FERC on Friday approved ISO-NE’s reduction in the dynamic delist threshold for Forward Capacity Auction 13, turning aside protests by generators.
The commission reduced the threshold to $4.30/kW-month from the $5.50/kW-month the RTO had used in FCAs 10-12 (ER18-620). The threshold, which must be revised every three years, is a key parameter for generators considering retirement, which must submit delist bids to opt out of the capacity auction.
ISO-NE accepted the retirement bid from PSEG’s 383-MW Bridgeport Harbor 3 coal-fired unit for Forward Capacity Auction 12. | PSEG
ISO-NE’s auction use static and dynamic delist bids. A static bid must be filed before the auction for review by the Internal Market Monitor; bids below the dynamic delist bid threshold will be removed from the capacity market for one year.
Dynamic delist bids are submitted during the auction and are not subject to IMM review. If the auction price falls below a resource’s delist bid, that resource is removed from the auction and does not acquire a capacity supply obligation.
ISO-NE’s proposed threshold is calculated by the IMM, whose objective is to set the level slightly below the competitive price from the marginal resource in the FCA to increase the likelihood that the marginal bid is subject to a market power review. If the threshold is too high, the RTO says, existing suppliers — who know the remaining supply in each FCA round — can exert market power by increasing the FCA clearing price through their dynamic delist bids.
FCA 13 will be the second consecutive reduction in the threshold. In FCA 9, the threshold was raised from $1/kW-month to $3.94/kW-month.
Methodology
The IMM calculated the $4.30 threshold based on the most recent supply-and-demand curve information and data on shortage conditions and resource performance. The Monitor said it was unable to use recent static delist bid data to represent net going-forward costs because suppliers have submitted fewer static bids in recent auctions. Instead, the IMM estimated going-forward costs using a proxy price calculated from a weighted average of capacity that remained in the auction during the last round of FCA 11. It also used several “implied bids” — bids from resources that did not submit a dynamic bid in the final round of the auction, instead remaining to the end-of-round price of $4/kW-month.
ISO-NE said the decrease in the threshold is consistent with changes in supply and demand, noting that the amount of capacity in the RTO has increased each year since FCA 9, while the installed capacity requirement has consistently decreased. The RTO estimated a surplus of 1,250 MW for FCA 12.
Protests
The New England Power Generators Association (NEPGA) protested the RTO’s threshold, saying the IMM’s methodology was inconsistent with that used in updates since FCA 9 and that it will distort market signals and harm reliability. It noted that the Monitor disregarded cost-based offers from fossil steam resources that had been used in the past, instead using a forecast of future market conditions.
The generators group also challenged ISO-NE’s assumption that the capacity market faces a surplus in future auctions, and that the number of hours of capacity scarcity conditions will decrease.
By sending a market signal that offers above $4.30/kW-month are unlikely to clear, NEPGA said, generators will be inclined to make below-cost offers to obtain capacity revenues.
Public Service Enterprise Group also protested, saying the $5.50/kW-month threshold is already less than 70% of the net cost of new entry (CONE) for FCA 12 and that offers in that range should be considered competitive. The first seven auctions used a threshold that was 80% of net CONE, PSEG said.
Ruling
FERC sided with the IMM’s methodology, saying it was reasonable given the changing supply-and-demand dynamics since the last update. “We agree with ISO-NE and [the New England Power Pool] that the question before the commission in this proceeding is whether ISO-NE has demonstrated that its proposed dynamic delist bid threshold and the methodology that the IMM used to calculate it are just and reasonable, not whether ISO-NE’s proposal is more or less just and reasonable than protesters’ proposed alternatives,” FERC said.
It added, “The fact that the IMM used different data than it has used in the past to calculate the dynamic delist bid threshold does not, on its own, render ISO-NE’s filing unjust and unreasonable.
“While NEPGA argues that the dynamic delist bid threshold should be based on the costs of oil-fired resources because they are typically the marginal resource, we find compelling ISO-NE’s statement that, under current market rules and conditions, it is difficult to forecast with certainty the type of resource that will submit the marginal bid,” the commission continued. “As ISO-NE notes, several different resource types have submitted dynamic delist bids near the auction clearing price in the last two auctions.”
It rejected NEPGA’s prediction that bids above the reduced threshold will not clear as “speculative.”
“We agree with ISO-NE that suppliers should not rely on the dynamic delist bid threshold as an indicator of the likely clearing price in the next auction; the purpose of the dynamic delist bid threshold is not to signal the likely market clearing price but instead to help ensure that the marginal bid is subject to IMM review for the potential exercise of market power. Further, the proposed dynamic delist bid threshold does not prevent capacity suppliers from submitting properly supported delist bids that exceed the threshold.”
The commission said PSEG’s protest that the reduced threshold will exacerbate problems with the delist process was beyond the scope of the proceeding.
By Amanda Durish Cook, Jason Fordney, Tom Kleckner, Rory D. Sweeney and Rich Heidorn Jr.
RTO officials asked FERC on Friday to allow their stakeholder processes time to develop additional resilience measures while urging the commission to require more coordination with natural gas operators and provide more information on cyber threats.
Friday was the deadline for the six jurisdictional RTOs and ISOs to respond to two dozen questions FERC presented in its January order rejecting the Department of Energy’s call for price supports for coal and nuclear generators and creating the resilience docket (AD18-7). ERCOT also responded, although FERC’s jurisdiction over the Texas grid is limited to NERC reliability rules. (See DOE NOPR Rejected, ‘Resilience’ Debate Turns to RTOs, States.)
The order asked RTOs to identify their resilience risks; whether they should assess their resource portfolios against contingencies from the loss of key infrastructure; and the bulk power system attributes that contribute to resilience.
ISO-NE expressed the most acute concerns among the RTOs, saying inadequate natural gas supplies could lead to load shedding on peak days by winter 2024. It said it will need until mid-2019 to develop solutions with its stakeholders.
An ISO-NE study found that extended outages of key energy facilities would result in as much as 138 hours of load shedding by 2024. | ISO-NE
PJM, however, said RTOs and jurisdictional transmission operators in non-RTO regions should be required to file rule changes needed to address resilience within nine to 12 months. “A deadline … would help ensure focus on these issues in the stakeholder process,” PJM said.
CAISO, meanwhile, criticized FERC’s definition of resilience as “somewhat vague.”
CAISO’s comments reflected its changing resource mix and unique circumstances compared with other RTOs, but the grid operator questioned the meaning of the term “resilience.”
“The CAISO notes that the concept of ‘resilience’ presented in the resilience order is general and somewhat vague. It includes no clear objective criteria, metrics or standards to evaluate whether the existing grid is resilient,” CAISO said in comments signed by General Counsel Roger Collanton and other attorneys.
The order also lacks cost-benefit analysis, financing concerns or “prudence assessment,” CAISO said, adding that current reliability standards address many similar issues.
While the ISO criticized aspects of the order, it did detail some challenges it faces, noting that the growth of renewables has put economic pressure on the gas-fired fleet through factors such as the inability to attain resource adequacy contracts and competition for flexibility services such as ramping.
Earthquakes, drought and wildfires are the unique risks facing California, CAISO said in its 176-page filing. It also cited as risks cyberattacks and the closure of the Aliso Canyon gas storage field and the San Onofre nuclear power plant.
