FERC on Thursday approved LS Power’s acquisition of two generating facilities in PJM, rejecting the Independent Market Monitor’s request for behavioral mitigation measures to address market power.
The commission approved LS Power’s purchase of the Panda Hummel Station, a 1,096.5-MW natural gas-fired facility in Pennsylvania owned by several individuals and Siemens Financial Services, a subsidiary of Siemens AG (EC20-55).
Separately, the commission approved LS Power’s purchase of Jersey Central Power & Light Co.’s 50% interest in the Yards Creek Pumped Storage Station, a 420-MW facility in New Jersey (EC20-65). The commission had approved LS Power’s purchase of the other 50% share of Yards Creek from PSEG Fossil LLC, a subsidiary of Public Service Enterprise Group, on Sept. 1 (EC20-49).
The Market Monitor argued that the three purchases should be considered together, saying they would increase concentration in some locational energy markets, have a significant impact on PJM’s market for regulation and increase concentration in the capacity market. Concentration in the Eastern Mid-Atlantic Area Council and MAAC locational deliverability areas (LDAs) would drop.
The Monitor said generators with market power can avoid mitigation by using varying markups in their price-based offers and by offering different operating parameters or using different fuels in their price-based and cost-based offers.
Panda Hummel Station, a 1,096.5-MW combined cycle plant on the Susquehanna River near Sunbury, Pa. | Bechtel Corp.
Because of that, it said LS Power’s combined cycle and combustion turbine resources should be prohibited from submitting price-based incremental energy offer curves that include both positive and negative markup relative to the cost-based offer. It also said they should be barred from submitting price-based offers with higher economic minimum output megawatt limits than the cost-based offer and required to submit cost-based offers for all available fuel types for dual fuel units.
The Monitor also expressed concern over the concentration in the ownership of fast-start resources, which it said allows sellers with high market shares the ability to use physical operating parameters to exercise market power. It said LS Power should be required to submit operating parameters for its fast-start units that meet PJM’s parameter limits.
The Monitor said pumped hydro units in PJM are not mitigated when their owners fail the three pivotal supplier test, allowing them to strategically withhold economic energy or to produce excess, uneconomic energy. It said the company should be required to follow the day-ahead schedule produced by the PJM hydro optimizer in real-time operations for Yards Creek and Seneca Generation, a 484-MW pumped storage facility in Pennsylvania.
Yards Creek Pump Storage Station in New Jersey | RE Warner and Associates
LS Power’s pump storage units should also be prohibited from submitting simultaneous dual offers for both RegA (slow regulation) and RegD (fast regulation) products in PJM because it can result in uneconomic solutions, the Monitor said.
Finally, the Monitor said, LS Power should be required to make capacity offers at no greater than the net avoidable cost rate (ACR) because structural market power in PJM’s capacity market is endemic.
The commission rejected all of the Monitor’s proposed restrictions. It said the Monitor failed to show that the transactions will increase market power and said its proposed restrictions on offers from LS Power’s combined cycle and combustion turbine units “relies on existing perceived limitations of PJM’s market power mitigation.”
FERC also dismissed the Monitor’s proposed mitigation on LS Power’s pumped storage units, saying it was “based on general concerns about certain elements of PJM’s market design that are not specific to the [Yards Creek] transaction. This Section 203 proceeding to evaluate the proposed transaction is not the appropriate venue for raising or addressing general concerns regarding market design.”
The commission said the transactions’ aggregate 1,517 MW is too small to have a material impact on the RTO’s ancillary services markets. It also rejected the Monitor’s call for limiting LS Power’s capacity offers to net ACR, noting that the company’s post-transaction market share in the MAAC LDA is 4.6%.
The New York State Climate Action Council on Thursday approved creation of an advisory panel on waste emissions to be established by Department of Environmental Conservation (DEC) staff.
The panel joins six others set up in August, along with a Just Transition Working Group to ensure social equity in the council’s proceedings.
Martin Brand, NYDEC | NYDPS
“We’re going to evaluate emissions and mitigation strategies for a wide range of these waste generating sectors, including the traditional municipal and commercial solid waste generation infrastructure; facilities like transfer stations, landfills and waste-to-energy; and municipal combustors and co-gen facilities,” DEC Deputy Commissioner Martin Brand said. (See NY Seeks Comment on Proposed Emissions Limits.)
The DEC also plans to look at all the handling, transportation and disposal aspects for that infrastructure, including some of the large-scale construction and demolition debris and materials processing activities around the state, Brand said.
New York’s Climate Leadership and Community Protection Act (CLCPA) directs the DEC to measure greenhouse gas emissions on a common scale using the carbon dioxide equivalence metric (CO2e) and the 20-year global warming potential (GWP20) of each gas, as derived from the U.N.’s Intergovernmental Panel on Climate Change (IPCC).
In addition, the CLCPA mandates that 70% of electricity consumed in the state should come from renewable resources by 2030 and that electricity generation should be 100% carbon-free by 2040.
Robert Howarth, Cornell University | NYDPS
“The waste stream overall for the greenhouse gas emissions for the state is smaller than fossil fuel use, but it’s not trivial — about 20% of statewide emissions are coming from this industry and these sources,” said CAC member Robert Howarth, Cornell University professor of ecology and environmental biology.
If looked at in detail, 95% of the total emissions from waste in New York is methane, not carbon dioxide, said Howarth, who recently published a study that shows methane emissions have grown as carbon dioxide emissions have declined, leaving New York’s total GHG emissions in 2015 virtually unchanged from 1990. (See NY Study Highlights Rising Methane Emissions.)
