ERCOT stakeholders last week began taking a deeper look at real-time co-optimization (RTC), the market tool that procures both energy and ancillary services every five minutes to find the most cost-effective solution for both requirements.
Asked by Texas’ Public Utility Commission to “reinitiate discussions” with stakeholders on the tool, ERCOT held a workshop on Wednesday. The PUC, which wants to see RTC “sooner rather than later,” is working to hold its own workshop in early June and is soliciting stakeholder feedback on a list of related issues. (See “PUC, ERCOT Set Real-time Co-optimization Workshops,” Texas PUC Briefs: Week of Feb. 25, 2019.)
Meanwhile, the member-led Technical Advisory Committee, which makes recommendations to the ERCOT Board of Directors, has been gathering member feedback on an RTC task force in advance of its upcoming March 27 meeting. TAC Chair Bob Helton, of ENGIE, said in an email to members that the committee’s leadership would like to see the task force led by two co-chairs reporting directly to the committee.
“The task force would not be a voting body, and [its] leadership would report any recommendations to TAC, including any minority positions,” Helton wrote.
The TAC will endorse the group’s final structure, leadership and other details, with the board making the final decision.
“This is a good opportunity for our stakeholders to come together and work to ensure we design something that helps achieve our objectives and reflects the value of ancillary service,” ERCOT COO Cheryl Mele said at a recent market summit.
Staff told stakeholders during the workshop that RTC will efficiently coordinate the provision of energy and AS in the real-time market and, similar to the operating reserve demand curve (ORDC), price AS shortages according to their defined demand curves.
Sai Moorty, ERCOT’s market design and analysis principal, said the RTC process will be executed with each security-constrained economic dispatch run, yielding “better visibility of the constraints and the capabilities of the resources.”
“As a result, the system can be operated more economically and reliably,” he said. “This benefits loads by selecting the lowest-cost resources to provide energy and AS.”
Unlike the ORDC, the SCED engine will apply a demand curve for each AS product, establishing offer-based prices for energy and AS types in the real-time market, staff said. The defined AS demand curve will set AS shortage conditions, and ORDC price adders will no longer exist.
“Real-time co-optimization will definitely impact temporary price spikes we’ve seen outside the ORDC,” NRG Energy’s Bill Barnes said at the same summit. “Demand curves for ancillary service … ensure we’re sending proper price signals during times of scarcity.”
ERCOT grid operations have not yet identified a reliability need to define a local reserve product, staff said, noting the RTC design will co-optimize the required reserves.
The PUC, which has opened a project for RTC (48540), is considering whether to allow financial-only AS offers.
Staff have said it will take four to five years and about $40 million to implement the RTC process and software.
ARLINGTON, Va. — Transmission developers, planners and regulators gathered last week on the top floor of the Key Bridge Marriott, overlooking D.C. from across the Potomac River, for Infocast’s annual Transmission Summit East. Panels and presentations covered a little bit of everything, from energy storage to cybersecurity.
Hoecker, Demarest Propose Interstate Tx Siting Bill
James Hoecker and William Demarest, both senior counsel at Kansas City-based law firm Husch Blackwell, proposed to the conference a legislative solution to the problem of getting high-voltage interstate transmission lines built.
The pair’s proposal would essentially give FERC jurisdiction over siting interstate transmission projects, similar to how the Natural Gas Act gave the commission siting approval over gas projects, but with numerous caveats and exceptions that they said would preserve some state authority. Crucially, only projects that have facilities in multiple states would be subject to FERC approval. Intrastate transmission projects, unlike intrastate gas pipelines, would remain solely under the purview of the states.
Hoecker, a former FERC chairman, said demand for renewable resources is growing as states increase their portfolio targets. Currently, transmission developers must get approval from a “multiplicity” of regulatory agencies in each state their projects pass through, he said. But “if the momentum picks up for interregional and multistate forms of transmission, I think there’ll be a growing drumbeat to somehow limit state authority in this area.”
The desire to access cleaner generation will be come a very powerful force in the transmission industry, Hoecker predicted. But without a good policy, “you could have states essentially getting steamrolled.”
Demarest elaborated on that point, noting his years working for Rep. John Dingell (D-Mich.). When members of Congress “get on a course, they tend to take political, rather than economic … solutions. They are frequently looking for a solution, and it need not be the best solution, because they delude themselves into believing that they can come back and address it and adjust it and fix it, which they never or rarely do.” State regulators and industry need to find a solution before Congress imposes something they don’t like, he said.