There are no baseload coal units in the CAISO balancing area, and the last remaining nuclear plant, Diablo Canyon, is set to retire in 2024. With natural gas generation declining and the system rapidly transitioning to renewables, in part because of the massive expansion of rooftop solar, CAISO has surplus power in daylight hours, resulting in curtailments and ramping needs illustrated by the “duck curve.”
The grid operator said that entities other than RTOs also have a role in providing resilience, such as transmission and generation owners, fuel suppliers, federal and state agencies, environmental groups and others.
CAISO said it did not see a need for an additional requirement for RTOs/ISOs to identify resilience needs as proposed in the order, for multiple generation outage scenarios, fuel disruptions and other events. Analyzing “common-mode” impacts is appropriate and addressed in normal utility reliability planning, it said.
“Creating a new risk-based analysis requirement would likely be overly prescriptive, difficult to clearly define and likely duplicate existing reliability standards given the wide range of varying specific risks different ISOs and RTOs face,” it said.
CAISO said its sensitivity analyses indicate 1,000 to 2,000 MW of retirements could result in shortfalls in load following and reserves after sunset when rooftop solar goes offline. It is supporting multiyear resource adequacy requirements for local capacity resources instead of one year and changing its backstop procurement programs.
The ISO has a filing with FERC regarding its capacity procurement mechanism and reliability-must-run changes, the topic of heavy debate in stakeholder discussions. The ISO’s internal market monitor has filed a protest to the proposal. (See CAISO, Stakeholders Debate RMR Revisions.)
Studies that CAISO has conducted include gas-electric coordination planning studies for both Southern and Northern California, as well as frequency response studies related to the replacement of conventional thermal resources with renewables, storage and distributed energy sources. Special reliability studies are done during the transmission planning process.
The grid operator added that the question as to whether the grid could “reasonably withstand” high-impact, low-frequency events was not defined and is difficult to respond to.
CAISO asked for a “a holistic approach that also considers the unique circumstances and conditions facing each region” as the resilience criteria is considered.
ERCOT, Texas PUC: Consider All Foreseeable Threats
ERCOT and the Public Utility Commission of Texas filed joint comments in the docket, although they noted that the Texas grid operator does not fall within the Federal Power Act’s definition of an RTO or ISO and “therefore does not fall within the coverage of the commission’s order.”
Still, both entities saw “great value in providing input” because it could inform FERC’s “possible application of its authority over public utility tariffs” and affect the potential development of NERC reliability standards, to which ERCOT is subject.
ERCOT is exempt from FERC’s rules for RTOs and ISOs but is subject to NERC reliability standards. | ERCOT
The two entities agreed with FERC’s concept of resilience. “Any disturbance to the bulk power system that impairs the continuous provision of electric service has, to that same extent, impaired reliability,” they said. “ERCOT and the PUC view resilience as an important subset of their existing reliability responsibilities.”
They urged FERC to look beyond “high-impact, low-frequency events” such as cyberattacks, fuel-supply disruptions and extreme weather events. “The ultimate goal of policymakers should be to ensure that all foreseeable threats to the reliability of the bulk power system are identified and addressed in the most cost-effective way,” they wrote.
ERCOT and the PUC also underscored the importance of Texas’ energy-only market design in ensuring system resilience, saying it “is inextricably linked to long-term system reliability.” As an example, they referred to February 2011, when cold temperatures knocked several generators offline and market prices hit the cap ($3,000/MWh, which has since been raised to $9,000/MWh).
“This resulted in severe financial consequences to generators with day-ahead commitments that failed to generate in real time, just as it greatly rewarded those generators that stayed online during the event,” ERCOT and the PUC said. Subsequent improvements in plant weatherization resulted in “substantially fewer generators suffering equipment failures” during similar events in 2017 and 2018.
“In short, ERCOT’s scarcity pricing mechanisms are designed to alleviate the need for many resilience-based regulatory controls,” they wrote in the 22-page filing.
ERCOT and the PUC said they address resilience concerns in operating and planning the grid, noting the “greater penetration of renewable resources … compared with most other ISOs” and the “greater vulnerability” they pose to certain extreme weather events.
“ERCOT has robust processes in place to ensure the ERCOT system will be operated in a way that can resist and recover from a variety of foreseeable disturbances,” they wrote. “These processes will continue to identify other areas for improvement as the system evolves.”
ISO-NE Sees Growing Fuel Security Risks
ISO-NE filed a 61-page response citing winter fuel security as its most significant resilience challenge and asking FERC to allow it until the second quarter of 2019 to develop a long-term solution through its stakeholder process.
The RTO said the stakeholder discussions will build on the sobering findings of its Operational Fuel Security Analysis (OFSA) report issued in January, which found the region would face energy shortfalls because of inadequate natural gas supplies in almost every fuel-mix scenario by winter 2024/2025, “requiring frequent use of emergency actions to fully meet demand or protect the grid.” (See Report: Fuel Security Key Risk for New England Grid.)
ISO-NE says natural gas generators will increasingly face fuel shortages during the winter, when heating demand is high. | ISO-NE
ISO-NE said potential solutions range from “changes to Pay-for-Performance parameters to market designs that increase incentives for forward fuel supply and resupply to inclusion of opportunity costs associated with scarce fuels and emission allowances.”
“New England’s fuel-security challenges do not lend themselves to easy solutions. Thus, the proposed time frame is necessary to allow for a systematic and deliberative regional process for examining the risks and possible solutions — a complex undertaking,” the RTO said. “A key question to be addressed in these discussions will be what level of fuel-security risk ISO-NE, the region, policymakers and regulators are willing to tolerate.”
The RTO noted that New England lacks indigenous fossil fuels production, leaving it reliant on imported fuels, including from five interstate natural gas lines whose winter capacity is mostly consumed by local distribution companies for heating. Generators are dependent on capacity released by utilities in the secondary market.
ISO-NE said it has made changes to its market design, operating procedures and systems since identifying fuel security as a problem during a cold spell in 2004. The RTO noted corrective actions it has taken, citing a change in the timing of the day-ahead market to give generators more time to procure gas; allowing market participants to modify their offers on an hourly basis to reflect changing fuel costs; Pay-for-Performance rules, which will take effect June 1; and the winter reliability program that Pay-for-Performance will replace.
But the problem has worsened as generators with onsite fuel have retired, largely replaced by natural gas-fired generators relying on just-in-time deliveries.
Changing Fuel Mix
In 2000, oil- and coal-fired power plants produced 40% of the electricity generated in New England, while natural gas fueled just 15%. Since then, the region added 16,000 MW of gas-fired generation while losing 4,600 MW of non-gas generating capacity.
By 2016, gas-fired generation was responsible for 49% of the RTO’s power, with coal and oil reduced to 3% of production, although they remain almost 30% of the region’s capacity. Natural gas’ generation share is expected to grow to 56% in 2026 while another 5,000 MW of coal- and oil-fired generation is at risk for retirement.
During the December 2017-January 2018 cold spell, oil and coal plants, which had been producing only 2% of the region’s electricity, were called on to supply one-third of New England’s power. Natural gas-fired generation dropped from almost half to less than one-quarter.
“With oil-fired generation operating at or near capacity, oil supplies, as well as emission allowances, at power plants around the region began to deplete rapidly over the two-week period, making system operations extremely challenging and significantly increasing the reliability risk to the system,” ISO-NE said.
The region, which has relied on dual-fuel capability in previous winters, said that option is becoming less viable “as emissions restrictions are tightening dual-fuel generators’ ability to use the oil-firing capability.”
