About 5,800 MW of offshore wind can be interconnected using AC cable connections to interconnection points along the southern New England coast without significant upgrades to the onshore transmission network, according to ISO-NE’s 2019 Economic Study Offshore Wind Transmission Interconnection Analysis.
ISO-NE Director of Transmission Services and Resource Qualification Al McBride presented the analysis, which noted that some local 345-kV reinforcement and/or expansion is still likely to be needed for this scenario, and that additional interconnections to these points would drive the need for significant network upgrades.
The New England States Committee on Electricity (NESCOE), Anbaric Development Partners and RENEW Northeast last year each requested separate studies from ISO-NE. (See “Modeling More Offshore Wind, Slowly,” ISO-NE Planning Advisory Committee: March 18, 2020.)
The 2019 Economic Study Offshore Wind Transmission Interconnection Analysis finds that HVDC alternatives can avoid major onshore transmission additions. | ISO-NE
Alternatively, additional offshore wind could be connected while avoiding significant onshore transmission upgrades by using HVDC connections from the offshore wind farms to load center substations, McBride said.
Anbaric has proposed the Southern New England Ocean Grid, an open-access, 1,200-MW HVDC network that would interconnect future offshore wind projects in the federal wind lease area off the coasts of Rhode Island and Massachusetts.
Such an undersea network interconnecting an expected surge in offshore wind projects would save New England developers and ratepayers more than $1 billion in onshore grid upgrades, The Brattle Group said in a study commissioned by Anbaric. (See Brattle Study Highlights Benefits of Offshore Grid.)
“There are also potentially hybrids, where you go part of the way with AC, part of the way with DC, or the other way around,” McBride said.
“Just to compare the alternatives, for what we call the AC alternative, you are continuing to add a lot of cable to the water,” he said.
The study also determined that 2,200 MW could be connected using HVDC without major onshore transmission upgrades, which, in addition to the 5,800 MW connected using AC cables, provides a total of 8,000 MW of connected offshore wind off the southern New England coast.
Offshore wind scenarios studied | ISO-NE
No Public Policy Tx Need
Director of Transmission Planning Brent Oberlin reviewed the steps ISO-NE took in the 2020 Public Policy Transmission Upgrade process that concluded there was no need to proceed with a Public Policy Transmission Study (PPTS) this year.
The RTO agreed with NESCOE’s position that none of the stakeholder submittals regarding public policy requirements identified a federal law that drives a transmission need and said it is not aware of any such requirements that drive the need for transmission.
Similarly, the RTO reviewed NESCOE’s submittal and found that the states have determined that there are currently no state or local requirements that drive transmission that should be studied in a PPTS.
FERC on Thursday approved ISO-NE’s Inventoried Energy Program (IEP) as a “reasonable” and “technology-neutral” short-term solution to compensating resources that provide fuel security during New England’s winters (ER19-1428).
The commission denied rehearing of its automatic acceptance of the IEP in August 2019. The four-member commission lacked a quorum on the matter at the time. Then-Commissioner Cheryl LaFleur had recused herself from all matters involving ISO-NE, later becoming a member of its Board of Directors after she left the commission. (See Lacking Quorum, FERC OKs ISO-NE Energy Security Plan.)
Thursday’s ruling affirms ISO-NE’s ability to implement the IEP for the capacity commitment periods covered by Forward Capacity Auctions 14 and 15, allowing it to compensate resources for maintaining inventoried energy during the winter months of 2023/24 and 2024/25.
The IEP is a voluntary program that consists of five components, including a two-settlement structure, a forward rate, a spot rate, trigger conditions and a maximum duration. Under the two-settlement structure, participants can choose to participate in either the forward and spot market components of the program or just the spot market.
“Participants that opt to participate in both components take on a financial obligation for inventoried energy during the program delivery period (December through February) at the forward rate in the first settlement period,” FERC explained. “Any deviations from inventoried energy maintained for each event trigger (an inventoried energy day) are settled in the second settlement period at the spot rate.”
ISO-NE proposed a fixed forward rate of $82.49/MWh for inventoried energy sold forward during the delivery period, an estimate of the minimum rate that a gas-only resource would require to sign a winter-peaking supply contract for LNG.
The RTO estimates the program will cost between $102 million and $148 million per year, depending on participation, resource performance and winter severity. It assumed that 1.2 million to 1.8 million MWh of inventoried energy, respectively, would be sold forward and maintained for each inventoried energy day per year.
Natural gas spot prices spiked during New England’s extended cold snap of 2017-2018. | EIA
The commission agreed with ISO-NE that a “misaligned incentives” problem in the current market design may cause fuel-secure resources to be insufficiently incented to invest in energy supply contracts, which may have adverse efficiency and reliability consequences.
Although IEP does not constitute a fully market-based solution, “the proposal is a step in the right direction … while ISO-NE finishes developing a long-term market solution,” the commission said.
Commissioner Richard Glick dissented in a separate statement, calling the IEP “an ill-conceived giveaway that acts as if throwing money at a problem is always just and reasonable.”
ISO-NE kicked off a two-year effort to address regional fuel security after its January 2018 Operational Fuel-Security Analysis (OFSA) showed that the loss of 1,700 MW from Exelon’s Mystic 8 and 9 gas-fired units would deplete 87 hours of 10-minute operating reserves and result in 24 hours of load shedding during the winters of 2022/23 and 2023/24. (See Report: Fuel Security Key Risk for New England Grid.)
The Energy Security Improvements filing by the RTO in April 2020 comprised long-term proposals prompted by FERC’s July 2018 finding that ISO-NE’s Tariff was not just and reasonable because the RTO lacked a way to address fuel security concerns. (See ISO-NE Sending 2 Energy Security Plans to FERC.)
Comments and Protests
Several commenters supported the IEP, with FirstLight Power Resources urging the commission to resist requests to amend the proposal because they would be an unhelpful distraction from the long-term market design efforts.
