The Illinois Commerce Commission has agreed to open the remaining meetings for its NextGrid study process to the public just days after two groups accused its chairman of keeping the public in the dark on the study and violating the state’s open meetings laws.
Sheahan | Illinois Commerce Commission
Consumer advocate Illinois PIRG Education Fund and Chicago-based energy storage and wind energy company GlidePath Development filed suit in Cook County Circuit Court on Monday against the ICC and Chairman Brien Sheahan, alleging that the commission is largely conducting its NextGrid study without public involvement (2018-CH-07943).
The two organizations allege that since launching the NextGrid study, the ICC and Sheahan have committed dozens of breaches of the state’s Open Meetings Act, including failing to post meeting notices and agendas in advance; repeatedly denying the public the opportunity to attend meetings; “actively” excluding certain individuals from attending meetings; failing to keep reliable meeting records; excluding input from working group members in meeting records; and issuing draft reports containing content that had not been discussed in meetings.
The ICC confirmed on Friday that it will open all remaining NextGrid working group meetings to the public, hours after meeting with the plaintiffs in court and working out an agreement order.
A handwritten agreement between the parties says that if the ICC wants to continue its status quo of closed meetings, it must postpone all NextGrid meetings, but if meetings proceed, they should be in full compliance with the Open Meetings Act. The ICC also agreed to provide plaintiffs with advance notice of all meetings and specific steps it will take to comply with the Open Meetings Act. The agreement also notes the ICC must still answer the plaintiffs’ complaint by July 20.
ICC Senior Public Information Officer Victoria Crawford said the ICC was “pleased that progress on this important study to explore the electric grid of the future will continue.”
“The ICC and the NextGrid facilitators and leaders remain committed, as always, to an open and transparent process,” Crawford said.
“The Illinois Commerce Commission agreed today to a court order requiring the NextGrid process to abide by the Open Meetings Act while the lawsuit proceeds. Despite an ICC spokesperson’s claims that the lawsuit was ‘frivolous,’ attorneys for the commission agreed to plaintiff demands to open the process and fully comply with the Open Meetings Act,” Illinois PIRG and GlidePath said in a joint statement on Friday.
‘Behind Closed Doors’
In their Monday complaint, Illinois PIRG and GlidePath asked the court to altogether restart the NextGrid study process in compliance with the Open Meetings Act, claiming that the study “contains recommendations that could impact competition while increasing utility control of electric generation.”
“NextGrid, as an arm of the ICC, is a public body and subject to the terms of the Open Meetings Act. NextGrid also qualifies as an advisory body of the state or a commission of the state and is subject to the terms and requirements of the Open Meetings Act,” the lawsuit contends.
The 18-month NextGrid study seeks to help Illinois prepare for the long-term needs of its utilities, grid and markets in light of new technology and an evolving resource mix. The study involves seven working groups created by the ICC, each tasked with writing one chapter of the report. The University of Illinois’ Electrical and Computing Engineering Department will edit and assemble chapters to form a final report that will likely contain recommendations for improving the state’s energy industry.
The working groups focus on separate issues, such as ratemaking, new technology, markets, metering, reliability and resilience, customer participation and environmental policy. The ICC selected working group chairs and group members. The groups have been holding closed meetings since early December.
The lawsuit claims that the ICC has so far held about 22 private meetings concerning NextGrid. In one instance in late January, a lawyer seeking to dial into a working group meeting was disconnected three times, even over the objection of a working group member, the plaintiffs contend.
The suit also alleges that the work of Next Grid lead facilitators Peter Sauer and George Gross, both professors at the University of Illinois Urbana-Champaign, is being paid for by Commonwealth Edison and Ameren. The resolution creating NextGrid acknowledges that “Illinois electric utilities will provide funding to support the work of the facilitator.”
Illinois PIRG and GlidePath also note ComEd and Ameren maintain representatives on every working group, the membership of which has not been made public.
GlidePath’s Elwood Battery Storage facility in West Chicago, Ill. | GlidePath
In a letter describing NextGrid, Sheahan said that because the effort was established by a commission resolution and is not a docketed proceeding, it will not produce a commission order at its completion.
“The purpose of the final report is to provide a comprehensive view of our current grid, and to provide a menu to policymakers, regulators, consumer advocates [and] the public about the tools, technologies and policies that could lead to the grid of the future,” Sheahan wrote.
“The report will not in every instance determine a ‘best path forward.’ We want the report to be an honest assessment of where there is agreement on policies and where there is dissention.” He added that the final report will document areas of consensus and discord alike.
Sheahan also said the decision to cap the number of members in the working groups was made to “control the number of participants and encourage frank, open dialogue and a participatory environment.”
Illinois PIRG and GlidePath disagree with Sheahan’s characterization.
“The electric grid of the future should empower consumers to have maximum competition and choice, but that won’t happen in a closed process dominated by the utility of the past,” Illinois PIRG Education Fund Director Abe Scarr said in a press release. “NextGrid must be developed with maximum transparency and in full compliance with the Open Meetings Act.”
“We can’t create good policy behind closed doors. Experience shows that excluding consumer watchdogs and market participants will hurt ratepayers,” GlidePath CEO Dan Foley said.
The two organizations say the nonpublic NextGrid process has already resulted in a draft report from the technology working group that includes a section on smart cities that had not been discussed in the meetings. They also argue the study could form the basis for major Illinois energy legislation that will affect ratepayers.
“It is important to note that the ICC has gone out of its way to ensure an open and transparent process. NextGrid is a collaborative study that relies on the input of technical experts, stakeholders and the general public,” Crawford said in an email to RTO Insider. “A diverse group of more than 230 individuals representing various sectors of the energy industry, consumer advocates, environmental groups, academia, business and community leaders are active participants in the NextGrid study.”
The commission also said it “actively” seeks involvement through mass emails, press releases and NextGrid public comment sessions after preliminary drafts of findings or report chapters are written.
The ICC keeps records of NextGrid working groups’ agendas, meeting summaries and presentations online. It also maintains separate email addresses for each working group to receive comments on the publicly available information.
“Interested parties are and have been encouraged to submit written input,” the ICC said.
SPP staff told stakeholders last week that the RTO will not conduct a joint transmission planning study with Associated Electric Cooperative Inc. this year, saying they were unable to find any “reasonable projects on either side of line.”
“The next shot will be in 2020,” said SPP’s Clint Savoy during a June 21 conference call of the SPP-AECI Interregional Planning Stakeholder Advisory Committee. “We will have plenty of time to get our hands around what we want to look at in the next study.”
A needs assessment along the seams identified more than 200 violations, but most were eliminated through model corrections or system adjustments, or because they were invalid contingencies. Most AECI violations were voltage issues, SPP said.
The RTO is proposing that one identified project, a 161-kV transmission line, be included in its 2018 near-term assessment.
A final report will be published at the end of July.
