The Energy Bar Association’s Canadian Chapter held its first annual meeting online Thursday, with discussions on cybersecurity and holding virtual adjudication hearings amid the COVID-19 pandemic.
The chapter, formed a year ago, was originally going to hold the meeting in D.C. in April, at the same time as the EBA Annual Meeting, but it was forced to reschedule it in an online format because of the pandemic. (See EBA Holds Annual Meeting Online Successfully.)
Here’s some of what we heard.
Challenges of Cybersecurity on the Distribution Side
David Morton, chair of the British Columbia Utilities Commission, opened the conference with an anecdote about visiting the U.S. Department of Energy for a briefing on cybersecurity earlier this year (before the pandemic hit).
There were two briefings that day: one for those with top secret security clearance and those without. Morton attended the latter, “but I’m not sure it would have made any difference,” he said.
“I couldn’t even tell anybody about it anyway. … I had to sign and swear I wouldn’t share [the information he received] with anybody when I brought it back to my commission,” Morton said. “So, what am I supposed to do with that information? How can I even apply it to any of the work that I do?”
Clockwise from top left: Mary Anne Aldred, Ontario Energy Board; BCUC Chair David Morton; EBA Canadian Chapter President Gordon Kaiser; and Louis Legault, Régie de l’énergie du Québec. | EBA
Morton also pointed out that NERC’s mandatory reliability standards only cover the generation and transmission side of the electric industry, leaving the distribution side vulnerable. “If you took out the distribution system in Greater Vancouver, that’s just as bad as taking out the transmission system, at least to the 2.5 million residents in Vancouver,” he said.
“I do think it would be appropriate to raise the bar somewhat on standards,” said Alex Foord, chief information officer for Ontario’s Independent Electricity System Operator. “The larger entities … are going to come along and do the right thing. The challenge is when you get into smaller [utilities] … they don’t have the expertise, the sophistication and the time to do it. But candidly, that’s no excuse for the lack of action; they owe it to their consumers to do better.”
Cintron Shares Experiences with Virtual Hearings
FERC Chief Administrative Law Judge Carmen Cintron gave attendees a candid behind-the-scenes look into how she transitioned the commission’s Office of Administrative Law Judges from in-person to virtual hearings after the pandemic hit.
The pandemic “caught me, to use an American expression, with my pants down. We had modeled for the whole United States being under a nuclear attack; we had modeled for hurricanes; we had modeled for everything, except a pandemic,” she said.
FERC Chief ALJ Carmen Cintron | EBA
The office was immediately able to transition to virtual settlement conferences, which aren’t as complicated as hearings, Cintron said. Its settlement success rate has actually risen to 92%, from its usual 89%. “We attribute this to the fact that the business entities, the decision-makers, can actually participate without having to travel” to D.C.
Meanwhile, Cintron postponed imminent hearings until the office’s IT department set up Cisco’s Webex platform and the ALJs trained in using it and practiced by simulating hearings. The first virtual hearing began May 6 and lasted 16 days. One of the parties filed a motion to halt the proceeding, arguing that its virtual nature was a violation of due process, but it was denied by Cintron.
Though she said the process has been an overall success — with even the party that filed the due process motion responding favorably after their hearing was over — Cintron said it has not been without challenges, mostly owing to technical problems. It was immediately clear from her opening remarks that she is not a fan of Webex, and later in the discussion, she said she wants to migrate to Microsoft Teams. The different parties’ varying degrees of computer proficiency and internet bandwidth were early frustrations. ALJs also needed to obtain up to three separate computer monitors in order to conduct hearings in their homes.
Cintron said she anticipates the online-only format to continue into next year. Even once the crisis ends, she expects hearings to be a mixture of in-person and virtual.
ERCOT staff told stakeholders last week they are working to reduce errors following two recent unrelated events that led to price corrections and resettlements.
Kenan Ögelman, ERCOT’s vice president of commercial operations, shared with the Technical Advisory Committee the speaking points he will deliver to the Board of Directors during its Oct. 12 meeting. He said the grid operator has several initiatives that will cut down on errors and price corrections and will also elevate testing, “which is kind of our last line of defense.”
“We’re making additional revisions and [instituting] controls around market changes that impact pricing,” Ögelman said during the TAC’s meeting Wednesday. “We’re reviewing all of our manual processes … especially around resettlement items.”
Ögelman said several revision requests are being drafted to address the problem. ERCOT is also evaluating protocol language to address recent discussions the Public Utility Commission has had in open meetings. While discussing a telemetry error that led to a price correction Sept. 14, PUC Chair DeAnn Walker said, “We shouldn’t wait for there to be a really huge event.” (See Texas PUC Rejects Call to Reprice Error.)
In February, staff updated the network model by adding dynamic ratings for three transmission transformers. A software error erroneously applied the new ratings to three unrelated 345/138-kV transformers in addition to the intended transformers. ERCOT didn’t discover the cause of the error and the affected transformers until July, when it issued a market notice.
Staff reviewed all binding transmission constraints in the day-ahead market between Feb. 14 and July 7, finding 67 operating days that had at least one constraint binding on one of the transformers. They also found one instance of binding transmission in the real-time market.
Staff will ask the ERCOT board to review day-ahead and real-time prices for the June and July operating days that are eligible for repricing, as required by the grid operator’s protocols. David Maggio, ERCOT’s director of market design and analytics, said the pricing changes were “fairly minimal,” but balancing account changes resulted in an overpayment to load of about $8,000 for June and an underpayment to load of approximately $15,000 for July.
The real-time constraint resulted in a net settlement to counterparties of almost $47,000.
More recently, a manual update to the network model inadvertently disabled a remedial action scheme for four day-ahead market operating days in August. Staff were able to correct the prices before they became final during the last day and will ask the board to review the other three operating days.
Members Reject Ancillary Service NPRR
Members rejected a Nodal Protocol revision request (NPRR1025) that would remove the real-time online reliability deployment price (RDP) from ancillary service imbalance calculations. The measure was approved by an 18-10 margin, with two abstentions, but its 64% approval fell short of the two-thirds threshold for endorsement.
ERCOT’s Independent Market Monitor reiterated its opposition to the NPRR as written, citing what it said were two flaws.