Calpine and Vistra Energy stated that the IEP’s forward component is the key to winter fuel security because it incentivizes market participants to take the necessary steps to achieve fuel security, including procuring an adequate amount of fuel and fully optimizing their existing fuel infrastructure.
Algonquin Gas Transmission supported the IEP but said that the long-term solution can only address New England’s fuel security challenges if it addresses the lack of firm natural gas transportation and storage in the region.
On the other side, the New England Power Pool stated that neither the IEP nor any other proposal had sufficient stakeholder support to win its endorsement. It said the commission “should not direct specific changes that were not already addressed in the stakeholder process without full stakeholder consideration of such changes through the commission-approved participant processes.” The Environmental Defense Fund meanwhile said the interim nature of the IEP does not permit deviation from the just-and-reasonable standard and that no provision under Federal Power Act Section 205 permits the commission to accept filings on an interim basis.
Several commenters also said ISO-NE had failed to demonstrate that the IEP will benefit customers. NRG Energy urged the commission to reject the program and provide guidance for a substitute interim fuel security proposal. The Massachusetts attorney general stated that the program lacks evidentiary support and will result in arbitrary and discriminatory rates. The Maine Public Utilities Commission argued that, without a determination of need, there is no ability to measure the program’s success.
The commission countered the complaints, saying that the IEP “will likely provide reliability benefits, such as incenting up to 1.8 million MWh of inventoried energy to be available during stressed winter conditions,” while also asserting authority under Section 205 to accept interim solutions proposed by applicants.
Rebutting the demonstrated need argument, the commission found “that a detailed cost-benefit analysis is not required for the commission to find proposed Tariff provisions just and reasonable.”
The commission disagreed with a joint protest by New England Consumer-Owned Systems and Energy New England that the IEP cannot be deemed just and reasonable because it is neither market- nor cost-based.
“By setting a fixed forward rate based on a winter-peaking supply contract for LNG, ISO-NE estimated the minimum value that would incent program participation from a natural gas-only resource, thereby approximating the price that would occur if inventoried energy was competitively procured through a market-based mechanism where a natural gas-only resource was the marginal resource that established the price paid to all resources providing the service,” the commission said.
FirstLight and NRG contended that the program does not correct for the suppression of FCA clearing prices that occurs when resources seeking retirement are held in the market for fuel security reasons and included in the FCA as price-takers, arguments the commission found were “outside the scope of this proceeding.”
The commission also disagreed with arguments that the existing fuel security cost-of-service Tariff provisions or Pay-for-Performance (PfP) negates the need for the IEP, or that its costs are duplicative to those of PfP, again citing the “misaligned incentives issue.”
“It is premature to judge whether the costs of the Inventoried Energy Program are duplicative to those of the long-term market solution because the long-term solution is pending before the commission and is not before us in this proceeding,” the commission said.
FERC said that establishing rates in advance increases the IEP’s effectiveness in deterring retirements by enabling participants to better forecast expected program revenues even if the forward rate is not fully precise. “Accordingly, we disagree with parties suggesting that the forward rate be updated closer to the time of delivery to capture prevailing market conditions,” the commission said. “We also decline to adopt the alternative proposals proposed.”
Rehearing and Program Revenues
On rehearing, several parties reiterated the same arguments made in their underlying protests, the commission said.
The New England States Committee on Electricity argued that the commission erred by failing to articulate a satisfactory explanation and otherwise engage in reasoned decision-making in accepting the IEP because it failed to respond meaningfully to the arguments before it, address substantial evidence in the record, or explain its departure from precedent.
“The commission acted consistent with the directives of FPA Section 205 given the lack of quorum in this proceeding at that time,” FERC said. “Now that the commission has a quorum, we have determined that, based on a review of the evidence in the record, the proposed Tariff revisions are just and reasonable.”
The commission agreed with ISO-NE and its Internal Market Monitor that net revenues from the program should be treated as revenue from an ancillary service in the calculation of an existing resource’s net going-forward costs. The revenues will also be reflected in the Forward Capacity Market’s delist bid mitigation.
“We acknowledge that there are many factors that influence a resource’s retirement decision and that IEP revenues will vary from resource to resource. And, as ISO-NE asserts, the program is not intended to deter the retirement of a specific resource,” the commission said. “However, we find that these revenues appropriately compensate resources that contribute to winter energy security. Moreover, we agree with ISO-NE that it is important that the program be in place in time for participants considering retirement decisions for FCA 14 and FCA 15.”
Dissent on ‘Fatal Flaws’
Commissioner Glick said that the willingness to spend customers’ money without evidence of a commensurate benefit will make stakeholders, including both states and customers, suspicious of actions by the commission and ISO-NE that purport to address fuel security, potentially undermining more serious efforts to actually address the issue.
“I am particularly troubled by the evidence in the record that the program will hand out tens of millions of dollars to nuclear, coal and hydropower generators without any indication that those payments will cause the slightest change in those generators’ behavior,” Glick said. “Handing out money for nothing is a windfall, not a just and reasonable rate. …
“Although the simplicity of ISO-NE’s proposal may, at first, seem appealing, the program contains a number of what should be fatal flaws,” he said.
FERC Commissioner Richard Glick tweeted about his dissent June 18.
Most importantly, Glick said, the RTO does not point to any evidence that there is a near-term operational problem that cannot be adequately addressed by its existing rules, or any evidence that the IEP would address such a problem by making the region more fuel secure.
“Creating a program to funnel money to uneconomic resources in order to prevent their retirement would seem to undermine a key element of the balancing act that the commission relied upon when it found the Capacity Auctions with Sponsored Policy Resources (CASPR) program just and reasonable,” Glick said.
The RTO’s willingness to propose a program that will “work at cross-purposes with the CASPR’s substitution auction raises serious questions about the durability of the CASPR construct,” he said. The proposal “does not possess even the basic principles of an effective market-based solution [and] evaluated against those principles, the [IEP] gets a failing grade.”