“When we think about the panel, I suggest that the membership be focused not on who the economic players are in the waste industry, but rather on where the GHG emissions are actually coming from,” Howarth said. “Our goal, of course, is to reduce those, so I would suggest a big focus on landfills, certainly on water treatment plants.”
Gavin Donohue, CEO of the Independent Power Producers of New York (IPPNY), said it is “really appropriate” how DEC has decided to reach out to local government authorities and waste management experts to help inform the panel’s deliberations.
Flexible Generation
John Rhodes, PSC | NYDPS
Of all the topics being covered by the panel on power generation, resource mix is especially important, said Public Service Commission Chair John Rhodes, who leads the advisory panel.
“Which resources need to come up, which resources need to come down, and how do we get resources into the mix that can provide flexibility, which is going to be a big theme of our panel,” Rhodes said.
There also are a series of topics surrounding equity in terms of access to clean energy solutions, access to new jobs in the burgeoning industry and affordability for the many low-income New Yorkers who face a heavy energy burden, he said.
The panel intends to finalize its work plan in October before briefing the CAC on priority policies and strategies in December, ahead of making final recommendations in March, Rhodes said, noting it would evaluate the costs and benefits of recommended strategies, informed by the value of carbon established in accordance with the CLCPA.
A NYSERDA report last year shows GHG emissions from waste management (MMtCO2e), 1990–2016. | NYSERDA
“In New York we’ve seen a number of studies that look at decarbonization, that try to inform the discussion and create greater awareness of the issues, such as how to manage electrification, how to create flexibility and, importantly, how to avoid overbuilt scenarios of extreme new peaks, which are the bane of every system,” Rhodes said.
“I was glad to see carbon pricing on the agenda, but you didn’t list interaction with other panels,” Howarth said. “I’d like to see carbon pricing done in a context of all fossil fuel use, including transportation and housing and all, and not simply in the electricity sector.”
“That was a deliberate punt,” Rhodes said. “You’re right, carbon pricing certainly should be discussed economywide. It’s a little above my pay grade to think about who should take that on, which I could see being a Climate Action Council-level issue.”
Anne Reynolds, ACENY | NYDPS
Anne Reynolds, executive director of the Alliance for Clean Energy New York (ACE NY), brought up biofuels and renewable natural gas and asked Rhodes if the panel considered defining the term “emission-free.”
“There’s a requirement for 70% renewables by 2030 and 100% emissions-free by 2040, and the statute’s pretty clear on what counts as renewable but a little more vague on what counts as emission-free after that,” Reynolds said.
The topic did not come up on the panel but should be dealt with, Rhodes said.
Basil Seggos, NYDEC | NYDPS
CAC member Paul Shepson, dean of Stony Brook University School of Marine and Atmospheric Sciences (SoMAS), asked what panel or panels would consider methane emissions, particularly if in big cities they prove to be coming from natural gas infrastructure.
“Many of the panels are going to be dealing with the issue of methane emissions,” said CAC Co-chair and DEC Commissioner Basil Seggos. “We may want to charge every panel with considering that, and then find a way to bring all the panels together in a joint session to cross-fertilize recommendations, rather than creating a new panel.”
Administrative Law Judge Molly T. McBride will conduct two public comment hearing webinars for the proposed emissions rule on Oct. 20, and the DEC will accept public comments until Oct. 27.
Grid in Transition
NYISO CEO Rich Dewey presented on the grid operator’s Grid in Transition initiative, which is taking place in conjunction with a state-mandated grid study underway by the New York State Energy Research and Development Authority and Department of Public Service to identify distribution upgrades, local transmission upgrades and bulk transmission investments needed to meet the state’s clean energy goals (Case No. 20-E-0197).
Rich Dewey, NYISO | NYDPS
“Upstate New York is pretty carbon-free already, in terms of the supply, and downstate there’s a high intensity of carbon producing power plants,” Dewey said. The challenge will be to move that power into New York City to displace the generation that’s coming from those resources, and that will be instrumental to how we achieve those goals.”
Tammy Mitchell, NYDPS | NYDPS
Tammy Mitchell, chief of bulk electric systems for the DPS, presented an overview of the grid in New York and how her office and the PSC regulate utilities, renewable energy programs and electric rates.
“Notably, the commission-approved energy affordability program provides $237 million in bill assistance to about 937,000 low-income utility customers to offset electric utility costs,” Mitchell said.
Donohue said that “renewables and what we have today, wind, solar and storage, are not going to get us to where we need to go all alone. We need new technologies … what do we need to do marketwise to attract those new technologies?”
The goal that electricity be 100% carbon-free by 2040 is the real challenge, especially getting rid of that last small percentage of nonrenewable resources, Dewey said.
Gavin Donohue, IPPNY | NYDPS
“We feel pretty comfortable that 70% by 2030 can be achieved by wind, solar and storage — you just have to make the right kind of investment, and they have to be located in the right spot,” Dewey said. “But we do not believe we can get to 100% carbon-free electricity without some sort of development of these newer technologies that can be dispatchable, that can be available and still be carbon free.”
The ISO is a big proponent of markets as the way to achieve the state’s environmental goals, he said.
“You take that risk off the ratepayers and you put it on the investors,” Dewey said. “Our approach is carbon pricing, but it’s not just carbon pricing. … The types of resources we need are a little bit different when you start thinking about backstopping the intermittency of the renewables, so you’re going to need units that can respond quickly, ramp quickly.”
California fire investigators are looking at a distribution line as the possible cause of the Zogg Fire, which killed four residents and destroyed more than 200 structures southwest of Redding, Calif.
The 56,000-acre fire started on Sept. 27 near the rural Shasta County community of Igo. Among the victims were a 45-year-old mother and her 8-year-old daughter, who died trying to escape the flames.
