CARMEL, Ind. — MISO is toying with the idea of foreshortening its 2020 Transmission Expansion Plan (MTEP) process in order to maximize time spent on the 2021 cycle of transmission projects.
The RTO last week said it wants stakeholder approval to stop work on the four 15-year future scenarios used in the 2020 MTEP (requiring it to instead rely on an older version of futures) and to forego the usual planning studies in favor of smaller, specialized studies to identify projects.
MISO Planning Manager Tony Hunziker said the idea is to finish MTEP 20 work early to provide more time to completely retool the future scenarios in time for the 2021 cycle.
“Throughout this process, there’s been this building momentum and increased interest in starting MTEP 2021 futures as early as possible,” Hunziker told stakeholders at a Planning Advisory Committee meeting Wednesday.
Stakeholders asked if the 2020 plan would still contain an Appendix A, the annual list of transmission projects recommended to the Board of Directors for review and approval.
“There would certainly be an Appendix A and the usual reliability projects. This would more impact economic projects,” Hunziker said.
If MISO stops work on MTEP 20, it won’t have the usual Market Congestion Planning Study for the cycle.
“In its place, we could do a couple targeted economic studies,” Hunziker suggested. “We haven’t completely thought through everything yet. We wanted to put this out there and judge stakeholders’ interest.”
He assured stakeholders that MISO wouldn’t skip economic transmission planning for the year; it would just come in a different form.
“We’re still very committed to the economic planning process,” Hunziker said.
He said moving forward with MTEP 20 futures development would “tie staff up until mid- to late summer.”
“If we continue down the path of completing MTEP 2020 futures, it’s going to slide down the time that we can start on the 2021 futures,” Hunziker said.
Stopping work on MTEP 20 would pull staff’s focus entirely to developing MTEP 21 futures, he said. Staff have previously promised stakeholders an extensive rework of the four futures that guide the annual transmission planning process in time for 2021.
MISO had been using the same set of futures with only minor edits for the last three years to evaluate transmission projects. The RTO developed the futures in collaboration with stakeholders with long-term use in mind. (See MISO: Minimal Change to 2019 Tx Planning Futures.)
In April, MISO said it would boost renewable generation estimates in each of the four 15-year future scenarios, bumping minimum penetration levels from 15 to 35% of the generation mix to 20 to 40%. (See Renewables Outlook to Get Boost in MTEP 20 Futures.) However, MISO’s pivot puts that proposal in doubt, with Hunziker saying it could either keep or discard the larger renewable assumptions.
In halting further efforts on MTEP 20, MISO would likely begin 2021 futures discussions in July and schedule four special workshops in fall to gauge stakeholder expectations around a new set of futures.
“Either way we go, we’ll start the MTEP 2021 futures discussion early,” Hunziker said, adding that MISO would begin discussions on MTEP 21 with or without a MTEP 20 work stoppage by September. MISO usually begins futures development in January of each year for the upcoming year’s transmission planning cycle.
A Hijacking?
Some stakeholders pointed out the move would give MISO 27 months to develop futures, risking that enough time could pass for the freshly developed futures to themselves become stale. But Hunziker said the first few months would be spent on how to improve the process and settle on what new data should inform the scenarios.
Clean Grid Alliance’s Natalie McIntire asked how the move would affect MISO’s annual interregional transmission planning efforts with SPP and PJM. She said that because MISO no longer builds a joint model with its neighboring RTOs, it should keep up with grid modeling.
MISO staff said they weren’t yet sure how the new course of action would interact with next year’s interregional planning.
“I’m really surprised and concerned by this,” McIntire said. “It’s concerning that a small number of stakeholders can hijack the process,” suggesting that only a few influential members were in favor of truncating MTEP 20.
However, Xcel Energy’s Drew Siebenaler thanked MISO for proposing a “pared-down” MTEP 20. He said the move would give the RTO the time necessary to evaluate several new state and company renewable targets, new resource retirements and recent zero-carbon commitments for use in its futures.
“Who says we’re going to have that kind of clarity in five months?” consultant Roberto Paliza challenged. “I just don’t see that we’ll have a new set of futures that are radically different.”
“We’re just about done with the MTEP 20 discussion here,” McIntire said. “The whole idea that we would get rid of a big part of MTEP 20 … I don’t think that extra two months [for MTEP 21 futures] is going to be that significant.”
But Hunziker pushed back on that assertion, saying his staff don’t have time to properly facilitate both MTEP 20 futures and studies and early preparations on MTEP 21. He asked for more comments on the issue by June 28.
A tag team of ERCOT executives last week reviewed the grid operator’s summer preparations at the Board of Directors’ last meeting before the big heat. Judging by the few questions from the board, the presentation was well received.
Staff have said they expect to use emergency measures this summer to meet a record forecasted peak demand of 74.9 GW. ERCOT has available capacity of 78.9 GW and a reserve margin of 8.6%. (See ERCOT: More Capacity, but Emergency Ops Still Expected.)
The June ERCOT Board of Directors meeting.
Dan Woodfin, senior director of system operations, told the board that ERCOT expects to “implement energy emergency alerts several times this summer.” He said the alerts would allow it to take advantage of the extra 2 to 3 GW of resources available “only in those limited situations.”
The grid operator does not expect any “wide-area reliability concerns,” Woodfin said. He said Far West Texas may see some congestion from oil and gas and solar development, and areas in the Texas Hill Country and the Rio Grande Valley could experience congestion as well.
The ERCOT system could get a boost if weather forecasts predicting cooler temperatures than the summer of 2018 — when the grid operator set a new peak demand of 73.5 GW — prove accurate. Senior Meteorologist Chris Coleman said it’s “unlikely” to be as hot as last summer, pointing to the ninth-wettest year on record for Texas.
“Wetness tends to suppress heat, to some extent,” Coleman said. He is projecting almost half as many 100-degree days in various Texas cities than last year (five to 14 in Austin, compared to 41 in 2018).
| ERCOT
Kenan Ögelman, ERCOT’s vice president of commercial operations, reminded the board of two Public Utility Commission-mandated changes to the operating reserve demand curve (ORDC), which provides a price adder when generation is scarce.
The grid operator will now blend 24 different ORDC curves, based on season and hour blocks, into one curve that aggregates all the data. This will raise adders above 2 GW of reserves during the summer months, but lower them in the winter, Ögelman said.
The PUC also directed ERCOT to shift the ORDC curve by 0.25 standard deviations, which Ögelman said will create a higher adder for any level of reserves above 2 GW.
IMM Market Report: Load Continues to Climb
The ERCOT Independent Market Monitor’s 2018 State of the Market report says the wholesale market performed “competitively” last year, but it also includes some future warning signs.
In briefing the report, which was filed at the PUC on June 5, IMM Director Beth Garza told the board that load is increasing in all four ERCOT load zones, led by a 15.4% increase in average real-time load from 2017 in the West zone, which includes the petroleum-rich Permian Basin. The average load in the North zone, home to Dallas and Fort Worth, increased 6.5% over 2017, and it was up 5.3% for the ERCOT system.
“There’s substantial load growth everywhere. There’s no other word to describe it,” Garza said.