SPP and AECI have been performing joint studies every other year since 2010, as outlined in their joint operating agreement. Their only success was in 2016, when their study identified two projects near Springfield, Mo.: a new 345/161-kV transformer at AECI’s Morgan Substation and uprate to an existing 161-kV Morgan-to-Brookline transmission line, and installation of a new 345-kV 50-MVAR reactor at City Utilities of Springfield’s existing Brookline substation.
SPP would have been responsible for $17.1 million of the projects’ estimated $18.75 million cost, but FERC last year rejected the proposed cost allocation for both projects. The Brookline reactor project is now being addressed through the RTO’s regional planning process as part of the 2018 near-term assessment, and the Morgan transformer project is being prepared for another filing at FERC.
AECI, based in Springfield, is owned by and provides wholesale power to six regional generation and transmission cooperatives.
President Trump’s nominee to head the Department of Energy’s Energy Efficiency and Renewable Energy (EERE) program sidestepped controversy in his confirmation hearing Tuesday but was unable to answer several senators’ questions about key legislation and programs.
Assistant Secretary nominee Daniel Simmons, who has been running EERE on an acting basis for the last year, told the Senate Energy and Natural Resources Committee that his work at DOE is much different than his previous roles at the Institute for Energy Research (IER) and American Energy Alliance — groups backed by the conservative Koch brothers that have supported fossil fuel use and called for Congress to “eliminate” EERE. Simmons also previously worked at the American Legislative Exchange Council, which also backed fossil fuels.
Simmons | Senate Energy and Natural Resources Committee
In his opening statement, Simmons said his parents’ decision to build “a passive solar double envelope home” sparked his lifelong interest in energy efficiency and renewables. “Since [joining DOE], I have approached this job with an open mind and an eagerness to learn and have focused on following congressional direction while advancing the administration’s priorities,” he said.
Later, Simmons discussed meeting with solar and wind industry representatives in his new role, acknowledging that “we’ve had policy differences in the past.”
Ranking member Sen. Maria Cantwell (D-Wash.) asked Simmons whether he would aid her in convincing the House of Representatives to back Senate legislation increasing energy efficiency standards for buildings and appliances. (See House, Senate Conferees Begin Work to Narrow Differences on Energy Bill.)
“I’m not familiar enough with that disagreement to really comment on it; I’m sorry,” Simmons responded.
“O-kayyy … ” Cantwell said incredulously. “This will be a key part of your job, so maybe before we vote on you, you could take a look at that.”
Cantwell also complained that DOE had repeatedly missed deadlines for completing EE regulations. “We had seen a slow walking by some on this, and I’m telling you it’s wrongheaded,” she continued. “ … Our nation is going to be in the manufacturing base very, very competitive on an international basis if we can drive down electricity costs. So, that should be our mantra, and I hope that you will lead that charge.”
“I will … I will not slow walk any of those regulations,” Simmons promised.
Nominees, left to right: Teri L. Donaldson, nominee for inspector general; Karen S. Evans, assistant secretary overseeing DOE’s new Office of Cybersecurity, Energy Security and Emergency Response; Christopher Fall, director of the Office of Science; and Daniel Simmons, assistant secretary of the Energy Efficiency and Renewable Energy (EERE) program. | Senate Energy and Natural Resources Committee
In response to a question from Sen. Tina Smith (D-Minn.), Simmons also distanced himself from his comments during a 2013 podcast in which he argued that “wind and solar is more expensive and will increase the price of electricity.”
He noted that solar PV costs have dropped sharply in the last five years. “That’s one of the things that [has] changed since I made that statement,” he said.
But Simmons stumbled again under questioning from Sen. Rob Portman (R-Ohio), who with Sen. Jeanne Shaheen (D-N.H.) has led the — mostly unsuccessful — effort to win Congressional approval for tougher EE standards.
Portman asked Simmons his opinion of DOE’s “Tenant Star” program, the result of narrower EE legislation approved in 2015.
“The Tenant Star program, I’m not familiar enough with that to comment on it. But I will look into it,” Simmons said.
The senator asked whether there were more DOE should be doing on EE without Portman and Shaheen’s larger EE bill. “I’m not familiar enough with the legislation to add on to it,” Simmons responded.
Simmons was the only one of four DOE nominees testifying Tuesday to receive pointed questions from the senators. Also testifying were Teri L. Donaldson, nominee to be DOE’s inspector general; Christopher Fall, named as director of the Office of Science; and Karen S. Evans, who would become assistant secretary overseeing DOE’s new Office of Cybersecurity, Energy Security and Emergency Response.
MISO’s markets performed competitively last year, but the RTO should implement several new recommendations to improve market functions, the Independent Market Monitor’s 2017 State of the Market report concluded.
MISO IMM David Patton said energy prices averaged $29.46/MWh in 2017, an 11% increase over 2016 but in line with rising prices for natural gas and other fuels.
“The markets continued to perform competitively, although we have areas of concentration with local market power,” Patton said during a June 26 conference call held by the Markets Committee of the MISO Board of Directors.
But market performance could be made more efficient, Patton said, offering seven new market recommendations in combination with past State of the Market suggestions.
Fast-Track Ideas
Patton said two of his new recommendations could be fast-tracked and not require a slot on MISO’s Market Roadmap process, which is traditionally reserved for more complex improvements.
The first: to improve market power mitigation rules. Patton said his proposed changes are “modest in scope and impact” but would help in the effectiveness of market power mitigation provisions.
“Every year, MISO makes a cleanup filing of [mitigation rules], and we collaborate with them on it,” Patton explained. This year he has recommended that MISO adjust its impact test and sanctions rules to include the impact of negative prices; make the price impact threshold for ancillary services better reflect prevailing clearing prices; and create a better generation shift factor cutoff on mitigation for broad constrained areas, a type of congested transmission area. Including negative prices in mitigation measures will allow the Monitor to “effectively mitigate conduct whose effect is to lower prices at locations and aggravate transmission constraints,” Patton said.
Patton’s second fast-track suggestion would remove transmission charges from coordinated transaction scheduling (CTS) transfers with PJM. MISO and PJM launched CTS last October to allow market participants to schedule economic transmission transactions based on forecasted energy prices in the two RTOs. While CTS should have lowered the cost of serving load in both regions, it has not been used since mid-February because MISO has been applying transmission charges to the transactions both when they are offered and scheduled, Patton said.
“We had advised that the RTOs not apply transmission charges or allocate costs to these transactions because they do not cause any of these costs,” said Patton, who estimates the charges average $6.24/MWh on MISO imports and $2.57/MWh on exports. He urged MISO to “unilaterally eliminate” all charges from CTS transactions.
“Although MISO should encourage PJM to do the same, there is no reason to wait for PJM to agree to eliminate its charges,” Patton said. “We could change these relatively quickly … This is a very discreet change,” he told MISO board members.