Under their plan, transmission rates for interstate service would be regulated by FERC, but any intrastate service rates would be regulated by each state the project serves. It also would not eliminate, nor allow FERC to eliminate, any state rights of first refusal for incumbent utilities to build intrastate projects. These projects would also not be subject to an “affecting commerce” standard, even though they’re still part of interstate commerce.
RTOs would continue their role as planners, but RTO sponsorship would not be necessary. “RTOs, at least in my view, are political critters, often captive to certain stakeholders,” Demarest said.
Order 841’s Impact on New York
New York is a very desirable market for the energy storage industry, but NYISO’s proposed compliance with FERC Order 841 is somewhat concerning, speakers said during a panel on the order’s implementation.
“When we think about what drives the business case for storage … by and large it is the need for capacity,” said Ray Hohenstein, market applications director for storage developer Fluence. Peaking plants are retiring at a faster rate because of the state’s increasing emissions targets. “New York is a state where if they get FERC 841 right, there could be a lot of energy storage that is making money.”
The state’s Public Service Commission has set a goal of 3 GW by 2030, with an interim target of 1.5 GW by 2025.
In its Order 841 compliance filing, NYISO said it would offer four modes for storage resources to participate: ISO-committed fixed, ISO-committed flexible, self-committed fixed and self-committed flexible. In the ISO-committed modes, suppliers would leave it up to NYISO to determine the most optimal dispatch times for their resources.
Last month, the Energy Storage Association filed responses to the grid operators’ compliance filings. With NYISO, the group focused on what it called “rules that bias against self-management of state of charge.”
Steve Wemple of Consolidated Edison, however, had an optimistic view on NYISO managing resources’ state of charge. The ISO would “look at the beginning charge level and look forward and try to find the right pairs of charging and discharging to meet the bidder’s economic desire … so I think that’s very positive.”
Hohenstein agreed. “I think state-of-charge management is one of the keys to unlocking participation in wholesale markets in general. It actually is a really great development to have the ability to … define your beginning and end-of-hour state of charge to ensure that you are available, for instance, if you have to provide a peak reliability service for part of the day. So it provides a lot more certainty.”
As an example, he said a resource could tell the ISO that it was bidding into the frequency regulation market but it has to be fully charged by 6 p.m.
Melissa Kemp, policy director at Cypress Creek Renewables, was skeptical of that. “I think if it were something that nuanced, we would not have a problem with it. My understanding of what they filed is that it’s not that nuanced, and that it’s more ‘We need to control what you’re doing here’ and that there’s a lot of concern from a lot of stakeholders in the ISO process [who] would like the option to select the ISO to control … but that just simply turning over the ability to control the asset to the ISO is a great concern and kind of a nonstarter.”
The ‘Weakest Link’ in Cybersecurity
A panel on cybersecurity focused on figuring out the most effective practices, which speakers said don’t apply to every utility in the country.
Among the panelists was Iowa Utilities Board Member, and president of the National Association of Regulatory Utility Commissioners, Nick Wagner, who said criminal or hostile foreign hackers are probably not interested in taking down a rural, municipal cooperative in his state.
When asked about NERC critical infrastructure protection standards, Wagner said, “I think those are important beginning points. I don’t necessarily [think] they should be a hard-and-fast rule that everybody should follow. One of the nice things about … our grid today is a conglomerate of very different systems, which in itself is inherently secure. So if a person gets in a system of one utility, that doesn’t necessarily mean that they’ll be able to get into every system. …
“Government does not move at the speed of industry. And it certainly does not move at the speed of hackers. So we will, from a standards standpoint, always be behind. And we want our utilities and our industry and our suppliers to move faster than that and be able to keep up with the threats that are out there,” he said.
Instead, Wagner said, industry needs to focus on training employees to recognize hacking attempts. “People are the weakest link,” he said. “Whether we like to admit it or not, we are the weakest link. … I’ve gotten into the habit of, when I get an email from my family, I call them up and say, ‘Did you send this email?’ Because that’s how sophisticated these hackers are getting.”