IMM Director Beth Garza presents an overview of the 2018 State of the Market report.
She said the additional load amounts to a 2.2-GW increase each hour, noting, “That’s like two new combined cycle [generating units] to serve load every hour.”
Given the ever-increasing load, Garza said, “In 2022, the existing fleet is no longer sufficient to serve peak load.”
As it is, the IMM report said system shortages increased in 2018, with about 17 hours of prices above $1,000/MWh. The Monitor expects the trend to continue in 2019.
“What seem like very low reserves may just be the new normal,” the report says. “Given the overall size of the system and projected growth, a more robust reserve margin may no longer be required to cover load forecast errors and mitigate generator availability risks.”
The report also said with distributed generation playing an “increasingly important role in ERCOT, the risk associated with generator outages should decrease.”
Overall, ERCOT’s average prices climbed to $35.63/MWh, a 26% increase from 2017. Higher natural gas prices helped drive the increase, up 8% to $3.22/MMBtu.
The grid operator’s real-time market experienced a 30% increase in congestion costs, which totaled $1.26 billion. The IMM said a costly, localized constraint in Far West Texas was the primary culprit.
The report offers three recommendations to improve the reliability commitment process and resulting pricing:
Evaluate and improve the reliability deployment price adder, which the IMM says is producing results “inconsistent with its original intent.”
Explore options to consider commitment costs for RUC-committed units.
Eliminate the opt-out option for RUC-committed resources.
“Continuing to have the opt-out option is an incentive to withhold capacity,” Garza said. “In our decentralized market, where we count on people to make their own best decisions, the incentives in front of us lead to a situation where people are incented not to commit.”
Senate Bill 1938 gives incumbent utilities the first shot at building transmission projects in the state. The bill, which went into effect immediately after Gov. Greg Abbott signed it May 16, will require ERCOT to modify its transmission planning process to no longer designate transmission provider endpoints.
A second law already in effect — SB475, signed June 7 — creates a Texas Electric Grid Security Council composed of Magness, PUC Chair DeAnn Walker and a designee of Abbott. Magness said Walker will chair the council, which will begin meeting later this year.
SB936, signed June 10 and effective Sept. 1, requires ERCOT and the PUC to contract with an entity to serve as the commission’s cybersecurity monitor. It will be funded by the grid operator’s system administrative fee, Magness said.
Magness also celebrated a two-year delay in the grid operator’s sunset review, which also applies to the PUC and the Texas Office of Public Utility Counsel (OPUC). The review has been pushed back to 2024/25.
ERCOT CEO Bill Magness makes a point.
“While we always welcome sunset reviews, we’re happy for it to be in 2024 and 2025,” he cracked.
ERCOT’s positive year-end variance to budget has slipped slightly, from $34 million to $33.2 million, still boosted by a large gain in interest income ($18.7 million), Magness said.
Telemetry Data Blamed for Market Event
Ögelman told the board that a May 30 market event that briefly resulted in $9,000/MWh prices was the result of the security-constrained economic dispatch system receiving bad telemetry data.
“This happens,” Ögelman said. “Normally for very short durations, but it doesn’t hit the SCED. This hit the [market] run.”
The telemetry data indicated about 5,000 MW of resources wanted to move down during an interval, he said, and when the market didn’t respond quickly enough, the SCED engine used regulation up to get the ramp it thought it needed. Energy on the power balance penalty curve, used by ERCOT to price ancillary services such as regulation up, hit $9,000.01/MWh for about 2.5 minutes before operators, sensing something was wrong, reran SCED and corrected the data.
The blip resulted in settlement prices of as much as $1,500/MWh in some load zones for one 15-minute interval, Ögelman said.
Staff investigated the event but determined it didn’t warrant a price correction, according to ERCOT’s Protocols.
“Incorrect telemetry coming from outside ERCOT is not something we run corrections for,” Ögelman said. Telemetry data are owned by the resources, not the grid operator.
He said staff would look into strengthening its telemetry data and follow up with stakeholders to evaluate alternatives.
TAC Vice Chair Coleman Leaves for CPS
Technical Advisory Committee Chair Bob Helton said the committee will “bring on” a new vice chair before the next board meeting, replacing longtime member Diana Coleman, who has left OPUC to take a position at CPS Energy, San Antonio’s municipal provider.
Coleman had served as the TAC’s vice chair since 2018, when Helton moved up from vice chair to chair to replace Adrianne Brandt when she also left for CPS.
Board Approves Budget, Change Requests
ERCOT’s system administrative fee will remain at 55.5 cents/MWh through 2021 as a result of the board’s unanimous approval of the 2020/21 biennial budget. The fee has remained level since 2016.
The board approved $268.3 million and $275.2 million for operating expenses, project spending and debt-service obligations for 2020 and 2021, respectively.
The board also approved seven Nodal Protocol revision requests (NPRRs), a change to the Nodal Operating Guide (NOGRR), two new Other Binding Documents (OBDRRs), two Planning Guide additions (PGRRs) and a system change request (SCR) on its consent agenda:
NPRR885: Adds new language to address the solicitation and operation of must-run alternatives, as directed by the PUC (Project 46369). The commission ruled that a resource entity must file a notification of suspension of operations at least 150 days prior to the date on which it intends to cease or suspend operations; within the 150-day notice period, ERCOT must determine whether the resource is needed for reliability.
NPRR896: Outlines the process to evaluate the cost-effectiveness of procuring reliability-must-run service or one or more must-run alternatives.
NPRR921: Replaces all instances of the “all-inclusive generation resource” and “all-inclusive resource” terms with “generation resource and settlement-only generator (SOG)” and “generation resource, settlement-only generator and load resource,” respectively. Eliminating the all-inclusive generation resource enables ERCOT to more narrowly tailor the requirement’s applicability to a reasonable scope.
NPRR923: Updates the weather-sensitivity process by allowing transmission and/or distribution service providers an additional 30 days to complete the investigation and execution of requests to revise electric service identifier (ESI ID) load profiles.
NPRR924: Moves the Independent Market Information System Registered Entity Application for Registration form into a section of the Nodal Protocols that houses similar forms.
NPRR926: Removes the 90-day period between subsynchronous resonance (SSR) study approval and initial synchronization, clarifies that the SSR mitigation plan is part of the SSR study and adds an ERCOT review process that gives the grid operator 30 days to review the SSR study. The change also gives ERCOT 45 days to implement any required SSR monitoring after the study’s approval.
NPRR929: Adds new criteria for determining whether a point-to-point (PTP) obligation with links to an option bid is eligible to be awarded based on the resource’s current operating plan (COP) status at the node where the bid sources. Bids will not be eligible for awards if they source at a resource with a COP status of “OUT” or “OFF” and the resource is not offered into the day-ahead market.
NOGRR185: Uses the terms created in NPRR889 (RTF-1 Replace Non-Modeled Generator with Settlement Only Generator) to replace the terms “all-inclusive generation resource” and “all-inclusive resource” in the NOG.