A PG&E distribution line, the Girvan 1101 12-kV circuit, serves customers in the area of Zogg Mine Road and Jenny Bird Lane, where the fire began, PG&E said in an incident report to the California Public Utilities Commission on Friday.
Wildfire camera and satellite data on Sept. 27 showed “smoke, heat or signs of fire in that area between approximately 2:43 p.m. and 2:46 p.m.,” it said.
“A PG&E SmartMeter and a line recloser serving that area reported alarms and other activity between approximately 2:40 p.m. and 3:06 p.m. [on Sept. 27], when the line recloser de-energized that portion of the circuit,” PG&E said. “The data currently available to PG&E do not establish the causes of the activity on the Girvan 1101 circuit or the locations of these causes.”
On Oct. 9, investigators with the California Department of Forestry and Fire Protection (CAL FIRE) told PG&E they had taken its equipment as part of their investigation of the Zogg Fire, PG&E said.
“PG&E is cooperating with CAL FIRE in its investigation,” the utility said. “This information is preliminary.”
CAL FIRE has not yet determined how the fire started, PG&E noted.
Searchers indentified at least four sets of human remains in the Zogg Fire. | Shasta County Sheriff’s Office
Involvement in another major fire would mark the fourth year in a row that PG&E equipment has been blamed for highly destructive conflagrations. Its equipment started the worst fires of the October 2017 “fire storm” in Napa and Sonoma counties and the November 2018 Camp Fire, which killed 85 people and destroyed the town of Paradise.
The company emerged from bankruptcy in June after agreeing to pay fire victims, local governments and insurers $25.5 billion in the 2017-18 fires and pleading guilty to 85 felonies stemming from the Camp Fire. (See PG&E Sentenced; Bankruptcy Plan Approved.)
CAL FIRE also determined that a PG&E transmission line started the Kincade Fire, which tore through Sonoma County wine country in October 2019.
The company has avoided blame so far for any of the major wildfires of 2020, one of the worst fire seasons on record. A series of massive fires sparked by lightning on Aug. 17-18 includes the August Complex, the first California wildfire to exceed 1 million acres. It was 67% contained as of Sunday, state and federal fire officials said.
In total, more than 8,000 wildfires have burned nearly 4 million acres in California this year.
Until Friday’s report — which PG&E also sent to the U.S. Securities and Exchange Commission — only one other investor-owned utility in California had fallen under suspicion for starting a major fire in 2020. (Calif. IOUs Escape Blame for Fires so Far.)
In a Sept. 15 report to the CPUC, Southern California Edison said the U.S. Forest Service had asked the utility to remove a section of its overhead conductor as part the agency’s investigation of the Bobcat Fire, still burning in the mountains and foothills northeast of Los Angeles.
SCE said it had experienced a “relay operation” on the 12-kV circuit at approximately the same time and in the same place as the fire started, but it contended that a fire camera had recorded smoke from the blaze prior to the incident.
“While USFS has not alleged that SCE facilities were involved in the ignition of the Bobcat Fire, SCE submits this report in an abundance of caution given USFS’ interest in retaining SCE facilities in connection with its investigation,” the utility told the CPUC.
Frogg said section 7.5.1 was changed to reflect that cold weather operational exercises will no longer be administered by PJM and instead be handled by generation owners. The RTO is recommending that generation owners self-schedule testing of resources that have not operated in eight weeks leading up to Dec. 1.
One change was made from the first read in September, Frogg said. Section 7.3, critical information and reporting requirements, calls for providing notification to PJM dispatchers at least 20 minutes prior to a change in state of each generating unit and will include any changes of more than 50 MW to the output of a self-scheduled resource that is not following the security-constrained economic dispatch (SCED) basepoint. Frogg said the change resulted from stakeholder questions.
Vince Stefanowicz, senior lead engineer of generation, reviewed updates to Manual 10: Pre-Scheduling Operations in a periodic review. The changes include several clarifying changes but nothing substantive, he said.
Stefanowicz said minor changes were made from the first read, including replacing the term “eDART Installed Capacity (eDART ICAP)” with the term “eDART Reportable MW” in Section 2.1, generation outage reporting overview. Stefanowicz said several stakeholders expressed concern over possible confusion with the capacity market term of ICAP.
Both manual updates will go to the Oct. 29 Markets and Reliability Committee meeting for first reads and final endorsements in November.
Day-ahead Schedule Reserve Update
David Kimmel, senior engineer of performance compliance, reviewed the preliminary proposed changes to the 2021 day-ahead scheduling reserve (DASR) requirement. He said the numbers may slightly change when the measure is brought for final endorsement in November.
The DASR is the sum of the requirements for all zones within PJM and any additional reserves scheduled in response to a weather alert or other conservative operations. It is the sum of the three-year average of under-forecasted load forecast error (LFE) and the three-year average of eDART forced outages.
Kimmel said the preliminary 2021 DASR requirement is 4.78%, slightly lower than the 2020 requirement of 5.07%. He said the number comes from the LFE component of 2.18% and the forced outage component of 2.6%.
Stakeholders will be asked to endorse the changes at the next OC meeting. The final 2021 DASR value will be incorporated into Manual 13 changes and be implemented in January.
DASR Requirement Components | PJM
Manual First Reads
Stakeholders heard several first reads of minor manual changes.
Lagy Mathew of PJM reviewed updates to Manual 3: Transmission Operations. Mathew said the changes featured minor clarifications, including defining the term “extra-high voltage (EHV)” lines as those equal to or greater than 345 kV.