Pennsylvania Public Utility Commission Chair Gladys Brown said that applies to state regulatory agencies as well. Agencies “have a wealth of information” that hackers would love to get their hands on, she said. Brown said that despite the robust training NARUC directs, even she has fallen for a phishing attempt, when she responded to an email from someone she thought was a state cabinet secretary. (Thankfully there was no link in the email to click.)
As part of the Electric Power Research Institute’s training, the organization sends out its own phishing emails to test its employees, said Ralph King, cybersecurity program manager. And “if you actually click on a phishing email, you get to sit down with someone pretty high up in the company.”
But King also warned that one utility company he worked with went too far in its training. “They had to back it off because all the employees, anything external, they deleted. And so they were missing a lot of emails.”
King also said that many cyber experts think “the biggest threat in the next five years are insider threats. These could be malicious; they could be mistakes.” Noticing unusual employee behavior — logging into a system in the middle of the night, logging into systems they’re unauthorized to access, etc. — will be key to preventing disruptions. He told the story of another company he worked with that had an employee displaying “very odd behavior. And by looking for these things, we actually uncovered a serious health problem that they didn’t know about. So it’s not always malicious; it could be other things. But regardless of what it is, you want to be able to identify it.”
“It may not impact the grid or the system overall, but it can certainly impact you as individuals and be a real pain to have to deal with some of that stuff,” Wagner said.
VALLEY FORGE, Pa. — The American Wind Energy Association on Thursday said that PJM’s proposal to change how wind and solar capacity values are calculated does not account for the technologies’ performance improvements over the last decade.
After a year of stakeholder discussions, PJM staff will ask the Planning Committee in April to endorse calculations based on effective load-carrying capability (ELCC), which measures the additional load that a group of generators can supply without a reduction in reliability. Jerry Bell, of PJM’s resource adequacy department, presented the Manual 21 changes during the March 7 PC meeting.
PJM’s five-step process for delivery year 2022/23 begins with an average of the ELCCs for each year since 2012/13. The RTO determined that the composite ELCC is 4,181 MW, 21% of the 19,910 MW of nameplate wind and solar capacity projected for 2022/23.
After calculating the ELCC’s for the two generation types separately, PJM then prorated the shares between wind and solar, resulting in capacity factors of 12.3% and 45.1%, respectively. (See “PJM Pushes Change in Wind, Solar Capacity Measurements,” PJM PC/TEAC Briefs: Feb. 7, 2019.)
PJM would assign the ELCCs to existing individual units based on their output during the top 10 daily peak load hours in the 10 most recent delivery years. Future units will get the class average credit unless they request a project-specific calculation.
PJM is proposing to change its capacity calculation for wind and solar resources. In step 1 of the plan, the RTO determined that the composite effective load-carrying capability (ELCC) is 4,181 MW, 21% of the 19,910 MW of nameplate capacity projected for 2022/23. | PJM
Representing AWEA, Gabel Associates’ Travis Stewart told the PC that the RTO’s proposal understates the current fleet’s capacity value by giving equal weight to all years in the sample.
Stewart said federal data shows wind capacity factors increased from 30.2% to 42.5% between 2009 and 2016, while solar’s capacity factors increased from 20.8% to 26.8% between 2010 and 2016. PJM’s equal weighting ignores the fact that older, less productive projects represent a small share of the current fleet, AWEA says.
“When PJM attaches an ELCC average to the entire renewable generation fleet, it fails to account for the individual generator’s share,” Stewart said.
The association proposed two options for remedying its concerns:
Option 1: Find the average ELCC for each renewable project vintage across all historical years, and then calculate the ELCC for the current fleet by weighting according to each vintage’s share of the current fleet.
Option 2: To account for Option 1’s potential to mask the underlying renewable performance trend, AWEA proposes building a larger dataset by combining each year’s renewable output profile with corresponding load patterns to calculate an average ELCC. The trendline of ELCC change across years could then be used to weight PJM’s results under its current method to recreate what ELCC performance in prior years would have been with the current fleet.
Patricio Rocha Garrido, of PJM’s resource adequacy department, said staff have “some issues” with AWEA’s second option.
“We want to capture the relationship between wind output and load. … Once you start mixing outputs from one year with load shapes from another year, then that relationship gets totally missed,” he said. “You achieve your goal of increasing sample size, but you totally lose that correlation.”