The OFSA report was the first time ISO-NE had performed a deterministic analysis that looked at the entire three-month winter season between December and February as opposed to a single forecast winter peak day.
The study found that load shedding would be needed to maintain system balance in 19 of the 23 scenarios considered and that extended outages of any key energy facilities — the Distrigas and Canaport LNG terminals; the Millstone nuclear plant; or an interstate pipeline compressor station — would result in as much as 138 hours of load shedding.
The analysis said load shedding could be minimized with higher levels of LNG, imports and renewables, changes that would require new transmission and “advanced arrangements for LNG with assurances for winter delivery.”
While most of its response focused on fuel security, ISO-NE also cited as risks cybersecurity, physical security and geomagnetic disturbances, issues it said were being addressed “in other forums.”
MISO: Work Already in Progress
MISO’s filing focused on the practices it already has in place to promote resilience and pointed out that its stakeholder processes and projects have been geared toward resilience “for nearly two decades.” The RTO said it doesn’t have any “imminent or immediate” resilience concerns.
“MISO’s core foundation of ensuring regional reliability needs are met at the lowest possible cost has facilitated the creation of robust planning, operations, markets and security mechanisms that are utilized to not only identify, assess and avoid resilience threats, but also to mitigate any impacts that may occur from high-risk events,” the RTO said.
Vice President of System Planning Jennifer Curran said MISO already works with stakeholders to ensure daily grid reliability and resilience.
“Grid resilience is core to our foundation and day-to-day activities at MISO,” Curran said in a statement that the RTO issued in addition to the 52-page response to FERC. “We constantly evaluate our operations and look for opportunities to strengthen our systems, reduce risk and contribute to the dialogue and knowledge-sharing that benefits the industry and the power grid.”
MISO said it addresses resilience through its biennial Market Roadmap, a process in which it and its stakeholders identify the most pressing market improvements to undertake. (See MISO Accepting Market Roadmap Ideas.) The RTO also said it enhances resilience through gas-electric coordination, drills on severe weather and other emergencies, and its annual Transmission Expansion Plan process. It currently studies “approximately 6,500 extreme events impacting loss of multiple facilities on the transmission grid” and maintains a cyber operations team to monitor critical systems.
In researching disruptive events, it said it found only one scenario that would violate the one-day-in-10-years planning criteria: “the extreme and long-term event of the loss of the largest natural gas pipeline for the entire summer peak season.”
MISO’s generation mix has changed dramatically since 2005. | MISO
It also said the replacement for its market platform computer system was selected following a “comprehensive assessment to determine the system performance and security requirements that will be necessary to meet MISO’s long-term needs.” (See MISO Makes Case for $130M Market Platform Upgrade.)
While MISO said it generally agreed with FERC’s definition of resilience, it urged the commission to add a nod to the “changing nature of the electric grid.”
For FERC to facilitate a resilient grid, MISO said the commission should make sure “inflexible” critical infrastructure protection compliance standards do not limit cybersecurity measures. It also urged the commission to research how to value resilience in the transmission planning process and “actively support” more efficient interregional operations that can respond to disruptions.
MISO called for “broader introduction of advanced operational tools” that can improve situational awareness and congestion management. “Current limitations in both processes and tools restrict the efficient use of transmission and redispatch opportunities to fully leverage available infrastructure. These limitations result in fewer operational options to address unplanned events that may test grid resilience,” the RTO said.
As an example, it said, using the interregional transmission load relief (TLR) process to manage congestion may become inadequate as more intermittent resources join the grid. “RTO/ISO energy market advancements have facilitated the development of superior market-based congestion management tools, including redispatch, seams coordination and market-to-market processes that improve reliability and reduce costs (particularly when compared to TLR),” it said. It cited its coordination with PJM as “the model for seams operation” that could be applied “to advance interregional operations more broadly.”
But MISO also said resilience planning shouldn’t rest with RTOs and ISOs alone.
“The commission’s evaluation of resilience issues should not be limited to just RTOs and ISOs; rather, grid resilience is a national issue that broadly impacts the bulk power system. Additionally, to the extent the commission is interested in addressing concerns at the distribution level, the commission should work in partnership with state regulators to help ensure a coordinated effort,” MISO said.
NYISO Cites ‘Track Record,’ Current Initiatives
NYISO’s 26-page response noted that its most recent Reliability Needs Assessment concluded that the ISO will meet its transmission security and resource adequacy requirements through 2026.
It also identified six initiatives it is pursuing to respond to challenges resulting from “technological developments, economics, environmental considerations and public policies” transforming the grid: re-evaluating its ancillary services products and shortage pricing; ensuring that market price signals incentivize compliance with dispatch instructions; considering changes to the measurement of capacity to reflect resource performance during critical operating periods; evaluating deliverability and performance requirements for external capacity resources; potential enhancements to interregional transaction coordination; and better integration of energy storage and distributed energy resources.
It also said it will perform a “comprehensive re-evaluation” of its planning process to ensure it “stands ready to facilitate the transmission infrastructure additions and upgrades and other resources necessary to meet the evolving needs of the grid.”
In addition, the ISO said its markets “inherently value and support elements of resilience,” including the use of shortage pricing in the day-ahead and real-time markets. Since the 2013-2014 winter, the ISO said it has boosted the statewide 30-minute reserve requirement by 655 MW to 2,620 MW and implemented a new reserve region for Southeastern New York with a 1,300-MW operating reserve requirement.
It also cited its fuel inventories, gas-electric coordination and improved situational awareness from phasor measurement units added to the grid in recent years.
NYISO also pointed to the importance of its interconnections with neighboring regions, saying its exports helped ISO-NE survive fuel supply challenges during the cold weeks surrounding New Year’s Day and “provided significant levels of emergency energy” to PJM for five hours on Jan. 7.
The ISO said its public policy planning process could result in changes to require additional resilience beyond that necessary to achieve minimum reliability requirements or additional infrastructure to improve energy delivery capability. Thus far, the process has identified two transmission needs: the 345-kV transmission project in western New York, expected in service in 2022; and AC transmission additions to relieve congestion on the UPNY-SENY and Central East interfaces.
NYISO cited its transmission expansions among its efforts to enhance resilience. | NYISO
The ISO said that because there are differences of opinions regarding the definition of resilience, “the commission could potentially facilitate this dialogue through a technical conference to explore near-term concepts being considered across the diverse regions of the country.”
It also asked FERC to trust its stakeholder process, saying it “has a proven track record of success in addressing the challenges and opportunities facing the bulk power system and wholesale energy markets in New York.”
“In recognition of this success, the NYISO respectfully requests that the commission allow the NYISO to continue to work with its stakeholders in assessing and developing the enhancements necessary.”
PJM Seeks More Coordination with Pipelines, LDCs
PJM says its grid is stable and secure but urged FERC to demand changes to improve identification and mitigation of current vulnerabilities and future grid resilience challenges. The RTO also touted itself as a good example in several areas and asked FERC to make other grid operators follow its lead.
The RTO’s 84-page response also offered revisions to FERC’s proposed definition of resilience: “The ability to withstand or reduce the magnitude and/or duration of disruptive events, which includes the capability to identify vulnerabilities and threats, and plan for, prepare for, mitigate, absorb, adapt to and/or timely recover from such an event.” The RTO said the definition needs to “accurately reflect” grid operators’ capabilities without imposing “additional liabilities and … a new duty and standard of care.” FERC should also stipulate that enhancing resilience is one of grid operator’s responsibilities within regional planning, the RTO said, and that the commission has authority over resilience under its responsibility under the FPA to ensure “just and reasonable rates, terms and conditions of service.”