Kevin Hatch of PJM reviewed updates to Manual 12: Balancing Operations to address changes from the five-minute pricing and dispatch Market Implementation Committee special sessions. Hatch said PJM has been working with the Independent Market Monitor to identify sections of Manual 12 to be updated and to improve transparency on the dispatch process.
Hatch said the changes include updated terminology for “day-ahead market” instead of the outdated “two-pass system.”
Stakeholders will be asked to endorse the changes at the November OC meeting.
MISO has at once rebranded and postponed its attempt to develop more sophisticated modeling software that can accommodate different combinations of combined cycle units and their dependencies.
The delay marks the third time MISO has pushed back an effort at combined cycle generation modeling. It also renamed the more involved process “multiple configuration resource” modeling.
MISO Director of Business and Digital Transformation Dhiman Chatterjee announced the further delay during an Oct. 8 Market Subcommittee call. MISO projects it will be able to model combined cycle interdependencies sometime late in 2025 at the earliest.
MISO first planned to put improved combined cycle modeling in place by 2020, then delayed until 2022, and again into mid-2023. The RTO said its current market platform couldn’t technically handle the software. (See “At Least 1 Market Project Delay,” New MISO Platform Headed to the Cloud.)
MISO now says General Electric is delaying delivery of a new market clearing engine beyond original expectations, making combined cycle modeling an even more distant prospect.
Chatterjee also said MISO experts, already working on other priorities, will be further taxed by implementation of FERCOrder 2222, which requires RTOs to enable aggregators of distributed resources the opportunity to compete in organized markets.
MISO has previously said it could save anywhere from $14 to $34 million annually if it implemented enhanced combined cycle modeling.
“This is beyond frustrating,” Xcel Energy’s Kari Hassler said. “I’m flabbergasted MISO continues to push this project out even though there are substantial savings to be had … This is a product that the entire footprint needs.”
Stakeholders asked if MISO could do something in the meantime to incrementally model combined cycle generators. Chatterjee said MISO is trying to be as transparent as possible about the challenges of implementing the modeling on its existing market platform.
“I just find it odd that [General Electric] said this is so complex of an ask when they’ve done something similar in SPP, and SPP has had it for about three years now. The complexity level is not extremely high,” Hassler said.
Chatterjee said SPP in fact encountered some technical difficulties when it introduced similar modeling. He also said SPP’s market clearing engine and interfaces are different from MISO’s.
“The tools are all customized, individualized for each RTO, and that’s why it’s so complex,” Chatterjee said.
“We’ll try to be ready, and if an opportunity presents itself, we’ll jump on that,” he added.
MISO Braces for 2nd Hurricane
At the time of the Oct. 8 meeting, Executive Director of Market Operations and Resource Adequacy Shawn McFarlane said MISO was preparing for the then-Category 3 Hurricane Delta, the 25th named storm of the 2020 Atlantic hurricane season.
“Unless you’ve been living under a rock, you know we have another hurricane forming in the Gulf and headed to Louisiana,” McFarlane said.
While Hurricane Delta’s projected landfall is only about 10 miles east of where Hurricane Laura made landfall, McFarlane said the relatively good news was that the new storm is weaker and faster-moving. He also said a weekend landfall means less load to be possibly interrupted.
“So on a relative basis, that is a better situation,” McFarlane said.
MISO declared conservative operations and a transmission advisory for its South region beginning Friday.
McFarlane warned that Entergy’s Louisiana territory is still experiencing transmission line outages from the last storm. Hurricane Laura’s landfall on Aug. 27 brought MISO’s first load-shed orders and widespread transmission damage. (See MISO Keeps Advisories in Effect a Week After Laura.)
“Certainly, we’re not as resilient as we could be because of Hurricane Laura,” he said.
IMM Reassures Stakeholders on Coal Self-commitments
MISO’s Independent Market Monitor reiterated that most coal self-commitment decisions in the footprint are made prudently.
Last month, Monitor David Patton provided the Board of Directors with analysis showing that most of the footprint’s coal self-commitments are profitable. (See MISO IMM Rebuts Uneconomic Coal Commitment Studies.) This time, he brought the results to stakeholders.
“We don’t see the level of concern that prior studies have indicated,” Patton told stakeholders.
The Union of Concerned Scientists has released its own study concluding that Xcel Energy, DTE Energy, Cleco Power and Consumers Energy repeatedly make uneconomic coal generation commitments, costing ratepayers. (See UCS Analysis Knocks Coal Self-commitments.)
Patton said self-committed coal dispatch returned fewer revenues in 2019 only because all energy prices were lower across MISO.
MISO Communication System Still a Source of Frustration
MISO has conceded again that its communication system for emergency resources needs to be more user-friendly.
The acknowledgment came during a review of load-modifying resource performance for an early 2019 generation emergency.
Market participants use the nonpublic MISO Communication System (MCS) to update availability of their load-modifying resources for use in emergency conditions.
“I know the MCS is not the most beloved system, but it does provide important information to MISO,” MISO Corporate Counsel Jacob Krouse told stakeholders during an Oct. 7 Resource Adequacy Subcommittee conference call. MISO stakeholders have long criticized MCS as being clunky and difficult to navigate. (See Stakeholders: MISO System Fix Too Late for Summer.)
MISO issued a maximum generation event Jan. 30-31, 2019, in its North and Central regions during a record cold snap. While it called on more than 180 LMRs, only 21% met their expected load reduction. MISO levied almost $3 million in penalties to underperforming LMRs, and nine market participants sought alternative dispute resolution that lasted until early 2020.
Krouse said during the course of the dispute resolution, market participants indicated they were confused about what data they needed to input into the MCS. Some market participants weren’t following MISO’s requirement to furnish the MCS with their most up-to-date LMR availability data either, Krouse said.