Next Steps
PJM will present a first read of the manual changes at the March 21 Markets and Reliability Committee meeting before seeking an endorsement in April. The discussion will likely rehash stakeholder concerns over the handling of capacity interconnection rights (CIRs). (See related story, Showdown Set on PJM Must-offer Exceptions.)
“We purchased a lot of these CIRs through upgrades. … [PJM is] making a change here; this is not us retiring units,” said John Brodbeck of EDP Renewables. “This is not the good Lord knocking a whole bunch of towers down. This is a decision to rerate units by PJM and that has a different impact than anything else. We don’t like to see our assets taken away.”
PJM’s ELCC formula represents a shift in thinking for the RTO, which had been pushing an alternative method using average values. The new methodology is more representative of the incremental value of adding a new unit to the existing fleet, PJM’s Tom Falin said in February.
The Manual 21 changes include a new section devoted to obtaining, maintaining or losing CIRs, as well as sections devoted to installed capacity calculations and testing requirements.
New rules on testing within temperature bounds will take effect June 1 with rules on simultaneous testing and the ELCC effective for delivery year 2022/23. Wind and solar units losing CIRs would be notified before Jan. 1, 2025.
Notably, the testing window for generators remains June 1 through Aug. 31 after stakeholders expressed concerns over an earlier proposal from PJM to instead start in July. (See “Skepticism of Gen Capability Changes Continues,” PJM Operating Committee Briefs: June 5, 2018.)
PJM wants MRC endorsement by the April meeting so that unforced capacity (UCAP) values for wind and solar can be posted by May 1 for use in the 2022/23 Base Residual Auction in August. They would not affect UCAP values from prior auctions.
CARMEL, Ind. — MISO will prototype its proposed short-term reserve product to demonstrate cost and benefits to its members.
The move comes in part at the behest of stakeholders, who want more information on the availability of resources that might provide the reserves; the cost and reliability impacts of a reserve product; and how the product would interact with out-of-market commitments, according to MISO Market Design Adviser Bill Peters.
MISO has said it hopes to roll out the product in mid-2021, supported by its soon-to-be-replaced market platform. (See New MISO Platform Headed to the Cloud.)
The product would be designed to furnish capacity within 30 minutes. The RTO has said it will be especially helpful in MISO South, which has less than 500 MW of offline capacity available within that time frame.
However, Robert Francis, speaking on behalf of the Entergy Operating Companies, questioned whether MISO South’s load pockets even have an adequate number of offline resources to support the 30-minute response time.
“One concern is that there may not be sufficient online and offline resources in the load pockets to enable the proposed product to work as intended,” Francis said in comments to MISO. “Of the load pocket units that are typically online during periods of system stress, are these units historically dispatched at levels that they would lend themselves to the [reserve] product?”
Peters said the reserve product will better compensate available resources while “incenting new capability for offline response.” He said there won’t be a minimum target amount of such reserves.
MISO Director of Market Design Kevin Vannoy said the short-term reserves would differentiate themselves from the current contingency reserves by addressing either an excess of flow on the regional dispatch transfer constraint or restoring normal operating conditions in a load pocket following the loss of a generator sooner to avoid violations of contracts and reliability standards.
“This is a method of making sure we’re able to replenish contingency reserves following a contingency. To date, we’ve been flush, but we’re finding” that reserves are thinning, Vannoy said. He added that the short-term reserve’s price signal will attract more generation willing to furnish reserves.
MISO has published a conceptual design of short-term operating reserves where online resources and offline resources can either register as a supplier or provide availability through hourly offers in the day-ahead and real-time markets. It plans to clear the resources according to opportunity costs, offer prices and a demand curve when insufficient amounts of the reserve exist.
Restoration Energy, Uninstructed Deviations and Tx Settlements
MISO plans to form a task team later this month to begin discussions on how it should price restoration energy — energy delivered to restore the system in the event of the real-time market ceasing to function. The RTO and stakeholders revived the idea of a plan to compensate restoration energy last year. (See Old Analysis Could Guide MISO Restoration Pricing Effort.)
It will also begin holding weekly conference calls Thursday to answer questions about its new uninstructed deviation threshold. The new threshold calculates a generator’s uninstructed deviation with a tolerance based on the minimum of five times the real-time ramp rate or 12% from the average set point instructions. Generators in MISO are currently flagged after they deviate by more than 8% from dispatch signals over four consecutive intervals. (See MISO Plans for New Uninstructed Deviation Rules.)