OBDRR013: Changes the current single-value voltage categories of 345, 138 and 69 kV used to define generic transmission shadow price caps for N-1 constraint violations to accommodate Lubbock Power & Light’s transmission equipment, which does not fall into the three existing categories. The ranges are: greater than 200 kV ($4,500/MW), 100 to 200 kV ($3,500/MW) and less than 100 kV ($2,800/MW).
OBDRR015: Sets the value of lost load (VOLL) equal to the systemwide offer cap, which changes the high cap to the low cap should the peaker net margin exceed its threshold within an annual resource adequacy cycle.
PGRR069: Uses terms created by NPRR889 to replace “all-inclusive generation resource” and “all-inclusive resource” in the Planning Guide. The PGRR also clarifies the applicability of the generation interconnection or change request process to different generators, based on NPRR889.
PGRR070: Aligns the Planning Guide with NERC Reliability Standard TPL-007-2 (Transmission System Planned Performance for Geomagnetic Disturbance Events) by identifying responsibilities for performing studies needed to complete benchmark and supplemental geomagnetic disturbance vulnerability assessments.
SCR799: Enables ERCOT to provide transmission service providers its current month, 60-day and 90-day outage study cases in the system operations test environment on a monthly basis.
CARMEL, Ind. — A key annual capacity report issued by MISO and the Organization of MISO States predicts the RTO is now unlikely to face a near-term shortfall in generation — a welcome reversal of last year’s more worrisome findings.
Credit the change to expectations for flat demand and the promise of ample resource additions.
The survey released Friday forecasts a generation surplus of about 3 to 6 GW in 2020, though the RTO says “continued action will be needed to ensure sufficient resources are available going forward.” Last year’s survey forecasted a possible 0.1-GW shortfall in 2020.
2019 OMS-MISO survey results | MISO
Unsurprisingly, OMS and MISO say the future through 2024 could bring a “range” of resource amounts, but the survey no longer predicts any regional shortfalls in generation before 2022.
Using this year’s 16.8% planning reserve margin as a baseline, the survey predicts a 1- to 4-GW surplus in 2021. By 2022, that excess dwindles to 1 to 3.4 GW. The range of possibilities in 2023 and 2024 varies the most, with the forecast indicating anything from a 1.3-GW shortfall to a 7-GW surplus in 2023, and a 2.3-GW shortfall to another 7-GW surplus in 2024.
MISO said more than 97% of its load-serving entities and additional non-LSE market participants responded to the survey.
Last year’s survey showed MISO’s footprint could see anything from a 7.5-GW surplus to a 4.5-GW shortfall from 2020 to 2023 and predicted spare capacity ranging from 0.6 to 6.6 GW this year. (See OMS-MISO Survey Reveals Dimmer View of Future Supply.) The newest survey results are also a far cry from the 2016 iteration, where MISO said a generation shortfall was possible in 2018.
But during a call Friday to discuss the results, MISO staff cautioned that the 2019 survey results will differ from future realities. MISO Executive Director of Resource Planning Patrick Brown stressed that capacity deficiencies could occur “if no action is taken.”
MISO said certain Midwestern zones could develop the greatest resource adequacy risks, including Southern Illinois’ Zone 4, Indiana and western Kentucky’s Zone 6, and Lower Michigan’s Zone 7. MISO said it foresees “lower resource commitments” in those areas in 2020 and beyond, including a possible 0.2- to 0.7-GW deficit in downstate Illinois and a potential 0.9-GW shortage in Lower Michigan in 2020.
But a possible capacity shortfall isn’t an immediate concern even in those areas, Brown said.
“Zones with deficiencies don’t automatically have a resource adequacy risk as they can use surplus resources outside of their zone … taking advantage of MISO’s footprint diversity. … They do have the option to import capacity into their zones to meet their local needs,” Brown said.
Brown also said those areas have ample time to adjust to ensure appropriate capacity. Contrary to OMS-MISO results, the Michigan Public Service Commission has said that state will have sufficient capacity in place to meet obligations through 2022, he noted.
As with prior reports, MISO’s demand growth rate is set to decline again, with the five-year annual rate adjusted to 0.2%, down from a 0.3% projection in 2018.
“Fewer resources are needed to serve load,” Brown said.
MISO has only expected “modest” changes in peak load over the next five years, anticipating a 4.4-GW variance in expected system peak, with electric vehicles adding about 1 GW in demand by 2023. The RTO doesn’t expect its current approximate 120-GW peak predictions to be “radically different” within five years, market design team member Dustin Grethen said at a June 6 Market Subcommittee meeting.
As of May, MISO’s generator interconnection queue consisted of 640 projects totaling 100.7 GW, nearly 30 GW of which (210 projects) are solar generation.
Brown also said this year’s survey shows significant amounts of generation retirements, with “a mix of wind, solar storage and gas” as well as load-modifying resources lined up in the interconnection queue set to replace them. MISO does expect emergency declarations to become more frequent as a result, he said.
The RTO plans to post and discuss the survey results in more detail, including a zonal breakdown, at its July Resource Adequacy Subcommittee meeting.
WASHINGTON — Several members of the House Energy and Commerce Committee’s Subcommittee on Energy on Wednesday urged FERC commissioners to holistically review RTO and ISO governance rules, while also pressing them on when to expect decisions on languishing dockets — including PJM’s capacity market proposal.
The commissioners did not tell the subcommittee anything they haven’t said before in open commission meetings or keynote industry speeches. And because the dockets are still pending before them, they could neither go into specifics nor estimate when any decisions would be forthcoming.
But House members gave RTO issues considerable airplay in an oversight hearing that ran the gamut: the commission’s role, if any, in mitigating climate change; landowner complaints over natural gas pipeline siting; and energy storage participation in wholesale electricity markets, to name a few.
Rep. Michael F. Doyle (D-Pa.) scolded FERC for creating uncertainty in PJM, where the Board of Managers decided to move ahead with the RTO’s annual Base Residual Auction this year (albeit in August, instead of May) despite the commission finding its capacity market rules unjust and unreasonable — running the risk that FERC could force it to rerun the entire thing later. (See PJM to Hold Capacity Auction in August.)
Doyle noted PJM filed its revised rules in October, “so either a rule is going to be published right before August, which won’t give participants enough time to adjust, or a decision will not be published, and participants will have to take part in an auction under rules that FERC has found to be unjust and unreasonable.”
Chairman Neil Chatterjee assured Doyle that “we’re working as diligently as we can.”
“This is a vexing challenge,” Chatterjee said, “because you have a situation where two things I think we all believe in — states’ rights and the markets — are colliding. … We’re coming to a point where actions that states are taking to make decisions about their local energy futures are impacting the markets and trying to figure out how to sort through that while ensuring just and reasonable rates has proven to be very, very challenging.”
“I am deeply, deeply troubled by the delay,” Commissioner Cheryl LaFleur said. “I had dissented in the initial order because I thought it would put PJM in an impossible situation, and I’m afraid that’s exactly what’s come to pass. I’ve been using my world-class powers of nagging to be a nag about it, but so far we have not gotten an order out.”
“I’m not sure how the auction can go forward without some clarity from FERC,” Commissioner Richard Glick said.
Speaking to reporters after the hearing, Glick said, “We should be working on this 24/7 because we owe it to [PJM] to provide some more certainty.”