He also noted that the MCS contained “default values inconsistent with LMR registration information,” which was fixed with monthly updates.
Krouse said there was confusion among MISO market participants on whether scheduling instructions would come from the MCS or another MISO mode of communication.
Krouse said MISO is working on MCS improvements following discussion from the Demand Response and MCS Alignment Task Team, formed last year. Further MCS improvements might be rolled out in mid-2021.
MISO resource adequacy staff are considering multiple options in the RTO’s effort to implement a sub-annual capacity mechanism and define new reliability criteria.
MISO has said it could define unique seasonal system reliability requirements as a bulwark against its increasing emergency events outside summer months. The RTO’s analyses indicate an emerging wintertime loss-of-load risk. MISO said it could be in the position of facing a winter peaking situation when electrification picks up in 2035 and beyond.
The shift could prompt MISO to issue a sub-annual reserves requirement based on a seasonal resource adequacy construct.
Stakeholders attending a virtual Resource Adequacy Subcommittee meeting Oct. 7 asked if MISO would run a Planning Resource Auction (PRA) four times per year.
MISO Director of Research and Development Jessica Harrison said several options are under consideration, including an annual construct that reflects sub-annual needs, one annual auction with seasonal or monthly segments, multiple seasonal auctions or monthly auctions across the planning year.
MISO is also exploring the use of additional risk assessments beyond loss of load, including the expected unserved energy calculation, where MISO calculates the expected amount of energy when load is set to exceed generation.
Senior Manager of Resource Adequacy Coordination Lynn Hecker said there could be additional “administrative burden” on MISO and its members if it develops separate planning reserve requirements and resource accreditations for each season.
“That’s really on the MISO to-do list, to get a better idea of what — if any — administrative burden … the proposed construct options might create,” she said.
If MISO moves to a sub-annual version of the capacity auction, Hecker said it would reduce its focus on summer peak modeling and forecasting in favor of pinpointing multiple loss of load risk hours throughout the year, called resource adequacy hours. RA hours would likely occur in summer and winter.
Harrison said MISO must decide if it should rely more on forward-looking projections or historical data to establish accreditation and reserve requirements using resource adequacy hours.
“In a time of slower-paced change, that’s reasonable; in a time of fast-paced change, that’s less reasonable,” she said of historical data being a predictor of system conditions.
Seasonal capacity auctions might give way to more seasonal economic outages, MISO and members said.
Harrison said MISO will be mindful of a seasonal auction’s possible effect of corralling too many generation outages into shoulder seasons. The RTO might consider must-offer obligations on capacity resources for each sub-annual period.
“The more granular we go, the more complex it will be to implement,” Hecker said.
The State Authority Quandary
The possibility of new reliability requirements has MISO and members probing the complicated relationship between MISO and state authority.
Some stakeholders have said that a move toward additional reliability criteria could infringe on state jurisdiction over resource adequacy and that MISO’s existing annual local clearing requirements and planning reserve margin are sufficient for reliability needs. (See MISO Closer to Seasonal Capacity, Reliability Reqs.)
To date, no states have ever requested that MISO increase or decrease a planning reserve margin, said MISO Managing Assistant General Counsel Michael Kessler.
The MISO Tariff stipulates that states have the authority to supersede the RTO and set their own planning reserve margins, but they cannot change MISO’s local reliability requirements or local clearing requirements. MISO would have to incorporate a state-set planning reserve margin into its planning resource margin requirements if it received a special state margin figure for a set of jurisdictional utilities. The Tariff also prohibits MISO from developing a resource adequacy requirement that conflicts with “state reliability or safety standards.”
Kessler said there’s “no other entity … than a state authority” that can alter MISO’s planning reserve margin requirement.
Some stakeholders questioned why states wouldn’t also have at least some authority over local reliability requirements or local clearing requirements if resource adequacy is ultimately the states’ prerogative.
Six of MISO’s ten local resource zones include territory from two or more states.
“Our interpretation of the Tariff — our literal reading of it — is that states do not have the authority to create a different local reliability requirement other than the one established by MISO,” Kessler said.
If a state chooses to set a lower planning reserve margin, the local clearing requirement of a local resource zone would still apply, Kessler said, with MISO still responsible for procuring capacity up to the requirement. Costs of the extra capacity procurement would be uplifted to the entire MISO footprint.
WEC Energy Group’s Chris Plante asked whether states could use a different loss of load risk than MISO’s one-day-in-10-years standard. A state’s decision to rely on a two-days-in-10-years risk would seem to affect zonal clearing and reliability requirements, he said.
“We haven’t had to work through a scenario where some of these mechanics would apply,” Kessler said, adding that MISO could pursue a deeper legal analysis of interaction between the Tariff and state law.
Plante has noted that states already largely rely on MISO’s recommended margins to set their resource adequacy plans.
“I think states increasingly look to MISO to establish their reserve margins,” he said during a special Aug. 21 MISO teleconference to discuss resource availability.
Zone 7 Reliability Requirements Questioned
Stakeholders are expressing consternation over draft 2021/22 PRA reserve requirements. This year, MISO began factoring unavailable generation due to planned outages into its loss of load expectation (LOLE) modeling, resulting in higher local reliability requirements for almost all local resource zones.
MISO is estimating it needs a 9.4% unforced capacity (UCAP) planning reserve margin, up from last year’s 8.9% figure. Translated into an installed capacity basis, MISO needs an 18.3% reserve margin requirement in 2021, compared with 18% last year. (See MISO Planning Reserve Margin to Climb in 2020.)