Lastly, MISO has delayed the introduction of its new transmission settlements system until spring. The new system was slated to go live March 1, but the RTO decided it required more test runs before rollout.
John Weissenborn said MISO decided to delay the new system “to allow testing and validation from market participants.” He said it will schedule a follow-up conference call in the middle of March to evaluate testing progress and discuss implementation.
CARMEL, Ind. — In an assessment of this year’s load forecast Wednesday, MISO told its load-serving entities they could do more to support their individual forecasts with documentation.
MISO adviser Michael Robinson began the annual load forecast review with an anecdote that Lake Superior was days away from freezing over completely.
“Every 30 or 40 years it typically does this,” Robinson said. “Assuming no forced outages and instantaneous replacement,” it would take one Zamboni 693 years to resurface the lake, he said.
“It hasn’t taken us that long to assess the load forecast, but it has taken us some time,” Robinson joked.
He said that while all of MISO’s 140-plus LSEs submitted demand forecasts, supporting documentation was often incomplete.
This year, MISO posted a template of information to emphasize the kinds of information and documentation it expects.
“Last year when we did this, we weren’t happy with the initial response we got from LSEs and the documentation supporting the coincident peak demands,” Robinson said.
Despite the written expectations, Robinson said LSEs again provided spotty documentation supporting their forecasts. MISO this year conducted a random sampling of 11 LSEs with peak demand under 1 MW and 17 LSEs greater than 1 MW, representing 48.5% of the RTO’s peak demand. It said it found “many instances where information was initially missing.”
“Well over half of our LSEs have given us insufficient information on the first go-round,” Robinson said. “We need to do better next year.”
However, Robinson said once MISO got the requested information, it resulted in only minor revisions to the load forecasts.
MISO this year expects a coincident peak load of nearly 122 GW systemwide and a 135-GW planning reserve margin; the RTO says it has about 172 GW of totaled installed capacity to cover it.
This is the last year MISO will use its historic load forecasting method. For its 2020 Transmission Expansion Plan, the RTO will rely on a blended forecast that will have Purdue University’s State Utility Forecasting Group and consulting firm Applied Energy Group work with 20-year forecasts provided by LSEs. (See “MISO Under New Load Forecasting Method,” MISO Planning Week Briefs: Feb. 12-13, 2019.)
This year’s capacity auction offer window will open at 12:01 a.m. on March 26 and close at 11:59 p.m. on March 29. Results will be publicly available on April 12.
LMR Registration Steady Despite New Requirements
The number of load-modifying resources registering for this year’s auction is in line with last year, MISO’s Eric Thoms reported. The RTO registered 809 LMRs representing 11.7 GW for the 2019/20 planning year. Traditional behind-the-meter generation (BTMG) totaled 340 resources at 3.6 GW, and demand response totaled 280 resources at 7.3 GW. The total also includes 189 intermittent BTM resources at 913 MW.
According to MISO’s count, 48% of traditional BTMG and DR LMRs have a lead time of fewer than two hours, while about 27% have a lead time of between two and six hours. Slightly less than 25% have a notification requirement of six or more hours.
About 81% of the traditional BTMG and DR reported availability for more than nine months out of the year. This is the first year that LMRs had to provide firmer and more clearly documented commitments regarding their availability before participating in the PRA. In years past, MISO LMRs were only required to be available for dispatch in the summer months. (See MISO LMR Capacity Rules Get FERC Approval.)
During the registration process this year, MISO created a bulk LMR registration template to allow market participants could register several LMRs at once, after the RTO noticed owners of multiple LMRs were experiencing a time-consuming process, Thoms said. Because MISO’s Tariff filing was intended to ensure that LMRs are available as promised, resource owners this year had an extended registration deadline. (See “LMR Registration Confusion,” MISO Preliminary PRA Data up Slightly from Early Prediction.)
AUBURNDALE, Mass. — Commercial demand is supplanting state policy as the driving force behind deployment of renewables, whose costs are declining in every category, participants at the Northeast Energy and Commerce Association (NECA) Renewable Energy Conference heard last week.
“You will see, maybe not so much yet in New England, but you will see across North America, customers are buying renewable energy,” Brattle Group principal Judy Chang said Thursday.
