The ERCOT Technical Advisory Committee’s leadership has canceled the committee’s April 24 meeting because of a “limited number of items to be considered” and does not plan to hold an email vote.
Instead, ERCOT will use the date to hold a workshop on outage activity related to its operating condition notice (OCN) in late February. The OCN set in motion events that resulted in market complaints about the grid operator’s communication practices and transparency. (See ERCOT Generators Upset over Early March Weather Event.)
The workshop will begin at 9:30 a.m. The TAC’s next regularly scheduled meeting is May 22.
SALT LAKE CITY — Regulators and industry experts from across the West last week heard about cyberattacks and natural disasters, having enough renewable energy to meet demand, and the possibility of using compact nuclear reactors to backstop wind and solar.
The spring joint meeting of the Committee on Regional Electric Power Cooperation and the Western Interconnection Regional Advisory Body (CREPC-WIRAB) focused on grid reliability and protecting crucial infrastructure. The conference spread across three days, with roughly 16 hours of panel discussions and approximately 175 people in attendance.
It opened with a panel on small modular nuclear reactor power plants, in which NuScale Power showed its design for a 60-MW reactor that is far more compact than traditional nuclear units. NuScale is working with the Utah Associated Municipal Power Systems (UAMPS) and the Idaho National Laboratory (INL) to develop a working module by 2026. (See With Big Nukes Dwindling, Supporters Focus on Modular.)
The NuScale unit looks like a 75-foot-tall, 15-foot-wide torpedo. Twelve of the units could be combined to form a 720-MW power plant covering 35 acres, much less ground than is usual today, said Chris Colbert, NuScale’s chief strategy officer.
“We’ve moved a number of components into the reactor pressure vessel, and what that allows us to do is to get rid of the piping and the pumps” that occupy much of the area in a traditional nuclear generating station, Colbert said. “When you go to a smaller design, you’re able to eliminate over two-thirds of the systems and components you find a in a typical reactor.”
That makes the unit simpler, with “less to operate it, less to maintain it and less things that can go wrong,” he said.
A compact nuclear unit designed by NuScale. | NuScale
Colbert and his fellow panelists acknowledged the public blowback that’s likely to greet any proposal for a new nuclear plant.
“Obviously we’ve got a lot of risk here,” UAMPS CEO Doug Hunter said.
The developers said they are planning to build the first generator at the Idaho National Laboratory, a nuclear research site larger than Delaware, with construction slated to start in 2023. They’re hoping the isolated site and lots of public outreach “will allow a new generation of reactors to exist,” said George Griffith, an INL relationship manager.
Colbert said the units will be needed to ensure reliability as older fossil-fuel generators are retired and a fast-growing number of states and cities establish carbon-free mandates. Wind, solar and hydroelectric may not be enough to keep the lights on because of varying weather and rainfall, he said.
“For those of you who’ve ever lost power for more than a day, you know what that can be like,” Colbert said. “Imagine if it did it all the time.”
Resource Adequacy Concerns
The same scenario was on the minds of state regulators and utility representatives who spoke at the meeting.
In a panel on Western resource adequacy and market purchases, Rick Link, vice president of resource planning and acquisition for Pacific Power, said diminished demand in the wake of the 2008 financial crisis had created surpluses and made it relatively easy to depend on market purchases to supply needed power.
The thinking went, he said, that “it may be cheaper to do that, as long as [the power’s] there, than spending $700 million to build a new gas facility.”
But supply is tightening, and the situation is changing, he said. Those tasked with ensuring grid reliability can no longer just talk about economics and the best use of existing resources. Instead, they need to look at the development of new resources and innovative responses.
“It’s great timing to have this discussion,” Link said. “We may be transitioning into a period where we at least have to ask the question, ‘Will [the electricity] be there?’ So, it is more one of reliability, and that needs to be pushed front and center.”
Panelists focused on the need for a regional entity to coordinate purchases and generation throughout the Western Interconnection and having sufficient transmission capacity. States will have to play a bigger role in regulation and coordination, they said. And utilities need to be able to share information about their activities to avoid conflicts, some contended.