Rep. Frank Pallone (D-N.J.), chair of the full committee, called for “greater scrutiny of wholesale capacity markets. Frankly, the current state of affairs is a mess, especially in the PJM market, where New Jersey participates. PJM participants are currently left in the lurch of both an old and new capacity market design. … It is vital that we figure this out immediately.”
Subcommittee Chair Bobby Rush (D-Ill.) expressed concern that “consumer voices are often overlooked, ignored or cut out of the RTO process entirely.” Pallone also noted “there has not been a comprehensive review by FERC of each RTO’s stakeholder process to ensure compliance with the requirements of Order 719,” issued in 2008.
“This is something we continually hear from people around the country,” Chatterjee replied. Reviewing Order 719 compliance “is one option, but looking with an eye towards ensuring consumers’ voices are heard as they come up through the process is another manner in which to do this. I think particularly as new technologies come into play and we look to break down barriers to entry, we need to ensure these new voices have an opportunity to be heard at the RTOs and ISOs.”
LaFleur agreed that “it’s probably a good time for a relook.”
Call for Transparency
Rep. Joe Kennedy III (D-Mass.) said he was “increasingly concerned about the [RTOs] and their governing structures.”
“My fellow citizens and I have no idea who makes decisions or how they are made at [the New England Power Pool] because unless you are a member, you can’t even observe any meetings or proceedings, let alone talk about it publicly. Other RTOs benefit from governance structures that enjoy slightly more transparency. Still, I believe more has to be done.” He asked LaFleur if the public should have more access, “even as a passive observer.”
LaFleur noted a pending request for rehearing on press access to RTO meetings before she began to point to consumer advocates’ participation in RTOs. Kennedy interrupted her, but LaFleur said she could not comment on the press issue.
FERC in April dismissed RTO Insider’s complaint seeking rejection of rules proposed by NEPOOL to keep reporters from publishing what is discussed at the group’s meetings. Consumer advocacy group Public Citizen filed a request for rehearing last month (EL18-196). FERC issued a tolling order June 7, giving itself more time to consider the request. (See FERC Rejects RTO Insider Bid to Open NEPOOL.)
Glick jumped in. He also said he could not comment specifically on the rehearing request, but he explained that FERC rejected the complaint because it lacked jurisdiction, as press access does not affect NEPOOL’s wholesale rates. But he said, “I agree with you, congressman, that transparency is a very important element of appropriate RTO functioning.”
A recent pair of dueling studies have drawn divergent conclusions about the merits of competitive transmission solicitations. The differences might have something to do with the reports’ respective sponsors.
Both studies appear to be aimed at shaping the discussion around possible changes to FERC’s Order 1000, the 2011 rulemaking that eliminated incumbent transmission owners’ right of first refusal over regional projects and opened transmission planning processes to independent developers.
The first report, released by The Brattle Group in April, found electricity customers could save $8 billion over five years if competitive transmission planning processes expanded to cover 33% of all transmission investments, compared with just 3% today. That study was commissioned by independent transmission developer LSP Transmission Holdings, whose affiliates are developing three competitively bid transmission projects in MISO, PJM and NYISO.
But another study published by Concentric Energy Advisors on Monday concludes there is no basis to expand the scope of competitive solicitations in RTOs and ISOs, claiming incumbent TOs’ initial cost estimates for projects generally prove to be accurate. That study was prepared for Ameren, Eversource Energy, ITC Holdings, National Grid USA and Public Service Electric and Gas — all incumbent TOs in various RTOs.
The two studies come as FERC is signaling a move to reexamine Order 1000. FERC Chair Neil Chatterjee earlier this year acknowledged some industry stakeholders are complaining the rules are not working as intended, with proponents of competitive projects seeking a replacement and opponents hoping for a repeal. (See “Chatterjee: Focused on PURPA, Order 1000 Reforms,” Overheard at the NARUC Winter Policy Summit.)
So far, the commission appears to be in the “replace” camp.
“As we think about addressing Order 1000, I believe we owe it to consumers to put our best effort forward toward spurring competition to work and getting the scope of competition right,” Chatterjee told a gathering of state regulators in February.
Order 1000 Rethink?
But the numbers suggest competitive project developers continue to face barriers despite the aims of Order 1000.
Brattle’s report showed that even seven years after FERC issued the order, 97% of RTO transmission investments are still made outside competitive processes. The study calculated that competitively bid projects only took about $540 million of the average $20 billion in annual transmission investment from 2013 to 2017, despite its finding that competitive projects typically result in cost savings of 20 to 30%.
Brattle took issue with the ongoing limitations faced by competitive developers.
“The tariffs that specify the rules for transmission planning for each region currently exclude the large majority of transmission investments from competitive processes,” Brattle wrote. “We do not see compelling policy reasons for broad limits or having significant differences in criteria used in various regions that directly or indirectly exclude transmission projects from the competitive processes.”
The report advocated federal and state policymakers move to expand the scope of competitive transmission investments to stimulate innovation and increase cost-effectiveness in an industry being transformed by new natural gas and renewable generation investments.
But Concentric contends Brattle’s report doesn’t paint a complete picture, maintaining the benefits of transmission solicitations are still unknown and Brattle’s cost-savings estimates are flawed. Concentric also argues RTO competitive processes are “time- and resource-intensive,” with solicitations involving more than one bidder taking anywhere from 113 to 1,498 days.
Concentric also questioned Brattle’s assumption that incumbent TO projects typically exceed initial cost estimates by anywhere from 18 to 70%, calling that conclusion “false and inconsistent with the empirical evidence.”
Instead, Concentric said it found incumbent TOs’ final project costs only vary from initial investments by a “very modest” -2.9 to 7%.
Concentric said there’s “no credible support for the claim that current transmission processes limit customer savings, or that expansion of competition will yield meaningful additional savings.”
“The Brattle report … uses a limited and unrepresentative sample size of incumbent TO projects to produce its average historical cost escalation estimates, which are significantly overstated,” Concentric added. “Importantly, of the 15 [competitive] projects the Brattle report used to calculate its cost savings estimates, the final cost of the majority of the projects is currently unknown.”
Concentric cautioned against any near-term moves to revise or replace Order 1000.
“If there is interest in expanding solicitations for transmission projects, we advise policymakers to wait until more of the projects selected through such solicitations have been placed in service. At such a time, more information will be available about the actual costs and operational performance of these projects and policymakers would be in a position to make better informed decisions about whether or not to expand such solicitations,” Concentric said.
Jim Holodak, National Grid vice president of FERC and wholesale regulatory strategy, agrees with that last point. He said he’s heard a variety of opinions about revisiting Order 1000, ranging from elimination or repeal to a series of slow modifications.
“We’re suggesting we need more time before FERC opens it up,” Holodak told RTO Insider.
He said multiple competitive projects should be completed before cost savings and benefit assumptions are made about them.
“You don’t know what that project will cost until it finally goes into service. Then make that comparison,” Holodak urged.
Concentric’s study pointed out that even the cost caps promised by winning bidders for competitive projects are subject to “exclusions and exceptions.” Holodak noted the caps can contain several exclusions related to siting, regulatory requirements and routing changes.