“The first, and most important, is that it breaks a foundational principle in the market, that dispatch sent out by ERCOT should be the most profitable dispatch, given their offers and limitations. With this NPRR, in times of high ERS [emergency response service], that won’t be true anymore,” the IMM’s Steve Reedy said.
“Secondly, the [operating reserve demand curve] adder calculation is not affected by the ERS deployment,” he said. “That weight is carrying right now by the RDP adder. If you take that away from resources … that should raise the ORDC adder. We would support this with those associated indifference payments, which would be smaller than the megawatt implications in effect right now.”
The NPRR was drafted by the Lower Colorado River Authority. John Dumas, the public utility’s vice president of market operations, said it was driven by the divergence between the value of real-time reserves and day-ahead ancillary service prices during ERCOT’s 2019 energy emergency alerts, caused by including the RDP in the price of real-time reserves.
“LCRA believes that only the ORDC adder should be included in the price of real-time reserves,” Dumas said. “This removes what we believe is an undue risk to loads and generators for participating in the day-ahead ancillary service market. It removes the real-time deployment price adder and removes risk and cost.”
2% Solution: Monitor to Draft NPRR
Based on discussions with TAC leadership and the IMM, the Monitor will draft an NPRR to address a desk procedure left over from ERCOT’s zonal market, Ögelman said.
Several stakeholders had suggested such action when staff brought forward a discussion of the “2% rule” to the August TAC meeting. An artifact from the zonal market, which was replaced by the nodal market in 2011, the rule says generating units with shift factors of less than 2% should not be dispatched by the real-time market in response to transmission overloads. (See ERCOT Technical Advisory Committee Briefs: Aug. 26, 2020.)
The IMM in August said it believes the 2% rule should be eliminated and all congestion priced in real time, regardless of generation’s effect. “Prices matter,” IMM Director Carrie Bivens said during the discussion.
“I presume [the Monitor will] be putting the [shift-factor] percentage at zero, and we’ll see how that progresses,” Ögelman said. “Stakeholders can modify that as they see fit.”
He said ERCOT will take a position on the issue when comments are filed.
Under the rule, if a transmission constraint exists for which there are no generator shift factors of at least 2%, ERCOT operators must verify that a mitigation plan or temporary outage action plan exists for the contingency, and they are to review the plans with the affected transmission owner. If no plans exist, then the operators are to develop a mitigation plan with ERCOT’s operations support engineer. If no plans have been developed within 30 minutes, the operations desk issues a transmission watch, a step down from an emergency.
TAC Adds 10 Change Requests to List
TAC Chair Bob Helton complimented the committee for its virtual work this year, noting that it has passed 79 revision requests, with 65 more in the pipeline, while working from home.
“That says a lot about how we’ve progressed in troubled times,” Helton said.
The committee then passed a combination ballot, with an abstention, that added 10 more RRs to the approval list.
In a separate vote, the TAC approved the annual update to the major transmission elements list. Four members abstained from the vote.
One of the endorsed changes, a revision to the Planning Guide, will likely be appealed during the October board meeting. The change (PGRR077) clarifies that ERCOT’s transmission planning analysis will assume DC tie flows are curtailed when necessary to meet reliability criteria.
Shams Siddiqi, with Rainbow Energy Marketing, said the current $23/MWh transmission charge for DC tie exports during summer off-peak hours is a significant barrier to exporting energy. It also suppresses the market’s opportunity to address the allocation of sunk costs, adversely affecting decisions to consume or export, he said. Only the Public Utility Commission can modify the DC tie export’s Tariff, he said.
“Until and unless the PUC eliminates or significantly reduces the DC tie export tariff, the only equitable treatment of DC tie load is to treat DC tie load as other load in the ERCOT reliability transmission planning process,” Siddiqi said in filed comments. “If the PUCT were to eliminate the DC tie export tariff … [it] would remove an inefficient barrier to trade.”
Staff told Siddiqi he could appeal the revision request when it comes before the board next month. Helton noted that at least one PUC commissioner will call in to the meeting.
“If parties or stakeholders want to do it, they can file a petition for a rulemaking at the PUC,” said Katie Coleman, who represents Texas Industrial Energy Consumers. “The issue of transmission allocations is a really old issue that’s come up multiple times. I think the PUC is aware of these issues and can address them, if [it] wants to.”
The combo ballot included six other NPRRs, two changes to the Nodal Operating Guide (NOG) and a system change request (SCR):
NPRR999: Revises protocol language on DC tie schedules and creates a section related to ramp limitations on DC ties. It is intended to clarify that when ERCOT determines system conditions show insufficient ramp capability to meet the sum of all DC ties’ scheduled ramp, it will curtail schedules on a last-in, first-out basis. Before curtailing DC tie schedules, ERCOT, with enough time, may request one or more qualified scheduling entities to voluntarily resubmit e-tags with an adjusted ramp duration.
NPRR1033: Specifies that ERCOT does not have an obligation to pay interest on former market participants’ cash collateral balances upon its determination that financial security is no longer needed to cover the terminated participant’s potential future obligations.
NPRR1035: Requires ERCOT to publish all DC tie schedules 60 days after the operating day.
NPRR1036: Clarifies some processes associated with late payments and payment breaches and aligns protocol language on market participants’ registration and qualification with language in the standard form market participant agreements.
NPRR1037: Corrects switchable generation resources’ (SWGRs) settlement when instructed to switch from a non-ERCOT control area to the ERCOT control area. The NPRR includes the SWGR’s operational costs in the non-ERCOT control area in calculating switchable generation operating cost for resources with approved verifiable costs.
NPRR1038: Establishes a limited exemption from reactive power requirements for some energy storage resources (ESRs). The exemption is available only to an ESR that achieved initial synchronization before Dec. 16, 2019, and applies only to the extent the resource is unable to comply with the reactive power requirements when it is charging. To qualify, the ESR’s operator must submit a notarized attestation to ERCOT that says the ESR would be unable to comply with the requirements without making physical or software changes.
NOGRR214: Describes ERCOT’s process for collecting geomagnetically induced current monitor and magnetometer data to satisfy requirements of NERC Reliability Standard TPL-007-3 (Transmission System Planned Performance for Geomagnetic Disturbance Events).
