PJM’s first-quarter energy prices fell to their lowest level since the RTO was created in 1999, according to the Independent Market Monitor’s first-quarter State of the Market report released Friday.
The Monitor cited lower fuel costs, mild winter conditions and a significant drop in energy use resulting from COVID-19 pandemic-related stay-at-home orders as contributing factors.
The report showed that real-time LMPs averaged $19.85/MWh during the quarter, down 34.2% from the same period in 2019. The Monitor found that 46.4% of the $10.31/MWh decrease was a direct result of lower fuel costs, specifically natural gas.
“Our analysis concludes that the results of the PJM energy market were competitive in the first three months of 2020,” Monitor Joe Bowring said in a press release.
PJM load was down 6.8% cumulatively in the first quarter compared to the same time last year, the report said, and heating degree days fell 21.8%. Total energy uplift charges decreased by $12.1 million — or 62.6% — from $19.3 million in 2019 to $7.2 million in 2020.
Energy prices were set mostly by generating units operating at or near their short-run marginal costs, the report said, providing evidence of competitive behavior and market outcomes. Net revenues decreased for all generator unit types compared to 2019, the report said, including theoretical net revenue drops of 98% for a new coal unit, 34% for new nuclear plant, 32% for a new combustion turbine and 29% for a new combined cycle unit.
Meanwhile, the trend toward more natural gas-fired generation and less coal grew in the first quarter, with the share of gas increasing from 33.2% to 40% compared to a year earlier, while coal declined from 26.9% to 18% today.
Congestion costs decreased significantly compared to the same time last year, falling from $163.9 million in 2019 to $85.1 million in 2020.
Structural Change Recommendations
The Monitor added four new recommendations to its list, some dating back as far as 2009.
In the “Energy Market” section of the report, the Monitor recommended that that PJM clarify, modify and document its process for dispatching reserves and energy when security-constrained economic dispatch (SCED) indicates that supply is less than total demand, including forecasted load and reserve requirements. The suggested modifications from the report include a definition of a SCED process to economically convert reserves to energy, a process for the recall of energy from capacity resources and a determination of the minimum level of synchronized reserves that would trigger load shedding.
“When the real-time security constrained economic dispatch (RT SCED) solution indicates a shortage of reserves, it should be used in calculating real-time prices, and those prices should be applied to the market interval for which RT SCED calculated the shortage,” the report said. “There are significant issues with operator discretion and reluctance to approve RT SCED cases indicating shortage of reserves, and in using these cases to calculate prices.”
In the “Demand Response” section of the report, the Monitor recommended that all demand resources register as pre-emergency load response and that the Emergency Load Response Program be eliminated. The recommendation was listed as a high priority.
“Emergency and pre-emergency resources receive capacity revenue from the capacity market and also receive energy revenue at a predefined strike price from the energy market for reductions during a PJM initiated emergency or pre-emergency event,” the report said. “The rules applied to demand resources in the current market design do not treat demand resources in a manner comparable to generation capacity resources, even though demand resources are sold in the same capacity market, are treated as a substitute for other capacity resources and displace other capacity resources in Reliability Pricing Model (RPM) auctions.”
Finally, in the “Interchange Transactions” section, the IMM made two recommendations:
Transactions sourcing in the Western Interconnection should be priced at either the MISO interface pricing point or the SouthIMP/EXP interface pricing point based on the locational price impact of flows between the DC tie line point of connection with the Eastern Interconnection and PJM. The recommendation is a high priority.
The assignment of the Saskatchewan Power and Manitoba Hydro balancing authorities from the Northwest interface pricing point should be changed to the MISO interface pricing point, and the Northwest interface pricing point should be eliminated from the day-ahead and real-time energy markets. The recommendation is a high priority.
ISO-NE’s winter wholesale market costs totaled $1.8 billion, a 32% decrease from the previous winter because of lower energy and capacity costs, the RTO’s Internal Market Monitor said in its quarterly markets report released last week.
“The headline for winter 2020 is that it was a very mild winter, with low-priced gas and low load levels,” IMM economist Donal O’Sullivan told the New England Power Pool Markets Committee on May 12.
[Note: Although NEPOOL rules prohibit quoting speakers at meetings, those quoted in this article approved their remarks afterward to clarify their presentations.]
Average day-ahead and real-time Hub LMPs were $30.32 and $29.97/MWh, respectively, with the lower prices resulting from three primary factors, O’Sullivan said.
“Firstly, we had milder temperatures and an absence of very cold periods, which we like to call cold snaps, such as the region experienced in 2018. Secondly, we had low average natural gas prices, which at $3.40/MMBtu was down 41% from the prior winter’s price,” he said.
Lower energy prices drove a 32% decrease in winter 2020 wholesale costs in New England compared to winter 2019. | ISO-NE
The low gas prices stemmed from declines at the supply basins, where year-on-year production increases outstripped demand increases, he said.
“And finally, downward pressure on energy prices also came from increased energy efficiency and additional behind-the-meter solar generation,” O’Sullivan said.
On the capacity side of wholesale costs, payments of about $751 million were also down 24%, a $242 million drop from a year earlier, he said.
Winter 2020 was the third quarter of the Forward Capacity Auction 10 commitment period, with clearing prices of $7.03/kW-month for Rest-of-System, compared with an FCA 9 price of $9.55/kW-month.
Gross real-time reserve payments totaled $1.8 million, a 40% decrease from the same period a year ago, with 97% of those payments going for the 10-minute spinning reserve (TMSR).
“This winter, there were 394 hours of non-zero reserve pricing, compared to 297 hours last winter. Despite there being more hours, payments were lower, with the average TMSR price of $7.56/MWh down from $16.31/MWh last winter,” he said.
There were just 35 minutes of non-zero 10-minute non-spinning reserve (TMNSR) this winter and no instances of 30-minute operating reserve (TMOR) pricing during the season, he said.
“This is similar to previous winters where there were very few or zero hours of TMOR and/or TMNSR pricing,” O’Sullivan said.
Energy market opportunity costs (EMOC) were $0/MWh during the winter, a feature implemented last year in reference levels in order to let the market preserve limited oil inventories for times when gas supply is low during extreme cold weather, he said.
For this winter, the EMOC values were updated prior to the real-time market opening to reflect the latest fuel prices, and the brief periods of cold weather allowed sufficient gas supply to ensure that EMOCs never rose above zero for any hour and had no impact on energy prices, he said.
New England energy market opportunity costs (EMOC) were $0/MWh during the winter. | ISO-NE
CASPR the Ghost
ISO-NE’s Competitive Auctions with Sponsored Policy Resources (CASPR) substitution auction did not proceed this year despite 14 existing resources with a combined capacity of 445 MW having elected to participate.
The CASPR initiative for the FCAs was implemented two years ago to prevent consumers from paying twice for the same capacity through both the Forward Capacity Market and subsidies for state-mandated new supply resources. The initiative is also intended to reduce the possibility that capacity prices will be depressed below competitive levels by large quantities of unmitigated new subsidized resources entering the market.
In FCA 14 in February, while there were 292 MW of supply seeking to acquire capacity supply obligations (CSOs), there was no demand because the existing capacity resources either exited the auction without a capacity obligation or the RTO deemed them ineligible because their test price was greater than the FCA clearing price, O’Sullivan said. (See ISO-NE Capacity Prices Hit Record Low.)
“I think the design of this [CASPR] does need to be re-evaluated as to whether as designed it can actually achieve the goals it was meant to achieve,” said Abigail Krich, president of Boreas Renewables. “Just because the region is long on capacity doesn’t mean that it’s not appropriate to have an organized way for resources that are trying to exit the market to trade their CSOs to resources that are trying to come in.”