Quick Fix to Make-Whole Payments
Patton said another “relatively simple” market change could help MISO distribute make-whole payments more accurately: improve commitment classifications and create a process to correct classification errors.
Patton said his team has observed MISO operators misclassifying “a fair number” of resource commitments needed to manage transmission constraints as capacity commitments. The RTO assigns a classification code to any resource it commits to either satisfy capacity needs or manage transmission constraints, which determines whether the resource is eligible for make-whole payments through its revenue sufficiency guarantee (RSG), how the RSG payment will be allocated and whether the payment will be subject to mitigation. Patton said the misclassification of code assignments can have “significant” implications on revenue sufficiency guarantee allocations and market mitigation.
“ … It is imperative that MISO have a robust process for reviewing and correcting commitment classifications as needed,” Patton said. He added that he also understood some commitments can address multiple issues and constraints and called on MISO to create clearer procedures for determining a classification based on “cost-causation” principles.
Operator Accountability
Another recommendation would place more accountability on MISO operators in the control room by improving operator logging tools to better describe operator decisions and actions. Patton said MISO operators often inconsistently log or describe manual adjustments, making them difficult to evaluate later.
Operators can make several system adjustments, including changes in generating units’ operating status, real-time adjustments to forecasted load, manual redispatch of resources for system needs, alterations of real-time limits for transmission constraints, real-time adjustments to the transmission constraint demand curve and requests for market-to-market constraint tests and activations.
“Because these actions can have significant cost and market performance implications, we recommend that MISO upgrade its systems and procedures to allow these and other operator actions to be logged in a more complete and detailed manner,” Paton said, adding that MISO could include new logging tools in its effort to replace its market platform.
Day-Ahead Market Change
Patton also proposed MISO’s platform replacement effort could provide MISO the chance to evaluate the feasibility of solving the day-ahead market with 15-minute — rather than hourly — scheduling intervals. Patton said when MISO first created its markets, the day-ahead software wasn’t sophisticated enough to be more time-specific.
“By producing hourly schedules based on 60-minutes of ramp capability and hourly load forecasts, the day-ahead schedules cannot track the expected changes in real-time system needs, particularly during ramping periods. It also regularly results in generator schedule changes from hour to hour that are not feasible, which results in substantial make-whole payments,” he said.
But advances in technology might permit 15-minute day-ahead market schedules, which could improve market response times and reduce uplift costs.
Auction Improvements
Patton’s two final recommendations involve MISO’s annual Planning Resource Auction (PRA).
The first suggestion would require that installed capacity of planning resources be deliverable over the transmission network. While the Tariff already requires all resources to be deliverable to load to qualify as capacity resources, Patton says that, in one instance, MISO’s deliverability requirements are too relaxed because resources with Energy Resource Interconnection Service (ERIS) must only secure firm transmission for its unforced capacity values, which tend to be about 5% to 10% less than their full installed capacity levels.
But Patton said resources with ERIS should be required to procure firm transmission service to the full level of their installed capacity.
“The requirements imposed by MISO on ERIS resources is not consistent with the intent of the Tariff. We recommend that MISO determine deliverability for all resources based on the entire [installed capacity] of applicable planning resources,” Patton said.
Such a move will improve the accuracy of MISO’s loss-of-load studies since they are conducted with the assumption that resources will perform up to their installed capacity when available, he noted.
The Monitor also recommended MISO establish unique capacity credits in the PRA for emergency-only resources that better reflect their availability. While those resources can be compensated through the PRA, they are only required to deploy during emergencies when called on by MISO. If they “are not available to mitigate capacity shortages that usually occur early in the emergency events, then they are not providing the reliability value assumed in the planning studies and for which they are compensated,” Patton said.
An increased volume of emergency-only resources cleared in this year’s PRA. (See MISO Clearsat $10/MW-day in 2018/19 Capacity Auction.) Patton pointed out that some of the resources have lead times up to 12 hours that “render them essentially unavailable in an emergency.” He said emergency-only and load-modifying resources should only receive full PRA capacity credit if “they are expected to be reasonably available in an emergency” and can respond to a benchmark not yet established by MISO.
Patton pointed out that other generation is subject to capacity-selling requirements, including qualifications based on past forced outage performance, day-ahead must-offer rules and reduced capacity credits for intermittent resources. He recommended MISO quantify emergency-only capacity credits based on factors such as expected availability, historical performance and curtailment ability.
Executive Director of Market Development Jeff Bladen said MISO will provide a formal response to this year’s report within 120 days, per its Tariff.
Bladen reminded the board that MISO’s ability to take on new market improvements will continue to be “constrained” by MISO’s technology capabilities as the RTO replaces its outdated market system platform. (See “Limited Improvements for Old Platform,” MISO Platform Replacement Risks Delay, Budget Overrun.)
A bill that would allow CAISO’s transformation into an RTO passed another key California State Senate committee on Tuesday after supporters were grilled on how the legislation could compromise the state’s control over its energy sector.
The Senate Judiciary Committee voted 4-1 to advance AB 813 to the Appropriations Committee, typically the final step ahead of a full floor vote. Committee Chair Hannah-Beth Jackson (D) cast the sole vote in opposition.
Holden | California State Senate
Speaking to the committee, State Assemblyman Chris Holden (D), the bill’s sponsor, touted the potential benefits of regionalizing the ISO, a three-year effort pushed by Gov. Jerry Brown that has failed to gain traction in the legislature out of concerns about yielding control over the state’s grid and the loss of energy-related jobs.
“Expanding CAISO’s participating transmission owners will allow electricity to be treated more efficiently across the West through CAISO’s markets as more of [the West’s] 37 balancing authorities join, and without layering of multiple transmission charges,” Holden said. “This will facilitate transactions such as exporting unused renewable power, like solar, throughout the region and importing power in the evening to meet California’s steep ramp as the sun goes down.”
AB 813 passed the Assembly in June 2017 but failed to come up for a vote in the Senate and was carried over to the current session. The Senate’s Energy, Utilities and Communications Committee approved the bill June 19 on a 6-1 vote. (See Senate Committee Advances CAISO Regionalization Bill.)
Loss of Oversight?
Cavanagh | California State Senate
Testifying with Holden was Ralph Cavanagh, a senior attorney with the Natural Resource Defense Council’s Climate and Clean Energy Program, who told the senators that California is already part of an integrated grid with its Western neighbors. The NRDC has been a strong proponent of regionalization.
“We’re involved in multistate grid planning now; we’re just doing it very inefficiently and at an unnecessary cost,” Cavanagh said.
He explained that while the bill would be authorizing the transition of CAISO’s state-appointed Board of Governors to a fully independent board, it would not be establishing the terms under which regionalization would proceed.
That prompted Jackson to ask: “We would lose our oversight. Is that right?”
“You have the decision to make as whether to authorize a transition to a fully independent board, and then you can pull the utilities out, senator, if for some reason you’re dissatisfied with the way the system operates,” Cavanagh said.
