El Paso Electric and the investment funds seeking to buy the utility have reached a settlement with most of the parties with an interest in the transaction, they told Texas regulators on Wednesday.
EPE, Sun Jupiter Holdings and Infrastructure Investments Fund (IIF) US Holding 2 said that the agreement’s “negotiated resolution” is in the public interest, will conserve the parties’ and the public’s resources, and eliminate controversy (49849).
The Public Utility Commission of Texas had set a Dec. 17 deadline to finalize a stipulated agreement but granted an extension to noon Wednesday. (See “Commission Denies Extension Request in EPE Acquisition,” Texas PUC Briefs: Dec. 13, 2019.)
EPE’s Rio Grande Plant in Sunland Park, N.M. | El Paso Electric
Parties to the agreement include the city of El Paso, PUC staff, the state’s Office of Public Utility Counsel, and several consumer and labor groups. The El Paso City Council approved the agreement on Tuesday, although it is still pondering EPE’s municipalization.
The signatories agreed that the transaction will not result in a transfer of jobs outside of Texas, adversely affect customers’ and employees’ health and safety, or result in degraded service.
Administrative Law Judge Hunter Burkhalter directed the two remaining intervenors not party to the settlement — a local activist who once served on EPE’s board and a group consisting mostly of local school districts — to respond by Dec. 30 as to whether they want to proceed with a scheduled Jan. 7-8 hearing on the sale. He warned that if the hearing goes forward, the PUC will rule on the stipulation, not the original application. The PUC had rescheduled the hearing from November to January in order to allow intervenors time to reach a unanimous agreement. (See Parties Near Agreement on El Paso Electric Purchase.)
EPE, Sun Jupiter and IIF, which is advised by J.P. Morgan, announced their proposed $4.3 billion purchase of the utility in June. The sale must be approved by the PUC, FERC and other regulators before becoming final.
ReliabilityFirst said Monday that inaccurate facility ratings continue to undermine the safety and reliability of the bulk electric system.
The regional entity said transmission and generation owners must shore up internal controls during the planning process to ensure that a facility’s rating remains accurate post-construction.
Speaking during an open forum conference call, Jim Uhrin, RF’s director of compliance monitoring, said that gaps in program execution — identified by NERC as an area of focus in the 2019 and 2020 ERO Implementation Plans — leaves owners noncompliant with the FAC-008 standard for facility ratings.
Uhrin said a majority of outages between 2015 and 2018 were caused by failed AC circuit and substation equipment and protection systems, according to information gathered from NERC’s Transmission Availability Data System.
ReliabilityFirst outages by cause, TADS 2015-2018 | ReliabilityFirst
While Uhrin said the exact reason for this is unknown, other issues occur alongside this data point. Often, he said, changes to equipment — from breakers to wave traps to line conductors — during the planning and construction process of a facility may not make it into the database used to calculate system operating limits and create planning models.
“Things are being missed,” Uhrin said. “What we believe is happening … as things change in the field, there is not a … ‘post-as-built’ field verification.”
The impact, he said, is obvious: Inaccurate data will create a host of errors that could jeopardize the safe operation of facilities.
“Each and every one of those things need to be accounted for as far the facility goes when establishing a line rating,” he said. “These are critical to make sure that everybody has it right.”
In April, FERC approved a $40,000 fine against Duquesne Light Co. for inaccurate ratings of some substation conductors and a 138-kV circuit, violations of FAC-008-3 R6. (See FERC OKs NERC Violation Settlements.)
Cycle for facility planning and modeling. | ReliabilityFirst
The substation inaccuracy — caused by entering an incorrect input value into one of the rating equations — resulted in a reduction of the overall facility rating for three transformers.
The violation extended for more than two years because Duquesne “lacked an effective verification control” to quickly detect and correct the error, NERC said. The company alerted RF of the problem in a self-report in August 2017, after completing its mitigation plan.
NERC credited Duquesne for its cooperation in the investigation but said the company’s FAC-008/FAC-009 compliance history was an aggravating factor in determining the penalty.
RF said Monday it will consider making substation visits when necessary if internal controls are not sufficiently tightened.
“We strongly encourage you to do whatever you need to do those post-field verifications,” Uhrin said. “Focus on high-risk assets first that are more impactful for the grid, and work backwards from there.”
Customers of Entergy’s five utility subsidiaries have saved about $1.3 billion since they joined MISO in 2013, the company said Monday.
Entergy said the savings — earned between 2014 and 2018 — can be “largely” attributed to participation in “a large pool of generating facilities that stretch across the vast MISO footprint.”
“By sharing in that large pool, Entergy can maintain reliability with less power generation capacity than if it were on its own — and pass the resulting savings along to customers,” the company said in a statement, adding that its dispatch is also more efficient since joining the RTO.
Entergy broke down the five-year savings by subsidiary. Unsurprisingly, Entergy Louisiana — the largest division serving about 1.08 million customers — realized the greatest share at $561 million. Savings at the other utilities generally followed in order of customer base:
$223 million for Entergy Arkansas’ 711,000 customers;
$207 million for Entergy Mississippi’s 450,000 customers;
$198 million for Entergy Texas’ 454,000 customers; and
$118 million for Entergy New Orleans’ 202,000 customers.
“When we proposed joining MISO, we told our customers this would be a good business decision that would benefit them each month. We believe we have made good on that promise,” said Rod West, Entergy’s group president of utility operations. “Our membership in MISO has been a highly effective tool in helping our customers keep more of their hard-earned money in their pockets. It has also helped us control costs and keep our rates among the lowest in the nation. Since joining MISO five years ago, Entergy customers have saved an average of $261 million per year. These are real savings for our customers.”