Recalculating Net CONE for FCA 16
Market development analyst Deborah Cooke led discussion of the RTO’s proposal for updating the cost of new entry (CONE) and net CONE calculations, and recalculating existing and establishing new offer review trigger prices (ORTPs) using updated data for FCA 16, to be held in 2022 to cover the 2025/26 capacity commitment period.
CONE estimates the cost to build a new resource in New England, while net CONE indicates the net revenue needed by the resource to be economically viable. ORTPs are low-end estimates of net CONE for specific — and less common — technologies.
Interdependencies between the various FCM parameters dictate the order in which the parameters are calculated. | ISO-NE
The RTO plans to work with stakeholders to review and estimate the impacts of two recently proposed market changes on the FCM parameters — the sunset of the Forward Reserve Market in 2025 and the Energy Security Improvements (ESI) filed with FERC in April.
The most recent recalculation was performed in 2016 for FCA 12. Historically, values are updated triennially, but the scheduled review was deferred one year to 2020 to allow for concurrent updates of two new related FCM parameters: dynamic delist bid threshold and performance payment rate, and the inclusion of estimated ESI revenues.
ISO-NE’s plan for sunsetting the Forward Reserve Market in 2025, presented earlier in the meeting, calls for a vote in July, so the RTO will bring related values to the committee in June.
The RTO proposes to file any calculation changes with FERC by Dec. 1.
ESI Timing
ESI would allow the RTO to procure energy call options for three new day-ahead ancillary service products to improve the region’s energy security, and option awards would be co-optimized with all energy supply offers and demand bids in the day-ahead market. (See ISO-NE Sending 2 Energy Security Plans to FERC.)
A FERC order on the ESI filing is expected by Nov. 1. One reason for a Dec. 1 filing is that the net CONE value is used early in the process for FCA 16, during the retirement and delisting window, and that window usually opens and closes near the beginning of March.
The RTO is estimating ESI revenues, given that the filing has two different proposals, one from the RTO and one from NEPOOL, and given the possibility that the commission might order some third way or a blend of the two.
Regarding new technologies such as continuous storage facilities, the RTO is modeling three new technology types for potential ORTPs: standalone batteries, co-located facilities with solar PV and offshore wind, according to the presentation.
Interdependencies between the various FCM parameters dictate the order in which they are calculated, and a memo from Mark Karl, ISO-NE vice president for market development, provided more detailed information on the various parameters and their interdependencies.
Concentric Energy Advisors Analysis
Engaged by the RTO to support the updates, Concentric Energy Advisors’ Danielle Powers, Meredith Stone and Keith Paul presented a preliminary analysis of the net CONE and ORTP recalculations. Their findings conclude that simple cycle and combined cycle gas turbines are primary candidates for CONE calculation based on established criteria, and that other renewable, energy efficiency, demand response and gas-fired generation are primary candidates for ORTP calculation.
A net CONE recalculation analysis by Concentric Energy Advisors found that simple cycle gas turbines like this one, as well as CC turbines, are resources most likely to meet established economic and performance criteria. | Rolls-Royce/Siemens
Powers said the application of the screening criteria to see whether CONE recalculation applies “should be consistent with the order given by FERC in 2017 [ER17-795], which is that net CONE should be high enough to attract new entry, but not so high as to introduce unnecessary costs.”
Paul addressed the various technologies, including biomass, which are considered a niche area because there are few such facilities expected to be constructed or entering the interconnection queue in the near future.
Biomass facilities are typically smaller units with dedicated supply chains and tend to be either site-specific or regionally specific. For example, a unit in one state actually has a supply chain that covers the entire New England region and somewhat beyond in order to supply adequate wood to the facility.
Concentric’s analysis found that paper mill combined heat and power facilities would not be a good application for a CONE or an ORTP calculation because of the variability of the energy output.
Concentric will continue its evaluation and analysis of technologies for CONE and ORTP calculations. In addition, the analysts will bring back to the committee in June preliminary technology costs for the calculations, determination of ORTP technologies and indicative FRM revenue-offset component values.
California should have enough capacity to get through this summer’s peak demand but dwindling hydropower and limited imports during late-season heat waves could strain supply, CAISO said Friday.
“Projections for summer 2020 show that the CAISO faces a low but somewhat increased risk of encountering operating conditions that could result in operating reserve shortfalls than was projected for 2019,” CAISO’s annual Summer Loads and Resources Assessment concluded.
CAISO’s summer demand is expected to peak at 45,907 MW, a negligible increase from last year’s weather-normalized peak of 45,826 MW. The increased risk this year compared with 2019 comes from lower-than-normal hydro conditions that could be “particularly impactful in late summer” when reservoirs are at their lowest.
CAISO’s breakdown of available 2020 summer peak capacity shows gas remains a major resource. | CAISO
California’s snowpack from winter storms is the primary source of water during the state’s dry months from late spring through early fall. The statewide snow-water content in mountainous areas, including the Sierra Nevada, was 63% of average at its peak on April 7, the report said.
The state’s major reservoirs were filled to 101% of average in April, but the snow that gradually melts and refills the reservoirs is far less than last year. On April 11, 2019, the statewide snow-water content was 161% of average.
Pacific Northwest hydropower, a major source of imports for California, is expected to be about the same as last year. For instance, the Northwest River Forecast Center projected the April-to-August reservoir storage at The Dalles Dam on the Columbia River to be 95% of average. It was 94% of average in 2019.
California, however, is competing more with other Western states for a tightening supply of electricity as coal plants retire. (See Western Resource Adequacy Program in the Works.) Moreover, the state’s peak demand has shifted to later in the day, as solar energy diminishes and stops.
CAISO reiterated its concern with the situation last week.
“The CAISO will be at the greatest operational risk of a system capacity shortage later in the summer if hot weather occurs that extends beyond the CAISO footprint and diminishes the availability of surplus energy in neighboring balancing authorities for imports into the CAISO during peak hours when solar production is near or at zero,” it said.
The 2020 summer report didn’t assess risk from transmission outages because of wildfires but acknowledged it “could hinder imports during critical supply conditions.”
Planners didn’t have enough data to factor in the effect of decreased load on summer demand from the COVID-19 crisis and California’s stay-at-home order.
After Gov. Gavin Newsom issued the order in March, weekday loads were down by about 7.5% during peak-demand times and down 5% during off-peak times; weekend load reductions were 3% during peak demand and 1% off-peak, CAISO has said. (See Western EIM Governing Body Hears COVID-19 Updates.)
CAISO and the California Public Utilities Commission have been worried about capacity shortfalls that were projected to start as early as this summer and grow significantly worse beginning in summer 2021.
The CAISO assessment could allay fears about capacity shortfalls this summer, but next year may be another story.
Last September, Mark Rothleder, CAISO vice president for market policy and performance, told the CPUC that the state was facing shortfalls to its capacity needs, including a 15% planning reserve, of 4,400 MW in 2021 and 4,700 MW in 2022. (See CAISO, CPUC Warn of ‘Reliability Emergency’.)
“The issue is not so much at the peak hour,” Rothleder said. “It’s at the near-peak hour as the sun goes down.”
CAISO and the CPUC have been working to address the issue. The commission ordered some older once-through-cooling plants that were scheduled to retire to remain open through 2023. It also ordered all load-serving entities under its oversight to collectively procure 3,300 MW of capacity, on a basis proportional to projected load, by August 2023. (See California PUC Votes to Keep Old Gas Plants Operating.)