Stern | California State Senate
“But there’s a dispute as to whether we could pull them out or not,” Jackson said, referring to lingering questions about the process for removing the state’s utilities from the new RTO after they’ve joined.
Sen. Henry Stern (D) asked whether FERC would have to approve a utility’s withdrawal from the RTO.
“It’s an administrative sign-off,” Holden said.
Anderson | California State Senate
Sen. Joel Anderson (R) expressed confusion about how the RTO’s board would be appointed and who would fill its seats.
“What the statute establishes is that a future board would be fully independent, would have no connection to any market participant,” Cavanagh said. “It would not be a board of political appointees. It would be a board of diverse experts, which is how the other boards of the independent system operators elsewhere in North America operate.”
“But where would they come from? So, they just walk in and say, ‘I’m on the board?’” Anderson asked.
Crowley | California State Senate
Stacey Crowley, CAISO vice president of regional and federal affairs, explained that the process for selecting the board would be determined through a “public stakeholder initiative.” She noted the ISO had held workshops in 2015 and 2016 with the California Energy Commission that resulted in a proposal to create a nominating committee consisting of stakeholder representatives.
“This is not finalized, and we would go through a public process to determine that,” Crowley said.
“So the answer’s, ‘We don’t know yet,’” Jackson said.
Exporting Power, Jobs
Stern sought more information about the potential loss of California jobs if CAISO’s expansion allowed out-of-state renewables to qualify as in-state — or Bucket 1 — resources under the state’s renewable portfolio standard.
Holden acknowledged that the International Brotherhood of Electrical Workers has expressed concern about the impact of regionalization on the RPS buckets.
“We put in language to address the buckets, and in doing so, we lost a good deal of support for this bill from out-of-state wind and from others,” Holden said. “To go as far as labor would like us to go would basically end the bill.”
Joseph | California State Senate
Representing the Coalition of California Utility Employees, Mark Joseph told the committee that the ISO’s own study shows regionalization would result in the loss of 10,500 California solar construction jobs each year from 2020 to 2030.
“What the ISO has told us is that it will assume all renewable generation outside of the current footprint will be assumed to be delivered into California and therefore qualify as Bucket 1, up to the physical constraints of the transmission system, which they have told us is 12,000 MW,” Joseph said. “So the next 12,000 MW of generation — you can kiss it goodbye.”
Moorlach | California State Senate
Sen. John Moorlach (R) asked whether load in other states was paying for California’s surplus solar energy, or whether the state’s generators were being charged to send it elsewhere.
“Senator, you’re identifying a problem with the current fragmentation, which is that sometimes we can’t use all the renewable energy that we’re producing in California and we can’t push it out to the rest of the West,” Cavanagh said. “It’s worse than paying — we have to turn off solar plants at the height of the sunshine, and one of the reasons to do [regionalization] is we’ll have access to a much bigger market. Having access to the market means more revenue for California.”
“Are you sure these states will cooperate?” Moorlach asked.
“Senator, basically they’re being offered a chance to reduce their costs,” Cavanagh said. “Almost everyone cooperates in order to do that.”
The bulk power system showed improved ability to rebound from severe storms last year while continuing to improve on most other reliability metrics, NERC said last week.
NERC cited two Category 5 events — the most severe — last year in hurricanes Harvey and Irma. “While wind and water damage were record setting, the restoration efforts and subsequent recovery times were improved from historical benchmarks,” NERC reported in its State of Reliability 2018 report.
Harvey damaged 85 substations and more than 850 transmission line structures in South Texas, resulting in 225 transmission line outages. But utilities’ use of amphibious vehicles, airboats and aerial drones allowed them to perform damage assessments even before roads were clear of flooding and storm debris, NERC noted.
Irma caused a record number of electric outages in Florida, with 4.45 million customers losing power in Florida Power & Light’s territory, up from 3.24 million from Hurricane Wilma in 2005. But system hardening between the two storms reduced restoration time to 10 days from 18, NERC said.
The report recommended NERC encourage increased use of mutual assistance programs and drones and increase information sharing by publishing event reports and conducting other outreach on the lessons learned from the storms.
The storm observations were among six findings in the NERC report. The organization also found that:
Inverter disconnects during transmission disturbances are becoming an emerging risk. It cited phase-to-phase faults on 220-kV and 500-kV lines during the Canyon 2 Fire east of Los Angeles last October, which resulted in the loss of more than 900 MW of solar PV in Southern California Edison’s territory. It also noted a 500-kV line fault during the 2016 Blue Cut Fire in San Luis Obispo County, Calif., that led to the loss of 1,000 MW of BPS-connected solar PV. “The majority of these inverter-based resources tripped offline due to sub-cycle transient overvoltages and instantaneous protective action at the inverters to disconnect them from the grid,” NERC said. (See Solar Inverter Problem Leads CAISO to Boost Reserves.)
Bulk power system transmission events resulting in loss of load. Load loss was lower in 2017 than in any year since 2002. (Note: Chart excludes Criteria 4, added in 2013.) | NERC
There was no loss of load because of cyber or physical security events, but “grid security, particularly cybersecurity, is an area where NERC and the industry must continually improve defenses as threats continue to rapidly evolve.” It said the industry should continue to push for security improvements through “technological hardening, growing a culture of security, and effective information exchange between entities, the E-ISAC [Electricity Information Sharing and Analysis Center] and trusted partner organizations.” It urged continuing to improve critical infrastructure protection standards and giving “particular attention” to supply chain risks. It called for expanding participation in the E-ISAC by lowering the cost of participation and seeking Department of Energy funding.
Transmission outages resulting from failed protection system equipment, AC substation equipment (e.g., breakers, transformers) and human error — historically among the largest causes of transmission outages — all decreased over the last five years. “However, these areas remain major contributors to transmission outage severity and will remain areas of focus,” NERC said.
Annual frequencies of automatic outages of 200-kV+ transformers for 2013–2017. Green arrows indicate overall improvement. | NERC
Frequency response performance remained acceptable but varied among the four interconnections. The Eastern, Texas and Quebec Interconnections “trended ‘improving’ during the arresting period,” while the Western and Texas Interconnections “experienced statistically significant improvement during the stabilizing period” for 2013-2017. No interconnection fell below its interconnection frequency response obligation (IFRO).
Protection systems misoperations rates declined for the fifth consecutive year but remain high priorities. The overall NERC misoperation rate fell to 7.1% in 2017 from 8.3% in 2016, while the three largest causes of misoperations remained the same year-over-year: incorrect settings/logic/design errors, relay failure/malfunctions and communication failures. “Protection system misoperations exacerbate the impact of transmission outages, thereby increasing their severity,” NERC said.
The report said the only metric “indicating cause for concern” is planning reserve margins, with all regions except for the Texas Regional Entity projecting sufficient reserves for the next five years.
