FERC on Monday released the disputed fuel-cost policy (FCP) at the center of a redacted complaint that PJM’s Independent Market Monitor filed last year against the RTO for not assessing a penalty against a generator (EL19-27).
The commission posted a mostly unredacted version of Tenaska Power Services’ response to the Monitor’s complaint, including the FCP in use Jan. 5-6, 2018, when the alleged violations occurred at the dual-fuel Brandywine Power Facility in Prince George’s County, Md.
The Monitor protested the release after FERC’s notice last month proposing to sunshine the docket, arguing that the confidential filings contain information that would undermine the markets and potentially give other participants insight into how Tenaska structures its energy offers.
The Brandywine Power Facility in Prince George’s County, Md. | Brandywine Power
FERC was unconvinced by that argument.
“While the fuel-cost policy details how the market seller develops its fuel cost, the fuel-cost policy lacks specific information that would be necessary for other competitors to estimate its actual energy offer,” FERC said Dec. 12 in its order approving the release. “The majority of the relevant cost data at issue here is not competitively sensitive information, but information available from a publicly available source. Moreover, these data are no longer current, as the data relate to a specific event that occurred nearly two years ago on Jan. 6, 2018.”
Tenaska Defends Actions
Tenaska’s unredacted response — originally filed in January — shows the company insisting it didn’t violate its FCP when it used third-party quotes for natural gas prices after no applicable trades became available on the Intercontinental Exchange in time to calculate day-ahead market offers.
The Monitor interpreted the language of Brandywine’s FCP to prohibit Tenaska from making offers in such an event — a choice that would leave the capacity resource facility subject to nonperformance penalties should extreme weather conditions disrupt its fuel oil supply, Tenaska said.
“In short, there is no reasonable basis for limiting PJM’s dispatching options, or for putting generators in a position where they are potentially subject to severe penalties or are unable to recover their costs, simply because the Market Monitor is taking an overly restrictive view of a PJM-approved FCP,” Tenaska said.
Houston-based KMC Thermo owns Brandywine and maintains a contract with Tenaska that allows the company to sell energy and ancillary services in PJM’s markets. KMC authored the disputed FCP using a standardized template available on Monitoring Analytics’ website, approved by PJM and subsequently reviewed by the Monitor before implementation, Tenaska said.
In defense of its actions, the company pointed to a statement from the FCP that says, “under a set of defined market conditions, natural gas costs may be based on independent third-party quotes.”
“At the end of the day, the broad language in the FCP permitting the use of third-party quotes was provided to both the Market Monitor and PJM and, absent any objections by the Market Monitor, was properly accepted by PJM,” Tenaska said. “Regardless of the Market Monitor’s hindsight dissatisfaction, there is no basis for claiming that the FCP must now be read in such a manner that it ‘does not allow the use of offers from ICE or estimates from an affiliate company or from an independent third party.’”
Market Power Precedent
The Monitor, in its initial complaint against Tenaska filed in December 2018, said the case “presents an important precedent for the role of fuel-cost policies in protecting the PJM energy market from market power abuse.”
“If PJM accepts market sellers’ unreasonable after-the-fact arguments to justify developing fuel costs using a method not defined in the fuel-cost policy, fuel-cost policies become meaningless and fail to serve the functions that the commission identified,” the Monitor said.
The Monitor first alerted Tenaska and PJM to the alleged violation in February 2018. Tenaska defended its actions to PJM the following April, with the RTO notifying the Monitor four months later that it would not penalize the company.
PJM asked FERC to dismiss the complaint in January 2019 on the grounds that the Monitor lacked the authority to override the RTO’s interpretation of Tenaska’s FCP. Ultimately, in a separate docket, FERC reaffirmed the Monitor’s right to protest FCPs. (See Another Win for PJM Monitor on Fuel-cost Policies.)
Collusion Concern
The Monitor reiterated its confidentiality concerns to FERC on Nov. 27, after the commission notified it of its intent to release documents in the proceeding.
“Release of such information could damage the efficient and competitive operation of PJM markets by facilitating tacit collusion and disseminating substandard fuel cost policy provisions,” the Monitor wrote. “The release of market sensitive information harms the public interest in maintaining competitive PJM wholesale power markets. That Tenaska Power Services Co. consents does not change the harm to the public interest. … In fact, Tenaska has a conflict of interest because it could benefit from the release of information that harms the public interest by weakening fuel-cost policy standards.”
CAISO’s Western Energy Imbalance Market is expanding its footprint to Colorado. Xcel Energy, Black Hills Colorado Electric, Colorado Springs Utilities and Platte River Power Authority announced Tuesday they will join the EIM as soon as 2021.
Although the companies “have different business models, customers and geography,” they said in a press release, “all share a commitment to leading the clean energy transition and believe the WEIM will provide the most benefit to their collective Colorado customers.”
Three of the companies currently share resources and balance demand through a joint dispatch agreement, and the fourth, Colorado Springs Utilities, will join in March.
The news is further evidence of the momentum of the EIM and a disappointment for SPP, which had hoped to lure the utilities to its proposed Western Energy Imbalance Service (WEIS). The four utilities serve almost 2 million customers and reported $3.7 billion in sales in 2018.
The companies said that a Brattle Group study concluded that the EIM had more potential to lower production costs “due to the size of its market footprint and the diverse resources available.”
The companies said the EIM also offered lower administrative costs and noted its exploration of a day-ahead market, which they said will allow the integration of more renewables.
“We’re very excited with their announcement,” CAISO spokeswoman Vonette Fontaine said. “Utilities are recognizing the savings the EIM brings to its customers, along with their ability to integrate carbon-free resources.”
SPP spokesman Derek Wingfield said the announcement “confirms that wholesale electricity markets can benefit the Western Interconnection, and we’ll bring significant value to participants of our Western Energy Imbalance Service Market like we’ve done through our other markets for more than a decade already. We are on track to launch the WEIS in Feb. 2021, and a number of western utilities have already expressed interest in joining it. We’re confident the WEIS’s performance will prove its value in lowering the cost of wholesale electricity and enhancing reliability, and that our roster of market participants will continue to grow over the next several years.”
“This decision is an important next step in our efforts to keep our customers’ bills low and provide more 100% carbon-free energy like wind and solar,” said Alice Jackson, president of Xcel Energy Colorado, the state’s largest load-serving entity.
The companies said they will work to finalize their implementation agreement with the EIM over the next several months and have set a target of 2021 for joining the market.