Incumbent transmission owners in PJM won a victory last week as the Planning Committee endorsed creation of a new regional targeted market efficiency project (RTMEP) process that would be excluded from competition. The new process will involve backward-looking analysis to address persistent congestion not identified in the forward-looking planning model.
The PC endorsed a combined proposal by American Electric Power and FirstEnergy on the RTMEP process with 56% support. The AEP-FE package, which would exempt RTMEPs from competition, edged out PJM’s proposal (55% support), which called for 30-day competitive windows to select the developer.
The two packages were otherwise identical. They would calculate benefits based on the average of the past two years of day-ahead and balancing congestion, adjusted for outage impacts. To be approved, a project would have to recover the project’s capital cost within four years.
AEP-FE’s proposal for the benefit calculation metric also was preferred, winning 54% to PJM’s 52%. AEP and FE would employ a single-draw Monte Carlo simulation, with simulations for both Reliability Pricing Model and Regional Transmission Expansion Plan (RTEP) years. PJM proposed averaging Monte Carlo results and running them on RTEP, RTEP+3 and RTEP+6 years. Projects must have a capital cost under $20 million and be in service within three years.
The Independent Market Monitor’s proposals on those two components each received less than 20% support.
PJM’s proposed window for capacity drivers won 52%, besting the IMM’s proposal with 25%. (AEP and FE did not offer an alternative window.) PJM proposed a 24-month cycle for energy drivers and a 12-month cycle for capacity.
AEP and FE said the interregional PJM-MISO TMEP planning process has produced six projects costing $120,000 to $6.7 million, none of which involved greenfield projects and each of which was assigned to incumbent TOs. Three involved line reconductoring; two required replacing or upgrading terminal equipment; and one was for reconfiguration of a ring bus. The companies said they expected that regional TMEPs would produce similar projects.
The PC’s May 12 endorsement culminated 18 months of work the Market Efficiency Process Enhancement Task Force and sets up final votes at the Markets and Reliability Committee. Each issue in the package needed at least a 50% vote to move on to the MRC for a final sector-weighted vote.
Greg Poulos, executive director of the Consumer Advocates of the PJM States, asked when manual language will be drafted for the AEP package to be voted on. PJM’s Jack Thomas said manual language or government document language will be drafted for the first read at the June MRC meeting but could be pushed back to the July meeting depending on how long it takes to put together.
Changes Approved to CISO Issue Charge
The PC approved Exelon’s revisions to the Critical Infrastructure Stakeholder Oversight issue charge over the objection of the original sponsor, the D.C. Office of the People’s Counsel.
Exelon’s redline of the issue charge that was originally endorsed by stakeholders in December was approved by a 61% vote. The D.C. OPC had proposed the issue charge in response to transmission owners’ decision to file a new Tariff Attachment M-4 for the planning of critical infrastructure protection (CIP-014) mitigation projects (CMPs). (See “Critical Infrastructure Mitigation,” PJM PC/TEAC Briefs: Dec. 12, 2019.)
The original issue charge said it would consider whether “procedures that provide stakeholder oversight of CMPs and CIP-014 facilities are appropriate.”
Exelon’s revision eliminates the term “stakeholder oversight,” saying instead that it will “evaluate whether procedures are appropriate for stakeholder review of measures to avoid a transmission facility from becoming a future CIP-014 facility and of the process that would handle mitigation of future CIP-014 facilities.”
Exelon brought the changes of the issue charge to the April PC meeting and agreed to delay a vote until the May meeting so discussion could be conducted with stakeholders. “We made an effort to make it clear that we’ll be focused on the avoidance of future assets,” Exelon’s Robert Taylor said.
Erik Heinle of the D.C. OPC presented an alternative to the redline version of the issue charge that included developing nondisclosure agreements regarding assets under CIP-014. His proposal was rejected, with 61% voting against it.
Heinle said stakeholders agree on wanting to address critical infrastructure avoidance. He said the biggest issue is determining the appropriate levels of confidentiality for projects.
“We should work on getting the policy right with mitigation, with avoidance, with confidentiality and send it to FERC and say, ‘This is the best policy that we’ve drawn up to address these facilities,’” Heinle said.
Poulos said the Critical Infrastructure Stakeholder Oversight group is very close to finishing its work. But he said the Exelon changes removed the consumer interest from the Tariff in regards to CMPs. Poulos said the changes proposed by Exelon are not typically done in an issue charge, and he indicated that he may bring the issue up directly to the MRC.
Taylor said Exelon incorporated stakeholders’ feedback in its revisions. “I think it’s fairly inappropriate to come out of the gate saying that if we don’t get our way out of the Planning Committee vote, we’re going to take it straight to the MRC,” Taylor said. “We’ve really tried to bend over backwards to take into account the concerns that have been raised.”
Emily Smithman of the New Jersey Board of Public Utilities said the BPU supported the original issue charge and disagreed with Exelon’s changes. Smithman said the BPU views the changes as increasing noncompetitive transmission investment in PJM.
Taylor said Exelon doesn’t see the mitigation of critical infrastructure as a competitive process, saying FERC has ruled that competition is not suitable for the assets.
“I don’t think anybody has envisioned or proposed that there would be a competitive window for these projects,” Taylor said.
PMU Placement First Read
PJM is considering using a “quick fix” Tariff revision to address the RTO’s plans to expand the use of synchrophasors and formalize their placements into the RTEP.
Shaun Murphy of PJM reviewed the problem statement, issue charge and proposed solution during a first read to require synchrophasors — also known as phasor measurement units (PMUs) — in all new substations and major construction projects to monitor bus voltage and line flows. The committee will be asked to approve the issue charge and endorse the proposed manual language at the June PC meeting under the quick-fix process detailed in section 8.6.1 of Manual 34.
In the PJM presentation, Murphy said additional language is being proposed for section 1.4.1.3 of Manual 14B that would include a PMU Placement Strategy (PPS) to identify the synchrophasor device coverage needed to support the RTO’s real-time synchrophasor applications. The PPS would include placement targets and required operational dates to guide installation plans and make mandatory a program that is currently voluntary.
Murphy said instituting the PPS would close the gap between research and real-time control room use, and improve data reliability and oscillation detection.
PJM completed a PMU data exchange with the Tennessee Valley Authority in February and expects to exchange data with Southern Co. and SPP later this year. The exchanges are intended to support reliability coordinator situational awareness and the Department of Energy’s oscillation detection pilot, an effort prompted by the Jan. 11, 2019, oscillation event. (See Oscillation Event Points to Need for Better Diagnostics.)
Murphy said the communication equipment needed at each substation costs as much as $120,000, and each substation would have two or three PMUs that cost about $10,000 each. As many as 889 projects could be created over a 12-year span if a voltage threshold of 115 kV for each unit is accepted, according to data presented by PJM.
Calpine’s David “Scarp” Scarpignato asked if the Tariff revisions would change the requirements for new generation having to install PMUs and if there would be any change for existing generators.
Murphy said PJM did not expect any changes for existing generators, but he said there could be an impact for generators on future generation projects depending on the manual language adopted.
Scarp requested that the impact on future generation projects be included in PJM’s next presentation.
Dave Mabry of the PJM Industrial Customer Coalition questioned the RTO about the cost of the initiative. According to numbers provided in the presentation, Mabry said, the cost could be as much as $135 million.
“I think my clients aren’t really sold that this technology is a need-to-have,” Mabry said. “We’re seeing it more as a nice-to-have and perhaps still not ready for prime time.”