The need for more padding is the most dramatic in Lower Michigan’s Zone 7. Some stakeholders said it was unfair that a few individuals in MISO’s modeling group could have such an outsized impact on capacity requirements.
Customized Energy Solutions’ Ted Kuhn asked for “guardrails” in the LOLE modeling inputs process so members could expect more stability in the results.
MISO said its LOLE analysis showed that Lower Michigan runs the risk of more peak demand days in September than other local resource zones.
MISO plans to publish final LOLE results by Nov. 1.
For the 2020/21 planning year, Zone 7 cleared at a cost of new entry price of $257.53/MW-day, due in part to a new MISO rule banning capacity resources from taking extended outages. (See MISO: New Outage Rules Boosted Mich. Capacity Prices.)
MISO Independent Market Monitor David Patton said two resources in Zone 7 raked in a combined $154 million in the 2020/21 Planning Resource Auction despite being on outages over the entire summer.
“Those resources are effectively unavailable even though we pay them the same,” Patton said during an Oct. 8 Market Subcommittee conference call.
Patton said he has long calculated leaner capacity margins than MISO projects because of the RTO’s failure to incorporate outages into its capacity picture.
Meanwhile, Planning Adviser Davey Lopez said MISO’s short-term resource availability and need fixes were successful in freeing up an additional 5-10 GW in capacity over the past year, as planned.
MISO launched new Tariff rules early last year to introduce demand response capability testing, seasonal documentation of the availability of load-modifying resources and a 120-day notice period for planned generation outages. (See “Near-term Filings,” MISO to Continue Resource Adequacy Talks in 2019.) The rules were meant as a stopgap measure to buy the RTO more time to flesh out bigger ideas.
“We are striving to come up with longer term solutions. The first phase was intended to buy time,” Lopez said, adding that MISO must continue working on the longer-term PRA changes. “Capacity margins continue to erode.”
The New England Power Pool Markets Committee last week rejected ISO-NE’s proposal for recalculating the dynamic delist bid threshold (DDBT) for Forward Capacity Auction 16, along with several proposed amendments to the RTO’s plan, none of which attracted the necessary 60% for endorsement.
The DDBT issue consumed half of the first day of the committee’s three-day meeting.
The DDBT for FCA 15 for 2024/25 is $4.30/kW-month. The Tariff requires the threshold, which was last updated in 2017/18, be recalculated for FCA 16 (2025/26).
The RTO proposed recalculating the DDBT annually using publicly available data, saying it would address transparency concerns and keep the threshold aligned with current and expected market conditions.
It would make the DDBT the average of the preceding FCA price and the price the capacity that cleared in the preceding FCA intersects with the estimated system-wide demand curve for the upcoming FCA. The threshold would not exceed the net cost of new entry (CONE) or fall below 75% of the preceding FCA price; the net CONE limit would apply if the two overlapped.
Jeffrey Bentz, director of analysis for the New England States Committee on Electricity (NESCOE), expressed concern in his presentation that setting the DDBT too high or at net CONE could improperly allow some bids to escape the scrutiny of a market power review. NESCOE proposed lowering the upper bound to 85% of net CONE or 125% of the prior auction clearing price, saying it would strike a better balance between the design objectives of providing adequate review to prevent market power and limiting unnecessary administrative interference.
NESCOE also proposed limiting the maximum rate of change in the DDBT from auction to auction to 30% of net CONE.
In a memo to the committee, ISO-NE’s Matthew Brewster wrote that NESCOE’s proposals would “constrain the DDBT value relative to the [RTOs’] proposal under various conditions, which could undermine this key enhancement achieved with the new DDBT calculation method. … By preventing the DDBT from adjusting to reflect projected market conditions for the next FCA, the amendments would cause the DDBT to remain a lagging, or ‘stale’ estimate of the appropriate delist bid review threshold.”
The memo also said that “while NESCOE suggests a one-directional remedy within the DDBT for (potential) errors” in net CONE, it does “not appear to provide a reasoned basis for the numerical value of the proposed cap at 85% of net CONE.” Additionally, NESCOE’s other proposed DDBT cap of 125% of the last FCA clearing price “has only a superficial symmetry with the floor present in the ISO’s design.
“The underlying assumption of this 125% cap is that the supply curve becomes flat at prices 25% higher than the last FCA clearing price,” the memo continued. “However, that outcome is not supported by theory … nor is it plausible in practice. The supply curve generally is increasingly steep as quantity increases (up to the point where prices reach true net CONE).”
The NESCOE amendments failed with only 34% support.
The committee also rejected proposals by Calpine and Vistra Energy’s Dynegy unit to address what Bill Fowler, president of Sigma Consultants, said is the disadvantage faced by resource owners having to lock in static delist bids four months before the FCA.
At the September Markets Committee meeting, Fowler said the DDBT should be set at a “reasonable margin” — 50 cents to $1/kW-month — above the expected clearing price. (See “Change to Delist Bid Threshold,” ISO-NE Challenged on Wind, Solar, Storage Revenues.) Fowler revised the proposal last week, calling for “a small cushion” varying with the level of the expected clearing price, declining to zero if the expected clear is at net CONE. It won only 49% support.
Also rejected was a Calpine/Dynegy proposal to eliminate the obligation to commit to a bid price in October and make the October static delist finalization requirement a cap on auction prices.
ISO-NE’s proposed DDBT changes, the last vote, received only 44.5%. The RTO will file the proposal with FERC despite the lack of stakeholder endorsement.
Support for Forward Reserve Market Sunset
On a voice vote, the committee approved ISO-NE’s proposal to sunset the forward reserve market (FRM) to avoid conflicts with its proposed Energy Security Improvements (ESI) initiative, which is awaiting FERC action. (See ISO-NE Sending 2 Energy Security Plans to FERC.)