NOGRR218: Removes the requirement that disturbance-monitoring equipment owners annually submit their databases to ERCOT.
SCR811: Adds a predicted five-minute solar ramp to the resource-limit calculator’s formula for calculating the generation-to-be-dispatched value. The solar ramp rate will be calculated from the intra-hour PV power forecast and the short-term PV power forecast.
CERAWeek organizers said last week that they are planning a virtual conference next year, citing “continuing uncertainty” surrounding the COVID-19 pandemic and advice from experts.
IHS Markit, the London-based global information firm that holds the conference each March in Houston, said in an email Thursday that it will continue to monitor the situation and “take guidance” from city officials as to in-person gatherings.
CERAWeek 2020 was one of the first business casualties of the coronavirus pandemic when organizers canceled it in early March. At the time, COVID-19 had infected more than 88,000 people worldwide and killed almost 3,000, including one in the U.S. (See CERAWeek Canceled as COVID-19 Virus Spreads.)
The annual event is one of the world’s largest energy conferences. The last in-person conference in 2019 drew more than 5,500 government officials, industry executives and thought leaders from around the globe.
CERAWeek 2021 will be held March 1-5 under the theme, “The New Map: Energy, Climate and Charting the Future,” based on the title of co-founder Daniel Yergin’s latest book.
“We will examine the dramatic changes reshaping the global landscape and what they mean for the energy future,” CERAWeek co-Chair James Rosenfield said. He said he has been pleased with the positive response to the online CERAWeek Conversations, “all of which have been aimed at bolstering the community through this era.”
“CERAWeek now has become a platform for ongoing engagement throughout the year,” he said.
ISO-NE presented the Planning Advisory Committee on Thursday with potential study conditions to identify transmission needs under increased penetration of distributed energy resources, renewables and energy storage resources (ESRs) and increasing imports via HVDC interconnections.
In addition to responding to different system conditions in this “future grid,” planners also will need to consider new approaches to data collection to ensure accurate modeling, said Dan Schwarting, transmission planning supervisor for ISO-NE.
The RTO said the discussion Thursday was the first of many it plans with stakeholders this year; studies with new assumptions may begin in 2021.
While the RTO’s current study methods and assumptions work well, Schwarting said, they may be inadequate in a decade, when these new resources become increasingly ubiquitous.
With a higher penetration of DERs, primarily solar PV, and continued offshore wind generation development, Schwarting said, “what we’re finding is that as time goes on, and these trends continue to accelerate — we continue to see more wind interconnections and more distributed energy resources — we really need to rethink some of these approaches.”
For example, ISO-NE lacks visibility on, and control of, storage assets on the distribution system. New England currently has less than 5 MW of solar PV connected to its distribution systems, but by December 2029, that will increase to 7,796 MW, according to the 2020 Capacity, Energy, Loads, and Transmission (CELT) report.
In addition to the 30 MW of offshore wind generation currently in service, an additional 1,504 MW have secured state contracts, with 156 MW committed through the Forward Capacity Market and another 1,600 MW of state contracts under negotiation.
Each blue dot in this scatterplot represents a single hour of solar output as a percentage of nameplate rating (vertical axis) and gross load data (horizontal axis) from 2012-2018. | ISO-NE
To date, New England’s planned offshore wind interconnections are located in southeastern Massachusetts and Rhode Island.
“There’s not a real lot of geographic diversity yet,” Schwarting said. “That may change further down the road.”
Low wind production at peak load could lead to high imports for the Southeast Massachusetts/Rhode Island region, while high wind and solar production at low load levels could lead to high exports. High wind production could also lead to voltage control challenges because of a smaller number of synchronous generators online.
As DER penetration increases, Schwarting said, net load will not accurately define system conditions. He cited two examples of an 8,000 MW net load level: at 3 a.m. on a mild spring night with 8,000 MW consumed and no solar, versus 1 p.m. on a mild, sunny spring day when 14,000 MW is consumed but is partially offset by 6,000 MW of solar.
The revised assumptions will be used in future needs assessments and solutions studies in addition to studies of market efficiency and public policy transmission upgrades.
Studies already underway will continue under existing planning assumptions and not restarted, Schwarting said. Solutions already planned or under construction based on previous studies will not be re-examined either.
“There’s still a lot of different areas that we have to explore. We don’t think that we’ll be ready to start a new study with these assumptions for at least quite a few months at this point, so we don’t want to put all of our existing studies on hold, especially those that are discovering time-sensitive needs,” Schwarting said. “We also don’t expect that a lot of the upgrades that we’re identifying will be significantly different under the new proposal.”
ISO-NE is taking feedback from stakeholders on the proposals until Oct. 9, with further discussion slated for future PAC meetings. In the meantime, RTO staff will continue their development of study assumptions concerning ESRs; areas with noncoincident peak loads; conventional generator outages; interface transfers; and light and shoulder load conditions in proposed plan application studies. Staff will also talk to distribution providers to obtain data on DERs.
Load served by ISO-NE transmission system with varying levels of behind-the-meter PV on a low-load weekend day, based on load and PV production for Sunday, April 24, 2016. (PV production, as a percentage of nameplate capacity, is assumed to remain constant as PV penetration increases.) | ISO-NE
Lower Maine 2030 Needs Assessment Draws Questions
Transmission planning engineer Meena Saravanan gave the committee a presentation on the scope of work for the Lower Maine 2030 Needs Assessment, which ISO-NE announced on Sept. 10.
The assessment is intended to evaluate the reliability and identify needs in Lower Maine under future load conditions reflecting the 2020 CELT report; resource changes based on Forward Capacity Auction 14 results; and reliability over a range of generation patterns and transfer levels. It also will seek coordination with needs assessments in Upper Maine and New Hampshire.
ISO-NE began a statewide needs assessment in June 2017 but split it into Upper and Lower Maine studies because of the need to consider the proposed New England Clean Energy Connect (NECEC) HVDC transmission line. RTO staff are conducting a solutions study based on the results of the Upper Maine assessment, which was completed in March.
The Lower Maine assessment could not proceed until NECEC’s system impact study was completed and its required system upgrades were known, Saravanan said.