While acknowledging the risks of high-impact, low-frequency events, PJM also warned about “addressing vulnerabilities that evolved over time and threaten the safe and reliable operation.” It asked that FERC develop a process for grid operators to receive a review and feedback on their threat and vulnerability assessments based on national security information the commission has access to that grid operators don’t.
PJM said it has already begun addressing flaws within its operating reserve, shortage pricing, black start, energy price formation, and integration of DERs and storage. (See “Stakeholders Challenge PJM Decisions on Reserve-Shortage Identification,” PJM OC Briefs.)
Restoration Needs
Interestingly, PJM also asked that it be required to develop procedures to “permit non-market operations during emergencies, extended periods of degraded operations or unanticipated restoration scenarios … including provisions for cost-based compensation when the markets are not operational or when a wholesale supplier is directed to take certain emergency actions by PJM for which there is not an existing compensation mechanism.”
PJM said work like it’s doing to require dual-fuel capability at all black-start units should be extended throughout the country to identify “critical restoration units” and fuel-assurance criteria for them. (See “Black Start RFP,” PJM Operating Committee Briefs: Feb. 6, 2018.)
Pipeline Coordination
PJM also sought help in improving information sharing and coordination with gas pipelines, asking FERC to:
Require information sharing by pipelines by revising the “voluntary nature” of Order 787;
“Encourage” pipelines to share their threat and vulnerability analyses with grid operators, along with real-time contingency modeling and restoration-planning coordination;
Encourage development of additional pipeline services tailored to the flexibility needs of gas-fired generation “beyond today’s traditional firm/interruptible paradigm”;
Work with the Transportation Security Administration and the Pipeline and Hazardous Materials Safety Administration to improve “harmonization of cyber and physical security standards between the electric sector and the natural gas pipeline system”; and
Support more communication and coordination with local distribution companies supplying generators, perhaps by imposing obligations on local distribution companies through interstate pipeline tariffs.
Grid operators should also be required to show how they’re coordinating with other “critical interdependent infrastructure systems” like telecommunications and water utilities, PJM said.
SPP: One-Size-Fits-All Approach ‘Not Appropriate’
SPP agreed with the commission’s approach to evaluating resilience, saying FERC should continue its holistic approach and “consider the roles and relationships all participants in the electric industry, not just RTOs and ISOs, have with respect” to the grid’s resilience.
In its 21-page response, SPP wrote that it “agrees with the commission’s premise that a one-size-fits-all approach to resilience is not appropriate given the differences that can exist between the various regions.”
It stressed the importance of weighing the potential benefits against the costs in considering changes to current requirements. “Changes to requirements to address resilience could increase the costs of transmission owners’ systems, and those increased costs would ultimately impact transmission customers and their end-use customers,” SPP said.
“Accordingly, SPP respectfully submits that the perspectives and practices of non-RTO entities, including, without limitation, transmission owners, generation owners and state regulators, should be sought out and considered, as different participants in the electric industry can provide valuable insight regarding their experiences.”
ERCOT and SPP have to account for large amounts of wind energy within their resilience efforts. | NextEra Energy Resources
The RTO said FERC’s definition of resilience is “a reasonable way to capture the concept” and said it is consistent with a framework NERC is using. The reliability organization’s Issues Steering Committee told the Board of Trustees in February that most resilience definitions have two common elements: that resilience is “time-dependent” and differs from business-as-usual operations, and that it cannot be measured in a single-unit metric. (See “FERC’s McIntyre Says Resiliency Still of Interest in DC,” NERC MRC/Board of Trustees Briefs: Feb. 7, 2018.)
The committee’s framework includes four outcome-focused capabilities:
Robustness: the ability to absorb shocks and continue operating.
Resourcefulness: the ability to skillfully manage a crisis as it unfolds.
Rapid Recovery: the ability to restore services as quickly as possible.
Adaptability: the ability to incorporate and improve with lessons learned from past events.
SPP said its approach is based on “(1) resolving potential problems before they have a chance to disrupt daily operation … and (2) restoring daily operation as quickly and seamlessly as possible in the event a disruption does occur.”
It cited the resilience benefits of new transmission. “The construction of new transmission facilities pursuant to modern design standards enhance the robustness of the system,” SPP said.
“Continually evaluating risk and upgrading equipment, tools and procedures … facilitates rapid recovery by minimizing the extent and impact of disruptions.”
SPP said its approach remains adaptive, “as it is based on historical experience … combined with forward-looking evaluation of new risks and evolving technologies used in the industry.”
FERC approved ISO-NE’s two-stage capacity auction to accommodate state renewable energy procurements, with Commissioner Robert Powelson dissenting and Commissioners Cheryl LaFleur and Richard Glick leveling new criticism on the minimum offer price rule (MOPR) (ER18-619).
ISO-NE proposed the Competitive Auctions with Sponsored Policy Resources (CASPR) construct in January to address state regulators’ concerns about ratepayer costs for policy-driven resources and generators’ fears that out-of-market procurements would suppress capacity prices.
Under CASPR, ISO-NE will clear the Forward Capacity Auction as it does today, applying the MOPR to new capacity offers to prevent price suppression. In the second Substitution Auction (SA), generators with retirement bids that cleared in the primary auction would transfer their obligations to subsidized new resources that did not clear because of the MOPR. The RTO will phase out the renewable technology resource (RTR) exemption, which has allowed it to clear 200 MW of renewable generation in its capacity auction annually (to a maximum of 600 MW) without regard for the MOPR.
CASPR failed to win a 60% supermajority among stakeholders, and the RTO’s filing was opposed by its External Market Monitor, Massachusetts Attorney General Maura Healey, municipal utilities, Connecticut, the Natural Gas Supply Association, a coalition of environmental groups, the New England Power Generators Association and several merchant generators. (See ISO-NE Defends CASPR Against Protests.)
The opponents challenged the definition of sponsored-policy resources (SPRs) eligible for the SA; the cut-off date of Jan. 1, 2018; restrictions on interzonal transfers; and the phase-out of the RTR exemption without a “backstop” to ensure SPRs receive capacity obligations. They also expressed fears that “fictitious” resources would enter the auction to collect revenues from SPRs and that the construct would worsen the region’s fuel security concerns.
The commission rejected all the protestors’ concerns, approving CASPR as proposed. The commission did acknowledge concern over potential anticompetitive bidding, urging ISO-NE “to work with its stakeholders to pursue market enhancements” to strengthen market mitigation rules.
Powelson Dissent
Powelson, however, wrote a dissent calling the construct “a complicated, patchwork solution that will neither accommodate the desires of the states, nor send proper price signals to market participants.”
“The two goals that CASPR tries to achieve are fundamentally in conflict and cannot coexist in one market,” he wrote. “By trying to both accommodate state policies and protect the [Forward Capacity Market], CASPR will likely only accomplish one goal at the expense of the other. Today’s decision threatens the viability of the FCM to serve as a mechanism to ensure resource adequacy in ISO-NE, and therefore, it is unjust and unreasonable and should be rejected.”