Load Forecast Update
Andrew Gledhill of PJM provided an update on estimated COVID-19 pandemic impacts on PJM loads.
Gledhill said the high-level findings of the pandemic’s estimated impact on load has shown weekday peaks coming in 10% less than normal, or about 9,000 MW. Gledhill said the weekday peak impacts have ranged from 6.5 to 15.2%, with the largest estimated impacts happening on May 4 and 5 at 15% and 15.2%, respectively.
Energy has tended to be less affected by the pandemic, Gledhill said, with the average reduction since March 24 coming in around 7.9%. He said the hourly load shapes have been flatter than what is typically seen in the spring, and weekends seem to have been less impacted.
Gledhill said PJM has updated the RTO forecast using economic assumptions from April in place of the September 2019 forecast. He said planners intend to use the April economics for the parameters for the 2021/22 delivery year in the second Incremental Auction scheduled for July.
Whether there will be additional forecast updates has to do with the timing of the eventual 2022/23 and 2023/24 Base Residual Auctions, Gledhill said, as forecasters are still waiting for guidance on when the BRAs will run.
“This is an event that we’ve never seen,” Gledhill said. “So, getting as much information as possible is key to understanding how it’s affecting load and how it might affect load in the next several months or year.”
Transmission Expansion Advisory Committee
Beaver Valley Reinstatement Cuts $93M in Tx Spending
The reinstatement of the Beaver Valley nuclear plant will eliminate $93 million in planned transmission upgrades, PJM told the Transmission Expansion Advisory Committee.
FirstEnergy Solutions (FES) had filed a deactivation notice for the two-unit, 1,872-MW nuclear plant in Shippingport, Pa., in March 2018, targeting a 2021 retirement. But Energy Harbor, the new name for FES after emerging from Chapter 11 bankruptcy in February, told PJM in March it would keep Beaver Valley in operation, citing Pennsylvania’s plan to join the Regional Greenhouse Gas Initiative. (See Beaver Valley Nuclear Plant to Say Open.)
Beaver Valley Nuclear Power Plant
PJM initially identified $414 million in needed transmission upgrades after FirstEnergy announced the retirements of the Davis-Besse, Perry and Beaver Valley nuclear plants and six coal plants in 2018. The RTO reduced the projects to about $216 million after Davis-Besse, Perry and three coal units were reinstated last July.
With the reinstatement of Beaver Valley in March, the price tag has been cut to $123 million, PJM’s Phil Yum said.
He said eight baseline projects totaling $94 million are either already built or too far along in construction to cancel. Three other baseline projects totaling $8 million are still required for identified violations from the remaining deactivations, Yum said.
PJM’s re-evaluation also identified a needed $21.4 million upgrade to the 138-kV Smithton-Shepler Hill Junction line (B3214), Yum said.
All pending baseline projects are currently on hold, Yum said, and a final decision on canceling the projects will occur after the completion of required RTEP analysis and interconnection service agreements (ISAs) for affected generation queue projects.
The Beaver Valley reinstatement was included in the 2025 RTEP model build, Yum said.
TO Supplemental Projects
TOs presented more than $300 million in supplemental project solutions to the TEAC.
American Electric Power
AEP will spend $120 million to reconductor or rebuild 18 miles of 138-kV lines and install a 138-kV +/-75-MVAR Statcom system for dynamic voltage support as part of a project in response to a customer request for new service west of Cameron, W.Va. The forecasted peak demand is 30 MW initially, with long-term prospects of 90 MW (AEP-2018-OH032). The $120 million project will address strains on the local 138-kV system.
Commonwealth Edison
Commonwealth Edison will spend $65 million to rebuild the 345-kV Itasca bus as an indoor GIS double ring bus expandable to breaker-and-a-half connecting four lines and two transformers (ComEd-2020-002).
ComEd also plans to spend $55 million to rebuild the 345-kV Elmhurst bus as an indoor GIS double ring bus expandable to breaker-and-a-half connecting two lines and three transformers (ComEd-2020-003).
Both projects are needed to replace straight bus designs that do not meet current standards.
Dominion Energy
Dominion Energy Virginia will interconnect a new substation by cutting and extending Line 2137 (Poland-Shellhorn) about a half mile to the proposed Aviator Substation with a four-breaker ring arrangement to create an Aviator-Poland line and an Aviator-Shellhorn line at a cost of $22 million. The new Aviator substation is needed to accommodate a new data center campus in Loudoun County, Va., with a total load in excess of 100 MW (DOM-2020-0003).
It also will spend $40 million to construct a 230-kV underground line from the Tysons Substation to a new Springhill Substation to replace the portion of existing overhead Line 2010. It will install a 230-kV, 50-100-MVAR variable shunt reactor at Tysons. The project, which will span about three-quarters of a mile, was requested by a customer and Fairfax County to allow construction of a planned mixed-use development (DOM-2020-0010).
PJM on Friday hosted an Interregional Planning Stakeholder Advisory Committee (IPSAC) meeting to provide input for the development of the Northeast Coordinated System Plan (NCSP), which outlines planning activities conducted jointly by ISO-NE, NYISO and PJM.
Nebiat Tesfa, a PJM transmission planning engineer, said the group will continue coordinating studies across the grid operators’ seams and issue the next NCSP by spring 2022.
PJM interconnection queue projects jointly coordinated with ISO-NE and NYISO | PJM
PJM Tx Planning
Tesfa presented updates on PJM’s planning processes and Regional Transmission Expansion Plan (RTEP).
She noted FirstEnergy Solutions’ March announcement that it would withdraw its deactivation of the 1,872-MW Beaver Valley nuclear plant in Shippingport, Pa., citing Pennsylvania’s efforts to join the Regional Greenhouse Gas Initiative (RGGI). (See Beaver Valley Nuclear Plant to Stay Open.) The company had filed a deactivation notice for the plant in March 2018, targeting a 2021 retirement.
PJM generation deactivation update since Nov. 1, 2019 | PJM
“As a result, there are several baseline upgrades identified,” Tesfa said. “Beaver Valley only recently announced the withdrawal of their deactivation request, and as a result, PJM is evaluating the impacts of the reinstatement of those generators, and we’ll provide the results in the future meetings.”
PJM is working to determine which transmission upgrades it can cancel in response FirstEnergy Solutions’ reversal, she said.
ISO-NE Tx Planning
Brent Oberlin, ISO-NE director of transmission planning, presented updates on the RTO’s transmission planning evaluations of the New England system.
Oberlin highlighted Tariff changes to enhance the competitive transmission solicitation process, which FERC approved in December, including:
creation of the Selected Qualified Transmission Project Sponsor Agreement (SQTPSA) to help determine the design and build of a new transmission project;
improvements to Attachment K to the Open Access Transmission Tariff; and
modifications to Schedule 12C of the Tariff to establish a new baseline for consideration of localized costs.
ISO-NE has completed a number of transmission planning studies, driven by the upcoming retirement of the Mystic generators in Connecticut, he said.
The RTO’s competitive transmission solicitation for Boston garnered 36 proposals from eight qualified parties by the March 4 deadline, Oberlin said. The RTO is confident that some proposals in the phase one study process are going to be available for New England ahead of the June 1, 2024, retirement date for Mystic 8 and 9. (See “Faster Boston RFP,” NEPOOL Participants Committee Briefs: May 7, 2020.)
ISO-NE received two submittals this year on the region’s public policy transmission planning process, one from National Grid and the other from the Episcopal Diocese of Rhode Island, each of whom identified public policy requirements or other actions that, in their view, drive transmission needs, he said.