States drove renewable energy adoption in the very beginning, “but now we’re really seeing customers, particularly large commercial and industrial customers, directly signing up contracts for renewable generation — and some of those come with storage,” Chang said.
“Change” is the watchword, according to Stephen J. Rourke, ISO-NE vice president for system planning, who said he’s seen more change in the past year than in his whole 40 years in the industry.
“One way to get a sense of what’s headed our way next, when you think about the resources that are going to come forward, is to look at the [interconnection] queue,” Rourke said. “If you followed our queue from roughly 2005 to 2017, we had 12,000 to 14,000 MW in our queue, three-quarters of it natural gas. The rest of it was wind and a little bit of something else.
“If you look right now, we have over 20,000 MW of generation in our queue, and 85% of it is either wind, solar, batteries, hydro, biomass or fuel cells,” he said. “The 15% that’s left over is natural gas, so what resource developers are saying to us … is these are the resources that are coming forward … and this has changed dramatically since just 2017.”
Big Projects for Big Goals
Richard Stuebi, president of Future Energy Advisors, said that renewables accounted for 10% of New England’s generation in 2018, so that if the region and New York want to achieve their ambitious environmental goals, “we need to start doing it now.”
Moderating a panel discussion, John Dalton, president of consultancy Power Advisory, asked whether the 100% carbon-free or renewable power goals in Massachusetts and New York were attainable at all.
“Large-scale renewables like solar and wind are a primary reason the state is able to achieve these lofty goals,” said Doreen Harris, director of large-scale renewables for the New York State Energy Research and Development Authority. “The last two years alone have brought about incredible cost reductions and competition from these resources. In 2017 and 2018, New York awarded agreements for long-term contracts for 46 different large-scale projects, and at prices over 20% less than those received just two years ago.”
Gov. Andrew Cuomo in January vaulted New York ahead of other states by pledging to secure 70% of electricity from renewables by 2030 and to achieve carbon-free electricity by 2040, while nearly quadrupling its offshore wind energy goal to 9 GW by 2035. (See New York Boosts Zero-carbon, Renewable Goals.)
New York is in the midst of reviewing 18 proposals from four developers responding to its first offshore wind solicitation issued last November seeking 800 MW or more of offshore wind. The state expects to award contracts in April, Harris said. (See Four Bidders Vie for NY Offshore Wind Project.)
Harris noted the “very interesting areas of regional overlap” among the lease areas capable of serving multiple markets from New Jersey north to New York, Connecticut, Rhode Island and Massachusetts.
“Big 100% renewable or carbon-neutral goals are attainable; it’s just a matter of how much you’re willing to spend to get there,” Chang said.
Emily Green, staff attorney with the Conservation Law Foundation, said Maine Gov. Janet Mills’ new renewable energy goals of 80% by 2030 and 100% by 2050 are attainable.
“Clearly it’s a very aggressive goal, calculated to fulfill Gov. Mills’ campaign pledge to establish Maine as a leader on clean energy,” Green said. “If you look at the technical potential in the state of Maine, our solar developers would really like to tell us that the state is 33% sunnier than Germany, the global leader in solar development. In terms of offshore wind, we rank seventh in terms of technical potential, so I think the resources are there.”
Transmission Issues
David Wilby, president of Maine-based consulting firm Wilby Public Affairs, said that if asked to rank the challenges to developing large-scale renewables, “I’d rank the top three as transmission, transmission, transmission.”
Dalton asked about the potential for regional cooperation in developing offshore wind transmission.
Transmission is “an existential issue” for onshore wind, Wilby said, but getting regional cooperation for offshore wind transmission, though not easy, “probably could be done in a limited way.”
“In some cases, we just have to do better together as stakeholders as part of ISO New England and New York ISO,” said Melissa Kemp, director of policy for the region for Cypress Creek Renewables.
“Right now, something like over 50% of distribution-level solar projects and storage projects in Massachusetts are on hold,” Kemp said. “There’s absolutely no clarity about how those will be studied; there’s been no process set up ahead of time for ISO-NE transmission coordination with the distribution-level companies. That’s just not OK … that’s a crisis.”
Offshore wind comes with its own set of transmission challenges, and New York “is seeking a bundled product in the sense that we’re looking for generation and transmission, and we’re paying for it in one associated contract,” Harris said.