The primary triggers for the Lower Maine assessment were compliance with reliability standards; transfer capability; short-circuit performance; and system performance considering delist bids and cleared demand bids.
One area that drew a sharp line of questioning from a stakeholder was the 2030 peak load assumptions for Phase II HVDC, from Quebec to New England, which was given a dispatch range of 950 MW.
Bruce McKinnon, who represents the Norwood Municipal Light Department in Maine, said Phase II normally carries at least 1,200 MW.
“I find that to be a little bit of a problem,” McKinnon said. “I can understand maybe doing some studies with it one way or the other. But the fact that you’re not pushing it to what it is normally contributing to the system, I think, is a failure of an assumption — and I’d like the minutes to say so too.”
Schwarting acknowledged that the line has operated at higher levels. “The 950 MW is essentially everything that we can contractually count on,” he said.
Comments on the work scope will be collected until Oct. 9. The assessment is expected to be completed and presented to the PAC in the first or second quarter next year.
SWCT 2027 Solutions Study Concludes
ISO-NE told the PAC that the Southwest Connecticut 2027 Solutions Study is complete because the time-sensitive needs identified in the corresponding needs assessment have been addressed by Eversource Energy’s Glenbrook static synchronous compensator (STATCOM) asset condition project.
The assessment’s minimum load analysis found four buses with N-1-1 high-voltage violations for contingency events that included the loss of both STATCOMs at Glenbrook and the loss of a 345-kV reactor in the region.
Eversource presented its proposed solution at the July PAC meeting, saying maintenance or refurbishment of the existing STATCOMs — which were installed in 2004 and have an availability rate of only 81% — was not feasible.
The project replaced the two Glenbrook STATCOMs by repurposing the existing STATCOM building and outdoor equipment. The replacement STATCOMs, which would have the same reactive capability as the existing STATCOMs under normal operating conditions, eliminate the common mode failure.
The project is estimated at $21.6 million and has a targeted in-service date of April 2021.
New York’s investor-owned utilities are working with government officials and project developers to fine-tune the processes and contract terms of state-mandated energy storage solicitations.
Approximately 60 energy storage developers participated Thursday in a technical conference hosted by the New York State Energy Research and Development Authority (NYSERDA), anonymously questioning a panel of three utility executives on matters such as expanding timelines for requests for proposals beyond the current six months; extending payment terms and contract duration up to 10 years; modifying in-service dates out to 2025; reducing the storage duration requirement from four hours to one; and providing developers the option to sell a project to the utility upon completion.
The New York Public Service Commission’s December 2018 storage order required Consolidated Edison to procure at least 300 MW of storage capacity and each of the other utilities (Central Hudson Gas and Electric, New York State Electric and Gas, Niagara Mohawk Power, Orange and Rockland Utilities, and Rochester Gas & Electric) to procure at least 10 MW each, with assets to be operational by Dec. 31, 2022, on contracts up to seven years.
The RFPs started in 2019 and are to continue annually as needed to meet individual utility storage goals. New York state now has about 93 MW of advanced energy storage capacity deployed with 841 MW in the pipeline toward meeting its goal of 1,500 MW deployed by 2025 and 3,000 MW by 2030. The 1,400 MW of traditional pumped hydro storage in the state does not count for the goal totals.
Stephen Wemple, Con Edison | NYSERDA
Each utility has conducted its initial RFPs and is developing the next round of solicitations after having notified bidders of first-round results.
“We’re looking for feedback from the participants during this session as well as through a follow-up email [with comments due Oct. 8], and this will culminate in a filing with the commission, which will allow for more formal comments for commission action,” said Stephen Wemple, Con Ed vice president of regulatory affairs. The next round of RFPs is expected in the second quarter next year.
The PSC on Sept. 17 modified dynamic load management implementation plans for the six utilities, all related to storage, saying the initial plans “resulted in a bias towards short-term, low-capital investment solutions” because of their yearly performance structure (18-E-0130). (See “DLM Incentives Extension,” NYPSC Accepts CLCPA Environmental Review.)
Time and Negotiations
The feedback indicated that six months is very compressed for an RFP, from posting to final selection, and that developers need more time; whether a month or more is yet to be determined, said James Mader, manager of smart grid programs at NYSEG.
Mader addressed these questions: How does the current process flow? Does it start with bidders who have potential projects, or does the RFP require those opportunities to be concrete and ready to go?
“The current process was you’d look at the RFP and submit your bid once you received bidding approval, and then we would analyze and review what we received,” Mader said. “Moving forward, that’s something we’re looking to potentially tweak or adjust.”
The RFPs also required developers to have site control and to have applied for their interconnection agreement, which utilities factored into the viability of a project, Wemple said. “We want to go through a process; we want to select bidders that are well positioned to deliver and complete their projects in the time frame required.”
The first round of RFPs “was a learning experience for everybody, and the idea is to have a value-based bid cap — what is the utility actually going to get — and developers are going to give their best proposal in there,” said Schuyler Matteson, senior energy storage project manager at NYSERDA.
“For the utilities who are still under contract negotiations, and that includes Con Ed, we hope to make an announcement in the near future. … We don’t want to bias those negotiations, but there were a couple of utilities that did not have any finalists,” Wemple said. “I know that included my affiliate O&R.”
Jeffrey May, CHGE | NYSERDA
Central Hudson also reported no bidders that met the bid ceiling, while NYSEG said it was still in negotiations. National Grid did not take part in the panel but did participate in the conference planning and had a manager listening in, Matteson said.
Utilities received feedback that high pre- and post-commissioning security requirements increased bid prices; large upfront payments caused difficulties with financing for some developers; and annual payments did not cover operations and maintenance costs.
“From our perspective, we didn’t see anything that really jumped out at us to indicate that one offer or another was assuming things that were significantly different from anyone else,” said Jeffrey May, energy resource manager at Central Hudson. “To speak to the spread in pricing, there was nothing obvious to us that indicated a driver as to why some bids might have been significantly higher than others. … There were no offers that met the bid ceiling, so maybe if we had gotten into a deeper dive, we might have seen where some of those differences were, but there was nothing on the surface from our evaluation matrix.”
Tech Specs and COD
Utilities determined that a commercial operation date of Dec. 31, 2022, is not feasible for resources being procured in 2021 and proposed to move the date out three years to year-end 2025.