“All that information was forwarded to the New England States Committee on Electricity (NESCOE), and the way that works is they have the option of providing a response to the ISO … and they can also supplement that information,” Oberlin said.
NESCOE responded that it does not think ISO-NE should be studying any public policy transmission upgrades for this cycle, he said.
“We did add two new projects, which were to address the time-sensitive needs in Boston,” Oberlin said.
Thirty-four new projects were added to the asset condition list, the lion’s share of which were for replacing aging infrastructure, such as wooden poles damaged by woodpecker holes, he said.
NYISO Tx Planning
Philip Chorazy, NYISO senior engineer for public policy and interregional planning, presented updates on the ISO’s Comprehensive System Planning Process (CSPP).
The 2020 Reliability Needs Assessment (RNA) will incorporate impacts of a new peaker rule into its base case reliability analysis, Chorazy said. The New York State Department of Environmental Conservation adopted a regulation to limit nitrogen oxide emissions from simple cycle combustion turbines, or peaking units, he said. The new regulations go into effect May 1, 2023, with initial rate limits of 100 parts per million on a dry volume basis, corrected to 15% oxygen. (See NY DEC Kicks off Peaker Emissions Limits Hearings.)
NYISO Congestion Assessment and Resource Integration Study (CARIS) phase I congestion groupings | NYISO
The RNA also will include a scenario evaluating the impacts of 70% of energy produced from renewable resources by 2030 for both transmission security and resource adequacy, with the first pass of RNA results to be presented next month, Chorazy said. New York’s Climate Leadership and Community Protection Act (A8429) signed into law last July calls for 70% of the state’s electricity to come from renewable energy resources by 2030, doubles the distributed solar generation target to 6 GW by 2025 and nearly quadruples the previous offshore wind energy target to 9 GW by 2035.
Chorazy also explained that the ISO’s the Congestion Assessment and Resource Integration Study (CARIS), which determines the top three congested locations in the New York Control Area and is intended to develop generic solutions for transmission, generation, demand response and energy efficiency. The 2019 CARIS Phase 1 draft report was presented at the ISO’s Electric System Planning Working Group in April, with a final draft scheduled for July, pending Board of Directors approval.
NYISO will initiate the 2020/21 Public Policy Transmission Planning Process cycle in August by issuing a solicitation for proposed transmission needs driven by public policy requirements, Chorazy said.
A regionally planned undersea transmission 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 released Thursday.
Brattle prepared the study on behalf of transmission developer Anbaric Development Partners, which has proposed the Southern New England OceanGrid, an open-access network that would interconnect future offshore wind projects in the federal wind lease area off the coasts of Rhode Island and Massachusetts.
Brattle compared the costs of such a proposal to the expected costs under the current approach of each offshore project using one generator lead line (GLL) to interconnect to an onshore point of interconnection (POI). Four projects under development worth 3,112 MW — Vineyard Wind, Mayflower Wind, Revolution Wind and Park City Wind — already plan to use their own GLLs.
The Brattle Group compared two different scenarios: one in which each offshore wind project interconnecting to the grid uses its own individual line (left), and another in which a shared, open-access offshore grid is planned. | The Brattle Group
But New England will need possibly more than 40 GW of offshore wind by 2050 to meet states’ decarbonization goals — or as much as 1.5 GW every year, Brattle said. If every project followed the current approach, it could lead to major onshore transmission overloads, the group found.
“These overloads, and the massive amounts of marine cabling, could be reduced dramatically with a planned approach,” Johannes Pfeifenberger, a principal at Brattle, said in unveiling the study during a webinar hosted by Massachusetts-based State House News Service on Thursday.
| Massachusetts CEC
Pfeifenberger explained that because projects would share HVDC lines under a planned approach rather than individual HVAC lines, in addition to reducing costs and congestion, a planned grid would also lessen the amount of marine trenching needed, mitigating damage to the undersea environment. Power line loss would also be reduced, as the length of cables would be shorter.
Brattle broke down its comparison into two phases: one based on states’ current procurements besides the four projects already expected to use GLLs (2.8 GW) and an expected extra 800 MW; the second based on using up the remaining lease area (about 8.2 GW).
Under both the baseline scenario, which assumes projects continue to use their own GLLs, and the planned scenario, Phase 1 would see 3,600 MW in transmission capacity built. But under the current approach, nine HVAC lines stretching a combined 694 miles would be built, with “significant onshore transmission overloads” in Southeastern Massachusetts. Under the planned scenario, only three HVDC lines totaling 356 miles are built, with only “minimal” congestion near the POI at the Mystic Generation Station in Everett, Mass.
‘A Bowl of Spaghetti’
The differences become even more stark in Phase 2. In the baseline scenario, onshore transmission becomes even more congested and spreads across Massachusetts, Rhode Island and Connecticut. More individual GLLs are added, crisscrossing each other under the sea before they reach their POIs: “a bowl of spaghetti,” as Pfeifenberger described it, “of many lines; 18 [to] 20 lines emanating from the offshore wind lease area and interconnecting at various points onshore.”
In the planned scenario, additional HVDC lines are bundled with existing ones, untangling the “spaghetti” to create only four discernable routes to about the same number of POIs.
Overall, under Brattle’s planned scenario:
total transmission costs are 10% lower, with a 65% reduction in onshore upgrade costs offsetting an expected 22% increase in offshore construction costs;
line losses are about 40% lower;
line mileage is about 49% lower; and
ratepayers would save about $20 million annually.
“Importantly, you also create more competition under the planned approach,” Pfeifenberger said. “You would have people compete for building the offshore grid; then you would have wind developers for interconnecting their projects to onshore grid locations. … Offshore wind developers would not have to worry about the transmission component of their projects.”
The risk of stranded assets is also lessened, Brattle said.
“Without a well-planned offshore grid, some of the existing offshore lease sites may not be economic to develop,” the study says. “After developers interconnect the bulk of their lease sites, it may be cost-prohibitive to interconnect the residual areas (of perhaps 50 to 250 MW each) using AC generator lead lines sized to carry about 400 MW each.”
There’s also “a limited number of landing sites for offshore wind transmission in New England,” said Pfeifenberger’s associate at Brattle, Walter Graf. “If each offshore wind project requires a separate cable interconnection to the onshore transmission system, viable cable routes become really constrained.”
Anbaric and other transmission developers, eager to capitalize on the growing interest in offshore wind, have long been advocating for the benefits of offshore transmission planning. (See Anbaric Pushes Offshore Grid Plans.) But Brattle’s study appears to be the first attempt to quantify those benefits.
Anbaric’s proposed Southern New England OceanGrid | Anbaric
“Brattle’s research underscores the pivotal role of transmission policy in the development of New England’s offshore wind industry,” Anbaric said in a statement. “By relying on landing points closer to population centers and at robust onshore grid locations, a planned system reduces grid congestion and the need for expensive, disruptive onshore transmission projects that could hinder the growth of offshore wind.”
States have shown interest in such an approach. (See Mass. DOER Explores Transmission for OSW.) And webinar attendees, many of which were state regulatory staffers, were eager to get their hands on the Brattle study, if the side chat room in the webinar was anything to go by: Pfeifenberger repeatedly linked to his presentation as Graf spoke in response to requests from those apparently unaware they could see his previous answers.
Brattle compared a planned offshore grid to previous renewable-facilitating transmission projects, such as Texas’ Competitive Renewable Energy Zones and MISO’s multi-value projects. “New England could adopt a similar approach to planning transmission infrastructure to support offshore wind,” it said.