The companies announced they were evaluating the EIM and WEIS in September, after the state enacted legislation requiring utilities to submit greenhouse gas-reduction plans and instructing state regulators to investigate the potential benefits of joining a regional energy market. (See Colorado Utilities Examine Market Membership.)
Xcel’s Public Service Company of Colorado had almost 1.5 million customers and $2.7 billion in revenue in 2018, according to the Energy Information Administration.
Colorado Springs has more than 231,000 customers, with Black Hills serving almost 97,000.
Platte River Power Authority provides wholesale electric generation and transmission to the utilities of Estes Park, Fort Collins, Longmont and Loveland, which have more than 162,000 customers.
CAISO says the EIM has saved its nine current participants $801 million since it launched in 2014. Nine other entities will join the EIM next year, with the Los Angeles Department of Water and Power following in 2021.
CARMEL, Ind. — MISO’s Reliability Subcommittee will next year examine whether the RTO’s footprint is suffering from an excess of load-modifying resources.
Speaking during a conference call Thursday, Chair Bill SeDoris — who will again serve in that role in 2020 — said the subcommittee will begin discussions on the issue at its Jan. 30 meeting.
MISO stakeholders are increasingly wondering at what point LMR saturation will cause reliability concerns, with some contending the RTO may need to limit the number of emergency-only resources eligible for compensation.
SeDoris has suggested MISO undertake a study similar to its renewable penetration study, in which the RTO would seek to measure at what point an influx of LMRs would disrupt the system.
RSC Liaison Mike McMullen said MISO is currently working on a more general analysis of LMR effectiveness, with results to be presented at the Resource Adequacy Subcommittee’s Jan. 8 meeting. He said it might be helpful for RSC members to listen in even though the study won’t focus on LMR saturation.
“Understand, it’s not the same conversation that will happen at the RSC,” he told stakeholders.
Eligible End-User Customers sector representative Kevin Murray said he was surprised the stakeholder community was concerned about a surplus of LMRs.
“Physically, you balance the system by shedding load. LMRs volunteer to be first in line to shed load. If you run out of load-modifying resources, you shed firm load,” Murray said during MISO Board Week last week.
“We have to have some steel in the ground to generate electricity to have load to shed in the first place,” SeDoris responded.
MISO is attempting to both define a possible limit on LMRs and make its procedures clearer for market participants who have criticized the communication during emergency events as being confusing. (See Stakeholders: MISO System Fix Too Late for Summer.) The RTO will also deliver a presentation on LMR communication and documentation in the MISO Communication System at the Jan. 30 RSC meeting.
LMRs are not capacity resources but are considered planning resources during emergencies, able to help meet the planning reserve margin requirement for auction clearing prices. They must respond five times per year, which includes a generator verification test and four acknowledgements of MISO’s scheduling instructions. A market participant can choose to forgo the test but risks being levied three times an LMP-based penalty for nonperformance during an emergency event. MISO must first declare an emergency before accessing LMR capabilities.
MISO allows resources to register as both LMR and emergency demand response, a point of confusion for some stakeholders. Emergency DR is an informal resource category created by MISO to allow demand resources to help the system during emergencies without a more involved registration process.
Stakeholders have also raised the idea of MISO not including LMRs in its planning resource margin calculation. Some have also asked the RTO to evaluate the capacity payments LMRs receive relative to their effectiveness during emergencies.
“Maybe LMRs aren’t pulling their weight,” MISO planning adviser Davey Lopez said during the RASC’s Dec. 3 meeting.
The Upper Limits?
MISO held an informational workshop in October dedicated to the operation of LMRs. There, MISO adviser Michael Robinson said the RTO has yet to discern how many LMRs should be considered too much in the resource mix. He brought up mathematician and father of linear programming George Dantzig’s diet problem, where he sought to create an optimal diet from an algorithm but ended with suggestions such as 500 gallons of vinegar, 200 bullion cubes and 2 pounds of bran as meal choices. The suggestion led Dantzig to introduce upper bounds in linear programming.
“So we may have that problem with LMRs. Right now, we have 10,000, 11,000 MW. The question is … is there an upper limit?” Robinson said.
LMRs’ contribution is by nature difficult to calculate, he said. “How do you prove consumption that does not occur? … We’re trying to prove the counterfactual consumption level.”
ATLANTA — SaskPower’s mass outage event of Dec. 4, 2018, was a double shock for the utility. Not only did the disturbance affect nearly 200,000 homes and businesses at its height — ranking as one of Saskatchewan’s worst outages in 40 years — but there seemed to be no immediate cause for the transmission line failures that led multiple generating stations, including the province’s entire coal-fired fleet, to trip offline before emergency crews restored operation.
“In my career at SaskPower, we’ve never seen this, so that’s at least a one-in-26 [years] event,” Wayne Guttormson, manager for interconnections, system planning, asset management and transmission service at SaskPower, told NERC’s Operating Committee last week in a presentation on the utility’s response to the emergency. “Prior to that, I’m unaware of any records that we have for how bad it had gotten.”
Unremarkable Origins
Later investigations found the culprit to be rime ice — a phenomenon in which water droplets in fog cling to a surface and freeze, with additional ice crystals forming on top. Normally, rime ice is quickly melted by the sun or blown away by wind, but on cloudy, calm days, the ice can build up into heavy loads on trees and on overhead shield wires on transmission lines, which do not carry power and hence don’t heat up the way phase conductors do.
By the night of Dec. 3, such conditions had been in effect in Saskatchewan for more than a week, creating what Guttormson called a “perfect storm.” Across the province, ice-burdened shield wires were sagging low enough to contact the phase conductors underneath and cause outages. Usually, such incidents are infrequent, and service is restored quickly once the line is de-energized and the fault is cleared. In this case, more than 100 temporary line outages were associated with sagging shield wires.
Rime ice buildup on Saskatchewan power lines, December 2018 | SaskPower
What SaskPower hadn’t anticipated was that more than 40 shield wires would break under the strain, beginning around 10:30 p.m. Dec. 3, causing permanent outages until crews could be dispatched to make repairs. Moreover, 34 transmission line structures sustained damage from the sudden release of tension because of broken shield wires; nearly half of these damages were reported as “significant.”
In response, the utility’s protective systems progressively tripped off 14 transmission lines and 10 generating units by the height of the incident around 9 a.m. Dec. 4. This resulted in a brief underfrequency event that lasted for about 10 minutes, after which frequency returned to near normal.