Washington Utilities and Transportation Commissioner Ann Rendahl said regulators are concerned that utilities are overly reliant on market purchases, putting consumers at risk of rising prices in times of high demand and tight supply.
“What we don’t know is whether [the utilities are] all basically relying on the same resources,” Rendahl said. That would become clear in a cold snap or heat wave when supply tightens and prices shoot up, she and others said.
“There’s increasing uncertainty that there is sufficient resource adequacy in the next five years, creating an increasing possibility of a regional capacity condition” in the Pacific Northwest, Rendahl said. “Everyone is agreeing that we’re approaching this point.”
The “capacity surplus is quickly dwindling,” she said, “and the utilities … are not stepping forward to build capacity, leading to this very tight capacity market.”
Disaster Readiness
Other panels at the meeting dealt with electric vehicles and the need to protect utility infrastructure from terrorist attacks. (See Western EIM Looks to Expand Its Authority.)
The discussion returned repeatedly to the theme of making sure the lights stay on.
During a presentation on the Initiative for Resilience in Energy Through Vehicles (iRev), panelists — including Laura Nelson, executive director of Utah Gov. Gary Herbert’s Office of Energy, and David Terry, executive director of the National Association of State Energy Officials — discussed EVs in the context of catastrophes. EVs could allow evacuations in situations where gas is unavailable and could ensure emergency workers have vehicles that run, they said.
Most areas only have a week’s worth of gas on hand at a given time, they said. Terry showed a photo of cars crowding a gas station after Superstorm Sandy in 2012.
Natural disasters such as Hurricane Katrina in 2005 and the 1989 Loma Prieta earthquake in the San Francisco Bay Area had shown the potential for the grid to go down for extended periods, said Doug Little, senior adviser in the U.S. Department of Energy’s Office of Electricity.
“Imagine if you had to live for a week without electricity. It’s pretty scary,” Little said during his talk on protecting defense-critical electric infrastructure in the West.
“Katrina got pretty ugly” in New Orleans, and San Francisco lost power for several days after Loma Prieta, he said.
“Now we have to worry about destruction by terrorists that have become more and more resourceful,” Little said. “We could see casualties and effects on security and economy from a cyberattack that would be comparable to weapons of mass destruction.”
The federal government’s Advanced Research Projects Agency-Energy is investigating longer-duration battery storage to power the grid from 10 to 100 hours during disasters, Little said.
“If there was ever a time for megawatt-scale storage to be important, this is it,” he said.
FERC on Thursday proposed changes to NERC’s draft critical infrastructure protection (CIP) standard addressing the cybersecurity of real-time communications between control centers.
The Notice of Proposed Rulemaking, which builds on a proposal by NERC, seeks comment on requiring the electric reliability organization to add protections on the availability of communication links and data communicated between control centers. It also sought comment on requiring NERC to clarify the types of data that must be protected (RM18-20).
NERC proposed standard CIP-012-1 in response to FERC Order 822 (RM15-14), issued in 2016. In addition to approving seven modified CIP standards, FERC’s order directed NERC to require responsible entities to implement controls to protect communications links and sensitive data communicated between control centers. (See FERC Postpones Action on Supply Chain Protections.)
The order acknowledged that not all communication network components and data require the same level of protection because they pose different risks to bulk electric system reliability. As a result, NERC said its standards drafting team focused on the types of real-time data a control center will communicate and whether their compromise would pose a high risk to grid reliability.
NERC proposed exempting operational planning analysis data used in next-day operations, saying if there is a risk such data have been compromised, the responsible entity can verify the data prior to any impact on real-time operations. Although “an operational planning analysis factors into how an entity operates, there is less of a risk that an entity would act on compromised data from an operational planning analysis given it will base its operating actions on real-time inputs,” NERC said.
Also exempt are oral communications, which are covered by standard COM-001-3.
PPL’s control room | Barco Inc.
‘Largely Responsive’
NERC’s proposed standard would apply to balancing authorities, generator operators, reliability coordinators, transmission operators and transmission owners that operate control centers. It would require them to identify security protections, where they are applied and the responsibilities of each entity for control centers owned or operated by different entities.