The PJM Operating Committee on Thursday unanimously approved an initiative to consider rule changes for the substitution and termination of black start resources.
David Kimmel of PJM reviewed the problem statement and issue charge, focusing on four areas in the Tariff that the RTO identified as in need of updates: testing requirements for black start resources not compensated through Schedule 6A; black start unit substitution rules; black start termination rules; and the black start capital recovery factor. (See PJM Eyeing New Black Start Changes.)
In March, PJM suspended an initiative considering fuel security requirements for black start units, which faced opposition from state regulators and consumer advocates. (See PJM Backs off Black Start Fuel Rule.)
Stakeholders also unanimously approved an amendment to the problem statement and issue charge proposed by Independent Market Monitor Joe Bowring to add an update to rules governing oil-carrying costs and minimum tank suction levels (MTSL).
Bowring said the MTSL issue has been left unaddressed in the Tariff for several years, leaving no clear language as to how shared resources like fuel tanks should be treated. He said many black start units charge customers for 100% of the MTSL. That charge is overstated when the tanks were sized to meet the needs of the generating units that share the tank and that use significantly more oil than the black start requirements, he argues.
The Monitor recommends that only a proportionate share of the MTSL for oil tanks shared with other resources be allocated for black start units, Bowring said, as this would help ensure that only costs directly related to black start service are paid by customers. (See “Black Start Fuel Assurance,” PJM Operating Committee Briefs: May 1, 2018.)
Becky Davis of PJM provided education on black start testing, termination rules, substitution and the capital recovery factor.
The work time on the black start issue is expected to take two to three months, and implementation of the changes needed to governing documents is estimated to take about six months following the potential Tariff changes.
COVID-19 Still Impacting Load
PJM’s Stephanie Monzon reviewed the April operating metrics, pointing to an hourly average error in load forecasting of 2.61% and a peak error of 2.31%.
Monzon said PJM continues to see the effects of state stay-at-home orders resulting from the COVID-19 pandemic and the impacts of warmer weather on load forecasting. Monzon said forecasters have predominantly over-forecasted on most days but remain within the target error of +/-3%.
Gary Greiner, director of market policy for Public Service Enterprise Group, asked about April 13, when PJM’s forecast fell short by more than 8%.
Daily peak forecast error (April) | PJM
Monzon said there was an unexpected morning peak in the Mid-Atlantic region. As the control room operators were adjusting for the morning peak, Monzon said, the models were trying to adjust for a different expected peak.
Greiner said that when the operator adjusts the forecast, that adjustment becomes the reported forecast and can have a major impact on pricing.
“It seems like I’m being nitpicky, but this is a huge driver of price, so it’s an important error to minimize,” Greiner said.
Monzon reported that the only spinning event for the month was also on April 13, lasting for eight minutes from 3:53 to 4:01 p.m. in the Mid-Atlantic Dominion sub-zone. Monzon said the event consisted of a Tier 1 estimate of 433 MW and a Tier 1 response of 207.2 MW.
She also said that overall, April was a quiet operational month, with five reserve sharing events with the Northeast Power Coordinating Council, 12 post-contingency local load relief warnings and eight high system voltages.
Two shortage cases were also approved, Monzon said, with both occurring on April 30 at 11:55 a.m. and 12:05 p.m. She said PJM was seeing generation that was expected to serve load start staggering online and had some generation trip off the system.
The Market Implementation Committee will be asked next month to choose between a PJM proposal and one from the Independent Market Monitor to resolve pricing and dispatch misalignment issues in the RTO’s fast-start pricing plan.
At the MIC meeting Wednesday, PJM’s Tim Horger outlined the RTO’s plan, which calls for three “work streams”: short-term market changes to address pricing alignment; LMP verification “enhancements and clarifications”; intermediate operational changes to implement more “regimented” real-time security-constrained economic dispatch (RT SCED) case approvals; and long-term operational changes to investigate changing SCED timing and consider previous dispatch instructions.
PJM’s proposed short-term fixes align the locational price calculator (LPC) to use the reference RT SCED case for the same target time. LPC would calculate prices for the interval from 11:55 a.m. to 12 p.m. using the RT SCED solution for a 12 p.m. target time.
“PJM is committed to both the short-term changes and the intermediate changes,” Horger said. “We will be moving forward with these.”
Proposed short-term implementation | PJM
Rebecca Carroll provided a timeline for the PJM intermediate solution that calls for conducting operator training and making software changes to limit automatic execution of RT SCED cases to once for every five minutes. Additional cases may be manually executed and approved as needed by dispatchers under what PJM calls this “intermediate” change.
Carroll said PJM already switched from a three-minute interval to four minutes for operators in February, moving closer to the desired five-minute dispatch interval. Carroll said no adverse impacts to pricing were discovered with the time change, but she said closing the gap gives less flexibility for operators to make changes in real time and urged being “cautious” before taking the next step.
The “more regimented five-minute case approval [is] very different from what PJM’s operators see today and have done [as long as] they’ve worked for PJM,” Carroll said. “It’s definitely going to be a philosophy shift in the control room.”
Catherine Tyler of Monitoring Analytics presented the Monitor’s proposal, which was originally the joint package between it and PJM. The RTO withdrew from the proposal at the April 15 MIC meeting.
Tyler said the proposal includes changes to dispatch SCED calculations and settlements, while the PJM proposal only includes making the settlement changes.
“The difference is not in the timing of implementation so much as commitment to making all of the changes that need to be made,” Tyler said.
Carroll and Adam Keech, vice president of market services, insisted the RTO is committed to making the changes, although it can’t say when. “PJM is planning to move forward to a five-minute periodic dispatch,” Keech said. “We need to take operational precautions … we need to learn along the way.”
Stability Limits in Markets and Operations
PJM’s Joe Ciabattoni told the MIC that the RTO could support the Monitor’s proposal to use capacity constraints to curtail generating output when needed to maintain stability during maintenance outages or continue using thermal surrogates.
Generating units must sometimes be reduced below their normal economic max limit if a planned or unplanned transmission outage presents stability problems that could result in damage to the units.
After stakeholder discussion and feedback at April’s MIC meeting, “PJM can still jointly sponsor the existing package with the IMM but can also support the status quo,” Ciabattoni said. (See “Work Continues on Stability-limited Generators,” PJM MIC Briefs: April 15, 2020.)
Ciabattoni said some of the feedback received from stakeholders was that the stability constraint or generator output constraint doesn’t fully resolve the issue that the LMP would not be aligned with the dispatch signal. Current rules require the RTO to implement a thermal surrogate to reflect the stability constraint in the day-ahead and real-time markets and to bind the constraint, affecting the unit’s dispatch.
Tyler reviewed the Monitor’s proposal. It says surrogate constraints are not modeled consistently in the day-ahead and real-time markets, resulting in differences that traders can take advantage of.
PJM’s Thomas DeVita provided an update on the RTO’s response to a complaint filed with FERC last month over its forfeiture rules for financial transmission rights.
XO Energy asked FERC to order PJM to change its FTR forfeiture rule or abandon it and adopt “a structured market monitoring approach” like the one used by Trader Challenges PJM FTR Forfeiture Rules.)
DeVita said he couldn’t give specifics as to how PJM is going to respond to the complaint, but he said the RTO’s answer will focus primarily on compliance with FERC’s January 2017 order (EL14-37). In that order, FERC instructed PJM to change how it implements the forfeiture rule, saying the RTO’s focus on individual transactions failed to capture the impact of a market participant’s overall portfolio of virtual transactions on a constraint. (See FERC Orders Portfolio Approach for PJM FTR Forfeiture Rule.)