A central theme in Guttormson’s presentation was the importance of devising effective, flexible emergency response and preparedness plans. Though the rapid succession of line outages caught the utility off guard, all distribution points were restored by 11 a.m. Dec. 4, and all transmission lines by 1 p.m. the same day.
The widespread outages gave the impression to outside viewers of a massive system failure, but SaskPower determined afterward that its emergency response procedures had in fact functioned properly. Automated protection systems “operated correctly to prevent a complete system shutdown,” while repair crews responded quickly in the emergency and were well supplied with material. The addition of gas-fired generation alongside traditional coal plants over the past 20 years also contributed to the overall resilience of the system, Guttormson said.
Mitigation, not Prevention
Because such widespread and persistent rime ice formation had never been seen before, SaskPower concluded that the event was “non-preventable.” The utility did identify several systemic risks from aging transmission lines and lattice towers that weren’t designed to withstand shield wire breaks. But the utility said that without foreknowledge of the event, there was no obvious widespread vulnerability that should have been guarded against.
Guttormson acknowledged that the experience gained might help to predict and mitigate future rime ice events. Those are unlikely to occur in the first place, however, as the conditions required — several days of light or no wind or sun, along with heavy fog — are so rare. Rather, the incident is a reminder that utilities cannot hope to anticipate every challenge and must be prepared to respond in the moment, with incomplete information.
“Everyone seems to have [advice], which we’ll certainly take a look at,” Guttormson said. “But in terms of the way the system was coming apart — from a planning perspective, it’s kind of hard to envision those scenarios in some respects, because you just don’t think of all that stuff happening that way in that time frame.”
The Texas Public Utility Commission last week denied the city of El Paso’s request for an extension of settlement negotiations, maintaining a Tuesday deadline for a stipulated agreement in the proposed $4.3 billion acquisition of El Paso Electric (49849).
The city asked for a 30-day continuance as it ponders whether to municipalize the utility. The City Council plans to discuss the issue during a Tuesday meeting.
“I welcome the city’s participation, but I hope they focus their minds if they’re really interested in municipalization,” Commissioner Arthur D’Andrea said during the PUC’s Dec. 13 open meeting. “I think it’s important that state and local governments stay shoulder to shoulder. I am very respectful of what the city is asking, but the train is moving.”
Eversheds Sutherland’s Lino Mendiola, who represents J.P. Morgan Investment Management’s Infrastructure Investments Fund (IIF), said he didn’t anticipate any “major issues” in the settlement discussions. He said he is hopeful of an uncontested settlement, “but realistically, one or two parties may not join.” (See Parties near Agreement on El Paso Electric Purchase.)
Lino Mendiola, IIF counsel, updates the commission on the El Paso Electric acquisition.
Mendiola said he may ask for a couple of days’ extension once the city’s direction becomes clearer.
“They do continue to be aligned with us, as far as the settlement agreement,” he said.
IIF and Sun Jupiter Holdings, a limited liability company formed to enter into the merger agreement, announced their proposed purchase of EPE in June.
The PUC has scheduled a hearing on the merits for Jan. 7-8.
Lubbock Asks for Revision to Settlement
The city of Lubbock offered during oral arguments to put up $2.4 million to help cut the cost of its late change it made to an agreed transmission route for one of the projects necessary to integrate Lubbock Power & Light’s load into ERCOT (48909).
Under the terms of a settlement with intervenors, the route would have crossed one of the lakes that provides the city’s drinking water. The revision adds 2 additional miles of 115-kV line at a cost of about $8 million.
The city urged the commission to approve the remainder of the unopposed route when it next considers the issue during its Jan. 16 open meeting.
The project is one of several needed to move 470 MW of Lubbock’s load from SPP to ERCOT. (See “LP&L Lines for ERCOT Integration near Final Approval,” Texas PUC Briefs: Sept. 12, 2019.)
PUC to Intervene in 2 SPP Dockets at FERC
Chairman DeAnn Walker notified her fellow commissioners that the PUC will intervene in a pair of FERC dockets involving SPP.
ER20-453 is SPP’s request to eliminate transmission revenue credits as an option for upgrade sponsors’ compensation under Attachment Z2 of the Tariff.
Left to right: Commissioners Shelly Botkin, DeAnn Walker and Arthur D’Andrea confer.
In docket ER20-418, SPP asked to unbundle the Tariff’s Schedule 1-A rate to change the allocation of services costs to reflect the increased revenue requirements that accompanied the growth of SPP’s Integrated Marketplace. Transmission customers would continue to pay administrative fees based on transmission usage while market participants would also pay administrative fees based on their settled market transactions.
The commissioners recently agreed to delegate the authority to determine FERC interventions to the PUC’s RTO representatives.
Commission Approves Rate Recovery, Admin Fees
In other business, the commissioners:
Approved a voluntary mitigation plan for Luminant Energy. Under state law, adherence to the plan will provide Luminant an “absolute defense” against allegations of market power through economic withholding (49858).
Agreed to a $145,000 administrative fee against retail electric provider XOOM Energy Texas over invalid door-to-door enrollments (50102).
Granted a request by CenterPoint Energy and parties to its rate case to defer regulatory consideration in hopes a settlement can be reached (49421).
Authorized adjusted transmission cost-recovery factors for EPE (49148), Texas-New Mexico Power (49586) and AEP Texas (49592); an additional $6.4 million in under-recovered costs for Oncor’s deployment of its advanced metering system (49721); and a $16.2 million refund by Southwestern Public Service for over-collected fuel costs (49690).
California Gov. Gavin Newsom filed court papers Monday saying he objects to the Chapter 11 reorganization plan that Pacific Gas and Electric submitted last week, including the utility’s proposed $13.5 billion settlement with fire victims.
The agreement would prohibit fire victims from supporting any other bankruptcy plan except for PG&E’s, “even one that provides identical treatment of the fire victims’ claims,” Newsom’s lawyers wrote in a motion filed with U.S. Bankruptcy Court Judge Dennis Montali in San Francisco.
“Progress toward fair treatment of victims is good … [but] that type of ‘progress’ is more about creating an illusion of momentum than it is about advancing the Chapter 11 cases,” Newsom’s attorneys said.
The motion included a copy of a letter Newsom sent Friday to PG&E CEO Bill Johnson, in which the governor said the utility’s reorganization proposal failed to meet the requirements of Assembly Bill 1054, a measure Newsom pushed through the State Legislature in July. The bill created a $21 billion wildfire recovery fund for the state’s investor-owned utilities, provided that the IOUs meet certain conditions meant to protect the public from utility-sparked wildfires. (See Calif. Lawmakers Rush to Pass Utility Wildfire Aid.)