About 170 stakeholders turned out Thursday for ISO-NE’s teleconference review of the Phase One proposals in its Boston competitive transmission solicitation, overwhelming the Planning Advisory Committee’s phone line and forcing the RTO to open another connection with greater capacity.
The RTO on June 8 surprised many stakeholders — and elicited a swift legal challenge — when it announced that it had narrowed the 36 responses to its first competitive request for proposals under National Grid, Eversource Finalist for Boston Tx Plan.)
ISO-NE Vice President of System Planning Robert Ethier prefaced the review with a defense of the RTO’s evaluation process.
“While the results of this process may be different than some people had hoped or maybe even expected, arriving at the least-cost solution that requires no transmission siting and very little permitting is, to me, a clear success,” he said.
Director of Transmission Planning Brent Oberlin “and his team did not operate in a vacuum,” Ethier said. “ISO management was kept well informed of the progress as we went along, having regular meetings with Brent and his team and certainly vetting each of the significant decisions along the way.”
Questions on Results, Methods
Seeking to extend its Mystic Generating Station cost-of-service contract for an additional year, Exelon on June 10 filed a complaint with FERC accusing the RTO of violating its Tariff by shortcutting its transmission security review and prematurely culling bids received in response to the solicitation. (See Exelon Challenges ISO-NE RFP in Bid to Extend Mystic.)
During the PAC meeting, stakeholders also questioned why certain proposals were rejected.
“I guess I was a little surprised, looking through this presentation, at how many of the proposals were eliminated just because of the right-of-way provision, and not meeting the reactive capability requirement,” said Abigail Krich, president of Boreas Renewables. “Both of those struck me as things that should have been pretty clear in the process, and the project proponents should have known whether their projects met the requirements.
“Given how many were screened out because they didn’t meet those, it raised the question in my mind whether this was confusion on their part; maybe these requirements weren’t made as clear as they could have been,” she continued. “Do you think a number of proposals that were submitted … that even though they didn’t meet the criteria, that they might still be able to move forward?”
“I can’t speak to what others were doing, but while we did have a number of proposals that tripped up on things, there were also some that did not,” Oberlin said. “As far as the instructions, we talked about the need for a dynamic reactive device at the PAC meeting; we provided it in the report; it was pretty clear what needed to be done at the POI [point of interconnection]. I don’t know why people didn’t do that.”
Mystic Generating Station, on the Mystic River in Everett, Mass.
Among eight qualified transmission project sponsors that submitted bids for the RFP was Anbaric Development Partners, which made two submissions. The first was an AC project that would move 900 MW of electricity on two tri-core cables between the former Pilgrim station area in Plymouth, Mass., to the Mystic substation in Everett. The second was a proposal for a 1,200-MW HVDC cable bundle between the same two points.
The RTO disqualified Anbaric’s AC proposal for missing a required step-up transformer to accompany its static synchronous compensator (STATCOM).
“For the STATCOM, if the transformer is included in the proposal and not the model — and in my experience the majority of STATCOMs in the Eastern Interconnection are modeled without the transformer — it seems to me that this would be an easy question for a deficiency cure,” said Phil Tatro of EN Engineering, which worked with Anbaric on the proposal.
Tatro noted that the STATCOM was included in both the project’s one-line diagram and the switching station layout, both of which were a part of Anbaric’s publicly posted bid.
“This is a feasibility assessment at this stage, and even if you wanted a transformer modeled, it doesn’t seem necessary in a feasibility assessment,” Tatro said.
Oberlin replied that ISO-NE’s goal was to determine whether or not a proposal met the need identified and specified in the RFP’s addendum report.
The RTO found a number of proposals that included the necessary transformer or other equipment but nonetheless weren’t able to meet the requirement, he said.
“Additionally, we did look through the proposals, and there were a number of files that were supposed to be attached that describe all of the electrical equipment … and also we had a section on transformers, and the [transformer] wasn’t described there,” Oberlin said.
Technical and Legal Challenges
The RTO also disqualified proposals, including Anbaric’s, for planning to interconnect using the Mystic 8 terminal, saying that facility is engaged through May 31, 2024.
Regarding the use of the Mystic 8 terminal, Adam Hickman of transmission developer Transource New England suggested that the RTO might consider using a planned outage to accommodate a transmission solution.
“We do encourage the ISO to go back and look at those property and [transmission owner] facility use provisions,” said Theodore Paradise, Anbaric senior vice president for transmission strategy. “We do think that how the ISO came out conflicts with both section 2.05 of the TOA [Transmission Operating Agreement], which requires interconnection of facilities and in fact good-faith negotiations to be engaged in by any signatories to the TOA, but also Section 210 of the Federal Power Act.
“Twenty-two of 35 projects were disqualified on that basis, and it’s just hard to believe that, with all the successful, sophisticated bidders who have won projects across the country, so many got it wrong,” Paradise said. The $49 million proposal from the incumbents is “probably not the least expensive project for consumers when you look at things like avoided transmission upgrades, or impacts on the energy market. One of our projects is less than 30 cents/month on a retail bill for a project that does a lot to bring in zero-priced renewable energy and also to avoid over $600 million in additional system upgrades for state policies.”
Michael Macrae, energy analytics manager at Harvard University, referred to the “the absence of any sort of an environmental impact” being included in the RTO’s evaluation criteria. He quoted from a June 5 letter from Massachusetts’ two U.S. senators “that highlights this concern and raises the question about how the outcome here aligns with New England state goals.”
In their letter, Sens. Ed Markey and Elizabeth Warren, both Democrats, criticized the RTO’s planning process for listing “environmental impact” in the lowest priority category for the evaluation and noted that “public health impacts are not called out at all.” (See Mass. Senators to ISO-NE: Think Clean on Boston RFP.)