“There’s a whole host of exclusions for cost caps. … At the end of the day, they’re not taking on any more risk, and the project price for customers is not really capped” any more than for an incumbent TO project, Holodak said.
“It’s as if you’re buying a kitchen remodel based on an ad for a $10,000 kitchen, but you want to add granite countertops and other design features that increase the quote. It would be unreasonable to expect to hold the contractor to the original ad price,” he said.
Holodak also argued the system’s “resiliency and robustness” won’t get the same attention if more project types are opened to competition. Complete competition on every level of transmission “is not the way to go,” he said.
Brattle Responds
Brattle’s conclusions couldn’t differ more.
Johannes Pfeifenberger, one of the authors of the Brattle study, said he still stands by the position that Order 1000 is ready for expansion, even if there are few case studies so far.
“The reality is there are not a lot of competitive projects to study. But the experience with those 15 Order 1000 projects is that those projects were bid below initial cost estimates,” Pfeifenberger said.
While Brattle is only beginning its review of the Concentric report, Pfeifenberger leveled several criticisms at Concentric’s study methodology, saying the competing analysis incorrectly relied on updated cost estimates later filed by the incumbent transmission developers, not true initial cost estimates.
“Since the competitive bids are compared against the initial estimates when the bids come in, the initial estimates are the most appropriate information for comparison,” Pfeifenberger explained.
Pfeifenberger also said the average 20 to 30% cost savings found in the Brattle study is consistent with the savings seen in other areas with transmission competition, including the U.K.; Brazil; Alberta, Canada; and the Path 15 transmission project in California.
He also lightheartedly addressed the cost cap criticisms: “I would say that some cost caps are better than no cost caps.”
Pfeifenberger also pointed out all transmission projects must undergo a process of identification and then study before approval. He said the planning process takes time, with or without bid windows and selection reports.
“The competitive process had only begun a few years ago, and these markets are still in the forming stage, and therefore the first few competitive projects take quite a bit of time to evaluate and approve. But these processes are improving and streamlining over time,” Pfeifenberger said.
“If you can add six months [to the planning process] and save 20%, was that worth it?” he asked rhetorically.
But Holodak maintains early planning estimates at the conceptual design stage shouldn’t serve as a study benchmark for cost savings, noting they often involve standard dollar-per-mile estimates and lack several design and engineering details unique to specific transmission projects.
“Nobody has ever suggested that’s a model you should hold someone to. Brattle’s suggestion that the preliminary planning estimate is a standard someone should be held to, we think it’s completely without merit,” Holodak said.
Brattle report co-author Judy Chang argued planning-level estimates could become more precise.
“It doesn’t make sense that project costs will always escalate based on the initial estimates,” Chang said. “That also means that nobody really cares about the initial estimate. The whole competitive process has induced these transmission owners to sharpen their pencils and really analyze costs they can control and bear the risk of costs coming in higher than they expect. This whole better cost containment is an innovative outcome of the competitive process. This is a benefit.”
Pfeifenberger added if planning-level estimates are made to be exceeded, then competitively bid projects would also consistently exceed those estimates. That’s not the case, he said.
“Beyond trying to confuse the issue, Concentric has not addressed the fact that competitive bids have come in significantly below initial cost estimates while traditionally developed projects of similar type have come in above their initial cost estimates,” he said.
VALLEY FORGE, Pa. — PJM’s Darlene Phillips will take over the Operating Committee in July after current Chairman Dave Souder starts his new role as executive director of systems operations.
Phillips is currently the senior director of strategic policy and external affairs and joined PJM in August 2015. She served in several leadership roles for MISO for more than 10 years and is a graduate of the University of Michigan and Indiana University’s Robert H. McKinney School of Law.
Souder’s promotion comes after a leadership shake-up following CEO Andy Ott’s retirement, effective June 30. (See PJM CEO Ott to Retire.) He will take over the role for Ken Seiler, who will become vice president of planning and be responsible for the oversight of the System Planning Division, which includes transmission planning, interregional planning, interconnection analysis, interconnection projects, infrastructure coordination and resource adequacy planning.
PJM said a wave of tornadoes on Memorial Day and throughout the last week of May left about 80,000 customers without power around Dayton, Ohio.
Half the customers were restored within 12 hours, staff said, but several transmission lines remain inoperable due to storm damage. PJM expects the lines will be under repair through the end of June.
Energy Storage Revisions Get First Read
Revisions to PJM manuals for energy storage mandates got a first read during Tuesday’s OC meeting. PJM staff said the changes follow directives from FERC Order 841.
First up were changes to Manual 14D: Generator Operational Requirements, including Operating Agreement definitions of energy resource, capacity resource, energy storage resource (ESR) and capacity storage resource. Language was also added to clarify applicability of manual requirements to generation and storage resources. Sections 4.1.7 and 4.2.3 were revised to include telemetry of state of charge for ESR model participants and specific metering requirements. Staff also added a definition for generating facility per FERC’s compliance filing for Order 845.
In Manual 36: System Restoration, PJM revised the exception to critical cranking power to include non-hydro energy storage resources and updated the participation model to allow ESRs to participate in all markets where technically feasible.
In Manual 40: Training and Certification Requirements, sections 3.2.4 and 3.2.6 were updated to account for small generation resource dispatchers and lower the megawatt threshold for training requirements to accommodate ESRs. Language was also changed to reflect ESRs are assumed to be more than participants in ancillary markets.
Laura Walter, a senior lead economist for PJM, said the purpose of the revisions — and many more anticipated in other manuals — is to open up markets for ESRs and ensure parameters allow such resources to operate effectively.
PJM’s ESRs include approximately 5,000 MW of pumped hydro and 310 MW of battery storage, she said. The resources will be allowed to offer into both the day-ahead and real-time markets and will be modeled as continuous resources with the ability to self-manage their own state of charge.
The manual revisions will return to the September OC for final endorsement to give stakeholders time to provide additional feedback.
Nuclear Plant Interface Coordination Updates
PJM wants to update Manual 39 with new sections and clarifying language for its nuclear plant interface coordination procedures.
The revisions include new language in sections 2.7, 3.6 and 3.7 that address coordination around remedial action schemes and load shedding schemes. They also cover the deactivation and retirement process for nuclear units and the regulatory requirements of that process, as well as the coordination between reliability coordinators when a non-PJM member is identified by a nuclear plant generator operator as a transmission entity.
Attachment B will also be renamed to “Plant Specific NPIRs.” Endorsement is scheduled for the July OC.
Emergency Operations Updates
Staff added multiple section changes to Manual 13: Emergency Operations to align with the new Markets Gateway functionality for resource limitation reporting to be implemented on Aug. 1.
Sections 1.1, 2.3, 3.1-3.5 and 5.2 have been revised to reflect the following:
Terminology for “fuel-limited” units has changed to “resource-limited” to clarify applicability of reporting requirements.
Units are considered resource-limited if they have less than 72 hours of remaining runtime at maximum capacity, limited by primary/alternate on-site fuel, emissions, demineralized or cooling water or other consumables.