FERC’s NOPR called NERC’s proposal “largely responsive” to Order 822, saying it supports situational awareness and reliability by requiring rules to prevent the unauthorized disclosure or modification of real-time assessment and monitoring data transmitted between control centers.
But the commission said NERC’s proposal may not address all cybersecurity risks, saying it does not require protections regarding the availability of communication links and data. The commission said it disagreed with NERC’s contention that the issue of data availability is adequately covered by standards IRO-002-5 and TOP-001-4.
The commission said those two standards only require redundant and diversely routed data exchange infrastructure within control centers, not between them.
It also said the standard must be revised to add a definition of “real-time monitoring,” which is not spelled out in the standard or the NERC Glossary.
FERC said NERC has “broadly defined” real-time assessments, which RCs and transmission operators must perform every 30 minutes to identify any actual or potential exceedances of system operating limits or interconnection reliability operating limits.
But it said “real-time monitoring is not defined at all.”
“We are concerned that without further clarity, reliability standard CIP-012-1 may be implemented and enforced in an inconsistent manner,” the commission said.
Comments on the NOPR are due 60 days from publication in the Federal Register.
WASHINGTON — FERC on Thursday finalized a streamlined licensing process for hydropower projects at non-powered dams and closed-loop pumped storage projects, a response to a Congressional directive.
Under the new rule, the commission said it “will seek to ensure a final decision” within two years after receipt of a completed license application (Order 858, RM19-6).
Chairman Neil Chatterjee said the commission completed the rulemaking with three days to spare under the 180-day deadline set by Congress in the America’s Water Infrastructure Act of 2018, which became law in October.
The expedited rules will apply to existing non-powered dams that are not already licensed or exempted from the licensing requirements of the Federal Power Act. The facilities must generate power through “withdrawals, diversions, releases or flows” from non-powered dams and must not make any material changes to the storage, release or flow operations of the dams.
Closed-loop pumped storage projects can qualify if they cause little or no change in existing surface and groundwater flows and uses and are unlikely to adversely affect threatened or endangered species. Reservoirs at natural waterways, lakes, wetlands and other natural surface water features would not qualify.
The rule permits only temporary withdrawals from surface waters or groundwater for the “initial fill and periodic recharge” of the storage facility.
The rule requires developers to document their consultation with stakeholders, including tribes, dam owners and federal and state agencies responsible for required authorizations under the Clean Water Act, the Endangered Species Act and the National Historic Preservation Act.
Applicants for projects at a non-powered dam must prove the owner of the dam is not opposed to hydropower development. Projects using any park, recreation area or wildlife area created by state or local law must provide documentation that the managing entity is not opposed.
FERC said it issued the new rule after consulting with 28 federal agencies, state agencies and tribes, which participated in an interagency task force.
Kentucky Dam and Lock 11 Hydropower Project | Rye Development
The new licensing option will be voluntary and will not change the commission’s current three prefiling process choices for developers to use in preparing license applications.
“I hope that we have a large number of license applicants” under the new rule, Commissioner Cheryl LaFleur said. “There are approximately 80,000 unpowered dams in the United States. Many of them are probably not suited for power production, but some of them are and could be brought online to help contribute reliable, carbon-free flexible electricity.”
The rule will take effect 90 days after publication in the Federal Register.
WASHINGTON — Anti-gas protester Ted Glick has been thrown out of FERC open meetings so many times that he’s no longer allowed in.
So, on Thursday morning, he and fellow protester Drew Hudson climbed a large ladder and took up residence on the three-story awning over the building’s main entrance, dropping a banner calling for renaming the agency the “Federal Renewable Energy Commission.”
The protest was timed for the commission’s monthly open meeting, at which the commissioners voted 3-1 to approve two additional LNG export projects. The meeting was interrupted twice by other members of the protest group, Beyond Extreme Energy, who were led out of the meeting room by security.
Glick and Hudson broadcast their protest from the awning via Facebook Live, saying that LNG export projects will be rendered obsolete as the nation moves to 100% renewable energy to combat climate change.
FERC Chairman Neil Chatterjee said he sympathized with the protesters’ climate concerns but that LNG exports provide net environmental benefits.