It cited ERCOT’s preliminary summer seasonal assessment of resource adequacy (SARA), which reported that operational tools such as load management and distribution voltage reductions could be needed to maintain sufficient operating reserves.
WILMINGTON, Del. — Members at last week’s Markets and Reliability Committee meeting approved PJM’s proposed revisions to adjust the methodology for developing the capacity model for winter peak weeks, despite strong dissent from stakeholders concerned about how the modifications might affect capacity procurement.
PJM’s Patricio Rocha-Garrido said the theoretical approach used by the RTO’s PRISM modeling software to derive aggregate outage levels during the winter peak week is not representative of actual aggregate historical outage levels because it relies on historical outage data at the individual unit level rather than the aggregate level.
To “better account for the risk caused by the volume of concurrent [outages] observed historically during this week,” the changes to Manual 20 create a “cumulative capacity outage probability table” using the historical forced outage data aggregated across the RTO. Planned outages will be based on the average historical planned outages aggregated across the RTO. (See “Winter Modeling Changes,” PJM PC/TEAC Briefs: May 3, 2018.)
However, several stakeholders expressed concern that the changes would reduce the potential for using seasonal resources.
“Given the summer-dominated loss-of-load-expectation, it is my takeaway that this change isn’t really going to have a measurable impact on the installed reserve margin,” Old Dominion Electric Cooperative’s Mike Cocco said. “However, if FERC orders changes to PJM’s annual capacity construct in response to several FERC [Federal Power Act Section] 206 complaints, then these Manual 20 changes potentially would have an effect by limiting the ability of seasonal capacity market resources to contribute. I would say there’s been a fundamental design change in [Capacity Performance], and I wouldn’t personally put so much focus on historical data but be looking at developing projections based on the design changes.”
“The challenge is making assumptions for the future; the only anchor point we have is the past,” Rocha-Garrido said.
“I believe that the assumption that planned outages is not a PJM-controllable level is not correct. It implies that PJM does not have control of planned outages,” CPower’s Bruce Campbell said.
He explained that lowering the expectations of units’ availability in the winter increases the overall procurement of annual resources, which means there would be less opportunity for seasonal resources to fill in the difference between the baseline amount of always-available resources and seasonal peak demands.
Carl Johnson, who represents the PJM Public Power Coalition, said he would be requesting a review for next year’s analysis of the model’s sensitivities and incorporating a different set of assumptions about how CP resources should be operating.
Some generation owners defended the revisions as necessary.
“We do need to do this. We cannot ignore it,” said Calpine’s David “Scarp” Scarpignato, who said he’s seen windmills in Texas stop working when the weather gets too cold.
Despite the concerns, stakeholders overwhelmingly endorsed the changes with 4.56 in favor and 0.44 opposed in a sector-weighted vote. The threshold for endorsement was 3.33.
The vote came on the same day PJM released a study analyzing the first year of partial implementation of CP in delivery year 2016/17 compared to the previous 2015/16 delivery year, which found that generator performance has improved since implementing CP even though the model has not been extensively tested by the extreme weather it was designed to address.
Unrelated to the MRC, Robbie Orvis of the clean energy consulting firm Energy Innovation, tweeted his own takeaways from the analysis. He noted the report’s acknowledgement of poor performance from coal-fired units during the January cold snap known as the “bomb cyclone.”
“Coal and oil Capacity Performance resources did not perform as well as their non-Capacity Performance counterparts during the cold snap. Understanding the source of this issue requires some additional analysis,” the report said. “Both coal and oil Capacity Performance resources showed no improvement in forced outage rates from the polar vortex to the cold snap.”
PJM said in the report that owners of coal-fired resources are making “major equipment overhauls and upgrades to ensure the longevity of these resources,” winterizing equipment to prevent icing and freezing, and “performing routine testing and inspections to ensure the quality of their equipment.”
Trust in Short Supply
A routine agenda item about cleaning up PJM’s governing documents turned into an impromptu stakeholder referendum on the RTO’s trustworthiness when stakeholders refused staff’s request for authority to file similarly innocuous revisions for FERC approval without stakeholder endorsement.
Members endorsed revisions to the Tariff to clarify cross references with the Operating Agreement and Reliability Assurance Agreement, but they drew the line when staff asked for stakeholders’ consent to file such non-substantive revisions in the future without having to bring them for an endorsement vote. Members allowed that staff wouldn’t need to make a presentation on the revisions but demanded they be on the consent agenda so stakeholders can review the changes.
American Municipal Power’s Steve Lieberman repeated his concerns that PJM was not affording the members sufficient time to review proposed changes to the governing documents and was shocked that the RTO’s response to that criticism was to seek the approval to make future non-substantive changes without prior member approval. Lieberman called into question whether the changes would be deemed non-substantive from a stakeholder perspective even if considered as such by PJM.
“Accidents have been made in the past, and sometimes we catch them for you,” Johnson added.
The reaction prompted Vince Duane, PJM’s general counsel, to weigh in uncharacteristically, saying he was “disappointed” given that members often complain they are overwhelmed by the slow pace of the stakeholder process and the extreme time commitments necessary to meaningfully engage in it.
“If you can’t trust us to make clerical changes … we’ve got a long way to go, and I don’t like the future at all,” he said.
Variable Operations & Maintenance Packages
Voting on whether to allow units to add certain variable costs in their cost-based offers derailed after American Electric Power asked to make several friendly amendments to its own proposal.
The proposed changes were a combination of proposals made by AEP and PJM that would allow units to include variable maintenance costs in cost-based energy offers as part of variable operations and maintenance (VOM). The package was endorsed at the Market Implementation Committee earlier this month. (See “Accounting for Maintenance Costs in Cost-Based Offers,” PJM Market Implementation Committee Briefs: June 6, 2018.)
The revisions appeared to be an effort to ensure the proposal is the first option to be voted on related to the matter. With the revisions, the proposal much more closely resembled a proposal brought for consideration at the meeting by Rockland Electric Co., which had previously expressed interest in a largely unpopular proposal from the Independent Market Monitor that eliminated all maintenance costs from energy offers. While RECO’s proposal was not as strict, it eliminated some double counting that the PJM/AEP proposal overlooked.
Because the proposal had been endorsed by the lower committee, AEP was no longer allowed to revise it, so it had to offer “friendly amendments” that required endorsement from the membership to be included in the proposal. When some stakeholders balked at being asked to consider last-minute amendments, others suggested the vote be deferred to a later meeting to give everyone a chance to review the changes.
PJM pushed members to commit to voting on the changes at the July MRC, explaining that the outcome affects the quadrennial review of the variable resource requirement curve in capacity auctions, which must be finalized in August. NRG Energy’s Neal Fitch questioned that argument, saying the parameters are cemented in August but the actual calculations don’t happen until January.
“I remain unconvinced that they’re tied together,” he said.