Resource-limited units are to report resource limitations via the new Markets Gateway page.
Natural gas-fired units with fuel limitations are not considered resource-limited and are excluded from resource limitation reporting via the Markets Gateway.
References to the Supplementary Status Report (SSR) for reporting resource limitations have been removed and replaced with instructions for using the new Markets Gateway page.
In Section 6.4, clarifications were made to address procedures when PJM has declared conservative operations or hot/cold weather alerts:
Fuel-limited gas-fired units are not to be placed in maximum emergency but should remain available to ensure PJM tools “economically schedule” the gas-fired units, unless PJM Dispatch directs them to be placed in maximum emergency dispatch status.
Dual fuel units — gas/other on-site fuel — should be placed in maximum emergency status when non-fuel resource limitations restrict runtime to less than 16 hours for combustion turbines and 32 hours for steam turbines. When fuel is limited, they should be placed in maximum emergency status only when natural gas is unavailable and their onsite fuel inventory is less than 16 hours for CTs and 32 hours for steam.
The changes were made to align with existing language in the PJM Operating Agreement for designating fuel-limited resources as maximum emergency.
First Primary Frequency Response Evaluation Reveals Low Participation
Most online resources don’t provide primary frequency response (PFR), a PJM analysis concluded.
PFR is the ability of generators to automatically change their output in five to 15 seconds when the grid’s frequency strays above or below 60 Hz. As more renewables enter the resource mix and coal plants retire, the grid can become more susceptible to these frequency swings, threatening system reliability.
Primary frequency response by unit | PJM
Danielle Croop, a senior engineer in PJM’s generation department, said 583 units with capacities of 50 MW or greater were evaluated for PFR across five events in late 2018 and early 2019. The selected events for analysis met one of three qualifications: frequency goes outside the +/- 40-mHz deadband, frequency stays outside the +/- 40-mHz deadband for 60 continuous seconds or minimum/maximum frequency reaches +/- 53 mHz.
No more than 20 resources provided PFR during the selected events, PJM data show. More than half remained offline and another third did not respond, Croop said. When pressed as to whether the analysis meant generators were performing poorly, she said only that clearly more follow-up is needed to fully understand why units did not respond as anticipated.
“I will say there is a concern here because we looked at 583 units, and the majority of them are not responding,” she said.
BTM Generation Rules Preview
PJM will soon bring rule changes for non-retail behind-the-meter generation (NRBTMG) to the OC for endorsement.
NRBTMG refers to resources used by municipal electric systems, electric cooperatives or electric distribution companies to serve load. They do not participate as supply resources in PJM markets but can be netted against their wholesale load to reduce transmission, capacity, ancillary services and administrative fee charges.
PJM’s rules on such resources resulted from a 2005 settlement agreement (EL05-127), before development of the RTO’s capacity market and CP constructs. NRBTMG resources can be called upon during the first 10 maximum generation emergencies annually, while CP resources are required to perform during all performance assessment intervals (PAIs). BTM operators that fail to perform face reduced netting benefits. In 2006, the grid operator identified about 400 MW of NRBTMG.
Terri Esterly, PJM’s senior lead engineer for capacity market operations, said manual changes are ready for stakeholder review. The revisions grew out of a problem statement and issue charge that showed PJM can’t accurately account for how much NRBTMG contributes to the grid, particularly with the growth of solar and other distributed resources. (See “PJM Continues Review of Non-retail BTM Generation Business Rules,” PJM OC Briefs: Feb. 5, 2019.)
Updates to Manual 13 show the phrases “maximum generation emergency action” and “deploy all resource action” have been identified as triggers to load NRBTMG. Updates to Manual 14D Appendix A include revisions to the business rules to clarify the reporting, netting and operational requirements of NRBTMG.
Southern California Edison’s request for a huge transmission rate adjustment based on potential wildfire liability got a tepid reception from FERC on Tuesday (ER19–1553).
The commission tentatively accepted the increase, per its customary procedure, but postponed any change for the maximum five months and set it for an evidentiary hearing, while encouraging the utility and protesters to settle. Protesters in the case include the California Public Utilities Commission, whose recommendations FERC largely followed.
FERC said its preliminary analysis indicated SCE’s proposed 2019 transmission revenue requirement could be unjust and unreasonable — and may provide the utility “substantially excessive revenues.”
SCE is seeking a whopping 17.62% return on equity, which includes the 11.12% base ROE the utility requested last year plus a 50 basis point incentive adder for CAISO participation, along with an additional 600 basis point cushion to account for the costs of wildfire liability. If approved, the new rate would boost SCE’s annual transmission revenues by nearly $290 million.
Investigators found that Southern California Edison power lines sparked the Thomas Fire, which killed two people in Dec. 2017 and led to mud flows that killed 21 more. | U.S. Forest Service
SCE said in its April 11 filing its proposal was based on “dramatic material changes to SCE’s regulatory and financial conditions that have occurred” since the utility filed its currently effective formula rate in October 2017.
Those changes include massive and deadly wildfires in SCE’s service area and the potential for multi-billion-dollar costs based on California’s strict liability standard for utility-sparked fires, known as inverse condemnation. (PG&E, which intervened in the case, faces similar circumstances and filed for bankruptcy in January due to wildfire liability.)
“Beginning in December 2017, several wind-driven wildfires impacted portions of SCE’s service territory and caused substantial damage to both residential and business properties and service outages for some of SCE’s customers,” SCE wrote. “California has unique inverse condemnation laws. These laws provide that an electric utility will be held strictly liable for property damages and legal fees if its facilities are the substantial cause of a fire regardless of fault and even if the utility was fully compliant with all applicable rules and regulations and acted reasonably.”
“As a result of these laws and recent fires, SCE is exposed to significant potential wildfire damage claims,” the utility said. “In 2017, the California Public Utilities Commission (‘CPUC’) issued a decision holding that it could preclude a utility from recovering these court-assigned costs if it finds the utility was not prudent, even if the source of the alleged imprudent conduct was not directly the cause of the fire.”
FERC, which has oversight of SCE as a transmission owner, and the CPUC, which regulates the utility’s distribution system, have different standards for cost recovery, SCE pointed out. The difference could be a costly one.
‘Atypical’ Risk
State investigators determined SCE equipment started the 282,000-acre Thomas Fire in December 2017 that killed two people and led to mudslides that killed 21 more in Ventura and Santa Barbara counties. The California Department of Forestry and Fire Protection (Cal Fire) has listed the official cause as “line slap,” whereby electrical conductors contact each other or adjacent components. (See Edison Takes Partial Blame for Wildfire in EarningsCall.)
The Woolsey Fire in November 2018 killed three residents, destroyed 1,500 structures and burned 97,000 acres in Los Angeles and Ventura Counties. Its cause remains under investigation, though lawsuits have blamed SCE. The fire began near an SCE substation where a nearby circuit experienced problems shortly before the fire started, the Los Angeles Times reported.
In its filing with FERC, SCE argued its conventional base ROE does not reflect “extraordinary wildfire liability risks.” The utility submitted testimony concluding an ROE allowance of 600 basis points added to its base ROE would match the size and insurance cost of the wildfire problem.
