in June that it could not force the Montana Public Service Commission to compel NorthWestern Energy to purchase power from solar developers at originally established and higher ACRs. (See Montana PSC Racks up 2nd Lawsuit over PURPA Rates.)
FERC this summer also avoided addressing whether the addition of storage facilities at the Beaver Creek wind farm in Montana would put the project’s QF standing in jeopardy under PURPA when the owner withdrew applications to recertify the four 80-MW projects (EL18-195). NorthWestern argued last year that the addition of storage units to 80-MW wind facilities would put them over the PURPA megawatt limit.
In comments to the petition, the Edison Electric Institute said the case raised new issues for PURPA’s treatment of energy storage and urged FERC to hold off on deciding on the motion until it could address the issues of “modernizing” PURPA in a more comprehensive proceeding, given that on-site storage capability could increase a facility’s capacity beyond 80 MW.
FERC has been reviewing its implementation of the law since 2016, holding a technical conference in June of that year, but it has languished under numerous shakeups at the commission. However, one of its agenda items (E-1) for this month’s open meeting Thursday concerns “qualifying facility rates and requirements” and “implementation issues” under PURPA. The item is listed under both the docket FERC opened in 2016 (AD16-16) and a new rulemaking docket (RM19-15), indicating a Notice of Proposed Rulemaking is potentially imminent.
VALLEY FORGE, Pa. — Exelon told the PJM Operating Committee last week it is near agreement with RTO staff on business rules for non-retail behind-the-meter generation (NRBTMG) that would exclude retail community solar and aggregate net energy metering programs.
Exelon told the Markets and Reliability Committee in August that it approves of the concepts and reporting requirements outlined in the changes to Manuals 13 and 14D but wanted more time to review the differences in the application of the rules — specifically whether community solar programs and aggregate net energy metering are within scope. It asked the MRC to delay its vote for 30 days. (See “Non-retail BTM Generation Vote Delayed,” PJM MRC Briefs: Aug. 22, 2019.)
Since then, both parties have agreed that neither program should fall under the category of NRBTMG. Exelon will bring its revisions to the MRC meeting scheduled for Sept. 26, Sharon Midgley, the company’s director of wholesale development, told the Operating Committee on Sept. 10.
NRBTMG refers to resources used by municipal electric systems, electric cooperatives or electric distribution companies to serve load. They do not participate as supply resources in PJM markets but can be netted against their wholesale load to reduce transmission, capacity, ancillary service and administrative fee charges.
Hot August Spawned 4 Weather Alerts
Soaring temperatures last month spawned four hot weather alerts Aug. 18-21. A feedwater control valve issue also tripped units at Salem 2, creating the first spinning event of the summer.
Manuals Endorsed
Staff must update all three manuals to comply with FERC Order 841’s energy storage participation mandates.
Manual 14D adds metering requirements specific to energy storage resources, outage reporting requirements and generating unit reactive capability curve specification and reporting procedures.
In Manuals 36 and 40, PJM updated the exception to critical cranking power to include non-hydro energy storage resources and added a lower megawatt threshold for electric storage resource training requirements.