Powelson said he shared the states’ concern that their ratepayers do not “pay twice” for capacity, as would happen if state-sponsored resources failed to win capacity commitments. “However, the states had the opportunity to foresee this ‘double-payment’ problem when they made the decision to support resources outside the market. … So unless the states are willing to reassume complete responsibility for resource adequacy, they must accept that the commission is required to take action to ensure the viability of the capacity markets.”
Powelson said CASPR will not prevent state-sponsored resources from suppressing prices, because they are exempted from the MOPR after their first year and thus permitted to offer into the market at a lower price that reflects their out-of-market revenues. “Instead of incentivizing developers to compete for market revenues, the message the commission is sending to market participants is that the best way to ensure the future viability of a particular resource is to seek state support,” he said.
In addition to suppressing prices, Powelson said CASPR also may fail to accommodate state-supported resources. “The FCM has been clearing at lower prices over the past few years, making it unlikely — if this trend continues — that a resource near retirement (i.e., one with high going-forward costs) would clear in the primary auction. As a result, there may be few or no resources eligible to swap capacity supply obligations with eligible state-supported resources.”
Glick: MOPR Rationale ‘Ill-Conceived’
Glick took the opposing view in supporting CASPR, but he dissented over the order’s “suggestion” that state-sponsored resources must either be subject to MOPR or some alternative mechanism for ensuring state policies don’t interfere with the capacity market. “That rationale — which is not adopted by a majority of the commissioners that support the order — is ill-conceived, misguided and a serious threat to consumers, the environment and, in fact, the long-term viability of the commission’s capacity market construct,” Glick said.
Instead, Glick wrote, the commission should “stop using the MOPR to interfere with state public policies and, instead, apply the MOPR in only the limited circumstance for which it was originally intended: to prevent the exercise of buyer-side market power.”
Glick contends FERC has misinterpreted the Federal Power Act, failing to respect “that states, not the commission, are the entities primarily responsible for shaping the generation mix.”
“The fact that state policies are affecting matters within the commission’s jurisdiction is not necessarily a problem for the commission to ‘solve’ but rather the natural consequence of congressional intent.
“I do not believe that it is — or should be — the commission’s mission to create an electricity market free from governmental programs aimed at legitimate policy considerations, such as clean air and combatting climate change,” he continued. “Nevertheless, today’s order appears to suggest that it is appropriate for the commission to insert itself into the states’ domain.”
Glick said the commission’s goal of ensuring “investor confidence” in the capacity market will result in over-procurement; with significant excess capacity, ISO-NE’s auction should send price signals inducing high-cost resources to retire. “There is nothing in the record that supports the conclusion that, to ensure resource adequacy in New England, the commission must act to ensure that investors in all forms of generation — both existing and new — remain confident that they will recover their costs,” he said.
Glick also said his support for CASPR is predicated on whether it facilitates the entry of state-supported resources into the FCM.
“To the extent that, as implemented, the CASPR proposal does not facilitate the entry of state-sponsored resources, it may render ISO-NE’s tariff unjust and unreasonable,” he concluded.
(Editor’s Note: Although Glick supported CASPR, his office said he was recorded as a no vote, making the tally 3-2. An earlier version of this article reported the vote as 4-1.)
LaFleur: MOPR ‘A Blunt Instrument’
LaFleur also supported CASPR but issued a concurring statement joining Glick in disagreeing with paragraph 22 of the order, which she said suggested MOPR should be the “standard solution” against the impacts of all state policies.
LaFleur said MOPR is “a blunt instrument” and that other constructs, such as carbon pricing, can also achieve state objectives within the market.
“I acknowledge that these issues are not easy, as evidenced by the split commission decision today. I also believe that these issues do not lend themselves to a cookie-cutter solution to be broadly applied across all regions,” she wrote. “I therefore hope we receive market design proposals developed by other RTO/ISOs and their stakeholders. Without prejudging any specific proposal, I believe we should be open to region-specific solutions of different types.”
CARMEL, Ind. — In what marked a first for the grid operator, MISO last week detailed its spring readiness and said there’s a small possibility of emergency conditions.
While the RTO expects to have adequate resources on hand to meet sometimes volatile demand, it might also have to rely on emergency operating procedures during what was once considered a calm shoulder period, stakeholders learned during a March 8 Market Subcommittee meeting.
“Projected spring transmission and generation outages show challenging but manageable outages, similar to recent years,” said Jeanna Furnish, MISO manager of resource planning and transmission studies.
MISO’s analysis shows a 25% probability it will need to invoke systemwide emergency operating procedures during the spring, but only if either loads or forced outages are higher than normal, Furnish said.
“My presence here isn’t to cause any alarm but to talk about … the realities of challenges that may exist on the system,” Furnish said.
Based on forecasts from the National Oceanic and Atmospheric Administration, the RTO is expecting a warmer-than-usual spring for MISO South and normal to above-normal precipitation in most of its footprint.
MISO said volatile spring loads that deviate from forecasts will require careful coordination of outages.
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Furnish pointed out that MISO maintains a nonpublic member webpage called “Maintenance Margin” that keeps a monthly forward account of how many megawatts can be taken out of service without affecting reliability. The RTO uses the data to inform generators when it predicts outages will have an impact on reliability and will recommend alternative outage schedules.
Last year, high generation and transmission outages paired with unseasonably elevated loads in MISO South produced an early April maximum generation event, unusual for a shoulder season, prompting the RTO to call on load-modifying resources for the first time in a decade. The event prompted the Independent Market Monitor to call for MISO to have increased authority over approving maintenance outages. (See 4 LMRs Face Penalties after MISO Max Gen Emergency.)
Customized Energy Solutions’ Ted Kuhn asked if Maintenance Margin provided any indication that emergency conditions were imminent last spring.
“Was the Maintenance Margin showing a deficit, or did we just fall into a black hole?” Kuhn asked.
Furnish didn’t know but said MISO continues to work with stakeholders to enhance outage coordination, including developing reserves that can be available within 30 minutes and improving congestion management with PJM at the seams by swapping control of flowgates.
MISO did not venture a guess about the projected spring peak. The RTO is planning for a 126-GW summer peak load, which it predicts will require a 17.1% planning reserve margin. (See MISO Planning Reserve Margin Climbs to 17% for 2018/19.)
WASHINGTON — Growing the electric vehicle market beyond early adopters will require creative regulations, an expanded charging network and a vastly improved customer experience, speakers told the Institute for Electric Innovation’s (IEI) spring 2018 forum Wednesday.
“The early adopters were able to deal with some of the challenges of interacting with five different charging networks and the fact that sometimes stations didn’t work; maybe they’re in the back of a parking lot that wasn’t well lit and it was kind of dangerous,” said Scott Fisher, vice president of market development for Greenlots, which sells EV charging software and services.
Fisher said he senses increased momentum for EVs, with moves in Europe to ban diesel vehicles and Volvo announcing all its models will be electric-powered by 2019.
“There seems to be a commitment among large credible companies to create this positive customer experience. So, it’s not going to cater to the 1% anymore. … To get to that 5% or 10% — that next stage of early adopters — thinking about the customer experience that’s needed” is crucial, he said. “Some of it’s in place, but making it more consistent is a really important objective.”
Alan M. Oshima, CEO of Hawaiian Electric and the owner of a plug-in Ford Fusion, agreed. “The [conflicting] charging protocols we have right now is even worse than Betamax vs. VHS,” said Oshima, who moderated the panel discussion.