The Thomas Fire left a massive burn scar across coastal Southern California. | NASA
“SoCal Edison states that authorizing such an amount on top of the base ROE would provide additional investor returns needed to account for the severe wildfire risk SoCal Edison faces,” FERC wrote.
In its protest to FERC, the CPUC called SCE’s proposed increase “extraordinary” and noted SCE’s request “touches upon similar issues in proceedings pending before the CPUC.”
“SCE’s filing would result in a retail revenue requirement of $1.328 billion, compared to the current revenue requirement of $1.038 billion,” the CPUC wrote. “SCE’s proposed rate increase is primarily tied to a proposed return on common equity (‘ROE’) of 18.4%, an unprecedented proposal which would create a windfall to SCE investors, at an unacceptable cost to SCE’s captive customers, in violation of the Federal Power Act. This proposed formula will result in unjust and unreasonable rates in 2019 and beyond and should be rejected.”
The CPUC said it calculated the higher rate based on an ROE of 17.12%, a 50 basis point incentive adder for membership in the CAISO and project-specific adders ranging from 75-125 basis points.
“The enormous increase in the rate of return request is due primarily to a 600 basis point adder ascribed to the legal issue in California of ‘inverse condemnation’ and the wildfire liability risk it imposes on California utilities,” the California regulator said. “The CPUC does not object to SCE raising this issue, but it does object to the magnitude of the proposed risk premiums, which stems from SCE’s departure from accepted cost of capital methods used to develop that estimate.”
“The wildfire liability issues in California, including state law on inverse condemnation, are complex and do create atypical utility risk,” the CPUC wrote. “It may be the case that a reasonable treatment of this risk as part of rate of return should be considered. That said, the proposed 600 basis point adder is unreasonably large, violates the upper end of the zone of reasonableness (for an electric utility proxy group, which is FERC practice) and is not consistent with the available financial metrics for SCE and its parent Edison International.”
The CPUC said SCE had overstated its risk. Though its credit rating fell due to fire liability, it remains in investment-grade territory, and its stock price has been relatively stable, the CPUC contended. “The presently observed risk indicators for SCE are not as dire as portrayed by company witnesses,” it said.
‘Utility Imprudence’
Protesters Public Citizen and The Utility Reform Network, both nonprofit public interest groups, advanced similar arguments.
“SCE misrepresents the liability regime in California, and the utility is not at risk for wildfire liability absent a finding that it was imprudent in managing its system [under the prudent manager standard],” they said. “FERC should not condone utility imprudence by insuring the company against its own negligence. Moreover, SCE has raised these very same issues in its recently filed cost of capital proceeding at the California Public Utilities Commission.”
“Since any alleged financial risk due to wildfires depends on California-specific factors and policies, and any such risk is caused primarily by ignitions on the distribution system, this commission should refuse to rule on such issues or authorize increases in ROEs for transmission investments and instead should allow the California PUC to evaluate these claims,” the groups argued.
FERC said it hopes the parties will settle prior to a hearing.
“While we are setting this matter for a trial-type evidentiary hearing, we encourage the parties to make every effort to settle their dispute before hearing procedures are commenced,” FERC wrote. “To aid the parties in their settlement efforts, we will hold the hearing in abeyance and direct that a settlement judge be appointed.”
VALLEY FORGE, Pa. — The 90-day clock for stakeholders to work out how PJM will unwind $100 million worth of financial transmission rights (FTR) settlements begins June 19, said PJM legal counsel Jen Tribulski.
The update comes after FERC issued an order June 5 that encouraged conflicting parties to hammer out disagreements ahead of a scheduled paper hearing under the guidance of a settlement judge, who will report progress on the discussions to the commission at the 45- and 90-day marks (ER18–2068). A one-time extension may be granted for 30 days, FERC said. (See FERC: PJM Settle Disputes Before GreenHat Hearing.)
“During the settlement proceedings, all issues are on the table,” Tribulski said. “It doesn’t have to be just the six [issues PJM raised in its request for clarification]. If we go to hearing, it’s limited to just the six issues.”
Stakeholders expressed a mix of confusion and frustration over the ruling, with most unsure of what’s left to settle considering many were in agreement with PJM’s initial waiver request.
“The real problem is FERC just making the wrong decision and setting us down a path that PJM said is untenable,” said Carl Johnson, of the PJM Public Power Coalition. “You asked them to clarify their own rules, so I think it’s unrewarding that FERC is going to ask us to fix it among ourselves.”
5-Minute Dispatch Problem Statement Endorsed
Stakeholders gave near-unanimous support for the Independent Market Monitor’s problem statement to review processes for real-time security-constrained economic dispatch (RT SCED) and market pricing that PJM uses to send dispatch signals to generators and calculate LMPs. (See “Monitor Presents Updated 5-Minute Dispatch Problem Statement” in PJM MIC Briefs: May 15, 2019.)
Siva Josyula of Monitoring Analytics said a publishing price delay on April 8 — as well as a July 10, 2018, low area control error (ACE) event and corresponding Manual 11 revisions — call into question the transparency of PJM’s RT SCED processes.
Education about RT SCED will begin in the MIC next month.
Electric Storage Participation Rule Changes
PJM presented more manual revisions for electric storage participation rules in compliance with FERC Order 841.
In Manual 11: Energy & Ancillary Service Operations, section 2.3.4B was added to explain how electric storage resources (ESRs) would participate in the markets, including clarification that the resources can sell in the energy, capacity and ancillary markets if they are technically capable of providing those services. It also provides information on dispatch and pricing, bid parameters and clarifies that stored MWh are billed at LMP as wholesale. Staff also added definitions for defined modes and the opt-in and opt-out processes and updated ESR hourly limits.
In Manual 18: PJM Capacity Market, staff updated the definition of capacity storage resource to include ESRs that participate in the reliability pricing model or are “elsewhere treated as capacity in PJM’s markets such as through a fixed resource requirement capacity plan.” Revisions also clarify that ESRs may not receive peak load contributions for energy they sell back to the grid.
Laura Walter, a senior lead economist for PJM, said the purpose of the revisions — and many more anticipated in other manuals — is to open up markets for ESRs and ensure parameters allow such resources to operate effectively.
PJM’s ESRs include approximately 5,000 MW of pumped hydro and 310 MW of battery storage, she said. The resources will be allowed to offer into both the day-ahead and real-time markets and will be modeled as continuous resources with the ability to self-manage their own state of charge.
PJM will seek MIC endorsement at the July 10 meeting.
CARMEL, Ind. — MISO will one day see a proliferation of electric vehicles, just don’t expect them to begin plugging in en masse before millennials begin hitting midlife crises.
The region served by MISO can expect to see significant EV penetration of anywhere from 1 to 12 million vehicles by 2039, according to a Lawrence Berkeley National Laboratory impact study prepared for the RTO.
MISO policy studies engineer Aditya Jayam Prabhakar opened his June 12 presentation on the study before the Planning Advisory Committee with an anecdote describing how his neighbor on one side had recently purchased a red Tesla model, while his other neighbor is also considering buying a Tesla.
“I’m going to be addressed as the guy between two Teslas,” Prabhakar joked.