“This was a very big deal,” he said after joining with fellow Republican Bernard McNamee and Democrat Cheryl LaFleur to approve the Driftwood (CP17-117, et. al.) and Port Arthur (CP17-20, et. al.) LNG projects and associated pipelines. Democrat Richard Glick — no relation to the protester — dissented.
Ted Glick (left) and Drew Hudson broadcast from the top of FERC’s awning via Facebook Live. | Facebook
The Driftwood project in Calcasieu Parish, La., will export an estimated 27.6 million metric tons of LNG annually, while the Port Arthur, Texas, project has a capacity of 13.5 million metric tons per year. There are currently 10 LNG export projects pending before the commission.
The U.S., which became a net exporter of natural gas in 2017, will see its role grow this year, FERC’s Adam Bennett said during a presentation of the commission’s annual State of the Markets report. “By the end of this year there should be six fully operational LNG export terminals here in the U.S.,” he said. “This year alone, domestic export capability is likely to double.”
Chatterjee said U.S. exports have “geopolitical” impacts, calling the LNG approvals “a very bad day for Russia,” which has sought to use its natural gas exports as leverage over its European neighbors.
In a press conference after the meeting, Chatterjee said he respects the passion of the protesters, “particularly the folks who risked their physical safety to climb the building to make the point that they felt was important to make.”
“I’ve been very vocal that I care deeply about climate change and the need to mitigate global emissions,” he said, contending that U.S. LNG is “being used to displace dirtier sources of energy in other parts of the world.”
“If people roll their eyes at me because I’m saying that the U.S. movement in LNG has … a positive impact on climate and carbon emissions, we’re never going to be able to have a reasonable conversation here. I’m trying to be constructive. It is significant and is not something that should be dismissed.”
Chatterjee and McNamee have won LaFleur’s votes on LNG projects since February by agreeing to include in the orders calculations of the direct greenhouse gas emissions from the liquefaction process.
But Chatterjee continued to reject calls by Commissioner Glick to quantify the downstream GHG impacts of such projects, saying it could leave the orders open to reversal. “I am not certain we have the capacity to do that. It could potentially jeopardize the orders in court,” he said.
At the March commission meeting, Glick rejected Chatterjee’s claim of a bipartisan “breakthrough” on the commission’s evaluation of LNG projects, joining with LaFleur to say the panel was still ignoring the projects’ impact on climate change. (See Glick Disputes FERC ‘Breakthrough’ on LNG Projects.)
Glick said the commission could require LNG exporters to mitigate their impacts on GHG emissions, as it does on environmental impacts on land, water and endangered species. “I think everyone knows what’s going on here,” the commissioner said. “This is climate change. That’s why we can’t talk about it.”
LaFleur said she has included in her concurring opinions her own analysis of the projects’ climate impacts as an alternative to dissenting.
“In spite of the fact that we have reached compromises on some language … it’s getting harder, not easier, to do that,” she said. “We treat climate change in our environmental analyses differently than every other environmental impact, and I think we’re just waiting for the court to impose requirements on us that could add unnecessary complexities and legal risk to these very big projects.”
New Jersey regulators approved zero-emission credits totaling $300 million for all three of the state’s nuclear reactors on Thursday, nearly a year after the governor signed off on an ambitious energy plan aimed at boosting the use of carbon-free resources to 50% over the next decade.
The state Board of Public Utilities permitted the subsidies for Public Service Electric and Gas’ Hope Creek Nuclear Generating Station and Salem Nuclear Power Plant — co-owned by Exelon — after determining the facilities qualified for relief because financial strain could shutter them within three years. To qualify for ZECs, the plants must be licensed by the U.S. Nuclear Regulatory Commission through 2030, contribute to the state’s improved air quality and not receive any other subsidies.
“We do not make this decision lightly, and the board must balance protecting ratepayers with our responsibility to the citizens of the state,” BPU President Joseph Fiordaliso said in a news release on Thursday. “We have a moral obligation to our fellow citizens to do everything we can to decrease carbon emissions. In making this decision, the board considered fuel diversity, resiliency, [the Regional Greenhouse Gas Initiative], the New Jersey economy and environmental impact, and we’ve concluded that now is not a time to move forward in a way that will remove nuclear from our energy mix and ultimately increase air pollution and carbon emissions in our state.”