“It can’t be depending on niches. It can’t just work in California or Massachusetts or New York,” said Mark S. Lantrip, CEO of Southern Company Services. “Somehow we’ve got to think about how we bring everyone along. Until that, it’s going to be a series of fits and starts.”
Exhibit A is Georgia, which — thanks to a $5,000 state tax credit — was the fastest-growing EV market in the U.S. between 2010 and 2014, according to the Edison Electric Institute, which funds the Edison Foundation and IEI. When the tax credit expired, EV sales in the state plummeted. (The federal government continues to offer a $7,500 tax credit.) Still, with 25,500 EVs as of 2016, the state ranked second to California in EV sales between 2011 and 2016.
Wooing Newcomers
Although U.S. EV sales increased by 26% last year to almost 200,000, they still represented only 1% of new vehicle sales. Globally, EV sales jumped by more than 60% last year, with China responsible for more than half the sales in the third quarter.
Fisher said the best marketing EVs could get is more charging stations. “Whenever I talk to my liberal friends in Princeton, N.J., where I live, [they say] ‘Oh, that’s a great car, but where would I charge it?’ If I have to explain to them, I’ve already kind of lost them.”
Lisa Wood, IEI’s executive director, said EVs also will benefit from the increasing visibility of electric fleets such as city buses, United Parcel Service delivery vans and school buses that can provide energy storage in summer. Electric companies have increased their EV fleets by more than 40% since 2015, according to EEI, with more than 70 companies investing more than $120 million last year alone.
Lantrip said proponents are discouraging potential adoptees from making the switch with talk of EVs’ potential as distributed energy storage.
“We’re trying to get people to just even entertain the idea of buying [an electric] car, and what I see in so many presentations on electric vehicles is they immediately go to vehicle-to-grid, vehicle-to-home, and that freaks out the average new potential buyer … because they just don’t get it or want it. It’s like, ‘You’re going to drain my battery?’ We have to separate those two conversations.”
Lantrip predicts EV penetration will not surge until there is price parity between EVs and conventional vehicles and charging times are reduced to five minutes. “We have to manage our expectations,” he said, warning that current investments in the technology and charging infrastructure should be limited to “no regrets” steps while the market remains small and different technologies are competing for dominance.
About 80% of EV charging is done at home, where residents can use either a Level 1 charger (a standard AC outlet providing up to 1.5 kW of electricity that takes 30 hours to fully charge a 115-mile battery) or a Level 2 (a 240-V AC outlet delivering up to 9 kW, which can charge in 5.5 hours). Commercial charging locations with DC-powered fast chargers deliver 50 kW and reduce a 90-mile charge to 30 minutes. In Europe, a new generation of chargers is being installed offering 350 kW, which would complete a charge in 10 to 15 minutes, but no vehicles currently offered can use them.
Norm Saari, a member of the Michigan Public Service Commission, shared Lantrip’s concern about investing in technology that could be rendered obsolete.
Saari said policymakers could be hesitant to act because of uncertainty over what is the “proven, right technology.”
“[Do] you want to have a Level 1 or Level 2 or DC fast charging? Or do you want inductive charging on the road? Or let’s forget about that. Let’s go to hydrogen fuel cells instead. There’s a lot of issues that still have to be resolved,” Saari said.
The Michigan commission held its second technical conference on EVs in February. Saari said he and his colleagues are concentrating on four primary areas: customer education, rate design, the impact of EVs on the grid and charging infrastructure — “who is going to build what, where and how is it going to be priced out?”
Under the “make ready” model, the utility supplies the service connection and supply infrastructure, with the customer supplying the charging equipment. Another model would have the utilities assume full ownership of the charging equipment — the opposite of the business-as-usual model in which the customer is responsible for all equipment.
Saari said he expects both DTE Energy and Consumers Energy to request money for EVs in rate cases the companies will file later this year.
Lantrip said Southern Co.’s Georgia Power will propose several pilot projects to regulators later this year on getting EVs to low-income customers. “It could run the gamut from something like Zipcars or it could be electrified Ubers targeted in certain areas or something in between that,” he said.
Lantrip called on utilities and regulators to be “creative in developing new rate designs.”
Fisher said that although higher EV penetration will mean more electric demand, the grid investments required to expand the market are “going to turn out to be a wise ratepayer investment.”
In California, which has more than 277,000 EVs — about half of the nation’s total — a joint study by the state’s three investor-owned utilities reported the costs of distribution upgrades to serve EVs have been “immaterial.” But Southern California Edison has said 25% of its network must be upgraded to support new chargers.
Dan Adler, vice president of policy for the Energy Foundation, which promotes energy efficient buildings and appliances, said the industry needs “durable” coalitions to ensure regulatory policy does not become an obstacle to growth. “You get better policy outcomes … if the coalition is formed ahead of time,” he said.
Role for Gas Stations
From the audience, D.C. Public Service Commission Chair Betty Ann Kane asked whether the industry was working with gas stations that might otherwise become “stranded investments” in an electrified transportation system.
“If you get the charging times down, there’s an opportunity to work with that community,” Adler said. Because gas stations make most of their profits from snack and beverage sales and not fuel, Adler said, station owners may welcome a new way to generate foot traffic.
Lantrip said new gas stations are increasingly being designed to be fit with electric charging. He said they may be the best locations for charging in urban areas where few residents own garages. Last October, Royal Dutch Shell announced it was buying one of Europe’s largest EV charging providers; it is also beginning to add EV chargers at its stations in the U.K. and the Netherlands.
AUSTIN, Texas — Texas Public Utility Commissioner Brandy Marty Marquez quietly resigned Thursday, saying she will pursue life in the private sector after two decades of public service.
Her resignation is effective April 2.
The announcement came several hours after the PUC’s open meeting. There was little hint of what was to come during the meeting, other than when Chairman DeAnn Walker, a close friend of Marquez, choked up in announcing the commission was going into a closed session to “deliberate personnel matters.” Walker avoided looking at Marquez as she gathered her composure.
“Is that it? Can we go?” Marquez said, smiling broadly. She had already met separately with Walker and fellow Commissioner Arthur D’Andrea before the open session to tell them of her decision.
Marquez’s resignation will mean the three-person PUC has completely turned over since last May, when longtime Chair Donna Nelson left. Her departure was followed by that of Ken Anderson, who resigned after his term expired in August. They were the two longest serving commissioners in PUC history, each having served eight years or more.
Marquez was appointed to the commission in August 2013 by then-Gov. Rick Perry and reappointed by Gov. Greg Abbott in 2015. Her term was to expire in September 2019.
She said in a statement she leaves the commission knowing it will continue to serve Texas “with fairness under the principled leadership” of Walker and D’Andrea.
“Supported by the best staff of any Texas agency, the PUC will continue working tirelessly on behalf of stakeholders and consumers,” Marquez said. “I am honored to have served my fellow Texans. I leave with a happy heart.”
Despite speculation that she would return to the political arena, Marquez said she plans to enter the private sector. She served as Perry’s policy director during his successful 2010 gubernatorial campaign and was his chief of staff during Texas’ 83rd legislative session. The Legislature next meets in January 2019.
“The state of Texas has benefited greatly from the more than 17 years of dedicated service from Brandy Marquez,” Abbott said. “Her commitment and passion for public service have been on full display throughout her impressive career. I commend Brandy for her extraordinary accomplishments during her tenure as commissioner.”
While at the commission, Marquez also served on the Texas Reliability Entity, which serves as the PUC’s reliability monitor for the ERCOT region and enforces NERC standards.