PJM filed Tariff revisions in April and June 2017 describing its new approach (ER17-1433). In September 2017, the RTO began billing forfeitures based on its new approach, XO said in its complaint, even though the commission has never acted on it.
“It’s been pending at FERC for three years, which is a significant amount of time, even by FERC standards,” DeVita said.
Comments on the XO complaint are due June 1.
PJM Seeking Consultant on ARR FTR Task Force
PJM is seeking a consultant to aid the ARR FTR Market Task Force in a review of the FTR and other markets.
PJM’s Dave Anders said the consultant is being hired in response to a recommendation of the Report of the Independent Consultants on the GreenHat Default, which called for expert help “to conduct a general review of the FTR market and other PJM markets in order to evaluate risks and rewards of structural reforms.”
After focusing primarily on the education portion of the key work activities, Anders said the task force has reached the point of needing to engage expert help in the review process.
The scope and timing of the review is currently being developed, Anders said, with PJM looking at the task force’s remaining key work activities to determine what can be accomplished and what should be put on hiatus during the external consultant review. The scope and timing plan will be discussed at the next task force meeting on May 27, Anders said, which has been cut back to a half-day of discussion.
Gary Greiner, director of market policy for Public Service Enterprise Group, asked if PJM has a sense of what the external consultant’s mission will be. He said it would be important to have an idea of the scope of the work ahead of time in order to pick the right consultant.
Anders said PJM is currently working on the scope and welcomed ideas from stakeholders on what they would like to see included in the work.
“We want to share the scope with stakeholders, but we’re not really ready yet because it’s still in development,” Anders said. “The selection is going to be interesting because there certainly are a number of experts out there that have deep knowledge of the products and the market.”
‘Quick Fix’ for NITS Rule
The MIC approved an issue charge and a “quick fix” Tariff revision to address a regulatory change in Ohio concerning the billing of network integration transmission service (NITS). PJM requires load-serving entities to sign NITS agreements and post collateral based on their peak market activity. The expected duration for Tariff revisions is two to three months. (See “‘Quick Fix’ on PMA Credit Requirements,” PJM MIC Briefs: April 15, 2020.)
If another television commercial or online public service announcement intones this lazy, probably insincere attempt to offer comfort during our collective pandemic experience, I might throw my laptop or television out a window. I might — except, because I’m largely confined these days to a single-story building, it wouldn’t result in the effect or satisfaction that is supposed to accompany this fit of pique. Cranky? Yes, I am! Along with many of my fellow pandemic inmates in cell block H. But while out in the exercise yard walking the dog recently, it struck me that another addition to our virus vernacular, “flatten the curve,” might offer a useful way to think about emerging challenges facing electric grid operators.
As we now unfortunately have all come to understand, in pandemic terms, “flattening the curve” refers to slowing the otherwise exponential spread of a virus to avoid overwhelming limited health care infrastructure and human resources. The analog in our industry is “flattening or shifting the peak,” and it’s not something we’ve historically done well.
Years ago, I likened grid planning and resource adequacy to a church designed to ensure every congregant, visitor, curious heathen, adherent to family tradition and the like was guaranteed a seat for Easter services, with 15% more pews added over the forecast attendance for good measure. As times changed, I shifted toward a more secular illustration: the example of a fictitious ordinance by the city of New Orleans requiring construction of hotels to cater to every person who might want to attend Mardi Gras, plus a prudent reserve. That’s a lot of excess capacity to expect the local hospitality industry to carry over the many sweltering, hurricane-threatened months when most sane tourists would opt for Maine or Yosemite over Bourbon Street.
The point was not to suggest that electricity should be planned and provided like church pews or hotel rooms. Society values continuous, on-demand electricity differently and for many good reasons. But still, the laws of economics aren’t suspended when it comes to our industry. Carrying large, fixed costs associated with infrastructure lying fallow for months on end is either quickly unsustainable or results in high tariffs that over time shift the supply-and-demand equilibrium, resulting in a suboptimal allocation of consumer and producer surpluses and reduced total economic well-being. In other words, in most industries, while shortage may not be a good thing, it is at least a necessary evil.
For grid operators and planners, demand is still largely unexposed or is inelastic to price. Shortage isn’t an option. And the price of electricity, despite being delivered like a guaranteed hotel room during Mardi Gras, is still a good deal as a “value proposition” for most consumers. But from the perspective of those interested in designing organized wholesale electricity markets, the economic inefficiency of our industry’s infrastructure profile keeps people working on demand response, advanced metering and regulatory reform to expose more customers to actual real-time prices for electricity in the wholesale market. Here, the hope is that prices can be harnessed to change consumption behavior to flatten peaks through a curtailment or temporal shift of consumption. As mentioned, despite huge theoretical promise, as an industry we have had modest success at best in identifying and controlling discretionary consumption through either price or programs.
Today, new fronts have opened to tackle this problem. The motivation here isn’t the economic inefficiency associated with transmission and generation infrastructure in waiting. Rather, the concern is operational. Public tolerance to ever-expanding infrastructure, particularly transmission, is limited. Let’s face it: Electric infrastructure has less aesthetic appeal than a cathedral and arguably even less than a Trump Tower hotel. More salient, is the changing generation resource mix and, in particular — through policy mandate, customer preference or otherwise — the increasing penetration of intermittent, renewable wind and solar generation. We’ve all heard of CAISO’s “duck curve” and seen ramp rates become steeper year after year. In a carbon-constrained world, the role of flexible natural gas generation to “back up” and follow load is viewed as a temporary solution at best. So, we redouble efforts to conform an uncooperative supply curve populated by intermittent generation to an inviolate load curve.[efn_note]Admittedly one can find isolated, but significant, efforts by certain large customers to change consumption patterns to better align to the limits of the supply curve. For example, Google, which has a goal of real-time, 24/7 zero-carbon operations, has begun shifting the timing of computing functions that are electricity intensive at data centers “to when low-carbon power sources, like wind and solar, are most plentiful.” https://blog.google/inside-google/infrastructure/data-centers-work-harder-sun-shines-wind-blows/We can hope this kind of participation by large data center customers will eventually involve a more complex optimization of business needs, the availability of renewable electrons, electricity price and communication costs across multiple data centers located in different geographies and in different electricity markets. These actions will change load shape to better conform to a changing supply shape.[/efn_note] We ruminate over ideas such as building more transmission to move solar power from Arizona at the speed of light to meet the 8 a.m. morning pick-up in Los Angeles when the sun is still low in the sky over coastal California, and then push overabundant California solar back to Phoenix as the sun begins to set out there. What about batteries and the promise of other advanced clean technologies to add to our supply mix? It’s old news to note that increasing reliance on renewable resources is creating new challenges for system operators responsible for reliably ramping a system up and down to meeting its peaks.
Timing of March/April weekday peaks in PJM | PJM
Fine. But what has the pandemic got to do with any of this? The answer is what today’s grand and involuntary social experiment shows about grid performance and the attendant price outcomes associated with new and different load curves. And while quarantines and shutdowns may persist, they are finite. So, the more interesting point to consider is how more permanent social distancing, work from home and staggered industrial production scheduling could change the load shape, and the grid operation, carbon and economic implications that in turn would follow from this change.