The FRM awards obligations for 10-minute non-spinning reserves and 30-minute operating reserves, but the RTO said it is becoming unnecessary because of ESI and transmission investments and market changes that address locational constraints and reward resource flexibility.
The RTO’s proposal included two alternatives. If FERC issues an order approving ESI as filed before Dec. 31, the RTO will file a “non-contingent” Tariff change by the end of 2020 to sunset the FRM on June 1, 2025, coinciding with the start of the 2025/26 capacity commitment period.
If FERC does not rule on ESI before the end of the year, the RTO would file a “contingent” FRM sunset that would take effect if FERC approves ESI as filed.
If FERC rejects ESI, the RTO will not file either Tariff change. The RTO said future discussions with stakeholders on reserves might be necessary if this is the eventual outcome.
The RTO plans a vote by the Participants Committee in November.
RTO Seeks Modifications for EERs, RAs
Ryan McCarthy of ISO-NE presented proposed modifications to the qualification process for energy efficiency resources (EERs) to better account for expiring measures. The RTO also wants to change the monthly reconfiguration auction (RA) and bilateral qualification rules to better account for new financial assurance and performance accounting rules.
The proposal would set the seasonal qualified capacity to the lower of the amount of capacity that has cleared as “new” in prior FCAs or the amount of measures marked commercial plus FCA cleared non-commercial MWs on critical path schedule (CPS) monitoring. The proposed methodology would apply to both the FCA and all annual RA qualifications.
The proposed methodology by ISO-NE is expected to increase energy efficiency qualification values. | ISO-NE
An EER will have two years from the start of the commitment period in which it first received a capacity supply obligation to install its measures. Previously cleared EERs will have until May 31, 2027, to install all measures.
As additional EE clears in the FCA, the capacity will be factored directly into the load reconstitution process. The RTO said the proposal will better align qualified capacity with its performance capabilities.
The RTO would assign monthly qualification to resources that become commercial during the capacity commitment period. The monthly qualification will track delayed commercial resources and allow non-commercial capacity to participate in monthly RAs and bilateral qualifications.
The Markets Committee will vote on the proposals next month. EER qualification changes would become effective in February 2021 for FCA 16. The monthly qualification changes would become effective in January 2022 and implemented for the March 2022 monthly reconfiguration auction and bilateral qualification period.
GIS Working Group to Consider Massachusetts ‘Clean Generation’ Changes
The MC agreed to direct the Generation Information System (GIS) Operating Rules Working Group to consider changes to the GIS and the GIS Operating Rules to reflect the addition of “Clean Existing Generation” (CES-E) to the Massachusetts Clean Energy Standard. The changes were requested by the Massachusetts Department of Environmental Protection.
NEPOOL counsel Paul Belval of Day Pitney said in a memo that DEP revised its regulations to include a requirement that retail load-serving entities subject to the standard have a certain percentage of energy from “Clean Existing Generation Units.”
Hydro-Québec Dam | Hydro-Québec
Clean existing generation units are nuclear or hydroelectric units with a nameplate capacity of at least 30 MW that began commercial operation before Jan. 1, 2011, and satisfy specific geographic requirements. In addition to adding a new category in the GIS, the DEP regulations pose two additional rule changes. Multiple co-located GIS generators could have their generation aggregated, and certain annual caps on qualifying output would have to be allocated among those GIS generators. Also, certain generators in Newfoundland and Labrador could be eligible. That would require a slight expansion of the area where qualified generators can receive unit-specific certificates in the GIS.
The committee is not being asked to vote on any changes to GIS rules, the memo said, but should refer issues to the working group to discuss and determine potential rule revisions.
The RTO proposes Tariff changes to comply with two FERC directives. The first change would address FERC’s concern that the Tariff language preventing double payment for charging energy at the retail and wholesale levels would allow host utilities to decide whether an electric storage resource (ESR) may participate in its markets. It would be effective in the first quarter of 2021.
The second responds to FERC’s directive that the Tariff include the bidding parameters the RTO will use to account for the state of charge and duration characteristics in the day-ahead energy market. It would be effective Jan. 1, 2026.
The RTO will seek votes on the proposed revisions at the committee’s next gathering on Nov. 9-10 and at the Participants Committee’s Dec. 3 meeting.
SPP staff last week said they considered several seams-related projects with MISO in their 2020 Integrated Transmission Planning (ITP) assessment but eventually declined to pursue them over differing methodologies in calculating benefits and costs.
“Rest assured we’re going to continue to look at these areas in the future,” Kirk Hall told the Seams Steering Committee during its Oct. 7 meeting, referring to three 345-kV projects along the Nebraska-Iowa border.
“MISO and SPP staff continue to work on understanding the cost differences,” Hall said. “Hopefully, we’ll come back with something that is agreeable to all parties.”
Hall shared a near-final version of the ITP assessment with the SSC. Staff identified 54 projects in the final portfolio, which includes 92 miles of 345-kV transmission lines and 141 miles of rebuilt high-voltage infrastructure. It estimated $532 million of engineering and construction costs but projected a 4.0-5.2-to-1 benefit-to-cost ratio.
The 2020 ITP takes a 10-year look at system reliability and economic needs. Staff spent more than two years evaluating more than 2,200 solutions, and said the projects will solve 163 system needs, help levelized market prices, improve congestion hedging and facilitate access to low-cost energy.
The ITP assessment will be taken to SPP stakeholders and the Board of Directors later this month for their approval.