Hope Creek Nuclear Plant
The plants will receive ZECs for three years and the balance of the first energy year following selection. They will be subject to review by the BPU for additional three-year periods.
The board said nearly 40% of New Jersey’s emissions-free energy comes from nuclear power, making it the largest source of carbon-free energy in the state.
In 2016, according to the U.S. Energy Information Administration, the combined generation of the Salem and Hope Creek plants was 25.3 million MWh, 33.6% of the state’s 75.4 million MWh usage. The state’s Office of Legislative Services calculated that a 0.4-cents/kWh charge assessed on ratepayers would generate $301.4 million based on 2016 consumption, translating to a ZEC cost of about $10/MWh.
“We are pleased with the decision to award ZECs to PSE&G to help support New Jersey’s primary supply of zero-carbon electricity,” PSE&G said in a press release. “The BPU just saved the people of the state hundreds of millions of dollars in what would have been higher energy costs, thousands of jobs lost and tons of environmentally damaging air emissions.”
Critics argue the “bailout” money would be better invested in renewable resources like wind and solar.
“When they are saying they are doing it for climate change, they are putting out more hot air,” said Jeff Tittel, director of the New Jersey chapter of the Sierra Club. “It’s going to end up undermining our renewable energy programs, especially offshore wind and solar.”
Tittel described Thursday as “one of the most shameful days” in BPU history because he said commissioners pushed through the largest corporate subsidy in state history without any justification.
“Their own independent consultant said the subsidy wasn’t needed,” he said. “Even the commission said PSE&G didn’t qualify based on financial needs. So really the height of hypocrisy was them basing it on clean energy goals.”
Illinois and New York approved ZECs for their nuclear plants in 2016 and 2017. State legislators in Pennsylvania, Ohio and Maryland are mulling similar legislation.
NYISO’s Management Committee should approve Tariff revisions on a new market design for distributed energy resources, the Business Issues Committee recommended Wednesday.
Michael Lavillotti, the ISO’s senior market design specialist, presented an outline of the new construct. The aspects range from electrically mapping each individual DER or facility for transmission node-level granularity, to authorizing entities to provide meter services to aggregations in the DER and reliability-based demand response programs.
The motion passed with 89.25% affirmative votes, despite concerns from several stakeholders about issues such as mitigation and the terms for dual participation, under which DERs that provide wholesale market services can also provide services to another entity such as a utility or host facility.
Couch White attorney Amanda De Vito Trinsey, representing New York City and Multiple Intervenors, a coalition of large industrial, commercial and institutional energy customers, said that despite concerns with several aspects of the market design and changes to capacity values for resources (including resources participating in the reliability-based DR program), her clients support the proposal.
The ISO would electrically map each individual DER or facility for transmission node-level granularity under its proposed market design. | NYISO
NYISO Vice President for Market Operations Emilie Nelson and Senior Vice President for Market Structures Rana Mukerji said the ISO feels it struck a fair balance between reliability and market risk, and that stakeholders can help refine and adjust the Tariff rules as they all gain experience working with DERs.
“Don’t let the perfect become the enemy of the way better, and this is way better than what we started with,” said BIC Chair Aaron Breidenbaugh, who represents small consumers.
New External SRE Penalty
The BIC also recommended the MC approve a new external supplemental resource evaluation (SRE) penalty regime to improve the ISO’s ability to call on external resources that have sold into its markets. The changes would take effect in the third quarter.
Amanda Carney, NYISO capacity market design specialist, said all external capacity suppliers required to offer their energy at an external proxy must bid at the offer floor, be operating and available, and flow the scheduled transaction.
Under the new proposal, any external resource that fails to meet the criteria will be subject to the penalty, which is equal to 1.5 times the applicable spot price multiplied by the number of megawatts of shortfall and the percentage of the SRE call hours that a supplier fails to respond to.
External capacity suppliers would not be subject to the penalty if their failure to deliver is beyond their control, Carney said.
Howard Fromer, director of market policy for PSEG Power New York, thanked the ISO for the greater comparability in treatment of internal and external resources, and particularly for not penalizing external resources for failure to perform because of events beyond their control.