AMP’s Ed Tatum echoed that, saying the MRC “does have the ability to make changes to VOM as it sees fit,” irrespective of any “urgency” PJM desires to put on the timeline.
Stakeholders eventually agreed to defer the vote to the August MRC meeting, maintaining the current voting sequence for the proposals and declining to remand it to the MIC.
Waiting to make the revisions until after the quadrennial review is finalized will mean that these variable costs continue to be included in the cost of new entry calculation that is part of the foundation of PJM’s capacity auction for the next four years. Any subsequent changes that would include them in the VOM component of energy offers would mean that generators could be paid for those costs in both the energy and capacity markets until the VRR can be revised again in four years.
Credit and Default
Staff announced two member issues that will impact market participant accounts.
On Thursday, PJM declared GreenHat Energy in payment default for failing to pay its weekly invoice from June 5 of $1.2 million. The RTO will liquidate the financial transmission rights portfolio GreenHat defaulted on by bidding the balance of the 2018/19 positions into the auction that opens on July 16. Any remaining positions that aren’t liquidated there will be offered into the Aug. 16 auction.
Positions for 2019/20 and 2020/21 will be offered into the long-term FTR auction on Sept. 4. Those that aren’t liquidated will be offered into the Dec. 3 long-term auction.
The net loss or gain on these liquidated positions will be added to the actual unpaid net charges or net credits that accumulate on these positions prior to being liquidated and will be included in the total default amount that will be allocated to PJM’s members. Staff said they can’t estimate the amount of the default allocation assessment but believe it is likely to be “in the tens of millions of dollars.”
PJM will calculate each member’s estimated default allocation assessment percentage that will be applicable to GreenHat’s default after the June 2018 month-end invoices are issued on July 9, which staff hope to post by July 13. Staff said they will pursue “reasonable avenues of collection of GreenHat’s default amounts” and that any money recovered would be allocated back to members that are charged a default allocation.
Staff stressed that they have made revisions to the credit policy that they estimated would have created a $60 million credit requirement for GreenHat to acquire its portfolio had they been in place at the time. Stakeholders are also considering additional revisions to the credit policy. (See “DC Energy FTR Credit Policy Complaint to FERC,” PJM Market Implementation Committee Briefs: June 6, 2018.)
Staff also outlined a plan for allocating funds disgorged by PSEG Energy Resources and Trade as part of a FERC enforcement settlement. The more than $31 million — $26,905,736 plus interest of $4,494,264 — will be allocated as a negative operating reserve charge to market participants that received operating reserve charges during the period covered by the settlement. (See PSEG to Pay $39.4M to Settle FERC Investigation.)
The allocations will be made using a formula “consistent with the methodology utilized to allocate the original PSEG operating reserve credits” and staff hope to have the allocations credited by either June or July.
Stakeholder Process Revisions
During the Members Committee meeting, Chairman Mike Borgatti of Gabel Associates detailed several different initiatives to consider revising the stakeholder process, which had been a source of confusion.
First, he outlined an “academic” exercise being performed by Christina Simeone at the University of Pennsylvania’s Kleinman Center for Energy Policy. Earlier last week, Simeone sent a letter to the committee explaining that her Aug. 2 workshop is outside the stakeholder process and had been planned prior to the announcement at May’s committee meeting of similar initiatives within the stakeholder process. Simeone said she invited approximately 20 undisclosed PJM stakeholders that formed a “representative sample” of the membership and that “increasing the number of invitees risks distorting the representative sample and inhibiting in-depth group dialogue.” The chosen few will discuss “data analysis pertaining to PJM governance trends,” receive a presentation on the topic from Pennsylvania State University researchers and consider “a mock FERC-proposed rule on governance.”
Borgatti offered no endorsement of the workshop.
“I don’t control what Christina does. PJM doesn’t. I didn’t tell her I think this is a good idea,” he said. “In my opinion, this is exactly what it states to be: It’s an academic exercise.”
He assured members that the workshop wouldn’t be used to redesign the stakeholder process without their involvement and input.
PJM CEO Andy Ott echoed that view.
“I don’t believe her scholarship has any direct impact on what we’re going to do here,” he said.
The initiative within PJM will begin with a half-day discussion in late July to consider “target-rich opportunities to improve our process,” Borgatti said. He said the goal won’t be to fix any problems identified, but rather to decide whether they’re worth pursuing. The goal of the July session is to develop a recommended path forward that could be voted on at a future MC meeting.
Ott said he is aware of concerns about the stakeholder process and a “resignation” that nothing can be done to improve it.
“I think that feeling may not be the best situation,” he said.
“On the thorny issues, I think we do have opportunities to do better,” Tatum said, adding that collaboration will require opponents to not “immediately dig in their heels” and instead move forward without “preconceived notions.”
Stakeholders Approve Manual, Operational Changes
Stakeholders endorsed by acclamation several manual revisions and other operational changes:
Manual 6: Changes to address replacing terminated nodes that are part of FTR paths. These are changes to the manual only, so they will go into effect without a vote at the MC. (See “Modeling Node Changes,” PJM Market Implementation Committee Briefs: May 2, 2018.)
Revisions to the confidentiality provisions of the OA to specify that PJM may share member confidential information with reliability entities in addition to NERC. (See “Stakeholders Approve Changes to Manuals, Operations,” PJM Markets and Reliability Committee Briefs: May 24, 2018.)
Changes to the long-term FTR auction construct to correct current processes that allow participants to obtain the rights to congestion on transmission paths before the owners of the underlying auction revenue rights. The Monitor reiterated its opinion that the revisions are positive but don’t go far enough. (See “Long-term FTRs Undercut Annual FTRs,” PJM Market Implementation Committee Briefs: June 6, 2018.)
WILMINGTON, Del. — A controversial proposal to bring cost-containment measures into PJM’s transmission planning cleared its final hurdle in the stakeholder process last week despite a late attempt to block it by CEO Andy Ott.
The proposed Operating Agreement changes have been among the most contentious in recent memory. Originally developed by LS Power, the proposal gained sponsorship from several consumer advocates and PJM’s Independent Market Monitor, withstanding strong opposition from transmission owners. (See Cost Containment Coming to PJM Transmission Bids.)
It was queued up for one final endorsement vote at last week’s Members Committee meeting when Ott took the unusual step of addressing the membership to seek a delay on the vote. “I think this might be the first time I’ve ever done this,” he said.
Ott used his platform to make one final plea to stakeholders that his staff can’t handle much more.
“I think it risks the [Regional Transmission Expansion Plan] getting so complex that it becomes even more burdensome than it is today,” he said. “If you all would just take a step back. My planning staff is not infinite. … We’ll deploy our resources and do the best we can. But I think it’s unreasonable to expect that the next day we should make the baseline process more transparent. … Certainly, we can do things over time, but if you’re saying do things quickly … we cannot do all of this in the same time frame.”