One question on that issue was whether the utilities could begin payments if a project comes online ahead of the date set by regulators. Wemple said Con Ed would.
Several developers provided feedback that uncertainty in the post-contract market led to attributing little or even negative value to merchant “tail” years, and that extending the contract duration from seven to 10 years would spread costs over a longer period while increasing potential contract revenue.
Developers said that removing the four-hour duration requirement would bring in a wider range of bids and address concerns related to buyer-side mitigation issues.
“I think the expectation is that a shorter-life battery, while perhaps not getting as much or any capacity value, could make up for it on its relative ‘less cells to pay for’ by providing regulation or other ancillary services,” Wemple said.
New York City’s Demand Response and Load Management Programs with Con Edison rely on real-time metering for analysis of energy usage. | NYSERDA
One commenter said that requiring a maximum number of cycles over the course of a year might be a good way to give bidders a sense of how the storage asset might be used.
Another commenter was concerned about “trying to align the NYISO class year process with knowing what the NYISO assignment of system upgrades are, because that impacts interconnection costs.”
“Hopefully we’ll get a little better clarity from the ISO on what their timing for the next class year process will be, and at least try to see if we can work that into this [RFP] process,” Wemple said.
One proposed revision to the RFP process would let the developer provide O&M services for a defined period (e.g., five years) and to mitigate uncertainty in post-contract market revenues by having the developer sell the project to the utility at the COD.
One developer asked whether the utilities are sure they can own storage in the first place.
“Certainly, with a commission order … the commission can allow us to do lots of different things, and actually in many cases, we already own storage as part of prior non-wires solicitations,” Wemple said.
MISO and SPP have once again failed to identify any beneficial cross-border transmission projects after a fourth interregional study.
RTO executives broke the news during a virtual meeting of the MISO-SPP Interregional Planning Stakeholder Advisory Committee (IPSAC) on Friday. Stakeholders were unsurprised by the announcement after already hearing indications that the fourth coordinated system plan (CSP) study would be fruitless. (See MISO, SPP Close to Ruling out Joint Projects Again.)
“All the work that we put into the study, I feel like it’s a building block for future studies,” SPP’s Neil Robertson told stakeholders, adding that the studied flowgates would most likely show up in future interregional studies.
This year the RTOs focused on 10 routinely congested flowgates in Minnesota, Iowa, Nebraska, Kansas, Missouri, Oklahoma and Arkansas.
“I fully anticipate that we’ll be seeing these constraints again,” Robertson said, citing expanding renewable generation flows between the RTOs. “The increase in interregional flows are only trending one way, and that’s up.”
MISO and SPP planners said the RTOs’ transmission planning futures scenarios — both updated this year — will probably yield larger project benefit ratios in future joint studies.
The study also turned up discrepancies in the RTOs’ separate project cost estimates, Robertson said. The grid operators will work together to produce more consistent cost estimates in the future, he said. (See SPP Seams Steering Committee: Sept. 17, 2020.)
“We intend to reach a lot more consensus about how cost estimates are determined in the interregional studies. Cost estimates are essential … to figuring cost-benefit ratios, and we’re going to make sure they’re not a roadblock in future studies. I want to stress that this will be a priority,” he said.
Congested flowgates studied under the 2020 CSP | MISO, SPP
Robertson noted that MISO and SPP haven’t worked out exactly how they’ll make their cost estimates line up better.
“The local [transmission owners] have a perspective; the RTOs have a perspective; even the stakeholders have a perspective. Those are the things you have to kind of talk out,” he said.
However, Robertson stressed that differing cost estimates didn’t prevent any project candidates from “crossing the finish line” this year.
“Cost estimates were not the determining factor in a project not getting approved,” he said.
The Advanced Power Alliance’s Steve Gaw asked if the RTOs suffer from a process issue in which they’re not examining solution candidates thoroughly enough.
Robertson said MISO and SPP studied more project candidates than the 34 they presented to stakeholders.
The RTOs have somewhat assuaged stakeholder concerns by announcing a new joint study targeting generation interconnection challenges. (See MISO, SPP to Conduct Targeted Transmission Study.) That study could yield new transmission capacity and thus facilitate development of the renewable generation in the RTOs’ interconnection queues.
Robertson said MISO and SPP have yet to determine the scope of the study, the geographic areas to be studied or whether the study will affect the possibility of a 2021 CSP study. The RTOs plan to hold an annual issues review in the first quarter of 2021 where they will discuss possible needs for transmission solutions.
“All of those questions are yet to be answered. … We’ll share details as soon as we possibly can,” Robertson said. “But please keep in mind that the vast details of the study have yet to be determined.”
MISO Director of Planning Jeff Webb said he expects study results to roll in at the end of 2021.
Stakeholders have repeatedly asked how this study will differ from MISO and SPP’s CSP studies.
“I think that’s a fair question. We’ll have to lay that out more clearly at the kickoff meeting,” Webb said at the MISO Planning Advisory Committee’s meeting Wednesday, though he added that the study will target needs for interconnecting generation, something the CSP studies don’t consider.
NYISO CEO Rich Dewey told the Management Committee on Wednesday that staff are determining whether a technical problem related to the 2017-2021 installed capacity (ICAP) demand curve reset violates the ISO’s Tariff or constitutes a market problem.
“When we’re confident that the software is accurate and reflecting the right impacts … we commit that we will share that with market participants as soon as possible,” Dewey said. “Look for a meeting invite by the end of this week.”
NYISO acknowledged earlier in the month that the model used to estimate net energy and ancillary services revenue earnings for the hypothetical peaking plant resulted in a misalignment of natural gas prices with the actual delivery date associated with such prices. (See NYISO ICAP/MIWG Briefs Sept. 14, 2020.)
Staff’s final demand curve reset recommendations, posted Sept. 9, said that “based on the review of stakeholder feedback and discussions with the data vendor, the model has been updated to reflect that gas prices published by the vendor for a particular date reflect the price to utilize gas on the specified date (e.g., gas prices published with a Friday date represent the cost to utilize gas on that Friday).”