“In my judgment, the amended plan and the restructuring transactions do not result in a reorganized company positioned to provide safe, reliable and affordable service to its customers, as required by AB 1054,” the governor wrote to Johnson.
PG&E’s proposed reorganization plan, filed Thursday, would create a trust for wildfire victims funded by $13.5 billion in cash and stock — the same as a competing plan filed by the utility’s bondholders earlier this year as part of their takeover bid. (See PG&E Reaches $13.5B Deal with Wildfire Victims.)
But PG&E’s plan to exit bankruptcy fails to enact the “fundamental change” Newsom called for after a series of massive blackouts this fall, the governor said in his letter.
PG&E’s bankruptcy “punctuate[s] more than two decades of mismanagement, misconduct and failed efforts to improve its safety culture,” Newsom wrote. He cited the San Bruno gas pipeline explosion that killed eight people in September 2010 and a series of catastrophic wildfires, including the Camp Fire, which killed 86 people and destroyed the town of Paradise in November 2018.
“For too long, PG&E has mismanaged, failed to make adequate investments in fire safety and fire prevention, and neglected critical infrastructure. PG&E has simply violated the public trust,” Newsom wrote. “It is against this backdrop that compliance with AB 1054 must be measured.”
Newsom told Johnson he believes a “transformed” PG&E should have a board of directors with a majority of Californians and more members with extensive safety experience.
“To facilitate transformation, the board that will lead the reorganized company should be acceptable to me and approved by the [California Public Utilities Commission] and identified in the amended plan,” the governor wrote. “I do not expect that the post-confirmation board of directors will include the current directors.”
Those current directors, many from out of state, include Chair Nora Mead Brownell, a former FERC commissioner. She moved to California to assume her role, as did Johnson, the former head of the Tennessee Valley Authority.
Newsom also called for “strict, clearly defined operational and safety metrics to which the reorganized company will be held accountable” and an “escalating enforcement process that provides for greater oversight of the reorganized company.”
The governor repeated his threat of a public takeover should PG&E fall short of state expectations.
“Because of this company’s history, the license to operate should be conditioned on it agreeing to this process,” Newsom said. “This should also include a streamlined process for transferring the license and the operating assets to the state or a third party when circumstances warrant.”
Newsom also said he thinks PG&E’s plan puts the company and public in peril because it relies so heavily on borrowing that a reorganized utility may be unable to access the billions of dollars in capital it needs to make safety upgrades.
PG&E and Wall Street Respond
PG&E was expected to move forward with its Chapter 11 plan at a hearing tomorrow in U.S. Bankruptcy Court in San Francisco, but Newsom’s criticism casts uncertainty on the proceedings. The utility’s plan relies on having access to AB 1054’s wildfire fund, which will be difficult without the governor’s blessing.
AB 1054 requires that the CPUC, headed by Newsom appointee Marybel Batjer, approve PG&E’s bankruptcy plan — and the resulting governance structure — before it can take effect.
PG&E CEO Bill Johnson
PG&E has said it hoped the court would confirm its reorganization plan by January to give the CPUC time to approve it. Under AB 1054, the utility must emerge from bankruptcy by June 30, 2020, to have access to the wildfire fund.
In response to Newsom’s letter, PG&E issued a statement saying, “We believe our restructuring plan meets the requirements of Assembly Bill 1054 and is the best course forward for all stakeholders. We’ve welcomed feedback from all stakeholders throughout these proceedings and will continue to work diligently in the coming days to resolve any issues.
“Looking ahead, we are committed to getting victims paid, continuing to implement changes across our business to improve our operations for the long term and emerging from Chapter 11 as a financially sound utility. In the meantime, we remain focused on delivering safe electric and gas service to 16 million people in Northern and Central California and working hard every day to reduce the ever-growing threat of catastrophic wildfires.”
Newsom’s letter to Johnson was made public over the weekend and caused PG&E’s stock price to tumble Monday morning.
The company’s stock had risen to a recent high of $12.32/share on Dec. 10 on news of PG&E’s $13.5 billion settlement with wildfire victims. News of the governor’s letter pushed down PG&E stock to $8.84/share at the start of trading Monday, though it recovered somewhat during the day’s trading and closed at $9.67/share.
PG&E’s stock sunk to a 2019 low of $3.80/share on Oct. 28 after the blackouts. In September 2017, its stock price had reached a 40-year high of nearly $70/share.
That was just prior to the catastrophic fires of October 2017 that wreaked havoc on Northern California’s famed wine country and started the series of disasters that led to the utility filing for bankruptcy in January, citing more than $30 billion in wildfire liabilities.
BOSTON — An overflow crowd of more than 200 people attended Raab Associates’ 164th New England Electricity Restructuring Roundtable on Friday to discuss state and federal policy around wholesale electricity markets and distributed energy resources.
Climate change “is playing a role in almost all our decision-making” and has contributed to making discussion at FERC “a little more contentious than it has been,” said Commissioner Richard Glick, the sole Democrat on the commission.
“But I don’t know if we’re going to put the genie back in the bottle … in large part because these are important issues that people have strong feelings about on all sides of the topics, and a lot is at stake,” Glick said.
Generators are contending that states’ renewable energy policies are having a negative effect on capacity markets, Glick said, adding that issues come up frequently in the regions with mandatory capacity markets, such as New England, New York and PJM.
Generators argue that state-sponsored resources are suppressing energy prices, but the states counter that the market is seeing low prices for a variety of reasons, principally low natural gas prices and the increasing penetration of zero-marginal-cost energy resources, he said.
“States have a legitimate interest in pursuing the resources they want, particularly in this time, when we don’t have a federal government very active on greenhouse gas emissions,” he said.
“I’m not sure FERC has a role in the debate,” Glick said.
“If you look at the Federal Power Act, it’s very clear … the law says that FERC doesn’t have authority over generator resource decision-making; it’s up to the states,” Glick said. “Whether it’s promoting renewable energy, or nuclear power, or coal, whatever it is, it doesn’t matter to me.
“Secondly, we’re drawing the line around subsidies when we have these debates about wholesale markets and state policies, and they were looking at more recent subsidies, whether it be nuclear [zero-emission credit] programs or state renewable energy programs,” he said. “If you’re going to address subsidies, where do you draw the line?”