He argued there are other areas in which increased efficiency would provide greater savings than the transmission cost caps. He suggested the Liaison Committee consider the issue.
“I don’t think there has been constructive engagement from all stakeholders,” he said. “I think there’s room to have more constructive engagement.”
Several of the proposal’s supporters responded to Ott’s comments. American Municipal Power’s Ed Tatum said Ott made “good observations” about the need for transparency for end-of-life projects in the RTEP process — a discussion that has been ongoing in the Transmission Replacement Processes Senior Task Force since March 2016. But, he added, “we are not proposing that PJM do the impossible.” He asked that staff “facilitate those [task force] meetings.”
“We think we’re asking for things TOs have already done to justify these discretionary projects to their management; no more, no less,” he said.
“It’s precisely because PJM and CAISO are national leaders on Order 1000 that it’s extremely important to get this right,” said LS Power’s Sharon Segner, who has shepherded the proposal from the beginning.
Susan Bruce, representing the PJM Industrial Customer Coalition, said even a 1% improvement would be “tremendous” and that the comparisons of financial significance might change as more projects become competitively bid instead of awarded to incumbent TOs.
“This will not stop us from demanding improvement in all spheres,” she said. “If I went back to my members and said [the cost-containment proposal] was deferred, they would be very disappointed in that.”
If PJM needs more staff to complete the intent of the proposal, “that’s an investment they’re willing to pay,” she said of her members.
Dominion Energy and Exelon requested and received approval for a friendly amendment to forbid PJM from requiring bidders to include cost-containment measures in their bids. That was immediately followed by a point of order challenge from PPL’s Frank “Chip” Richardson, who noted a section in the OA that required input from the Board of Managers before the MC can vote. He noted that the board hasn’t responded to a letter TOs sent to it more than a month ago to block action on the proposal. Richardson’s motion initiated a parliamentary process requiring that MC Chair Mike Borgatti, of Gabel Associates, determine whether the vote could proceed.
Ott said the board has seen the letter but hasn’t deliberated on it. Because it was sent right after the board held one of its bimonthly meetings, Ott considered whether it was of enough consequence to reconvene the board to discuss it. He decided it was not, he said.
Left to right at the PJM Members Committee meeting June 21, 2018: Chris O’Hara, PJM; Dave Anders, PJM; Mike Borgatti, Gabel Assocs; Andy Ott, PJM
Chris O’Hara, PJM’s legal counsel for the MC, said the board has been briefed on the topic and provided comments to the RTO. Board members attending the MC meeting in addition to Ott were Mark Takahashi and Dean Oskvig. O’Hara said the OA provision noted by Richardson “should not provide a legal impediment to stop the vote today” given his interpretation of the OA language and PJM’s practice since its inception of holding MC votes without the board weighing in beforehand. However, he said the final call was up to Borgatti.
“Don’t worry; the bus tires don’t hurt at all,” Borgatti responded.
Greg Poulos, executive director of the Consumer Advocates of the PJM States, said he was “disappointed” that Richardson waited until the last second to unveil his challenge and suggested that TOs and PJM were playing a “game.”
“I don’t think the conversation is advanced by suggesting there was a surprise,” O’Hara said.
“What I can offer you is that [if you think] this was a backdoor dealing, it was not. This is a real-time issue,” Borgatti said. “I have been advised that Roberts Rules require me to render a decision before we continue the meeting.”
Bob O’Connell of Panda Power Funds announced he would challenge Borgatti’s ruling either way to force a membership vote on the issue and relieve Borgatti of the weight of the decision.
“I don’t believe I or any other MC chair should be asked to dictate when the MC can vote on an issue. This is a very uncomfortable position to be in,” Borgatti acknowledged, before siding with O’Hara’s opinion and allowing the vote to proceed.
O’Connell challenged the ruling as promised, and it went to a vote, requiring a simple majority. It was taken as a sector-weighted vote, which meant it had a 2.5 threshold out of 5. It passed easily with 4.5.
The subsequent vote on the proposal also received overwhelming support with 4.28 in favor. The total was later adjusted to 4.17 with votes that hadn’t been recorded at the time, but it was still well above the 3.33 threshold necessary for endorsement.
The RTO must now work with the Monitor to develop the comparative frameworks, the first of which on construction costs is expected to be introduced in September and endorsed at the Markets and Reliability Committee on Dec. 6. It would be effective for long-term transmission proposal submission window, which runs from November to March. The second framework comparing return on equity and capital structures is expected by May 1, 2019, to be effective for all submission windows going forward.
As you may have read, the nuclear industry is promoting a new “study” by the consultancy ICF, purporting to show that failure to bail out nuclear plants would cause widespread blackouts in the Mid-Atlantic region of PJM.[1]
There are glaring fatal flaws. Let me offer just 10 (please email me with stuff I missed):
The Nuclear Energy Institute — not ICF — came up with the study assumptions, thus giving us the classic GIGO — garbage in, garbage out — problem. The study admits this: “NEI specified the scenarios for the analysis and the key assumptions for those scenarios” (page 1). So when you read below about all the unrealistic scenarios and assumptions, please keep in mind that they are the self-serving creations of the nuclear industry.
The study assumes that all the nuclear units (13 GW) in the PJM Mid-Atlantic region will retire if not bailed out (see App. A). No analysis supports this assumption. It is directly contradicted by PJM’s Independent Market Monitor, which has demonstrated, using NEI’s own cost data, that all these nuclear units except one cover their going-forward costs.[2] In other words, instead of 13 GW retiring, 1 GW retires.
The study assumes that retiring nuclear capacity is not fully replaced by other capacity resources, such that PJM overall suffers a capacity reduction of 10 GW (page 36, going from 152 GW to 142 GW). No analysis supports this assumption. It is directly contradicted by experience with PJM’s capacity market, which is designed to, and does, replace retiring capacity with new, more reliable capacity. In the last capacity auction, 67 GW cleared in the PJM Mid-Atlantic region, and there were another 6 GW that offered but didn’t clear — meaning they are available at a higher price if, for example, more nuclear units were to retire (which they won’t, as discussed in #2 above).[3]
The study assumes two gas pipeline incidents happen to occur at the same time, happen to occur during the highest winter demands in history and happen to affect only gas-fired generation (no other pipeline customers), causing the sudden loss of 13 GW of generation, and the outage persists for 60 days. Please note how absurd this scenario is: (a) two incredibly rare incidents happen at the same time; (b) during the highest winter demands in history; (c) only gas-fired generation is curtailed (despite the study’s premise that this curtailment is causing power blackouts); and (d) nothing is restored for 60 days (again, despite the study’s premise that there are blackouts). There is no legitimate basis for these wild assumptions, or for cobbling them together.
The study assumes that all demand response resources fail to perform. No analysis supports this assumption. It is simply buried in a footnote (fn. 22) questioning whether DR would perform, despite enormous penalties for failure to do so.