Illustration of demand curve slope, wherein the zero crossing point represents the point at which the value of additional capacity declines to zero | NYISO
When no gas price is reported, the model will use the next available day on which data are published. For a non-holiday weekend, the gas price published for Monday will be used as the gas price for Saturday, Sunday and Monday, the ISO said.
Although it is too early to know the magnitude of the impacts from the software issue for the 2017-2021 period, delaying the October ICAP spot market auction is not an option, Dewey said. While NYISO has obtained a revised version of the model, it must be tested for unintended consequences, he said.
Peak Load of 30,660 MW on July 27
When Vice President of Operations Wes Yeomans reported satisfactory hot-weather operations to the MC on July 29, he said the three heat waves that month were starting to blend into one another. But the excessive heat did not continue into August, leaving the peak load of 30,660 MW recorded July 27 as the record for summer 2020. (See “Hot Weather Operations OK,” NYISO Management Committee Briefs: July 29, 2020.)
In his report on Wednesday, Yeomans said the peak load represented 95% of the 50/50 forecast of 32,296 MW. Daily mean temperatures in New York were above the 20-year average in June, July and August, and below average in May, with the highest temperatures recorded in Central Park (96 degrees Fahrenheit) and Albany (95 F), Yeomans said.
The ISO also operated satisfactorily through its first summer without Indian Point Unit 2, the Somerset coal station in western New York and the Cayuga generating facility north of Ithaca. It was also its first summer with the 1,000-MW Cricket Valley combined cycle plant.
Load profile for peak load day July 27 (30,660 MW) includes dark blue line to show what load would have been without BTM solar and demand response | NYISO
Gov. Andrew Cuomo declared a state of emergency Aug. 5 after outages from Tropical Storm Isaias affected 920,000 customers, mainly on Long Island and around New York City.
“We did have multiple bulk electric system transmission elements tripped … mostly transmission lines over 100 kV, so the majority of the multiple transmission elements we had were 138 kVs that either tripped and came right back, or they tripped and locked out and the [transmission owner] was able to get them back quickly. … Some others, which had damage … took time to get back,” Yeomans said.
Steam up in NYC
The committee approved increasing the exemption from real-time generation penalties for units that supply the New York City steam distribution system by 10 MW to a total of 533 MW. The electricity output of the plants is driven by the city’s steam requirements, making the units unable to follow NYISO dispatch instructions.
Chris Hargett of Consolidated Edison presented the same slides as at the BIC on increasing the exemption for the company’s East River Units 1, 2 and 6. The increase was needed because a number of projects completed over the past several years have increased the efficiency and output of Unit 6, Hargett said.
If the Board of Directors approves the revisions in October, NYISO will submit them to FERC under Federal Power Act Section 205.
2021 Draft Budget down $600K from 2020
For the second year in a row, NYISO is proposing a decrease to the budgeted revenue requirement, with the draft budget allocating $167.4 million across a forecast of 147.3 million MWh for a Rate Schedule 1 charge of $1.137/MWh, down from the 2020 budget of $168 million allocated across 154.3 million MWh ($1.089/MWh).
Alan Ackerman of Customized Energy Solutions, chair of the Budget and Priorities Working Group, presented the draft budget, reporting that the ISO is holding the number of staff positions steady. Every line item except computer services in support of projects and corporate insurance were cut from the 2021 projections made during the 2020 budget cycle. Major cuts in approved spending for 2020 have come through deferring some capital expenditures, such as $5 million to renovate the control room.
The ISO made a special effort to hold spending flat in light of the economic challenges facing many market participants as a result of the pandemic, Ackerman said.
The MC expects to vote on the final draft budget in October before it goes before the board for final approval in November.
Yes to ESR Bidding Rules
The MC recommended the board approve proposed capacity market bidding rules for energy storage resources (ESRs) reflecting their energy-duration limitations.
Market Design Specialist Sarah Carkner presented the Tariff revisions specifying that such ESRs bid or schedule a bilateral transaction for their full injection range for all hours during the peak load window and to bid their full withdrawal range for all hours outside of the peak load window, or notify the ISO of a derate.
Given board approval, the ISO will later this year or in early 2021 submit the revisions to FERC and update the ICAP Manual with the new rules.
A Place for Solar in Dispatch
The MC also recommended the board approve expanding market rules for wind energy resources to also encompass solar resources.
The Tariff revisions would require dispatchable solar resources to submit flexible day-ahead and real-time offers and require them to respond to economic curtailment signals from the ISO. They would not be eligible for day-ahead margin assurance make-whole payments.
“Proposing the Tariff revisions at this time allows us to give as much notice as possible to new solar resources and existing ones as they look to understand what’s required to participate in NYISO markets going forward,” analyst Cameron McPherson said in presenting the revisions.
The rules would allow solar resources to indicate their economic willingness to generate, reducing the need for out-of-market curtailments and self-directed curtailments, he said.
If the board approves them, the ISO will file the revisions at FERC in November or December and look to implement them in 2021.
Committee OKs Credit Policy Enhancements
The MC recommended that the board approve changes to NYISO’s policy on extending unsecured credit to public power entities and government entities.
The Tariff revisions would make government entities eligible for up to $1 million in unsecured credit, as public power entities are currently. The credit would only be available for entities with investment-grade debt ratings.
FERC in April granted the ISO a nine-month waiver allowing it to grant up to $1 million in unsecured credit to government entities that do not meet the current Tariff definition of a public power entity, said Sheri Prevratil, the ISO’s manager of corporate credit.
If the NYISO board approves the revisions in October, the ISO will make a Section 205 filing with FERC.
The MC also recommended board approval of proposed changes to the ISO’s transmission congestion contracts (TCC) credit policy to address concerns raised by GreenHat Energy’s default in PJM’s financial transmission rights market. The changes would allow for earlier recalculation of the collateral requirements for the second year of a two-year TCC.
NYISO also would use market clearing auction prices to calculate credit requirements for TCCs instead of congestion rents over the prior 90 days. The ISO said market-clearing prices, “which are forward looking, provide a more appropriate predictor of future payments due than historic congestion rent values.”
If the board approves them, the ISO will submit the changes to FERC in the fourth quarter.