Regarding New England and its concern about natural gas supply constraints on very cold days, Glick said, “We’re going back to the issue of attributes, of saying, ‘Let’s pay this generating plant because it has these attributes.’ I would prefer that the commission and the various RTOs around the country would say … ‘Why don’t we pay the generating plants for the value of the services or benefit they actually provide, not just for sitting around?’”
Tom Michelman, senior director of Sustainable Energy Advantage, asked who can push if there is a delay at the commission in dealing with a docket: “How much power does an individual commissioner have?”
“The chair has enormous authority,” Glick said. “First of all, the chair controls the agenda, so Chairman [Neil] Chatterjee doesn’t have to bring up anything that he doesn’t want to bring up, unless there are certain matters that have to be dealt with statutorily within 60 days, but that’s a relatively small number of issues.”
Peter Fuller of Autumn Lane Energy asked about a hypothetical case of states agreeing on regional carbon pricing: How would FERC respond?
Glick declined to speculate, but he did say that RTOs would have a stronger chance of succeeding if they made a filing under FPA Section 205 rather than Section 206, because under the former, the commission must only determine that the new scheme is just and reasonable, while under the latter it must determine that the existing set-up is unjust and unreasonable.
Speaking on her last day as commissioner of the Massachusetts Department of Energy Resources (DOER) after four years in office, Judith Judson highlighted the growth in solar, from practically zero in the state a decade ago to 2,537 MW installed and operating today, with another 1,029 MW approved.
Solar’s success has bred interconnection woes, with developers in many parts of the state facing costly transmission and distribution infrastructure upgrades in order to connect their projects to the grid, Judson said.
Judson also touted the state’s Clean Peak Standard, the first in the nation. The law, passed in September last year (H4857), requires DOER to set a baseline minimum percentage of retail electricity sales to be met with clean generation resources or load reductions during seasonal peak periods. (See Mass. Inaugurates Clean Peak Standard.)
“The Clean Peak Standard really is designed to be able to utilize clean energy that’s generated during times of less demand and move those into the peak hours,” Judson said. “And that is how we’re going to be able to integrate and reliably depend on more and more renewables on our system.”
“The Clean Peak program is about addressing peak demand, but what’s exciting about it is it creates a financing model and monetizes the benefits of flexibility,” she said.
Raab Associates’ Jonathan Raab, who conducted the roundtable, asked, “How can states better align investments in the grid of the future with our clean energy goals? What are the types of T&D upgrades that we should be socializing?”
“The question comes to me as what is a customer,” Judson said. “It used to be that a customer was load; it was very clear. Now, a customer may be load, it may be generating, it could have all different uses of the system but still be a customer. … Certainly when we think about socializing costs, we have to make sure that it’s fair and equitable for all customers.”
Power is Information
Raab asked whether dynamic pricing should be part of the solution to integrating DERs, such as with advanced metering infrastructure (AMI) or other technologies.
“AMI is an expensive endeavor,” said Penni McLean-Conner, chief customer officer for Eversource Energy. “Advanced metering functionality is needed surgically, no doubt about it. As we think about distributed energy resources, we need visibility into the edge of the grid, and we need capability in understanding the power flows.”
She noted that most AMI installations do not have time-varying rates associated with them because New England customers don’t have enough discretionary load to have a “meaningful impact” on those rates.
“At Eversource, we’re also having discussions about the latency of time-varying rates, meaning that we will see pretty rapid dynamic shifts in the peak hours as we put in more resources at the edge of the grid, such as storage combined with PV,” McLean-Conner said.
She suggested that incentives based on rebates that can be readily changed might be a more dynamic solution.
“Because when you build it into rates, they’re going to be latent. And we’re already seeing this in California, that they will be incenting the behaviors at the wrong time,” she said.
Henry Yoshimura, director of demand resource strategy at ISO-NE, said that increasing penetration of DERs means the bulk power system becomes less predictable and power flows more variable.
“If we operated DERs in the distribution system in the same way we operate resources generally, we would model the system so that we know exactly what available capacity is on the system at any moment, which includes knowing what the loads are and what the other resources are doing on each segment of the system,” Yoshimura said. “We do that in transmission, [and] we would need to do that in the distribution system, which is way bigger in terms of length and complexity. It’s designed differently, as well.”
Yoshimura called the effort a “daunting” but “solvable” task.
“It is critical that policymakers identify the entity responsible to solve this problem,” he said. “I struggle with dispatch … but what is essential, whether we’re in the dispatch regime or accounting for customer behavior, is that we have time-based prices that follow the marginal cost of service in real time. Otherwise, there’s no signal to the customer to know when it’s best to charge or discharge their battery, and the same holds for demand response.”
Janet Gail Besser, managing director of regulatory innovation and utility business models at the Smart Electric Power Alliance, said her two areas of responsibility are closely linked.
“You can’t expect utilities to make investment in new technologies and operating practices without evolution in the regulatory framework, which has to drive where we want them to be making that investment,” Besser said. Massachusetts has been leading in some areas, such as performance-based ratemaking, she said.
Christopher Rauscher, Sunrun’s director of policy and storage market strategy, agreed.
“The bring-your-own device program here, we are proposing that now in California,” Rauscher said of Sunrun’s programs with Green Mountain Power and National Grid in which it works with customer-sited solar and storage resources. “It’s really amazing that California is one to two years behind Massachusetts in DER policy, so it’s an exciting time to be here.”
WASHINGTON — This year’s gridCONNEXT — GridWise Alliance and Clean Edge’s third annual conference focusing on visions of the grid of the future — delivered the usual goods last week when it came to discussions of the advanced technologies and policies necessary to modernize how the U.S. produces and consumes electricity.
But a grim sense of urgency permeated much of the discussions, as speakers, panelists and audience members repeatedly reminded each other that the world is way behind on its decarbonization goals to limit the rise in the average global temperature to under 2 degrees Celsius, as documented by a U.N. report released last month. (See U.N.: Decarbonization ‘Key’ to Cutting Global Emissions.)
There was also much discussion about what is occurring around the world, and what the U.S. can do to help lead decarbonization efforts.
Here’s some of what we heard Wednesday and Thursday at the Liaison Capitol Hill hotel, just down the street from the U.S. Capitol.
Climate Crisis
The conference occurred during the final days of the 25th U.N. Climate Change Conference of Parties (COP25) in Madrid, which was widely seen as a disappointment. The talks ended with a partial agreement to put forward more aggressive emission targets than those of the 2015 Paris Agreement at next year’s conference in Glasgow, Scotland.