Recently, PJM published data illustrating aggregate impacts of the pandemic situation on its operations over the past six weeks. Of course, it showed overall energy consumption had declined across the region, in a range of about 6 to 8%. It also showed that the peaks had declined by a greater amount — more like 10 to 12%. But things get more interesting looking at the ramp or load shape. Yes, the morning pick-up started later, but it also appears less concentrated in the 7 to 9 a.m. hours and spread out over a longer time period[efn_note]The graph on page 9 of the following document, in particular, illustrates changes to peaks: https://pjm.com/~/media/committees-groups/subcommittees/las/2020/20200505/20200505-item-03-covid-19-impact-update.ashx[/efn_note] — a “flattening of the curve,” if you will. Other operators are also showing evidence of a more gradual and delayed morning peak just like PJM; implications to the evening peak are less conclusive.[efn_note]NYISO spokesperson Zach Hutchins reported: “We continue to observe a more gradual morning ramping period.” (April 2, 2020 9:45 a.m.) https://www.nyiso.com/covid[/efn_note]
I’m not one to characterize anything associated with our current human health and economic catastrophe as a “silver lining.” But very early observations suggest that certain “new normal” post-COVID scenarios affecting how society lives and works may change load behaviors in a way that decades of price incentives and regulatory programs have largely failed to do[efn_note]The data we have after just six weeks of a shutdown that has occurred during the industry’s shoulder season serves as only a glimpse of what we might expect by way of more permanent changes in load profiles.[/efn_note] — behavioral changes that cause a temporal shift in electricity consumption, flatten the peak and, thus, reduce the strain on a supply side increasingly challenged to meet peaks as it transitions toward cleaner, carbon-free resources.[efn_note]It’s also sometimes easy to forget that in order to meet decarbonization goals, the electric sector is going to have to do more. The electrification of transportation, industrial processes and heating in buildings will increase total consumption and also affect consumption patterns.[/efn_note]
To further burden the analogy, a monthlong Mardi Gras allowing access to more people on less costly terms may be less intense, less fun and have a less obvious crescendo, but it’s probably healthier. More gradual load curves that reduce reliance on fossil-fueled, load-following generation promise beneficial carbon reductions while buying additional time for the development of clean supply side and storage technologies.
It remains to be seen — in fact, I have heard these are “uncertain times” — whether we will return to the “good old days” or instead a “new normal” of social distancing with different patterns of work and life. I hope it’s Door No. 1. But the thought nagging me is that we might be better positioned to address our other evolving global crisis, the climate, if we are forced for health reasons to change how we live and work and, as a consequence, we flatten the curve; that is to say, the load curve.
Vincent Duane is presently consulting through his firm Copper Monarch, LLC. He was previously the Senior Vice President: Law, Compliance & External Relations at PJM Interconnection, LLC.
Texas regulators last week adopted rules establishing a cybersecurity monitor and coordination program for investor-owned, municipal and cooperative utilities that count on their voluntary participation (49819).
The amendments to the Texas Public Utility Regulatory Act (PURA) don’t require utilities to participate or to submit documents to the monitor. Utilities have made the rules’ voluntary nature a key issue in the proceeding.
But that left members of the Public Utility Commission nonplussed over comments made in the docket. Chair DeAnn Walker said during the commission’s open meeting Thursday that she was “taken aback” and “floored” by some of the stakeholders’ comments “and some of the people making those comments.”
The amendments are the result of two bills approved last year by the state legislature. Senate Bill 64 established the cybersecurity coordination program to share guidance on best practices, while SB 936 set up the cybersecurity monitor.
“Over the years, we have had input from the legislators that they clearly wanted something like this,” Walker said.
Commissioner Arthur D’Andrea said that he too was “taken aback” by the utilities’ comments, noting that the PUC has stood “shoulder-to-shoulder” with its stakeholders during the recent legislative session.
Commissioner Arthur D’Andrea
“While [the program is] voluntary, this is not an audit,” he said. “We want to protect their data, but we do expect participation and cooperation.”
When several utilities asked that “voluntary” be added to the rule, the PUC responded by saying the “voluntary nature of participation … is made clear throughout the rule.”
Monitored utilities will contribute to the program through their administrative fee to ERCOT. Those outside the ERCOT footprint will pay for the monitoring under a separate fee.
Any Texas utility “may” participate in the cybersecurity coordination program at no cost.
Commissioners Defend PUC Staff
Walker and D’Andrea both defended commission staff after they felt staff’s comments on an ERCOT Nodal Protocol revision request were devalued in a grid operator stakeholder meeting last week (NPRR1020).
PUC staff filed joint comments with ERCOT staff on NPRR1020, which clarifies that emerging battery storage technologies can be interconnected and operated as a resource. The change proposes to add a definition for “integrated battery storage system” (IBSS) and modifies the definition of “wholesale storage load” (WSL) to include IBSS.
PUC staff did not sign their individual names to their comments, while ERCOT staff did. During the Protocol Revision Subcommittee’s (PRS) meeting Wednesday, at least one stakeholder questioned why PUC staff didn’t sign their names, according to another stakeholder who requested anonymity.
“They wanted a name of a particular staff member. I find that offensive,” said Walker, who relayed her understanding of the PRS meeting based on a phone call she had received from staff.
PUC Chair DeAnn Walker makes a point during the commission’s May 14 open meeting.
PUC staff said PURA rules already allow for storage system loads integrated into a single container to be eligible to receive WSL treatment. They said the current IBSS definition “may arbitrarily exclude some integrated battery systems that do not meet all of the criteria specified in the proposed definition.”
“Therefore, [PUC] staff and ERCOT suggest revisions … in an effort to provide clearer guidance and minimize arbitrary treatment in extending WSL treatment to integrated battery systems,” agency representatives wrote. “The definition should focus on the characteristics that support extending WSL treatment to [storage systems] integrated into a single container instead of adding a new technology category to the WSL definition, which already includes the term ‘batteries.’”
“Technology is going to change. We have to be nimble to be able to change and do things with it,” Walker said. “If staff believes [NPRR1020] falls under our current rule, I find it offensive that people at ERCOT are challenging and saying that staff has no rights and has to [identify themselves].”
“Staff’s position is an institutional voice, and that should be good enough,” D’Andrea said. “This [NPRR] is already two-and-a-half years in the making. I’m already embarrassed by how long it’s taken us to nimbly account for this technology. This is the kind of thing Texas should be able to adapt to and that the markets should be able to handle well.”
The Wholesale Market Subcommittee agreed to take up NPRR1020, and ERCOT staff said it would schedule a workshop on the issue. Like the PRS, the WMS reports up to ERCOT’s Technical Advisory Committee.
ERCOT and PRS Chair Martha Henson, with Oncor, both declined to comment.
Customer Protections Extended to June 17
The commission added another month to its pandemic-related provision that suspends customer disconnections for non-payments, from May 15 until June 17, acknowledging concerns that extensions of the emergency order are being issued open meeting by open meeting (50664).
“I was really hoping at this point we would be further along in our reopening of the state,” Walker said, pointing to the Texas Panhandle and the rising numbers of COVID-19 cases related to meatpacking plants. The state reported more than 700 cases on Saturday alone.
“Those customer bills will continue to rack up,” she said. “At some point, they’re going to get a bill they have to pay.”
“I’m concerned we’re just starting to see the effects of economic disruption,” Commissioner Shelly Botkin said.
The order applies to low-income customers of vertically integrated electric utilities that operate outside of ERCOT: Entergy, El Paso Electric, Southwestern Public Service and Southwestern Electric Power Co.
In other actions, the PUC approved an amendment to the PURA that adds retail brokers or aggregators to those governed by customer protection rules for retail service (50406).