“As we laid out in the RFP itself that was issued in December 2019, we proposed a tiered approach to the evaluation of the proposals,” Oberlin said. “The environmental impacts would be considered as we got through evaluating each of the proposals; assuming that they had met the needs and were all cost competitive with each other, we were going to use that to separate the proposals.”
Several stakeholders asked about whether the RTO’s recommended project utilized a usually prohibited remedial action scheme — or special protection system (SPS).
Oberlin explained that the $49 million project did use an SPS as defined by the Northeast Power Coordinating Council, but that he expected that definition to change in the future. Asked whether any of the other reliability projects use such a scheme, he responded that they do not.
Steve Kerr of Exelon asked whether the proposed solution would meet the system needs and allow Exelon to retire Mystic if the New England Clean Energy Connect (NECEC) project designed to carry 1,200 MW of Canadian hydropower to Massachusetts is not built. ISO-NE counsel Kevin Flynn interrupted and directed Oberlin not to answer, saying the RTO “would not speculate.”
Paradise also noted that the ISO-NE final needs assessment from June 2019 shows additional needs without the NECEC line and said it was not speculation that the proposed solution does not meet the needs without that project moving forward. A public referendum on the NECEC project is planned in Maine in November.
ISO-NE requested that PAC members complete their review of the Phase One proposals report and send their comments to pacmatters@iso-ne.com by July 2. The RTO plans to post the final listing of qualifying Phase One proposals on or before July 17, Oberlin said.
MISO has four months to make two more filings to comply with Order 845, FERC ruled last week.
The commission’s order Thursday marks the second time MISO has been directed to refine its proposed compliance with Order 845, meant to increase the transparency and speed of generator interconnection processes. (See MISO Almost There on Order 845.)
This time, MISO must clear up language relating to surplus interconnection service and studies of projects’ technological advancements (ER19-1823-002, et al.).
FERC said MISO still hasn’t properly explained why it gave itself 60 days to decide whether to conduct additional studies when an interconnection customer seeks to include technological advancements in its project prior to an interconnection facilities study agreement. The commission prescribed 30 days to decide on new studies and told MISO in December to either justify the 60-day timeline or halve it.
In response, the RTO had proposed to “perform the required studies and communicate the results to the customer” within 30 days “after receipt of any additional data that MISO requires the interconnection customer to submit.” FERC’s latest ruling said that language could still allow MISO more than 30 days to decide whether a technological advancement to a project would constitute a material modification and warrant further study.
| National Renewable Energy Laboratory
FERC also said MISO interchangeably used the titles “Surplus Interconnection Service Agreement” and “Surplus Interconnection Service Interconnection Agreement” in monitoring and consent agreements, which the RTO drafts to list the roles and responsibilities of a transmission owner and an interconnection customer seeking to interconnect through surplus interconnection service.
“We find that the proposed revisions create a lack of clarity that may cause confusion to interconnection customers,” the commission said, suggesting that MISO might avoid confusion by swapping the two terms with “Surplus Interconnection Facility’s Generator Interconnection Agreement.”
But FERC did accept MISO’s fuller description of how it determines which projects in its annual Transmission Expansion Plan are “contingent facilities.” Order 845 defines those facilities as a generation project’s unbuilt interconnection facilities and network upgrades that, if delayed or canceled, “could cause a need for restudies of the interconnection request or a reassessment of the interconnection facilities and/or network upgrades and/or costs and timing.”
FERC said MISO’s description of the impact criteria it uses in its distribution factor analysis fit the bill.
No Rehearing
The commission also denied the American Wind Energy Association’s rehearing request that it direct MISO to remove “barriers” preventing interconnection customers from exercising the option to build network upgrades.
AWEA contested the compliance filing’s inclusion of Tariff language describing a TO’s right to self-fund network upgrades for interconnection customers. FERC last year ordered MISO to reinstate TOs’ rights to self-fund the network upgrades, and the RTO requested an independent entity variation in its compliance filing to note the change, which the commission accepted. (See MISO Gauging Aftershocks of TO Self-fund Order.)
AWEA argued that “interconnection customers have had very little success exercising the option to build since the commission issued Order No. 2003 and that the commission, in Order No. 845, intended to restore that right.”
But FERC agreed with MISO that “not harmonizing a transmission owner’s right to self-fund with the expanded option to build could impermissibly undermine a transmission owner’s right to self-fund.” It said the RTO had no choice but to reconcile Order 845’s expanded option to build for interconnection customers with the TOs’ right to elect to provide initial funding for standalone network upgrades.
ERCOT last week approved two suspension-of-operations requests from Austin Energy, saying both generating units are not required to support the system after it conducted a reliability analysis.
On June 16, the Texas grid operator gave the go-ahead to retire Decker Lake 1, a 49-year-old gas-fired steam unit with a capacity of 315 MW. The unit will be decommissioned and retired permanently as of Oct. 31.
The next day, ERCOT signed off on Austin Energy’s request to place the Nacogdoches Generating Facility into seasonal mothballs, with an operating period of May 15 to Oct. 15. The wood-fired East Texas plant is the country’s largest biomass plant at 105 MW.
The Nacogdoches Generating Facility during its construction | Southern Co.
Austin Energy has told ERCOT it intends to retire both steam turbines at its Decker Lake facility. Decker 2 will be retired following the 2021 summer peak. Both units are nearing the end of their normal life expectancies. (See “Austin Energy to Retire 735 MW of Gas Units,” ERCOT Briefs: Week of June 1, 2020.)
The municipal utility acquired Nacogdoches from Southern Power last year. It has a 20-year power purchase agreement for the plant’s energy that expires in 2032.
System Demand Nears Pre-COVID Levels
Staff said “it appears” the pandemic had less effect across all hours for the week beginning June 7. Weekly energy use is down by about 1%, and there have been no impacts on daily peak demand.