“The proposals that we received, in several cases the leaseholder actually partnered with a transmission company for delivery into New York,” Harris said. “It might have been conceivable to think about radials when you’re talking about 2,400 MW of offshore wind, but when you’re thinking about 9,000, obviously that’s a very different ballgame from the perspective of scale and points of interconnection.” (See Vineyard, Anbaric Team on 1,200-MW Offshore-Tx Proposal.)
Storage and Hybrid
Distributed storage will continue to be a significant part of the region’s installation base, said Jason Burwen, vice president of policy for the Energy Storage Association.
“You’re going to see a significant fraction of deployment coming onto distribution systems … and the duration of these assets getting longer,” Burwen said.
The story, he said, is the decline in costs, precipitous and somewhat unprecedented in the history of energy technologies at bulk scale, with 8 to 10% declines in installed costs from year to year.
All the storage in the country amounted to 1,200 MWh in 2017, while today a single facility planned to go online in California next year will have the same 1,200-MWh capacity, Burwen said.
“That gives you a sense of how the order of magnitude of the amount of storage coming onto the system is changing, as well as the size of these projects,” he said.
Aside from its known benefits of providing flexibility and balance on the grid, “you’re going to see storage used for congestion avoidance and curtailment avoidance, and that becomes particularly important at much higher levels of renewables, whether that’s in more localized systems for congestion, or on a more systemwide basis for the curtailment issue,” he said.
“Adding storage to our assets across the country is the lowest-hanging fruit,” Kemp said. “In the Northeast … the first and easiest entry point has been the distributed market … relatively straightforward, predictable revenue streams for adding storage to various sizes of distributed assets.”
But there is still work to do on the wholesale market side, Kemp said, citing the ISO/RTO filings in December on Order 841 implementation to allow for greater market participation by storage resources. (See RTOs/ISOs File FERC Order 841 Compliance Plans.)
“There are a lot of problems there,” Kemp said. “I think Order 841 from FERC symbolically looks great, but … we’re not there yet. In New York, there’s discussion about dispatch, whether that has to be controlled by the ISO because of software constraints. … ISO-NE is in some ways simpler because they have the Pay-for-Performance.”
The Pay-for-Performance program took effect last June to replace the RTO’s Winter Reliability Program, increasing financial incentives for resource owners to make investments to ensure reliability and responsiveness during periods of scarcity.
VALLEY FORGE, Pa. — The PJM Market Implementation Committee on Wednesday heard a first read on a proposed change to the calculations for financial transmission rights forfeitures.
Brian Chmielewski, manager of market simulation, said PJM and the Independent Market Monitor agreed the current forfeiture rules should be adjusted because they do not distinguish between on-peak and off-peak FTRs.
Chmielewski said the issue was discovered in January but that the RTO determined its code is aligned with the Operating Agreement and Manual 6 and that no rebilling was necessary.
FTR forfeitures are intended to discourage traders from cross-market manipulation — for example, placing increment offers or decrement bids to cause congestion on paths where they hold FTR positions.
Holders subject to forfeiture are credited for the hourly cost of the FTR. Under current rules, a $1,500 off-peak FTR for June 2018 would be credited an hourly cost of $2.08, equivalent to $1,500 divided by 720 hours (30 days x 24 hours). Under the proposed change, the FTR cost would be divided by only 384 off-peak hours, increasing the credit to $3.91.
PJM plans a vote on the changes at the April MIC, with first read at the April meeting of the Markets and Reliability Committee and an effective date in the third or fourth quarter.
Current and proposed FTR forfeiture formula | PJM
Incremental Auction Revenue Rights Funding
Chmielewski also presented the first read on a problem statement and issue charge to address a risk to FTR market revenue funding. The initiative concerns the awarding of incremental auction revenue rights (IARRs) — ARRs created by the addition of required transmission enhancements, merchant transmission or customer-funded upgrades.
IARRs are granted to the customer only if the transmission improvement provides additional capacity that makes the request feasible. PJM guarantees that awarded IARRs are at least 80% of studied IARR megawatts.
Chmielewski said underfunding of interregional IARRs could occur because MISO’s rules cannot guarantee future firm flow entitlements (FFEs) to PJM for upgrades built for IARR requests. Any portion of the FFEs for an affected coordinated flowgate that is less than 80% of the IARR megawatt total will result in inadequate FTR revenues, the RTO has found.