The cost of the Greater Boston Project is expected to increase by $191 million (33%) primarily because of the underground Wakefield-Woburn, Mystic-Woburn and Sudbury-Hudson lines, Eversource Energy told the New England Power Pool Reliability Committee on Wednesday.
The cost of the three components is increasing by $147 million, to $352 million (72%).
The remaining 30 components’ cost is rising from $367 million to $411 million, a 12% increase over the transmission cost allocations supported previously by the RC and approved by ISO-NE.
Eversource said 25% of the increase is resulting from the need to underground the 115-kV Sudbury-Hudson line. It was initially proposed as an overhead line, but Eversource was unable to secure property leasing rights from the Massachusetts Bay Transportation Authority (MBTA). The proposed underground line is estimated at $91 million, more than double the original cost of $45.3 million, and has an in-service date of December 2023.
Eversource performed an updated alternative analysis and found that a new 9-mile, 115-kV underground transmission line within an MBTA right of way was the “most cost-effective and constructible alternative.” The two alternatives analyzed — a new 10.3-mile, 115-kV underground transmission line entirely in roadways ($110.4 million), or multiple upgrades to convert a 14.5-mile, 69-kV line to 115 kV, reconductor 11.6 miles of other 115-kV lines and upgrade seven substations ($116.1 million) — had higher costs.
The Wakefield-Woburn and Mystic-Woburn lines are increasing to a combined $260.6 million from $160.2 million, representing 50% of the total cost increase. Eversource said additional restrictions on the design and construction required a realignment of underground construction within roadways to avoid interference with existing utilities. Restrictions on work hours and the number of crews also increased the construction bids, the company said.
The matter is slated for a future committee vote.
ISO-NE, NYISO Propose Revision to Coordination Agreement
ISO-NE proposed revisions to its Coordination Agreement (CA) with NYISO to eliminate the need to make a FERC filing when the grid operators update their description of shared interconnection facilities.
The grid operators share three interconnections: the NY/NE Northern AC Interconnection (comprising the PV-20, K7, K6, E205W, 393, 690/FV and 398 interties); the Norwalk Harbor-Northport, NY, Cable (NNC Intertie) and the Cross-Sound Cable Interconnection (CSC Intertie).
Rather than maintaining the detailed list of interconnection facilities in Schedule A of the CA — which requires a FERC filing for any changes — the grid operators are proposing to update the list on their external websites. The addition or removal of an interconnection would still go through the grid operators’ stakeholder processes and filed with FERC.
ISO-NE said it and NYISO sought the change after the addition of a new transmission substation and common metering point modified one of the interties in the NY/NE Northern AC Interconnection. The change replaced the Pleasant Valley substation and common metering point in New York with the Cricket Valley substation and common metering point on the 398 Intertie.
Although the change did not alter the makeup of the NY/NE Northern AC Interconnection, current rules required that it be filed with FERC. “ISO-NE and the NYISO recognized that such ministerial revisions to the ISO-NE/NYISO CA place an unneeded burden on the respective ISOs, their stakeholders and the FERC,” ISO-NE told the committee.
The grid operators plan to file the revised CA with FERC at the end of 2020 and expect an effective date of early 2021. NYISO will go through a similar stakeholder process, which it expects to complete in November or December, according to ISO-NE.
The RTO requested that the RC vote in support of the proposed modifications at its Oct. 20 meeting.
Tie Benefits and ICR Recommended by Vote
The RC voted to recommend that the Participants Committee support ISO-NE’s tie benefits and installed capacity requirements (ICR) and related values for Forward Capacity Auction 15. (See ISO-NE Sees 722-MW ICR Jump for FCA 15.)
The Hydro-Québec Interconnection Capability Credit (HQICC) values for FCA 15, which is associated with the 2024/25 capacity commitment period, is 883 MW, and the ICR is 34,153 MW with a net ICR of 33,270 MW.
The following megawatt values were also recommended for support: Southeast New England Local Sourcing Requirement (10,305), Maine maximum capacity limit (4,145) and Northern New England maximum capacity limit (8,680).
The PC will vote on the ICR and related values on Oct. 1, with a FERC filing expected by Nov. 10.
Winter Readiness, Gas Infrastructure Surveys Added to OP-21
The RC voted to recommend that the PC approve changes to Operating Procedure 21 to add the generator winter readiness survey and natural gas critical infrastructure survey.
OP-21 is being renamed “Operational Surveys, Energy Forecasting & Reporting and Actions During an Energy Emergency” to reflect the additions.
The annual generator survey process enhances situational awareness of pre-winter generator preparations, while the natural gas survey ensures critical infrastructure of the interstate natural gas system is not on electrical circuits subject to automatic or manual load-shedding schemes.
ISO-NE distributes the generator survey before Nov. 1 each year, and it is due back no later than Dec. 1 unless specified otherwise.
The RTO distributes the natural gas survey to representatives of each interstate natural gas pipeline company operating in New England, as well as the Canaport and Everett LNG facilities. It is typically completed in June.
NERC’s Standards Committee voted Thursday to accept the standard authorization request (SAR) presented by the drafting team for Project 2019-06 (Cold weather). It also appointed the team as the standards drafting team (SDT) for the project.
Much of the discussion of the measure at the meeting reflected the responses that it received from industry stakeholders in previous comment periods. (See Cold Weather Team Seeks More Time to Process Response.) Some committee members questioned the wisdom of moving forward with a project that has proven so controversial.
“The industry has rejected this SAR numerous times, and now it’s come to the Standards Committee, and industry has not approved it yet,” said Marty Hostler, reliability compliance manager for the Northern California Power Agency. He added that “numerous issues” remain with the SAR, including unaddressed compliance burdens and the potential impact of adding more detail to existing NERC standards that were intentionally written vaguely to give more flexibility to registered entities.
Sean Bodkin, NERC compliance policy manager for Dominion Energy, agreed that while “almost all of industry supports” some kind of cold weather preparedness requirement, several rounds of stakeholder feedback made clear that the committee shouldn’t support moving forward with the SAR in its current form.
SPP’s Matthew Harward, the chair of the drafting team, pushed back on this interpretation of the stakeholder comments. While he acknowledged that “multiple comments did not agree that a new standard was needed,” he said the team had taken this into consideration and planned to work within existing standards as much as possible. The only new standard that is likely to be needed is “a requirement for [generator owners and operators] to prepare [for] cold weather.”