“Though the penalty is still draconian, we understand this is an interim measure to get the electrons here,” Fromer said. “We believe something could be done in the future to avoid using bidding gymnastics to achieve the goal and instead make bids that reflect costs in a more reasonable way to ensure reliability and performance.”
Under the new penalty provisions, the ISO will calculate deficiencies monthly, using the total number of SRE call hours in a given month that the resource could be online for and the total number of megawatts of shortfall in that month, Carney said.
External capacity suppliers are currently able to receive capacity payments without providing energy if their bids are uneconomic, even when called upon by NYISO during critical system conditions.
The BIC also approved changes to the accounting and billing manual, including to local reliability rule names, to be in line with changes made last May by the New York State Reliability Council.
| NYISO
LBMPs, Gas Prices up Slightly in March
NYISO locational-based marginal prices averaged $34.91/MWh in March, up about 4% from February and nearly 17% from the same month a year ago, Mukerji said in delivering the monthly operations report.
Year-to-date monthly energy prices averaged $42.54/MWh, a 29% decrease from a year ago.
Day-ahead and real-time load-weighted LBMPs came in higher compared to February. Average daily sendout was 411 GWh/day in March, compared with 436 GWh/day in February and 413 GWh/day in the same month a year ago.
Transco Z6 hub natural gas prices averaged $2.93/MMBtu for the month, up 6.5% from February and 2.6% from a year ago.
Distillate prices were up about 2.6% year over year and were mixed from the previous month, with Jet Kerosene Gulf Coast averaging $14.08/MMBtu, down from $14.21/MMBtu, while Ultra-low Sulfur No. 2 Diesel NY Harbor rose to $14.18/MMBtu, up from $14.02/MMBtu in February.
March uplift increased to -33 cents/MWh from -44 cents/MWh in February, while total uplift costs, excluding the ISO’s cost of operations, came in higher than the previous month.
The ISO’s 31-cents/MWh local reliability share in March was up from 11 cents/MWh the previous month, while the statewide share dropped to -64 cents/MWh from -55 cents/MWh in February.
The Thunderstorm Alert cost was 1 cent/MWh, up from the usual $0.
MISO will take another crack at identifying a project that could provide an alternative to the constrained transmission path linking its North and South regions.
But staff now have the “bandwidth” to take on the effort as part of this year’s market congestion planning study, MISO Planning Manager Matt Ellis told the Planning Advisory Committee on Tuesday. The study is designed to identify congestion-relieving projects that provide economic benefits exceeding the costs stemming from congested flowgates.
Ellis said MISO’s motivation to find possible solutions stems from both its research into showing that renewable growth is set to increase flows on the contract path, and the uncertainty around future terms and costs of its settlement agreement with SPP.
He said the RTO will reuse some underlying data from its 2017 footprint diversity study, which was exclusively aimed at finding a solution to alleviate the contract path. He said the lack of solutions from that effort isn’t deterring staff, pointing out that there are two years of fresh data on the contract path to study now.
“This is classic transmission planning. Many times, we look at the same flowgate multiple years in a row. The idea is ‘Hey, it’s a been a few years; let’s see what’s changed,’” Ellis said.
Beginning April 25, MISO will open a second, special project submission window for the market congestion planning study. Project submissions will be limited to solutions that physically cross the North-South interface and terminate on either side in MISO territory. Solutions must either eliminate or reduce settlement costs, or increase MISO’s regional transfer capability.
MISO will test project candidates against a scenario based on the possibility that the terms of its agreement with SPP continue in perpetuity. Ellis said MISO will also consider a sensitivity where the agreement is terminated and flows are again limited to the original 1,000-MW contract path. The agreement currently limits MISO line flows to 3,000 MW north-to-south and 2,500 MW south-to-north.
Ellis said MISO will likely develop a more specific list of design requirements. All project ideas will be due June 21.
While MISO intends to produce project recommendations by late August, Ellis stressed the research will be thoughtful and methodical. “Throughout this process, if we feel that we’re rushed … we have the flexibility to push back the timeline [and] add meetings. We’re not bound by an MTEP 19 decision point in this study.”
By Michael Kuser, Christen Smith and Rich Heidorn Jr.