Commission Directs ERCOT to Revise ORDC
The PUC directed ERCOT to begin the process of removing reliability unit commitment (RUC) capacity from the ISO’s operating reserve demand curve (ORDC), which creates a real-time price adder to reflect the value of available reserves and is meant to incentivize resources to produce more energy and reserves (Project No. 47199).
Marquez said her preference was to wait until after the summer, when operating reserves are expected to be tight, but she joined with Walker and D’Andrea in the decision.
“I think taking out the RUC is the right thing to do,” Walker said. “I don’t think it’s going to make a significant difference for the summer, but it sends the signal we’re fully supportive of the energy-only market, and we will stand behind it.
“I want to be clear that this decision is based on what I believe is the correct decision, and not because anyone has made me believe this,” she continued. “I’ve been there a long time, and I didn’t need help getting there.”
“I can’t envision anybody … who believes in this market that wouldn’t support this change,” Marquez said. “We’ve never gone into a summer like this. It will be an incredible learning opportunity for our market. Anything we’re preparing for now will potentially look very different after August.”
PUC staff have also recommended removing the RUC and reliability-must-run capacity from the ORDC, saying it would ensure that scarcity pricing is accurate and reflective of market dynamics. Some market participants have pushed back, sharing Marquez’s view that it would be best to wait until after the summer to make the change. (See “Participants Caution Against Market Changes Before Summer,” Overheard at the Infocast ERCOT Market Summit.)
ERCOT staff filed a report with the PUC on March 2 that indicates removing RUC capacity from the ORDC would have provided generators an additional $6.6 million and $18.6 million in revenue in 2016 and 2017, respectively. Given that total generator revenues in ERCOT were about $8.4 billion in 2016 and $9.5 billion in 2017, the adders respectively represented about 0.07% and 0.2% of total revenue, staff said.
The ISO study estimated it would cost $15,000 to $25,000 to modify ERCOT’s systems to remove online RUC and RMR resources from the ORDC capacity value, and could be done internally within 60 days.
ERCOT will include the revised protocol language for its April 10 Board of Directors meeting.
PUC to Intervene at FERC in MISO’s Docket
Following the PUC’s executive session, Walker announced the commission would be intervening in MISO’s application before FERC to create targeted market efficiency projects, a new category of small interregional transmission projects (ER18-867).
Walker also said Thomas Gleeson, the commission’s director of finance and administration, will serve as its interim executive director until a full-time replacement can be found. Brian Lloyd resigned from the position March 1, after seven years. (See Texas PUC Executive Director to Resign.)
LOS ANGELES — Despite recent developments favoring more organized energy markets, Westerners still hold some “anxiety” and “hesitancy” about a new RTO in the region, says Doug Howe, chairman of the Western Energy Imbalance Market’s (EIM) Governing Body.
Howe, a doctor of mathematics, independent consultant, former utility executive and former New Mexico regulator, joined the body when it was established in 2016.
At an EIM meeting in Los Angeles last week, RTO Insider asked Howe how he sees the Western landscape taking shape, and what his concerns are about a possible new Western RTO.
“My sense is still that there is a lot of hesitancy towards a full RTO,” Howe said. “The idea of transmission allocation and a uniform transmission price across a region as big as the Western Interconnection gets a lot of people a little nervous, because we have widely varying transmission costs in the West.”
Several possible changes are stirring the West, including a joint proposal by Peak Reliability and PJM to create a new market and CAISO’s plan to extend its day-ahead market across the EIM. (See Calif. Lawmakers Relaunch CAISO Regionalization.)
While the Peak/PJM market proposal only sets out to establish an energy market, and not a full RTO, Peak executives have described it as a “pathway” to an RTO.
“All of these initiatives are in some sense a pathway to an RTO,” Howe said. The question is how to deliver the benefits of an RTO, such as day-ahead, real-time and ancillary services markets, “without triggering all this anxiety,” he said.
The best approach, according to Howe?
“Let’s get the energy markets established first and then we will see where stakeholders are comfortable going.”
Howe said industry participants have several choices to examine now and will be analyzing the costs and benefits of each one, “and whether it has sufficient bells and whistles — is it the right market to be in?”
One concern is “the absence of a real exit strategy” if a market participant joins an RTO, he said.
“If you find it’s not working out for you, getting out is extraordinarily expensive,” Howe said. While CAISO is seeking to extend the day-ahead market across the EIM, an RTO “is not what we are proposing at this point.” The trade-off is that participants don’t get the full benefits of an RTO either, he said.
When asked about whether there is unease about a balkanized and noncontiguous market taking shape, Howe said, “I don’t think there is a lot of concern about that.” The Eastern U.S. is balkanized to some degree and “it’s a spider web of transmission,” he said. In the West, transmission lines run north and south and east and west from the coast inland.
“They have worked that out in the East, but there is some concern that the West is not the same as the East, and that is going to be part of the working-out process,” Howe said. “There might be a little more concern about the reliability coordinator becoming balkanized, because they are the ones that have a high-level view of the entire grid.”
LOS ANGELES — Western Energy Imbalance Market (EIM) leaders last week endorsed CAISO’s controversial proposal to give generators more bidding flexibility, but not without giving ground to the plan’s skeptics.
The EIM’s Governing Body on Thursday approved the ISO’s Commitment Costs and Default Energy Bid Enhancements (CCDEBE), designed to give generators more latitude in how they reflect their commitment — or start-up and minimum load — costs and overhaul the way the ISO calculates the default energy bid, which replaces bids of units found to have market power.
The current method can artificially limit a generator’s commitment cost and limits what the generator can bid in, the ISO has said.
But to the end, market participants and the ISO’s Department of Market Monitoring raised questions after a lengthy stakeholder process to develop the rules. (See CAISO Developing New Bidding Rules.)
The rule changes still require approval by the CAISO Board of Governors, which will consider the proposal at its March 21-22 meeting.
‘A Good Place’
CAISO’s proposal replaces a static commitment cost bid cap with a local market power mitigation test, which identifies whether a resource needs to be committed to relieve a transmission overload or other constraints, the same way energy bids are handled. The ISO will only mitigate bids when a generator fails the test.
Under the current rules, the ISO calculates reference levels for each gas-fired generator based on published natural gas price indices. The commitment cost reference level is determined by multiplying costs by 125% and bids are capped at the generator’s reference level.
CAISO plans to phase in commitment cost bidding flexibility, first raising the commitment cost multiplier to 150% for the first 18 months after implementation, and then increasing it to 300% if no issues arise.
During the rulemaking process and at Thursday’s meeting, there was heavy debate over CAISO’s plan to automatically increase the reference levels after 18 months. Some commenters, such as Governing Body member Kristine Schmidt, suggested that a new stakeholder process might be needed at the 18-month point.
But CAISO Vice President of Market and Infrastructure Development Keith Casey resisted the idea, saying “it sends a message to the market that we are not serious about this.”
Body members compromised by adding a provision to the decision that the ISO provide a status report to the EIM and CAISO board at the 18-month point.
“This was tough one, but I think we ended up in a good place on this,” Governing Body Chairman Douglas Howe said.
The ISO recently lowered the proposed multiplier for the first 18 months to 150% from 200%, in an “abundance of caution,” Market Design Manager Brad Cooper said, calling the bid cap a “circuit breaker.” The proposal also allows suppliers to seek adjustments to their reference levels based on changes in documented costs.