ERCOT’s peak demand is back to normal. | ERCOT
ERCOT came close to a monthly record on June 8-9 when demand approached 69.1 GW. The grid operator did set a monthly record in April with a peak demand of 55.2 GW.
The backcast analysis compares model results using actual weather versus actual hourly load. The model was last updated in January and does not reflect the pandemic’s effects.
The National Association of Regulatory Utility Commissioners and National Association of State Energy Officials have launched an initiative aimed at improving cybersecurity defenses in solar energy facilities.
The Cybersecurity Advisory Team for State Solar, which is also backed by the Department of Energy’s Solar Energy Technologies Office, will include experts on digital security, the electric grid and photovoltaic technologies. Leadership will be drawn from state-level policymakers and regulators — with additional expertise from the federal government and private sector — in order to create “model cybersecurity programs and actions for states to take in partnership with utilities and the solar industry.”
In a press release, NARUC and NASEO said “the rapid growth and importance of solar energy” to the bulk power system in recent years has introduced new weaknesses into the grid that must be addressed. New communication technologies have provided grid operators with considerable flexibility but also created more points of entry for malicious actors hoping to gain access to critical infrastructure.
“As energy systems become more integrated and cyber-connected, their vulnerability to malicious actions grows,” said Andrew McAllister, a member of the California Energy Commission and chairman of NASEO’s board of directors. “Solar technologies are no exception. New tools and a dedicated, multi-stakeholder approach should strengthen solar cybersecurity and, by doing so, enable states to make meaningful progress on climate and resilience goals.”
| FLS Solar
NARUC has a history of pushing state utility regulators to take seriously the cybersecurity implications of new grid technologies. The topic was a major theme of the organization’s 2019 Summer Policy Summit, where experts warned that the growth of distributed energy resources means utilities must protect many more generation facilities than they are used to. (See Experts Urge State DER Cybersecurity Standards.)
Such systems can be highly vulnerable to attack: One analyst described accessing a solar array and its microinverters through a webpage without having to enter any login credentials. Security factors are often overlooked because a lack of regulatory urgency on cybersecurity leaves it a low priority for utilities and equipment vendors.
NERC has also become increasingly concerned about the cybersecurity implications for rooftop solar panels and other DERs in recent years. At a meeting earlier this year of the System Planning Impacts from Distributed Energy Resources Working Group, Thomas Bialek, chief engineer for San Diego Gas & Electric, warned that not only does such equipment often contain security flaws overlooked by the vendors, but exploiting such openings may be easier for malicious actors because the systems are not protected by utilities’ existing cybersecurity measures. (See Rooftop PV’s ‘Hidden Loads’ Challenge Grid Planners.)
“We have our cybersecurity and our firewalls over our interfaces … but we don’t do that for any of the rooftop PV installations that are now using home Wi-Fi,’” Bialek said. He observed that more than 58% of rooftop solar installations in his utility’s territory are provided by just two vendors, which poses a significant risk because hackers can often use the same attack vector against multiple types of systems from a single manufacturer.
PJM members endorsed a proposal to open end-of-life (EOL) projects to competition Thursday, setting up a showdown with Transmission Owners at FERC.
The joint stakeholder proposal, which was sponsored by American Municipal Power (AMP), Old Dominion Electric Cooperative (ODEC) and others, cleared the two-thirds threshold with a sector-weighted vote of 3.45 (69%) to win the Members Committee’s endorsement. The measure had fallen short with a 3.23 (65%) vote at the May 28 Markets and Reliability Committee meeting. (See PJM End-of-life Proposals Fail at MRC.)
In the interim, the Transmission Owners Agreement-Administrative Committee (TOA-AC) on June 12 filed Attachment M-3 amendments with FERC, laying out their own EOL proposal, which aligned with the position of PJM staff (ER20-2046). (See TOs Vote to File End-of-life Rules with FERC.) [Late Thursday, ODEC and AMP Transmission filed a motion seeking to have the TOs’ filing dismissed on procedural grounds. The companies said the TOs issued the 30-day notice of their filing without a formal vote of the TOA-AC, violating the Consolidated Transmission Owner Agreement and AMPT and ODEC’s rights as PJM Transmission Owners.]
PJM General Counsel Chris O’Hara said after Thursday’s vote that the RTO will file the stakeholders’ proposal with FERC within two weeks, even though it believes it violates its governing documents.
“This is obviously a difficult spot for PJM,” he said, citing the “tension between PJM’s obligation to … comply with all of its governing documents [and its] obligation to accomplish the will of the members.
“We understand there’s a pending TO [Section] 205 proposal at FERC, so we will act with reasonable diligence to accomplish this filing,” O’Hara added.
On Thursday, the joint stakeholders’ proposal won support from 100% of End-Use Customers, 97% of the Electric Distributors, 83% of Generation Owners and 51% of Other Suppliers. It was opposed by all but two of the 14 Transmission Owners. The difference maker was a shift by Other Suppliers, who only gave the proposal 41% support at the May 28 MRC meeting, and Generation owners, whose support increased by 12 percentage points.
Under the stakeholders’ proposal, TOs would be required to notify PJM and stakeholders of any facility nearing the end of its life at least six years before its retirement date so that the project could be included in five-year planning models and potentially opened to competitive bidding. It would also modify the supplemental project definition to exclude EOL projects, which would become a new category of regionally planned projects.
The MC vote was one of two victories for advocates of transmission competition in PJM Thursday as FERC ruled that the RTO has failed to comply with its conditions for the “immediate need” exemption under Order 1000. The commission said PJM must increase the transparency of its practices. (See related story, More Transparency Ordered on PJM `Immediate Need’ Tx.)
The Proposal
Mark Ringhausen of ODEC gave a presentation on the joint stakeholder proposal, saying the goal is to improve transparency and incorporate the EOL determination process into the Regional Transmission Expansion Process (RTEP).