WASHINGTON — FERC on Thursday ordered PJM and NYISO to revise their tariffs to allow fast-start resources to set clearing prices, saying their current rules are not just and reasonable.
The order concludes investigations FERC began in December 2017 under Federal Power Act Section 206 and directs the grid operators to eliminate inflexible operating limits and other rules that the commission said are preventing prices from reflecting the marginal cost of serving load. (See FERC Drops Fast-Start NOPR; Orders PJM, SPP, NYISO Changes.)
“Fast-start resources are typically committed in real time, very close to the interval when needed, and can respond quickly to unforeseen system needs. But without some form of fast-start pricing, some fast-start resources are ineligible to set prices,” the commission said in a press release.
FERC said the changes it is requiring will more accurately reflect marginal costs when the dispatch of a fast-start resource is the next action taken to meet load. It said the new rules will provide more accurate and transparent price signals to influence investment decisions, minimize production costs and reduce uplift.
“We find that commitment costs for fast-start resources are marginal because they are generally incurred in coordination with the real-time dispatch,” the commission said.
FERC ordered NYISO to revise its pricing logic to reflect the start-up costs of fast-start resources and relax the economic minimum operating limits of all fast-start resources by up to 100% to allow them to set prices (ER18-33).
The commission gave PJM a longer list of changes, ordering it to make a compliance filing by July 31 (EL18-34).
In opening the investigations in 2017, the commission said MISO and ISO-NE have already implemented fast-start best practices and that CAISO would get limited benefit from such changes. The commission also opened a Section 206 investigation into SPP’s practices, which remains pending (EL18-35).
NYISO
The commission directed NYISO to make a compliance filing by Dec. 31 and implement the Tariff changes by Dec. 31, 2020.
NYISO currently applies fast-start pricing logic to online and offline fixed block units that can start in 10 minutes. The ISO defines a fixed block unit as one that, “due to operational characteristics, can only be dispatched in one of two states: either turned completely off, or turned on and run at a fixed capacity level.”
In the first step of its optimization process, NYISO establishes resources’ physical base points in their real-time energy schedules. In the second step, the pricing run, the ISO relaxes the economic minimum operating limit of fixed block units to allow them to be eligible to set prices. The price of offline fixed block units can include a unit’s start-up costs.
“However, NYISO neither relaxes the economic minimum operating limits of dispatchable resources (i.e., resources that are not block-loaded), nor does it include the start-up costs of these or any online resources for the purpose of setting prices,” the commission said.
FERC acknowledged that NYISO does have fast-start pricing rules and said it is not proposing that the ISO implement a new pricing concept, nor would it require it to change its offline fast-start pricing or its rules on overgeneration “at this time.”
The Electric Power Supply Association and the Independent Power Producers of New York filed comments in February 2018 supporting the changes, saying that “reflecting all resources which have fast-start capability in energy and operating reserve real-time pricing is a fundamental concept,” and “it is critical that fast-start pricing includes all commitment costs.”
NYISO’s Market Monitoring Unit also filed supportive comments last year, saying that, “We agree with this proposed change because it is fully consistent with the economic principle that the competitive price for any good should reflect the marginal cost of supplying the good. Hence, well-designed fast-start pricing rules allow real-time prices to include the cost of committing and running peaking units when they are the marginal source of energy.”
PJM
The commission identified six Tariff revisions needed to correct PJM’s rules.
First, the commission said PJM must update its software to consider fast-start resources dispatchable from zero to their maximum operating limits for the purpose of setting prices.
Fast-start pricing also must apply to all applicable resources, which FERC said should only include those with a start-up time of one hour or less and minimum run time of one hour or less. Currently, PJM identifies combustion turbines with a two-hour start-up time as fast-start resources.
FERC also required PJM to:
Alter the real-time energy market clearing process to consider fast-start resources in a way that is consistent with minimizing production costs;
Include commitment costs in energy prices for fast-start resources in both the day-ahead and real-time markets; and
Implement its proposal to use lost opportunity cost payments to offset the incentive for overgeneration or price chasing.
In addition to submitting a compliance filing by July 31, PJM must make a one-time informational report by Aug. 30 explaining how the revisions do not raise new market power concerns.