Multiple news reports described how poorer, developing countries grew frustrated with the talks over the lack of U.S. leadership and left early. Many countries, however, are waiting to see if a new U.S. president will lead to a stronger agreement than Paris, which the U.S. will exit on Nov. 4, 2020 — ironically the day after Election Day.
Attendees made clear how they felt about the climate issue when U.S. Sen. Jeff Merkley (D-Ore.) in a keynote speech Thursday mentioned the young Swedish activist Greta Thunberg being named Time’s Person of the Year and the room erupted in applause.
But most of the talk about the state of Earth’s climate was more dire.
A report by the U.N.’s Intergovernmental Panel on Climate Change last year found that even limiting global warming to 1.5 C — predicted to occur by 2040 if current trends continue — would still result in catastrophic effects in certain parts of the world, especially affecting developing countries, which are rapidly purchasing coal power technology from China to continue industrializing. (See IPCC: Urgent Action Needed to Avoid Climate Trigger.)
“I think people need to understand the huge difference in just half a degree” Celsius, Melanie Kenderdine, principal for the Energy Futures Initiative (EFI), said Wednesday. “Urgency becomes very important when every 10th of a degree matters. … I approach our pathways to decarbonization from the position of what we can do now, what can we do consistently, [and] what should we be investing in for the future, because we cannot get there from where we are now. But we need to start now and stop fighting over it.”
“Is this the part where I’m supposed to disagree?” joked Rich Powell, executive director of ClearPath, a nonprofit that focuses on conservative policies to address climate change.
Kenderdine — who worked at the Department of Energy in the Obama administration under Secretary Ernest Moniz, the founder and CEO of EFI — and Powell were speaking on a “point-counterpoint” panel on the best policies to decarbonize the grid. But there was little disagreement or debate among them.
Powell said that for most of the world, “priority 1 is to staunch the bleeding.” Through China’s Belt and Road Initiative, for example, Pakistan is building subcritical coal plants. “To get yourself out of a hole, first you need to stop digging, and in many parts of the world, we’re still digging.”
He said the U.S. needs to focus on researching and developing “higher performing, more affordable, flexible clean energy technologies” for not just domestic use but to export to compete with China. Rather than subsidies for specific resources, such as wind and solar, the U.S. should put in place a “technology-neutral” subsidy for any new decarbonizing tech that phases down over time. “If something needs to be permanently subsidized, we can’t expect a Nigeria or Indonesia or Bangladesh to permanently subsidize clean energy in their markets,” Powell said. “We need technologies that are so good, you could actually imagine them being like-for-like substitutes for subcritical coal in the developing world.”
DOE already does “invest a huge amount in basic research,” Kenderdine said. “But I’m not sure that basic research is not all that the federal government needs to be doing right now. It needs to … move into different spaces.”
Around the World in Two Days
There was also much discussion on what the U.S. could learn from E.U. countries’ actions.
On Wednesday morning, Angelina Galiteva, founder of the Renewables 100 Policy Institute and a member of the CAISO Board of Governors, talked about how Europe is investing not in battery storage but “using their excess capacity from wind [to] make hydrogen,” which can be used to generate electricity — a practice virtually unheard of in the U.S. The next step, she said, is to create renewable natural gas by synthesizing the hydrogen with carbon dioxide in the air.
“Very ambitious, but certainly something that is doable,” she said. The Los Angeles Department of Water and Power, she added, is working to convert the coal-fired Intermountain Power Plant in Utah to a natural gas-fired generator by 2025, and then to hydrogen power by 2045, using a salt mine to store excess fuel. The comment prompted a grunt of laughter from a member of the audience.
“What? Hey! Science fiction, but the future is coming!” Galiteva said.
While Kenderdine and Powell’s discussion was cordial, some of their comments provoked Galiteva’s ire as she listened in the audience.
“I think we are mercifully moving away from the juvenile discussions of 100% renewables,” Powell said. “In an incredibly rich place like California that appears to have a truly unusual appetite for spending more and more money on their power sector … it’s potentially possible there.”
“I think that the deniers on the one hand of the climate debate and the magical thinkers on the other hand of the climate debate, who say it’s all going to be wind and solar in 10 years …are actually delaying action when action is urgently needed,” Kenderdine said.
Galiteva told them that while she agreed with the general premise that California needs a diverse set of technologies besides wind and solar, such as geothermal and hydro, “we don’t need nuclear. Nuclear is being shut down. Our biggest failure was investing several hundred million into upgrading San Onofre only for it to leak.” All the nuclear plants in development in the U.S. have been overbudget and there are risks involved, she noted.
While China and India lead the world in gross carbon emissions, Galiteva noted that the U.S. is the largest emitter per capita. “We don’t need to be jumping on [Pakistan]; we need to be helping them stay clean.” She said she grew up in Tanzania, where “the easiest solution was microgrids, solar panels, local resources [and] biofuels. … Let’s do that, and let’s not go back into the dangerous technologies that caused Chernobyl, Fukushima [and] Three Mile Island. … We don’t need to, it’s expensive and we have good alternatives, so let’s make it happen.”
Other speakers also talked about the need to address “energy poverty” around the world, and not just because of climate change.
Kristina Skierka, who gave the morning keynote address Thursday, is CEO of Power For All, which works to deploy decentralized electrification solutions in the fastest, most cost-effective ways in energy-poor communities, mostly in Africa and Southeast Asia. These solutions largely involve microgrids, with rooftop solar.
“It’s been really exciting to be here for the last 24 hours and hear Africa or India or developing countries mentioned so consistently,” Skierka said. “I certainly wasn’t expecting that.”
She described how people living in villages in Uganda and Nigeria need to walk hours to charge their phones and use hazardous fuels to power their stoves and lamps. “There’s almost a billion people without any access to energy, in this day and age where we run businesses from cell phones. And we have all the technology we need. So, this is actually a complete injustice in my view.”
Powell and Kenderdine were critical of California’s recent SB 100 excluding new natural gas plants that incorporate carbon capture and sequestration from being considered a clean energy resource. Kenderdine said the state can’t possibly meet its goals without CCS.
She brought up a study by EFI that found that Nigeria would become the third most populous country by 2050, and that the world will add 10 cities of 10 million or more people by 2030, with four in Africa. “You’re not going to power [these cities] with rooftop solar,” she told Galiteva. “It will make a huge difference in rural Africa, where four hours of electricity means something very different for people’s lives.” But these growing cities will still need centralized power plants, and they will need CCS to stay clean, she said.