Ringhausen said he wanted to clarify some misconceptions about the proposal, explaining that the language allows TOs that don’t want to utilize the EOL process to continue to use maintenance activities for their transmission facilities. The new rules would only impact TOs declaring an entire line or facility as having reached its EOL, he said.
“It’s very clear in the CTOA that maintenance activities are 100% under the purview of the transmission owners,” Ringhausen said.
The stakeholder proposal should also lead to fewer supplemental projects from the TOs, he said. PJM has reported that TOs’ supplemental projects totaled almost $3.4 billion in 2019, more than double the less than $1.5 billion in regionally planned baseline projects. It was the fifth year out of the last six in which supplemental projects exceeded baseline projects. (See Stakeholders Urge PJM: Plan ‘Grid of the Future’.)
“It just gives PJM the ability to plan a better transmission system to allow market participants to use going forward,” Ringhausen said.
Sharon Segner of LS Power offered a series of friendly amendments to the OA changes. Segner said the amendments were a result of conversations with PJM staff and other stakeholders to clarify definitions and other language in the proposal.
Segner said PJM staff made it clear they were not endorsing the changes when discussions took place but simply wanted to provide legal comments on what was being proposed and help edit draft language.
Some of the changes included making sure the TOs, not PJM, are responsible for the EOL look ahead program, Segner said.
“I think it’s fair to say there continues to be policy differences with PJM, but it’s certainly been a good faith effort on everyone’s part,” she said.
Dave Souder, PJM senior director of system planning, presented the RTO’s response, including a May 27 letter from the Board of Directors, detailing PJM’s concerns with the stakeholder package.
Souder said the stakeholder proposal introduces a “dichotomy” by requiring a final EOL determination six years in advance when final EOL determinations typically occur at the one- to three-year time frame. Forcing a final binding six-year EOL determination may result in premature retirement of transmission facilities, he said.
Supporters
Cynthia Holland, director of federal and regional policy for the New Jersey Board of Public Utilities (NJBPU), said the joint stakeholder proposal provides a path to transparency in the planning process.
“We appreciate the efforts of the stakeholders who have put forward this proposal,” she said. “We do think it has merit.”
Susan Bruce of the PJM Industrial Customer Coalition (ICC), which co-sponsored the joint proposal, said that consumers have been living with “unprecedented transmission costs” for years and that her members experience difficulties budgeting for the rising costs of transmission each year.
She said many ICC members are pursuing clean energy, and generation interconnection is a key issue for them.
“It’s important for this issue to be before [FERC] for us to make progress,” Bruce said.
Disagreements
Robert Taylor of Exelon said the stakeholder proposal is “substantively and legally flawed.”
Alex Stern, director of RTO strategy for PSEG Services Corp., went even further in his critique of the proposal, saying the result of Thursday’s vote calls into question the entire stakeholder process. He said the TOs spent six months trying to work with other stakeholders only to find “divide and a disconnect” in the stakeholder process.
He said the OA changes will hinder, not facilitate, “the grid of the future.”
The proposal would confront needed transmission projects with “unnecessary roadblocks while some gamblers in the crowd hope there’s uncertainty that brings competitive opportunities,” Stern said.
PJM has failed to comply with FERC’s conditions for exempting “immediate need” transmission projects from competition under Order 1000 and must increase the transparency of its practices, the commission ruled Thursday (EL19-91).
Separately, the commission terminated Section 206 investigations into ISO-NE (EL19-90) and SPP (EL19-92), concluding they were in compliance with the exemption rules.
FERC opened investigations into the three RTOs’ practices in October 2018, questioning whether they were thwarting Order 1000’s competition mandate by abusing the immediate need exemption. (See FERC to Probe Order 1000 Competition Exemptions.)
Order 1000 required RTOs to eliminate any federal right of first refusal (ROFR) from commission-jurisdictional tariffs and agreements but allowed a ROFR for reliability projects whose needs are so urgent that there is insufficient time to hold a competitive proposal window.
Five Criteria
Saying the exemption should be used only in “certain limited circumstances,” the commission set five criteria to limit the RTOs’ discretion for applying it.
In Thursday’s order, FERC concluded PJM was complying with only two of the criteria, ordering it to make Operating Agreement changes regarding the other three within 60 days.
The commission said PJM complied with the first criterion that projects exempted from competition must be needed in three years or less to solve reliability criteria violations. PJM also complied with a requirement to post annually a list of immediate need reliability projects to be built by incumbent transmission owners.
But FERC said it agreed with stakeholders’ comments that PJM’s explanations “do not provide sufficient detail” of the reliability violations and system conditions for which there are time-sensitive needs. “Similarly, we find that PJM generally fails to include any discussion about system conditions related to the reliability violations in its TEAC [Transmission Expansion Advisory Committee] presentation materials. For example, we find one-line labels (e.g., ‘short circuit,’ ‘end-of-life,’ ‘overstressed’) identifying the reliability violation driving the immediate need reliability project insufficient to comply.”
FERC said it was not requiring “an exhaustive description” but said PJM “may provide details regarding the specifics of the violation; why the violation arose; when it first occurred; the implications of the violation in terms of generation, load, congestion, etc.; the severity of the problem; and expectations for the violation’s severity in the future (i.e., will the problem get worse or have a cascading effect at a later point in time).”
The commission also cited PJM for failing to post a “full and supported written description” on any decision to award a project to an incumbent transmission owner, including an explanation of other transmission or non-transmission options that the RTO considered and the cause of the need and why it was not identified earlier.
‘Little Insight’
“The TEAC presentation materials provide little insight as to PJM’s reasoning,” the commission said. ” … In addition, we find that PJM does not provide in its presentation materials an explanation for its determination that there was insufficient time to open a full or shortened proposal window.”
Going forward, FERC said, PJM must “expound on its description to support the designation of its immediate need reliability projects, specifically addressing the time-sensitive nature of the need, why the incumbent transmission owner was selected, alternatives considered and why the need was not identified earlier. … PJM could also explain the urgency of the violation and compare it to the typical timeline of a standard or shortened competitive proposal window, explaining how the proposal window would delay the solution further.”