But he said the story illustrates that “what was once was out-of-reach is now becoming attainable.”
If EV adoption revs up, MISO could see as many as 36 million EVs in the footprint if “MISO turns into San Jose,” Prabhakar said. But that’s an extremely unlikely case, he pointed out.
“There’s obviously a very high range,” Prabhakar said.
The likeliest range of future EVs, he said, lies somewhere among the study’s “low,” “base” and “high” case scenarios of 1.6 million, 4 million and 12 million vehicles, respectively, by 2039. To come up with its estimates, Berkeley used a combination of MISO and state-level data, 2018 projections from Boston University researcher Peter Fox-Penner and figures from the U.S. Energy Information Administration.
The MISO footprint currently contains only about 70,000-80,000 EVs, Prabhakar said.
“That’s a very small number compared to where we could be in the future,” he said
The study shows that if left uncontrolled, EV charging stands to steadily increase peak loads and the ramps needed to accommodate those peaks. However, if EV charging is controlled, it can deliver “significant load shaping grid services,” MISO said.
Controlled charging can occur in one of two ways, the study explained. Under “unidirectional” control, the flow of power to the vehicle can vary over the course of a charging session based on a timer, price signal or other set of rules based on grid conditions. “Bidirectional” control offers all those same features, while additionally allowing power to flow from the vehicle to the grid, helping to alleviate grid stress during periods of peak consumption.
MISO also noted that managed EV charging can help mitigate the daily load troughs and morning and evening ramps that increased renewable use can exacerbate.
In the extreme, 36-million vehicle case, uncontrolled EV charging “dominates loads throughout the day” and could add about 40 GW to MISO load by mid-2038. MISO’s average summer load last year was 86.6 GW.
“Preparing for EV impacts and their charging is a really great thing to start thinking about,” Prabhakar said. ” … This is uncharted territory in terms of what can happen; there’s so much that can happen.”
“I think EVs are a question of not if, but when,” Wabash Valley Power Association’s Matt Dorsett said. “What are the next steps for MISO? It’s certainly on our radar, and I think it’s coming quicker than we’d like.”
Prabhakar said MISO can begin adding more sophisticated EV load shapes in planning models. He said previous attempts to model future EV use boiled down to simple energy use increases.
“This is a more engineering-based approach,” he said, referring to the load-shaping approach.
Veriquest’s Dave Harlan asked whether MISO would also consider that, by 2040, several MISO generators could have already installed storage that would already serve to flatten load.
Prabhakar agreed potentially disruptive technologies like storage and EV charging should be considered together.
Multiple stakeholders also asked MISO to keep an eye on burgeoning, ultra-fast technology that can fully charge a vehicle within minutes, placing extra demand on the grid.
PHILADELPHIA — “There’s probably no topic that inspires more emotions” than electromagnetic pulses (EMP), says Electric Power Research Institute CEO Michael Howard.
An Amazon search of the topic shows why, he said at the Edison Electric Institute’s 2019 conference here Tuesday. “I haven’t done this in a little while, but I know three years ago, the first 19 of the top 20 books [on EMPs] were science fiction. And [they talk] about the end of the world,” he said. “It’s not a good day, but it’s not the end of the world when you have an EMP blast. That emotion creates hysteria. It creates unrealistic understanding about what EMP is really about and what we need to do to mitigate the impact.”
In April, EPRI released a study that concluded a high-altitude nuclear explosion could cause a multistate electric outage but not the nationwide, months-long blackout some observers have warned of. (See EPRI Report Downplays Worst-Case EMP Scenario.) On Wednesday, a NERC task force met for the first time publicly to discuss the EPRI research and President Trump’s March 26 executive order directing the federal government to protect the nation’s critical infrastructure from EMPs. (See EMP Task Force Takes ‘First Bite of the Elephant.’)
Mark P. Harvey, the National Security Council’s senior director for resilience policy, told the EEI crowd the executive order was long overdue.
“It’s been a known threat for a long time, and we get a lot of questions that say, ‘Has the threat picture changed? Is somebody now more capable? Why are you doing this now?’” said Harvey. “Frankly, it was time to take action. We’ve known about this for so long, but we haven’t had decisive action.”
Harvey said those who consider the risk of a high-altitude EMP (HEMP) remote shouldn’t dismiss the threat.
“Twenty-five years ago, the Department of Energy proved you could take material that’s already posted online and build an EMP generating device for as little as $50 with a trip to Sally’s Beauty Supply and Home Depot and knock out power to a building about this size,” he said, referring to the Marriott Hotel where EEI met.
“Don’t think just missiles over the poles, high-altitude nuclear detonation when you’re thinking about EMP. … There are ways of doing this on smaller scale with flux compression devices [or] high-powered microwave devices that could be applied against particular critical infrastructure.”
Harvey said the potential impact of such an attack has been magnified because “our critical infrastructure not only is more interconnected than it ever has been, it is now to a point where its operating with as little excess capacity as possible. It is almost maxed out within our electric sector, our communications sector, our transportation networks. So, there is little margin for error and little margin for loss across all of those critical infrastructure sectors, especially when you consider how connected they are and that you can have cascading impacts.”
Moderator Caitlin Durkovich, a director at Toffler Associates and the Department of Homeland Security’s former assistant secretary for infrastructure protection, said she is amazed by the lack of awareness about the threats of EMPs and geomagnetic disturbances. “There are people who very much think this is a thing of science fiction. They would laugh and say, ‘Really? There’s something called space weather?’”
“We are very good at planning for what’s in the rear-view mirror,” she said. “We have to get better at planning for what’s on the horizon, and even the unimaginable.”
Robert Blue, CEO of Dominion Energy’s Power Delivery Group, noted his utility supplies power to the Pentagon and numerous defense contractors and military facilities, including the world’s largest naval base at Norfolk, Va. “And a large portion of the world’s Internet traffic goes through data centers that are ours … in Northern Virginia,” he added. “So, as we think about these issues, we feel like we have a particularly important role to play because of that customer base.”
Blue said Dominion began developing expertise and mitigation measures after a GMD event in March 1989 caused the failure of the Hydro Québec system and trips of capacitor banks that Dominion used to control voltage.
“We started off by changing the specs for substations — capacitors, transformers [to] make sure they have the ability to withstand GMD-type events. [We] improved our situational awareness … equipment changes, process changes,” he said. “That sort of view has transferred to much of what we do on other issues of physical and cybersecurity.”
David W. Roop, Dominion’s director of electric transmission operations and reliability, has become a national authority on GMDs and EMPs, testifying before Congress on the topic in February.
Harvey said utilities and other critical infrastructure providers are now in a role like that of police and firefighters after 9/11.
“We looked to cops and firefighters after 9/11 and said, ‘You’re on the front lines of the global war on terror,’ and they said, ‘Hold on, I’m not ready for that.’ We said, ‘That’s fine. We’re going to give you doctrine, we’re going to give you training, we’re going to give you tools. And they stepped up.
“Now you, your members, your colleagues, are on the front lines of the great power competition of the 21st century,” he told the audience. ” … The defining threat of this era is the asymmetric threat to critical infrastructure.”