Entergy integrated into MISO at the end of 2013 after coming under pressure from state regulators and a U.S. Department of Justice antitrust investigation examining the company’s “exclusionary conduct” in its service area. The department said Entergy would “resolve” the Antitrust Division’s concerns if it followed through on promises to join an RTO and divest its transmission system to ITC Holdings. The actions would eliminate “Entergy’s ability to maintain barriers to wholesale power markets,” DOJ said at the time.
Three years prior to DOJ’s integration, a FERC-commissioned study estimated that if Entergy’s operating companies and Cleco Power joined SPP, they could stand to save a net $1.3 billion from 2013 to 2022.
Entergy Louisiana crews work in November on new lines and a substation near the Jefferson and Plaquemines Parishes. The $100 million reliability project is slated for completion in mid-2020. | Entergy Louisiana
Entergy on Monday also noted that its residential rates are about 27% below the national average, according to 2018 data from the U.S. Energy Information Administration.
MISO Chief Customer Officer Todd Hillman said he was pleased the company and other members are “realizing the benefits of MISO membership.”
“Our vision to be the most reliable, value-creating RTO remains strong as we help our members pass on savings to their customers. MISO’s Value Proposition affirms our core belief that a collective, regionwide approach to grid planning and management delivers the greatest benefits,” Hillman said in a statement emailed to RTO Insider.
MISO has scheduled a Feb. 14 stakeholder presentation to discuss its 2019 Value Proposition, where it documents the savings it provides to all members. The RTO estimated it provided members between $3.2 billion and $3.9 billion in regional benefits in 2018. It doesn’t estimate savings to individual members.
Pacific Gas and Electric scored major wins Tuesday in its effort to emerge from Chapter 11 bankruptcy with its shareholders still in control of the utility.
In U.S. Bankruptcy Court in San Francisco, Judge Dennis Montali approved PG&E’s $13.5 billion settlement with wildfire victims, despite objections from Gov. Gavin Newsom and lawyers for a group of bondholders trying to seize control of the company.
Judge Dennis Montali | Commercial Law League of America
Montali also approved a controversial $11 billion settlement between PG&E and the subrogation claimants, a coalition of insurance companies and hedge funds that hold claims against the utility for insurance payments to businesses and homeowners.
And PG&E announced it had made a pact with the California Public Utilities Commission’s Safety and Enforcement Division over its role in starting wildfires in its service territory in 2017 and 2018, agreeing to not seek reimbursement from ratepayers for more than $1.6 billion in wildfire-related costs.
“If approved, this would be the largest dollar amount ever imposed by the commission in connection with alleged wildfire-related violations,” lawyers for the parties wrote in a joint motion to the CPUC.
Lawyers argued on Tuesday for six hours before Montali, who weighed the ramifications of the utility’s deal with fire victims and the governor’s harsh criticism of the restructuring support agreement between PG&E and the Tort Claimants Committee (TCC), which represents fire victims.
The judge noted that Newsom — in a court filing Monday and a letter to PG&E CEO Bill Johnson last week — had not objected to the $13.5 billion amount but had said the utility’s amended bankruptcy plan failed to meet the requirements of AB 1054, a law the governor championed last summer.
Newsom told Johnson that he wanted wholesale change in PG&E’s governance as well as provisions to let the state more quickly takeover the utility if needed. (See PG&E Chapter 11 Plan Won’t Do, Governor Tells Judge.)
Cecily Dumas, a lawyer representing the TCC, told Montali she believed the company’s reorganization plan could be amended to meet the requirements of AB 1054 and satisfy Newsom.
“Notwithstanding the fact that the governor is sending nastygrams to PG&E every few days, we have not lost hope that the debtor will be able to improve the plan so that it is AB 1054-compliant and can be confirmed,” Dumas said.
Montali said he wouldn’t overrule the decision by fire victims to back PG&E’s proposal. It was the same reasoning he used to admit the bondholders’ reorganization plan in early October. Fire victims initially backed the bondholder plan because it offered them $13.5 billion. When PG&E met that offer two weeks ago, the TCC switched its allegiance. (See Judge Admits Takeover Plan as PG&E Starts Blackouts.)
Dumas and other lawyers said they think PG&E’s plan has a better chance than the bondholders’ proposal to be quickly confirmed by the court and CPUC, allowing PG&E to exit bankruptcy by June 2020, as AB 1054 requires. If it can meet that deadline, the utility can participate in a $21 billion wildfire recovery fund established by the state.
Lawyers for wildfire victims also switched their stance on PG&E’s $11 billion settlement with the subrogation claimants. After initially opposing the settlement, the victims withdrew their opposition when PG&E agreed to up its offer to them.
Victims weren’t thrilled that their $13.5 billion settlement with PG&E will consist of cash and stock but agreed to accept it as the best deal they were likely to get from the utility. Under the agreement, a trust to pay fire victims will receive shares equal to about 20% of a reorganized PG&E.
“We see this as the most expedient path forward,” Dumas told the judge. “This is by no means a perfect solution.”
The agreement between PG&E and the CPUC was announced Tuesday afternoon as lawyers argued in bankruptcy court. It provides that the utility will spend $1.625 billion on transmission and distribution line inspections and repairs and other wildfire measures without seeking rate recovery.
It also requires PG&E shareholders to spend $50 million on system enhancements and community engagement.
“Today’s filing sets in motion the next steps,” which include review by an administrative law judge and the CPUC, the commission said in a news release.
PG&E declared bankruptcy in January after a series of catastrophic wildfires in 2017 and 2018 saddled it with potentially billions of dollars in liabilities. The blazes included the Camp Fire, the deadliest and most destructive in state history, which killed 86 people in and around the town of Paradise.
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.”
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.