The Fourth Risk
John MacWilliams, senior fellow at Columbia University’s Center on Global Energy Policy, gave a pre-lunch keynote speech Wednesday in which he detailed the top five risks facing the electric grid.
The theme of the speech stemmed from Michael Lewis’ 2018 book, “The Fifth Risk,” which recounts President Trump’s transition into office in the early months of 2017 and its effect on the work and ongoing projects of several federal departments and their career employees. MacWilliams, DOE’s first chief risk officer, featured heavily in the first section of the book, which is about DOE and its many responsibilities, and he gave the book its title and theme. When he told Lewis about the top five risks the U.S. faces, he said the fifth was “project management.”
MacWilliams told Lewis the fourth risk to the U.S. was an attack, either physical or cyber, on the country’s electric grid (following a nuclear weapons accident, an attack by North Korea and conflict with Iran). Speaking on Wednesday, he said anthropogenic climate change was the fourth risk to the grid itself, coming after cyberattacks, physical attacks and aging infrastructure.
“Unfortunately, the recent scientific reports … [are] suggesting that we’ve actually underestimated the velocity and the magnitude of climate change’s negative impacts,” MacWilliams said. He tallied off the more well known impacts in general — including increased storm intensity, rising sea levels and more frequent wildfires. But he said the risks to the electric industry are more frequent and longer droughts causing reduced hydropower capacity, warmer air reducing solar power efficiency, and increased temperatures reducing air density and, thus, wind production.
“Massive investment needs to be made and needs to be made now,” he said.
MacWilliams’ fifth risk to the grid? Like project management, it was more mundane, but no less dangerous. “It’s the common squirrel. Yes, squirrels.” He said that in 2016, “these furry suicide bombers” were estimated to have caused 3,456 outages in the U.S.
VALLEY FORGE, Pa. — PJM’s Planning Committee will consider whether the RTO must develop governing document language to deal with the mitigation of existing and future critical infrastructure on NERC’s CIP-014 list.
Some 54% of stakeholders endorsed the issue charge from the D.C. Office of the People’s Counsel after two deferrals and a late-stage challenge from Exelon that many on the committee considered out of order. (See “Critical Infrastructure Vote Delayed Again,” PJM PC/TEAC Briefs: Nov. 14, 2019.)
At the heart of the debate was Exelon’s preference to exclude mitigation of existing projects from the scope of the issue charge, as described in their alternative motion. Transmission owners, including Exelon, are currently working on a Tariff attachment that would handle those specific facilities. (See PJM TO Tariff Filing Stirs up Transparency Concerns.)
The issue came to a head at the Markets and Reliability Committee meeting in August when incumbent TOs asked for feedback on their proposal that would establish a process for vetting transmission system enhancements designed solely to reduce the number of critical assets identified under NERC’s critical infrastructure protection standard CIP-014, of which fewer than 20 exist within the PJM footprint. NERC deems these assets “highly critical … that, if rendered inoperable or damaged due to physical attack, could result in significant grid concerns: widespread instability, uncontrolled separation or cascading.”
Other sectors expressed concerns about the opaqueness surrounding the proposal, encouraging the D.C. OPC to bring its problem statement forward the following month. After successfully lobbying for a deferral on the vote for two months in a row, the TOs in November held a webinar to address concerns about their proposal to no avail.
At the PC meeting Thursday, Exelon presented for a vote its slightly modified issue charge that excluded existing CIP-014 projects. Some stakeholders pressed PJM on the appropriateness of voting on an alternative issue charge that’s not been moved properly through the stakeholder process or even attached to its own problem statement. After more than an hour of debate — and a failed motion to overturn the decision of the committee chair — stakeholders chose the D.C. OPC’s issue charge over Exelon’s alternative.
The PC will take on the scope of the issue charge and formulate recommendations within six months.
DER Ride Through Task Force Sunset
Stakeholders agreed to sunset the Distributed Energy Resources Ride Through Task Force now that its work considering a default standard is done.
PJM said distributed energy resources currently function on settings designed to respond to unexpected system malfunctions that disrupt power flow. Some sources “ride through” the event, providing much-needed reliability benefits, while others trip off to prevent system damage. Solar panels and other DERs also can’t tell the difference between a transmission fault and a distribution fault, causing inappropriate responses and overstressing the system.
The task force had been considering ways to fix this problem — even going so far as to bring in federal experts to help develop new standards — but decided against an RTO-wide rule because of the uniqueness of local distribution systems. (See DER Ride Through Task Force Considers New Direction.) Instead, the task force suggested that PJM create a recommendation when a local distribution system lacks an official policy. The committee also endorsed revisions to Manual 14G: Generator Operational Requirements that include this guidance from the task force.
PJM Defends Transource Tx Project Analysis
PJM said Thursday a recent analysis of multiple projects designed to relieve congestion in central Pennsylvania and northern Maryland — including Transource Energy’s reconfigured Independence Energy Connection project — still exceed the RTO’s 1.25 cost-benefit ratio threshold. (See Transource Files Reconfigured Tx Project.)
LS Power disputed the RTO’s analysis of the newly proposed path for the eastern segment of the project, telling the Transmission Expansion Advisory Committee in November that it only carries a benefit-cost ratio of 1. (See PJM Analysis of Transource Alternative Challenged.) The TO said PJM’s base case used to calculate its 1.6 ratio doesn’t consider the impact of a nearby project that would alleviate congestion on the Hunterstown-Lincoln 115-kV line.
PJM’s additional calculations performed after the November TEAC meeting concluded that the aggregate benefit-cost ratio for the alternative Transource project, the Hunterstown-Lincoln 115-kV line and a third project that upgrades the Gracetone-Bagley 230-kV line falls between 2.25 and 2.33. If state regulators in Maryland and Pennsylvania opt for the original configuration for the Transource project, that ratio jumps to 2.87.
LS Power objected to the aggregate ratio presented to the committee Thursday, arguing that market efficiency projects should be re-evaluated on a standalone basis.
RTEP Upgrades
PJM will recommend that the Board of Managers approve system enhancements totaling $134 million for inclusion in the Regional Transmission Expansion Plan in 2020. Two projects, from American Electric Power and Old Dominion Electric Cooperative, are Form 715 criteria-driven enhancements; two others, in MetEd and NIPSCO, are PJM-selected market efficiency projects; and the last project, from Penelec, is being considered for its baseline load growth deliverability and reliability-driven enhancements.