Although its prior order did not specify how much time PJM should allow stakeholders to comment on project descriptions, FERC said the RTO’s practice of posting materials three days before meetings at which the projects are to be discussed “is not sufficient.” It noted that the RTO gives stakeholders 10 days to review materials for supplemental transmission projects under its Attachment M-3 process.
“As a result, we direct PJM to submit a compliance filing to designate a specific time period greater than three days for stakeholders to provide comments in response to the project description,” it said.
PJM also failed to provide transparency in addressing stakeholder questions about immediate need projects, FERC said, ordering the RTO to post on its website all stakeholder comments and PJM answers, “whether provided in writing or submitted verbally at TEAC meetings.”
The commission also said PJM must make it easier for stakeholders to locate information on immediate need projects, noting that the RTO has put such information in more than 60 locations on its website. “While we do not find that PJM must post all immediate need reliability project information to a single webpage to meet the transparency requirements … we direct PJM to post all information regarding immediate need reliability projects in a manner that is more easily accessible to stakeholders than the current approach.”
‘Reasonable Balance’
The commission rejected other requested relief, including LS Power’s request to eliminate the immediate need exemption and the New Jersey Board of Public Utilities’ request that the commission hold a technical conference to determine whether it should continue to allow other exemptions from competition such as those for lower voltage projects and substation equipment.
The commission noted PJM’s statement that it is working to reduce the use of immediate need designations by improving the efficacy of its five-year model. PJM said improved modeling and testing has already begun to reduce the use of immediate need designations. In 2019, PJM said that it reported only eight immediate need reliability projects — totaling 11 baseline upgrades.
FERC also declined a request to shorten the three-year time threshold for immediate need projects, saying it “continues to strike a reasonable balance” between reliability and competition.
In addition, it rejected LS Power’s request to exclude “end-of-life” projects from the immediate need category. LS Power said EOL projects represent a large portion of immediate need designations.
The commission also refused LS Power’s request to require transmission owners to provide PJM with information on EOL projects seven years in advance and American Municipal Power’s call for more frequent and timely submission of information by TOs on load changes to aid system modeling.
“We make this determination because such a requirement is outside the scope of the proceeding. We expect that, as PJM has committed to do, PJM will continue to improve its processes, to both timely receive the relevant system information from transmission owners and timely incorporate this information into its planning models, to potentially reduce reliance on the immediate need reliability project exemption,” FERC said. (See related story, PJM Stakeholders Pass End-of-Life Proposal.)
SPP, ISO-NE Cleared
FERC terminated the Section 206 investigations into SPP and ISO-NE, saying they had not produced evidence that the RTOs were implementing the exemption “in a manner that is inconsistent with or more expansive than the commission directed.” It noted that no stakeholders had accused either RTO of violating their tariffs.
SPP said that it had designated only five transmission projects as “short-term reliability projects” out of 144 projects identified in its Integrated Transmission Planning studies since study year 2016.
The Public Utilities Regulatory Authority had argued that ISO-NE’s need-by dates are artificially early because the RTO performs its needs assessments under assumptions more conservative than those used by day-to-day operations. But FERC said ISO-NE had “sufficiently justified” its approach. The RTO explained that its operators do not have to respect certain contingencies if they don’t have impacts outside of the local area where they occur. It also said the operators have access to a wider range of equipment ratings and system operating conditions than are allowed in transmission planning.
Several New England state agencies, including the attorneys general for Massachusetts and Connecticut and the Maine Public Advocate, said FERC should find ISO-NE’s exemption unjust and unreasonable because the region was the only RTO that had not completed a competitive transmission procurement. “Although ISO-NE’s lack of a competitive solicitation was one reason the commission instituted this proceeding, this outcome is not a sufficient reason to find the relevant Tariff provisions unjust and unreasonable,” FERC said. (On June 8, the RTO announced that it would recommend a project by incumbent utilities National Grid and Eversource Energy as the lone finalist in its first competitive solicitation.)
The commission also rejected arguments regarding the efficiency of New England’s transmission spending, its accommodation of non-transmission solutions and its “reactive” planning process as beyond the scope of the proceeding.
MISO members say that work-from-home measures and social distancing mandates in workplaces aren’t generally impeding their pace of work, but they do miss the personal collaboration afforded by in-person meetings.
The RTO asked Advisory Committee members to discuss how the novel coronavirus has impacted their company operations during a June 17 teleconference.
“COVID has impacted every industry, every business around the world,” MISO Vice President of Strategy and Business Development Wayne Schug said in opening the discussion.
He asked stakeholders “what a path to normality” looks like for their companies, or if they could even return to complete normalcy.
“Once the stay-at-home orders were in effect, many of us found ourselves at home, probably taking way too many virtual meetings,” Schug said.
According to a MISO survey, only about 14% of member companies had had more than 25% of their workforce working remotely before the pandemic hit. Now, most MISO member companies have more than a quarter of their employees reporting from home.
“In large part, our projects are on schedule. There have been some delays to accommodate this new work environment,” Otter Tail Power’s Stacie Hebert said, referring to rescheduled public meetings and temporarily closed courthouses.
DTE Energy is returning employees to the field to resume maintenance work, the company’s Manager of Wholesale Power Markets Nick Griffin reported.
North Dakota Commissioner Julie Fedorchak said it was at first difficult to maintain the pace of the commission’s work remotely while still honoring open meeting requirements. However, state commissions now largely have the remote format down pat.
“I think commissions got to the point where they could do just about anything,” Fedorchak said, adding that her commission had already been laying the groundwork for more virtual meetings prior to the pandemic.
She said the commission was able to honor all biweekly regular meetings, as well as permitting and routing meetings, while many employees worked from home. She also said about 75% of commission staff have returned on-site.