“We believe that we have a robust design, but we agree we need to proceed cautiously with changes,” Cooper said during a presentation to the Governing Body.
Respectful Disagreement
DMM Director Eric Hildebrandt supported the proposal, saying “the basic framework is there.” But he recommended a few changes, saying there are some gaps, a potential for economic withholding and for a “kind of gaming.” (See Monitor Critical of CAISO Commitment Cost Mitigation Plan.)
“We have looked at it, and we respectfully disagree,” Casey responded, adding that some power suppliers are “sort of biting their tongue” on the arrangement for the first 18 months. An automatic change at the 18-month point provides certainty that the ISO is committed to moving to the higher cap, he said, adding that CAISO can always file with FERC to keep the level at 150% if it discovers issues.
Howe said the EIM’s decision “is trying to carve a middle road,” but he didn’t think CAISO should “back into” a second stakeholder process that would “allow everybody to have a second bite” at things they didn’t like.
Body member John Prescott said, “I support this, and I would advise the Board of Governors to support this as well.” He said he expects the DMM to make sure issues don’t materialize.
Representing the Western Power Trading Forum, Carrie Bentley of Resoro Consulting told RTO Insider that the parties most affected by the change will be EIM entities or others who have experienced challenges with CAISO calculating their proxy costs, and generators and scheduling coordinators impacted by high gas prices.
She said that while WPTF supports the proposal, she called CAISO’s changing the reference level late in the proceeding “an unfortunate circumstance of panic policymaking in response to a few influential stakeholders. The CAISO had an excellent proposal, and it would have been better if they just remained confident in it.”
CARMEL, Ind. — MISO’s Independent Market Monitor is backing the RTO’s proposal to revise its uninstructed deviation rules to allow generators to recoup a portion of make-whole payments even when their ramp rates fall short of expectations.
Monitor David Patton said last week that he now favors the “less draconian” performance-based proposal over his original recommendation from last year’s State of the Market report.
MISO’s plan would calculate a generator’s uninstructed deviation by comparing the time-weighted average of its real-time ramp rate with its day-ahead offered ramp rate, while allowing for a 12% tolerance from set point instructions. The proposal eliminates the RTO’s current “all or nothing” eligibility for make-whole payments, instead allowing generators to collect full payments when they respond to dispatch instructions at a rate of 80% or higher over an hour, while excluding payouts when performance rates fall below 20%. Units operating between those two thresholds would earn make-whole payments in proportion to performance.
The RTO currently flags generators that deviate from ramp rate dispatch instructions by more than 8% over four consecutive five-minute intervals, putting them at risk of losing day-ahead margin assurance payments (DAMAPs). The new approach would eliminate all current ramp rate requirements except for the one requiring rates of greater than 0.5 MW/minute.
Patton said MISO’s time-weighted approach provides generators greater incentive to follow their offered ramp rates than his earlier proposal requiring units to move at least half their offered ramp rate within a 20-minute grace period before being flagged and losing make-whole payments. (See MISO Tempers Dispatch Plan After Stakeholder Pushback.)
“That 15 minutes is a knife edge,” Patton said of the originally proposed 20-minute grace period before becoming ineligible for DAMAPs. “Generators motionless after 15 minutes will have to move at 100% of their ramp rate immediately to avoid exceeding 20 minutes.”
He also pointed to the benefits of performance-based partial payments.
“Over the course of an hour, generators will have a stronger incentive to perform better. If you perform reasonably well, you’ll make more money than if you don’t perform reasonably well,” he said.
Patton said MISO generators have so far been discouraged from providing a “multi-point” ramp rate that factors the time it takes to move a unit in the first few moments after firing it up. He said using an average of hourly performance will allow for nuances.
Some stakeholders agreed that it was a good idea to allow a lagging lead-time for slow-moving units but said the proposal doesn’t help wind and solar generators, which have a tendency to be flagged for excessive energy production.
Patton acknowledged that wind power may need a “special rule,” saying MISO could make “simple” changes to excessive energy flags for wind only when the excessive ramping doesn’t cause congestion.
MISO plans to continue refining the uninstructed deviation proposal through April.
While structural issues persist, PJM’s markets were competitive in 2017, the RTO’s Independent Market Monitor said Thursday, contradicting concerns from PJM and some stakeholders that prices are unsustainably low.
In his annual State of the Market Report, Monitor Joe Bowring noted that PJM’s energy, capacity, regulation, synchronized reserve, day-ahead reserve and financial transmission rights markets all produced competitive results with competitive participant behavior, although all showed either market structure or design issues. Bowring recommended improvements for each market.
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But the results show that the generation fleet remains relatively diverse and that most plants are receiving enough revenue to be profitable. All diesel and pumped-storage resources, and nearly all gas-fired combustion turbines and hydro stations, received full recovery of their avoidable costs, as did 88% of oil- or gas-fired steam units and 86% of gas-fired combined cycle plants.
Among nuclear plants, 68% earned enough revenue to cover an industry-standard calculation of costs developed by the Nuclear Energy Institute.
Using capacity auction results going forward, the report found only four nuclear facilities are threatened with negative revenues: Oyster Creek (which is already slated for decommissioning), Davis-Besse, Three Mile Island (TMI) and Perry. Quad Cities and Byron, the beneficiaries of Illinois’ controversial zero-emissions credits legislation, had been unprofitable four of the past five years but are projected to turn a profit through 2020.
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The Salem nuclear plant also is expected to remain profitable through 2020. Asked why Exelon and Public Service Enterprise Group, which jointly own the two-unit facility in southern New Jersey, decided to halt capital expenditures at the plant, Bowring said he was “not quite sure” the reasoning.
“Based on publicly available data, it is more than covering its costs,” he said. “Nuclear units are not making a lot of money, but generally … they are not receiving a retirement signal from the market.”
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“It’s not surprising” that single-unit facilities are the ones that are getting that signal, Bowring said. Additionally, he argued that NEI’s number was “inappropriate” because it included additional costs that were incurred in the aftermath of the Fukushima disaster in 2011. Using two-thirds of those costs, all but TMI and Davis-Besse will be profitable.
Just 52% of coal-fired plants recovered their avoidable costs, the report showed. PJM’s plan to revise price formation would support large, inflexible units like coal plants, but Bowring said the reforms were not based on market flaws. Nearly 79% of the $24.7 million uplift costs from day-ahead operating reserve differences were paid to coal units in 2017, but not because of market design issues, he said.
“That actually has to do with some very specific circumstances about coal units that have nothing to do with convexity and non-convexity and would not be affected by PJM’s price-formation proposal,” Bowring said.
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Coal units also received nearly 85% of $20.4 million in uplift paid for reactive services, but gas turbines gobbled up the vast majority of the remaining $83 million uplift payments for lost opportunity cost, black-start services, local constraints control and balancing operating reserves.
While new combined cycle facilities could turn a profit in some zones, the revenue available in 2017 didn’t cover the cost of entry for new combustion turbine generators, nuclear or other units.
“The PJM system is significantly long” on generation, Bowring said, in part because the RTO has been regularly over-forecasting demand. The average real-time demand was down 2.2% from 2016 to 86,618 MWh. Peak and average load were also down.
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That factored into a $30.99 average LMP, which was up 6% from 2016 but lower than every other year since 2000. Much of that came from coal and gas prices, which combined to account for nearly 70% of the LMP.