The measure passed with no negative votes, though Bodkin abstained, along with Venona Greaff of Occidental Chemical, Linn Oelker of LG&E and KU, and John Babik of JEA.
IRPTF SARs Accepted
The committee voted to accept two SARs requested by the Inverter-based Resource Performance Task Force (IRPTF) and approved by the Reliability and Security Technical Committee in June. They will be posted for a 30-day informal comment period as members are solicited for a SAR drafting team. (See “IRPTF SARs Pass After Debate,” NERC RSTC Briefs: June 10, 2020.)
IRPTF’s SARs would apply to the following standards:
FAC-001-3 (Facility interconnection requirements) and FAC-002-2 (Facility interconnection studies) — Clarify which entity is responsible for determining which facility changes count as material modifications; clarify that generator owners should notify affected entities before making a material modification; revise the term “materially modifying” to avoid confusion between Facilities Design, Connections and Maintenance (FAC) standards and FERC’s interconnection process.
MOD-026-1 (Verification of models and data for generator excitation control system or plant volt/VAR control functions) and MOD-027-1 (Verification of models and data for turbine/governor and load control or active power/frequency control functions) — Revise or replace with a new model verification standard that accounts for inverter-based resources.
Two other SARs suggested by the IRPTF — to modify PRC-002-2 (Disturbance monitoring and reporting requirements) and VAR-002-4.1 (Generator operation for maintaining network voltage schedules) — were also approved by the RSTC but were not submitted to the Standards Committee. NERC’s Manager of Standards Development Soo Jin Kim said that the two that the committee approved were considered “higher priorities based on some issues that are occurring today with regard to compliance.”
None of the prospective team members for Project 2020-04 — who were not identified by name during the meeting — met with serious opposition, but some committee members did raise questions about the nominating process.
Bodkin said one candidate did not seem to have relevant expertise and lacked an endorsement from a generator or transmission owner/operator. However, he dropped the question after Kim and Howard Gugel, NERC’s vice president of engineering and standards, reminded him that ERO staff have the authority to certify a candidate as a subject matter expert — and had done so in this case.
Robert Blohm, managing director of Keen Resources, noted that none of the candidates nominated by stakeholders but not recommended for inclusion by NERC had references on file. He asked whether they had been rejected for failing to submit references — a policy that the committee has objected to before. (See “SDT Candidate Restored After Application Oversight,” NERC Standards Committee Briefs: July 22, 2020.)
In response, Kim explained that the candidates did submit references, but the template used by her team in preparing the report did not have a space for the information. Blohm suggested that the form be updated to ensure those candidates not recommended by NERC were represented with the same level of detail as those who were endorsed.
NERC’s Bulk Power System Awareness Team on Thursday gave stakeholders a presentation on their role as the ERO’s “eyes and ears.”
“We collect data, analyze the data and report on the data,” Bill Graham, principal bulk system awareness coordinator, said during NERC’s eighth annual Monitoring and Situational Awareness Technical Conference, held via WebEx. “We’re continuously observing system conditions and using various tools that we have, as well as expertise, [to] try to identify any kind of threats.”
Graham gave his presentation after an update by Wei Qiu, senior engineer of event analysis, on trends in NERC’s energy management system outage data.
Bill Graham, NERC | NERC
The seven-member Bulk Power System Awareness Team, part of NERC’s Reliability Risk Management department, has an average of 22 years of experience. It is headed by Director Darrell Moore, a former transmission operator for Georgia Power.
In addition to Graham, who received nuclear training in the U.S. Navy, it includes senior engineer Mani Mardhekar, a former power trader and analyst of bulk power system operations; senior analysts Ara Johns, a former generation dispatcher for Southern Co., and Brent Kane, a former reliability coordinator for PJM; Tony Burt, former supervisor of reliability coordination operations at Peak RC; and administrative assistant Stephanie Lawrence, who holds a degree in information technology.
In addition to issuing about a dozen special reports annually, the team provides a report each morning that is circulated to NERC CEO Jim Robb, FERC, the regional entities and some reliability coordinators. “It’s a description of what we’ve seen … threats that are potentially in place against the bulk power system, as well as any kind of weather events or anything of the like that needs to be at the forefront of everyone’s mind,” Graham said.
It also collects the EOP-004 disturbance reports filed daily by regulated entities.
“What my team does is the initial triage of these events to understand if there’s an immediate concern,” Graham said. It also files the information into databases used for event analysis and Lessons Learned reports.
NERC’s Bulk Power System Awareness Team uses “nifty tools” like Genscape (top) and SAFNR (bottom) — as well as social media and weather sites — for signs of problems on the grid. | NERC
But it is not involved with any compliance monitoring, Graham emphasized. “We do file the mandatory EOP-004 reports into the NERC database … but we don’t provide any kind of comment or input with regard to any compliance monitoring issues,” he said. “We steer clear of that 100%. If compliance ever does become an issue, we stop the conversation and get the correct parties involved. We just simply are not part of the compliance regulatory arm of NERC.”
The team has a variety of what Graham called “nifty tools,” including OSIsoft’s PI Vision, which tracks system frequency, and SAFNR v.3 (Situational Awareness for Situational Awareness Tool Nears Rollout.)
It also uses Genscape, which collects power prices and uses sensors to monitor transmission line loads.
Although it is largely used by power traders, “we use it to understand the health and wellbeing of the bulk power system,” said Graham, showing a screen shot from a day when he said there were “buying opportunities” in MISO.
“What my team does is we see this and try to understand why. Why is there a buying opportunity up in the Michigan area? Is there a plant that’s in a forced outage? Is there transmission congestion?”
The group also monitors “all the social media and news websites that you can imagine. So, for example we keep an eye on all the utility websites, all the reliability coordinator websites [and] all the balancing authority information that’s publicly available,” Graham said. “Likewise, we keep a close eye on social media. We do not participate, but we do watch what’s being talked about.”
And because NERC is a nonprofit organization, Graham said, “we make the best use of any single free Internet tool that’s available.”
“So, we’ve become experts at all the different weather websites,” he said. “Hurricanes are a huge deal for us.”