When MISO Director Todd Raba asked what member companies do when employees come down with a COVID-19 infection, multiple members said their companies have yet to confront that situation. Griffin noted that cases among DTE Energy’s 11,000 employees jumped from about 50 to about 200 “after an isolated incident at one of our power plants.”
Audrey Penner said her fellow Manitoba Hydro employees would return to offices “not earlier than the end of the summer.”
Director Barbara Krumsiek asked how member companies are preparing for a possible second wave of infections in the fall.
Many companies are targeting a return to work at year’s end or spring of 2021, Griffin responded.
“I would expect more telecommuting practices even after the pandemic,” he said.
Missing Meetings
Schug asked how MISO members are faring under an entirely virtual stakeholder process.
LS Power’s Pat Hayes said an online stakeholder process has been working “rather well,” though connectivity during meetings sometimes lags. “Of course, you’re hearing some dogs bark and some family conversations in the background.”
Hayes also lamented an inability to directly interact with people at meetings and make personal connections. He wasn’t alone.
“It’s about getting to know people in the process. But it’s also about when you have a differing opinion, maybe meeting in the hallway to have a follow-up, asking clarifying questions, having a meeting of the minds,” Beth Soholt of Clean Grid Alliance added.
“It’s impossible to read body language,” said CMTC’s Kevin Murray about virtual meetings.
“A lot of the work that we do is based on in-person interaction,” noted Travis Stewart of Gabel Associates, who requested that MISO find a way to facilitate more spontaneous conversations.
“I dearly miss sitting around a table and the congeniality,” Penner said of quarterly MISO Board Weeks. “I’m looking forward to getting back into a room together.”
MISO has halted all in-person stakeholder meetings at its offices through the end of the year. Offsite meetings — such as Board Week — have also largely been converted to a virtual format, though RTO executives hold out hope that the December Board Week in Orlando may yet be spared. MISO has also begun allowing employees back on-site on a voluntary basis at its three office locations.
MISO also plans to hold virtual Nominating Committee meetings through November, where new MISO board candidates are vetted and selected for member voting.
Directors Theresa Wise and Baljit Dail will reach their term limits at the end of the year. Wise is eligible to serve another three-year term, while Dail has already exceeded his total three-term limit through a special waiver in 2017, which was granted to retain his IT expertise. (See “Committee Permits Consideration of Extra Term for Dail,” MISO BoD Briefs: June 22, 2017.)
“We miss seeing you in the auditorium. We’re doing this virtually, but we’d much rather do it in person. As soon as it’s safe to do so, we’re going to resume these,” Board Chair Phyllis Currie said during the June 18 board meeting.
Difficult Times
Schug asked how companies are considering stressed-out ratepayers under the pressure-cooker combination of the pandemic’s economic fallout and social and racial justice protests in every state.
“There’s a lot of pressure on customers right now … manifesting in a lot of ways,” Public Consumer Advocates Sector Representative Christina Baker said. “… The economic effect is going to be around for years to come.”
She said “all customers — not 1% of customers” are experiencing stressors related to the pandemic and the push for societal change.
“For the customers it’s a much broader, longer, multilayered time for them,” Baker said.
Krumsiek agreed: “For the end-use customer, there’s no return to normal. Our vulnerable populations for COVID run along the same lines as those affected by racial injustice.”
Schug asked if MISO members anticipate a slowdown in the political push for renewables and carbon reductions given the political and social turmoil.
“I don’t anticipate a reduction in demand for renewable energy because of the pandemic. I really don’t,” Fedorchak said.
Soholt also expects carbon reduction goals to continue as planned.
“I think our sector expects to see some of these issues percolate up in integrated resource plans,” she said, adding that a renewable buildout could put some people back to work.
In the MISO footprint, load dipped by about 11% during the country’s strongest lockdown measures. Now, Schug said load is currently trending about 5% below weather-adjusted norms.
Murray said his clients are experiencing different load recoveries. For instance, he said steel companies, automobile manufacturing and oil and gas production have been significantly dragged down. Other manufacturers are less affected.
Further waivers of MISO Tariff requirements might still be necessary, Griffin said. MISO has so far put together a waiver of load modifying resource registration deadlines for the capacity auction and a 60-day grace period on the June 25 deadline to demonstrate exclusive land use for some generation projects in the interconnection queue. (See MISO Drafts COVID-19 Waiver for LMRs.)
MISO made a rare foray into addressing political and social events Thursday when its CEO and board members condemned systemic racism and vowed to listen to minority employees in order to effect organizational change.
Board Chair Phyllis Currie said directors and executives had engaged in “considerable discussion” in a closed session about the “long-term disparate treatment of African Americans by the police and in the workforce.”
“These issues impact our employees, so in turn, they impact MISO,” Currie said during the virtual board meeting.
“Obviously, racism and prejudice still exist, and we need to eradicate them in all their forms,” Director Baljit Dail said.
“Obviously, we’ve all been shocked into realizing there’s so much more to do,” added Director Barbara Krumsiek. She said the board will be more open to adopting actions to assist MISO employees and go further in promoting diversity.
The board’s comments come about three weeks after Minneapolis resident George Floyd was killed while in police custody, galvanizing racial justice protests that have reverberated around the world.
During the meeting, Director Mark Johnson reflected on a recent blog post his daughter wrote on experiencing racism.
“Being an African American parent, you try to insulate them from the racism. But it’s unavoidable that anything you try to do, they will experience it,” Johnson said.
“It’s a community in pain right now,” CEO John Bear said of African Americans. Bear said MISO has recently instituted all-hands meetings discussing systemic racism and historical inequalities. He also said the RTO’s leaders plan to embark on “listening tours” inside the company.
Bear also lauded the U.S. Supreme Court’s recent decision granting protected class status to gay and transgender employees.
“I am proud of the diversity on our board and in our senior leadership. … But I think we can take that much further,” Bear said.
“This is not a flash; this is something we will press on,” he promised.