The study assumes that no oil inventories at dual-fuel gas generators could be restocked over a 60-day period. There is a half-hearted effort to support this assumption with statements about how difficult it might be (page 33). Given enormous penalties for failure to perform, generators would move heaven and earth to resume gas delivery and to restock oil inventories. And, of course, if oil inventory levels are problematic, adding a few more oil tanks would be an infinitesimal cost relative to the subsidies demanded by the nuclear industry.
The study assumes no gas pipeline expansion projects are built, despite the many projects underway like Transco’s Atlantic Sunrise project (1.7 Bcfd) and the PennEast Pipeline (1.1 Bcfd).[4] The study makes an argument that increased pipeline capacity somehow doesn’t increase pipeline capacity (pages 34-35).
The study implicitly assumes zero capability to transmit electric generation from the western and southern regions of PJM into the Mid-Atlantic region. There are 4 GW of such capability in the summer, and more in the winter when circuit ratings are higher because of lower temperatures.
The study implicitly assumes PJM has no tools to mitigate a temporary generation shortfall other than customer outages. No analysis supports this assumption. In a potential emergency, PJM has tools like maximum emergency generation, load management, imports, voluntary conservation and voltage reduction.[5]
I saved the best for last. The nuclear industry is claiming that without a bailout there will be hundreds of hours of blackouts. You would think that if this claim had a shred of credibility that customers facing this prospect would be screaming for a nuclear bailout. Instead, customers are diametrically opposed.[6] Why? Maybe it’s #1 through 9, above.
Let me give you a realistic take on the PJM Mid-Atlantic region. Seventy-three gigawatts offered in the last capacity auction, and there is a conservative 4 GW of transfer capability from western and southern regions of PJM, for a total of 77 GW of resources. The PJM Monitor says 1 GW of nuclear is expected to retire, for 76 GW of resources. Now let’s take the totally unrealistic scenario (see #4 above) of suddenly losing 13 GW of gas-fired generation at the worst possible time. That would leave us with 63 GW, 13 GW more than ICF’s historic peak-hour demand of 50 GW depicted on Figure 6.4 of its study. And that’s before considering pipeline expansion projects, PJM’s emergency tools, etc.
Case specifications and findings for an ICF study commissioned by the Nuclear Energy Institute. The study warns that major gas pipeline outages could result in extended blackouts in PJM if the region continues to lose nuclear generation. Columnist Steve Huntoon says the study’s assumptions are unrealistic. | ICF, Nuclear Energy Institute
There are plenty of things in this world to worry about. Blackouts from not bailing out nuclear plants? No, those pigs aren’t flying.
Use-limited resources will be allowed to attach opportunity cost adders to their bids in CAISO’s energy market under a proposal approved by FERC on Thursday.
The change was the only significant part of a package of Tariff changes — proposed in March in phase 3 of CAISO’s Commitment Costs Enhancements initiative — that the commission approved (ER18-1169). FERC rejected the ISO’s proposals to alter the information generators are required to submit to its Master File (a database of all resources participating in its markets and their characteristics) and to remove all ramp rates as components of daily bids.
The initiative is separate from, but related to, CAISO’s Commitment Costs and Default Energy Bid Enhancements; both involve better reflecting resources’ costs in their offers, thus improving market efficiency.
Use-limited resources are those that have limits on the number of start-ups and runtime hours, or on energy output, over a certain period. Small hydro facilities, for example, are automatically classified as use-limited resources by CAISO, while other resources must submit a request that includes certain data to be classified.
The 3-MW New Hogan Dam in Calaveras County, Calif. Small hydro facilities such as Hogan are automatically classified by CAISO as use-limited resources. | U.S. Army Corps of Engineers
But because the ISO’s market optimization software makes unit commitment decisions only one day ahead, it cannot take into account that dispatching a use-limited resource may hinder its ability to run later. As a result, the resources’ opportunity costs are not reflected in their offers.
CAISO said the changes are necessary because of the increase of variable energy resources on its system, making supply more unpredictable and use-limited resources necessary at any given time.
The opportunity cost adder that FERC approved “will capture the value of a use-limited resource’s limited availability so that the use limitation is not reached until the end of the monthly or annual use limitation period and the resource may be dispatched when it is valued most,” it said.
As part of the changes, effective Nov. 1, CAISO will all but eliminate one of the two methodologies under which use-limited resources are able to bid — the registered cost method. Under that approach, resources can elect to submit fixed commitment costs on a 30-day basis. CAISO told the commission that most use-limited resources use this method because it better reflects their opportunity costs and limitations, but because the costs are fixed, it cannot reflect variables such as the daily fluctuations of natural gas prices.
Use-limited resources will be required to use the proxy cost method, in which resources submit bids based on their start-up, minimum load and transition costs at a 125% cap. Resources less than a year old may still employ registered costs because, CAISO said, it needs a sufficient price history to calculate the adder.
“We find that the proposal is an improvement over the existing commitment cost recovery mechanism because the market optimization tool will be able to dispatch use-limited resources when they are most needed,” FERC said.
However, FERC agreed with NRG Energy’s protest of CAISO’s method for calculating opportunity costs. The commission ordered CAISO to submit within 30 days more details on its calculations as part of its Tariff revisions; the ISO had proposed to include them in its business practice manual.
The Master File
FERC rejected CAISO’s proposal to replace resources’ listed physical characteristics in the Master File with “design capability values,” information that reflects their capabilities when operating at maximum sustainable performance over a minimum run time. The ISO also proposed to allow scheduling coordinators to register “market values,” such as maximum daily start-ups, maximum daily number of transitions, operational ramp rates, operating reserve ramp rates and regulation ramp rates. CAISO said this would allow the market to consider, for example, that “a resource may be designed to start up five times a day, but starting it up more than twice a day could dramatically increase wear and tear and increase the probability of catastrophic failure.”
“We are concerned that, outside of exceptional dispatch, CAISO’s proposal does not include a mechanism to ensure that market values cannot be used to undermine the market’s economic resource dispatch when transmission constraints or other supply limitations create opportunities for the exercise of market power,” FERC said.
Using the market values instead of the design capability values may reduce available capacity, the commission said. “Permitting market participants to make less capacity available to the market raises the potential for physical withholding, which can affect dispatch and increase energy and ancillary service prices that may benefit the market participants’ affiliated resources. At times of tight supply conditions, it is more likely that withholding capacity could be a profitable action.” FERC also noted that CAISO proposed no new market mitigation measures to address this concern, and that its existing measures would be insufficient to handle the change.
Because CAISO predicated its proposal to remove ramp rates from daily bids on the changes to the Master File, FERC summarily rejected this as well. “If we were to accept the ramp rate proposal and reject the Master File proposal, scheduling coordinators would lose the flexibility currently afforded to them by the existing daily bid-in ramp rate functionality,” it said.