The projects include:
In AEP’s zone, rebuild 3.11 miles of the 69-kV LaPorte Junction-New Buffalo line with 795 aluminum conductor steel reinforced wire: $12.3 million.
In ODEC’s zone, create a line terminal at Belle Haven Delivery Point (three-breaker ring bus) and install a new single-circuit 69-kV line rated at 55N/55E from Kellam substation to new Bayview substation (21 miles): $22 million.
In Penelec’s zone, rebuild 20 miles of the 115-kV East Towanda-North Meshoppen line and adjust relay settings at the 115-kV East Towanda and North Meshoppen substations: $58.6 million.
In NIPSCO’s zone, rebuild the 138-kV Michigan City-Trail Creek-Bosserman line: $24.69 million ($22 million is PJM’s portion).
In MetEd’s zone, rebuild the 115-kV Hunterstown-Lincoln line and upgrade substation equipment: $7.21 million.
Projects costing less than $5 million — which often include transformer replacements, line reconductoring, breaker replacements and upgrades to terminal equipment, including relay and wave trap replacements — are not broken out individually in PJM’s whitepaper.
Dominion, FirstEnergy Supplementals
FirstEnergy would like to replace the 230-kV static VAR compensator at its Atlantic substation in central New Jersey with a 300-MVAR, 230-kV STATCOM for $55.7 million. The enhancement will address the increasing trend of outages and failures on the line.
FirstEnergy would like to replace the 230-kV Static VAR compensator at its Atlantic substation in central New Jersey. | FirstEnergy
Dominion Energy revised an earlier solution it identified for a customer-requested data center in Loudoun County, Va. The TO said with projected load likely to exceed 100 MW, two transmission sources will be required to comply with its facility interconnection requirements and avoid a violation of mandatory NERC reliability criteria.
Its latest solution would cut and extend the Brambleton-Yardley Ridge line into and out of a new Evergreen Mills switching station, which will be constructed with four 230-kV breakers in a ring bus arrangement. The customer has also requested two additional 230-kV breakers to be installed for additional redundancy and will be responsible for excess facilities charges, Dominion said. The entire project will cost an estimated $21.2 million.
VALLEY FORGE, Pa. — The PJM Market Implementation Committee endorsed two fuel-cost policy (FCP) packages — including one authored mid-meeting — that would consider the market impacts of breaking the rules and adjust penalties accordingly.
The first package, compiled by a group of stakeholders, won 87% support and will advance to the Markets and Reliability Committee as the main motion next month. The plan reduces penalties when a market seller self-identifies violations of its FCP and provides safe harbor for situations of noncompliance that weren’t contemplated by the policy. The plan would also expand the use of temporary FCPs. (See PJM MIC Briefs: Nov. 13, 2019.)
PJM’s Glen Boyle, however, questioned how the plan would apply penalties, noting that existing language could allow for duplicate benefits. The plan would fully penalize units that clear the day-ahead market or run in real time on a cost-based offer and are either paid day-ahead/balancing operating reserves or have cost-based offers above $1,000/MWh. If a market seller self-identifies noncompliance to PJM and the Independent Market Monitor, the penalty is reduced 75%.
“There could be a scenario under this proposal where a cost-based unit running on its cost-based schedule is the marginal unit setting price and still getting a discount on the penalty,” he said. “I think that position is a little tough to justify.”
Adrien Ford of Old Dominion Electric Cooperative acknowledged that the scenario could occur but said it wasn’t a big enough risk for stakeholders to consider modifying their plan.
“Knowing whether or not there was an impact is tough, so we are coming up with something to indicate that there might have been an impact,” she said. “I think what you’re pointing out is a thin risk that there could be an impact and it wouldn’t be assigned. It is likely that a marginal unit would be paid DA/balancing operating reserves and caught by the impact test. There’s no perfect test, but we think this is a pretty good one.”
The PJM Industrial Customer Coalition and Calpine offered revisions to the first package that they said would address Boyle’s concerns. When it wasn’t accepted as a friendly amendment, the two stakeholders proposed the alternate language as a second package on which the MIC would vote. The revisions clarify that the full penalty would be imposed if a unit is marginal in the day-ahead or real time on its cost-based offer. A unit committed on its price-based schedule that later fails the three-pivotal-supplier test during its minimum run time or hours of its day-ahead commitment would also not incur the full impact factor unless the other conditions for market impact were met. About 81% of the committee endorsed these small language tweaks too.
The Monitor withdrew its package in support of PJM’s own set of revisions, which only won 29% support from the MIC. The RTO also rescinded an alternative package that offered its own version of an impact factor.
Parameter-limited Schedules
PJM and the Monitor presented their divergent views to the MIC on the implementation of parameter-limited schedules (PLS) and whether governing document revisions are needed.
According to PJM, Tariff and Operating Agreement language errors introduced with the implementation of Capacity Performance means that the RTO’s practice regarding PLS contradicts its own rules and conflicts with other governing documents. The Monitor said, however, that PJM should simply follow the language set out in the Tariff instead of revising the document to fit its current practice.
“What we want to do is make sure the Tariff reflects what’s in that manual,” PJM’s Adam Keech said. “The Tariff conflicts with what’s in the manual, and the manual is the correct implementation.”
According to the Monitor, however, the compliance issue rests solely with PJM’s misinterpretation of the Tariff. The RTO’s current implementation of PLS does not mitigate the exercise of market power, as it was intended to do, the Monitor said.
Both the Monitor and PJM discussed their viewpoints with the MIC at the request of the MRC on Dec. 5. The conversation will continue Dec. 19 when the MRC considers Tariff changes authored by PJM to align PLS with the manuals.
Border Rate Manual Revisions
The MIC endorsed revisions to Manual 27: Open Access Transmission Tariff Accounting that would reflect FERC’s recent order on border rate calculations (ER19-2105).
In June, PJM transmission owners submitted a filing that updates the yearly border charge to prevent network integrated transmission service (NITS) customers — network load located outside the RTO’s boundaries but served from within — from subsidizing border and non-zone service rate customers who use transmission service through and out of PJM. (See Settlement Hearing Set for PJM Border Dispute.)
FERC accepted the TOs’ filing subject to refund, with an implementation date of Jan. 1, 2020, but also set a paper hearing and settlement procedures for involved parties to work out their differences over the proposed methodology behind the rates.
PJM’s Market Settlements Development Department said the manual revisions will move forward but acknowledged that refunds will be issued if changes to the methodology are approved in a settlement.