Neil Robertson, SPP’s interregional relations senior engineer, said the grid operator remains “committed to coordinating” with MISO. The RTOs once again failed to agree on an interregional project during their fourth coordinated system plan (CSP) study but have since agreed to combine forces on a year-long transmission study to identify “comprehensive, cost-effective and efficient upgrades.” (See MISO, SPP to Conduct Targeted Transmission Study.)
“SPP will … work with MISO and determine how we would rectify costs differences if we decided to factor in whether a project can be recommended or not,” Robertson said.
He said SPP and MISO analyzed 10 needs in their CSP, but no solutions met “fundamental requirements.”
Robertson also discussed the final report of SPP’s joint CSP with Associated Electric Cooperative Inc. The entities will combine forces on what would be the RTO’s first competitive project under FERC Order 1000. (See FERC Approves SPP-AECI Competitive Project.)
M2M Settlements Again Favor SPP
Market-to-market (M2M) settlements once again flowed in SPP’s favor during August, staff told the committee, resulting in a $1.1 million accrual for the grid operator. Temporary and permanent flowgates were binding for 725 hours during the month.
SPP’s market-to-market settlements with MISO are approaching $95 million. | SPP
SPP has now accrued $93.82 million in M2M settlements since it began the process with MISO in March 2015.
August marked the 10th time in 11 months, and the 49th time in 66 months, that settlements have ended up in SPP’s favor.
NERC is seeking comments through 8 p.m. Nov. 20 on proposed changes to SERC Reliability Corporation’s Regional Reliability Standards Development Procedure (RSDP), stemming from recent changes to the regional entity’s executive structure.
Each RE files an RSDP with NERC to “define the steps in that region’s process for developing, reaffirming and withdrawing its regional reliability standards” and to ensure that regional standards align with continent-wide standards approved by FERC and its Canadian and Mexican counterparts. RSDPs must be reviewed and submitted to NERC every five years — or earlier if the RE’s board feels revisions might be needed.
SERC headquarters in Charlotte, N.C. | SERC
SERC’s current RSDP was approved by the RE’s Board of Directors in October 2017 during its five-year review and accepted by NERC the following year. This revision, which comes about two years before the regularly scheduled review, is a relatively minor update intended to bring the RSDP in line with SERC’s updated executive structure as described in the RE’s revised bylaws approved by FERC in July. (See FERC Approves SERC’s Bylaw Changes.)
Changes to be implemented under the new bylaws include changing the Board Compliance Committee into a Board Risk Committee, transforming SERC’s Board of Directors into a hybrid board comprising both sector representatives and independent directors and eliminating the use of alternates and proxies for directors and independent directors. The updated RSDP reflects these changes by removing references to Board representatives and alternates and replacing references to the SERC Executive Committee with SERC Board of Directors.
In addition, the new document replaces references to the former executive committees of SERC’s technical committees to reflect their unification into a single Operations Planning and Security Executive Committee, and revises abbreviations throughout the RSDP to ensure internal consistency. The updates are planned to take effect Jan. 1, 2021, along with the new bylaws.
Openness, Balance Among Commenting Criteria
Industry stakeholders are being asked to comment on whether SERC’s updates meet NERC’s requirements for all regional RSDPs. Those requirements include the following:
Openness — The RSDP must allow any person or entity that is “directly and materially affected by the reliability of the bulk power system within the regional entity” to participate in the reliability standard approval process.
Inclusivity — Any person or entity with a direct and material interest must be permitted to express and justify an opinion, have that position considered and appeal through an established process in the case of an adverse decision.
Balance — Regional RSDPs must have a balance of interest and not be dominated by any two interest categories. No single interest category can be allowed to defeat a matter.
Due process — Standards development processes must provide reasonable notice and opportunity for public comment, including, at minimum, public notice of the intent to develop a standard, a comment period on the proposed standard, due consideration of comments and the opportunity for stakeholder ballots.
Transparency — All actions and materials relating to standards development must be transparent, and members of the public must be notified and allowed to attend all standards development meetings.
Following the comment period, SERC will submit the revised RSDP for approval by NERC’s Board of Trustees, most likely at its meeting in February 2021. Earlier this year, the Board accepted the Northeast Power Coordinating Council’s revisions to its own regional standard processes manual, aimed at clarifying outdated language and establishing closer alignment with NERC’s standard development process. (See “Budget, ROP, Standards Actions,” NERC Board of Trustees/MRC Briefs: Aug. 20, 2020.)
FERC on Wednesday approved a cost-and-usage agreement between SPP and Associated Electric Cooperative Inc. (AECI) that could result in the RTO’s first competitive project under Order 1000 (ER20-2707, ER20-2708).
SPP’s Wolf Creek-Blackberry project (dotted line), connecting to the AECI system | SPP
The letter order accepted the terms and conditions governing the construction, ownership, operation and cost for the installation of 345-kV terminal equipment at AECI’s existing Blackberry substation, the endpoint for SPP’s 109-mile, 345-kV Wolf Creek-Blackberry transmission project. It also accepts Tariff revisions to include the substation’s construction costs in each SPP transmission owner’s respective annual transmission revenue requirement.
“We were glad to see that outcome,” Neil Robertson, SPP’s interregional relations senior engineer, said in breaking the news Wednesday morning to the Seams Steering Committee.
The Wolf Creek-Blackberry project is expected to cost $152 million. SPP members will fund the line according to load-ratio share. The RTO’s Board of Directors last month lifted a suspension on the project and authorized the Oversight Committee to create an industry expert panel (IEP) to evaluate responses to a request for proposals, which staff have since issued. (See “Board Lifts Suspension on Competitive Upgrade,” SPP Board of Directors/MC Briefs: Sept. 22, 2020.)