FERC said PJM has special pricing rules only for block-loaded units — resources whose economic minimum operating limits equal their economic maximums, meaning they have no dispatchable range. The RTO seeks to let them set prices by relaxing the economic minimum operating limit of online block-loaded resources by up to 20% — increased from 10% in 2016.
“Even with this increase, we remain concerned that without allowing relaxation by up to 100%, marginal actions taken by system operators will not be reflected in prices,” FERC said.
The commission also said PJM’s limiting of applying fast-start pricing to block-loaded resources alone does not reflect the marginal cost of serving load when a dispatchable fast-start resource is needed. It said it agreed with commenters on “a technology-neutral approach [that] ensures that no resource that can perform the same service is unnecessarily excluded from fast-start pricing treatment.”
Commissioner Cheryl LaFleur noted that the order limits fast-start resources to those with start-up or minimum run times of one hour or less, rejecting PJM’s request for a two-hour threshold.
Daniel Kheloussi, of FERC’s Office of Energy Policy and Innovation, said the order finds that resources with start-up and minimum run times exceeding an hour “lack the flexibility to operate in a manner consistent with unforeseen and transient real-time needs, and therefore, commitment and dispatch of such resources are not analogous to a marginal decision.”
The RTO is in the process of “refreshing” an ongoing list of possible new benefit metrics, planning adviser Adam Solomon said during a Planning Subcommittee meeting Tuesday.
MISO last year created two new metrics to help size up the benefits from market efficiency project candidates: the value of deferred or avoided reliability transmission projects resulting from an MEP, and the value of increased capacity on the contract path connecting its Midwest and South regions.
The RTO said it may develop even more benefit metrics by the end of the year, including increased capacity import and export limits, reduced congestion from fewer transmission outages, reduced transmission losses and whether projects can boost grid resilience. (See “More Benefit Metrics?” MISO MEP Cost Allocation Plan Goes to FERC.)
In 2017, MISO and stakeholders participating in the Regional Expansion Criteria and Benefits Working Group (RECBWG) created a “high potential” list of possible benefits that included the transmission losses and resilience metrics, as well as reduction of capacity costs from reduced peak load losses and the value of future capacity expansion deferral from increased capacity import/export limits.
Stakeholders asked MISO to elaborate on how it plans to measure the benefits of added resilience.
“We were hoping you would actually,” Solomon joked, noting the RTO is seeking stakeholder input on the metric.
“Resilience seems so vague and broad … you would almost have to create a separate stakeholder process to [define it]. I would just hate to see this bog down the process when you have other, specific and quantifiable ideas,” said Sam Gomberg, senior energy analyst with the Union of Concerned Scientists.
Solomon said he would return to the RECBWG with an updated list of benefit ideas stakeholders want to explore. MISO and stakeholders will work on prioritizing the list in the middle of the year, then discuss the feasibility of the selected benefit metrics in the third quarter. He asked stakeholders to submit written comments on the issue by May 17.
Release of 2nd Tx Cost Estimate Guide
MISO and stakeholders are finalizing the second-ever version of a cost estimation guide for the RTO’s 2019 Transmission Expansion Plan.
The RTO released its first cost estimation guide for market efficiency or multi-value projects early last year with the intent of updating the estimates as appropriate. (See MISO Releases Transmission Cost Estimates Guide.)
MISO divides transmission costs into four categories: land and right of way; structures and foundations; conductor, optical ground wire and shield wire; and professional services and overhead. Substation cost estimates are the sum of land and site work; equipment and foundations; protection and control; and professional services and overhead.
This year, MISO has added estimates for wooden poles as a structure type and for removing existing transmission lines.
But the cost estimates will be limited to traditional transmission construction components. The guide does not include estimates for HVDC lines and burgeoning technology such as energy storage-as-transmission, design engineer Alex Monn said.
“More specialized and customized project ideas are challenging to generalize for the purposes of a cost estimation guide. MISO will consider these project types on a per project basis,” the RTO said.
“From our research … those projects are really customized and site-specific, so you won’t find those in our cost estimate guide,” Monn said.
MISO could finalize and post the guide for MTEP 19 as early as the end of this week.