The MIC will vote on the initiative at the April meeting. PJM wants stakeholder work completed by Aug. 1 to allow implementation of the new rules for the 2020/21 planning period.
Gas Contingencies Update
PJM will take its rejected gas contingencies proposal back to the MRC on March 21 for stakeholder input on what a new plan might look like, PJM’s Thomas DeVita told the MIC.
PJM’s filing would have allowed generators to request cost recovery across nine categories, such as overrun charges and exceeding maximum daily quantity.
The proposal would have allowed crediting of non-penalty switching costs prior to commission approval, subject to refund, while penalty costs would be credited only after commission approval.
FERC described PJM’s definition of “penalty” — costs that are designated as such in the pipeline or local distribution gas company tariff — as “unreasonably narrow and unsupported.” The commission said situations that trigger penalties by some pipelines are called switching costs by others.
The commission also said PJM must add events that trigger fuel-switching directives in its Tariff because they “significantly affect rates, terms and conditions.”
PJM staff said Wednesday it was “somewhat telling” that FERC rejected the order without prejudice, leaving the door open for the RTO to tweak the proposal for resubmission.
March 6 Day-ahead Results Rerun
PJM told members it had to rerun the results of its day-ahead market for March 6 but that the changes were minor.
The bidding period was extended by a half-hour because of “challenges” getting up-to-congestion bids into Market Gateway, PJM’s Tim Horger said. Staff had to make some manual transfers of data, which resulted in about 10% of UTCs not being transferred properly.
“The impact was minor. I understand that’s relative to participants as to what minor would be,” Horger said. He said unit commitments for physical generation did not change, although the dispatched megawatts may have. The revised results were posted Wednesday afternoon.
PJM said the RTO’s current testing rules are based on limited demand response (LDR) requirements made obsolete by Capacity Performance.
LDR applied only to summers, non-holidays and weekends, while CP requires the resource on demand year-round. Likewise, CP events can now last up to 15 hours — versus just six under LDR — and lack LDR’s cap of 10 reductions a year.
The Demand Response Subcommittee is expected to take 12 months to investigate the issue and recommend potential changes. Any rule changes would require revisions to the Reliability Assurance Agreement and several manuals, PJM’s Jack O’Neill said. (See PJM DR Subcommittee to Review Capacity Test Requirements.)
OASIS
PJM’s Chris Advena provided a first read on the update of the Open Access Same-Time Information System (OASIS) tool, which he said has been unchanged since 1990.
New OASIS screen | PJM
Advena said the changes are administrative and cosmetic, including product name changes, additional fields and the automation of annulment request evaluations, a process currently done via email. The MIC will be asked next month to endorse related changes to the regional transmission and energy scheduling practices.
The new tool also will reflect changes to the business practices of the Neptune, Hudson and Linden VFT merchant transmission facilities.
Early Look at Redesigned Homepage
PJM has posted a betaversion of its redesigned home page available for visitors to test and provide feedback before its scheduled rollout at the end of March. RTO officials also gave stakeholders a sneak peek at the redesign during meetings last week.
PJM home page beta | PJM
The new design is intended to highlight “more dynamic and up-to-date content,” including announcements and real-time grid conditions, PJM said. The new homepage also includes a new section for filings and orders, streamlines meeting and training information, and includes a reorganized and expanded footer with links and contact information.
VALLEY FORGE, Pa. — PJM last week scheduled two meetings in the coming weeks to discuss rules for removing projects from the Regional Transmission Expansion Plan.
Aaron Berner, PJM’s manager of transmission planning, told the Planning Committee on Thursday that the RTO crafted a problem statement for a holistic review of the process in response to stakeholder concerns over rules for removing supplemental projects.
The initiative could result in changes to Manual 14B. Staff, he said, are otherwise “unconcerned” with existing manual language.
He said meetings scheduled for March 22 and March 29 will focus on educating stakeholders about PJM’s past project cancellations — a process that is currently handled on a case-by-case basis resulting from a reduction in load forecasts or because developers are unable to get state siting approval.
“We should look to solidify rules that are consistent among the three project types: baselines, network upgrades and supplementals,” Berner said. “They are all modeled the same.”
The issue arose after Sharon Segner, vice president of LS Power, proposed an amendment to Manual 14B: PJM Region Transmission Planning Process specifying that a transmission owner’s supplemental project “will generally be removed from the RTEP” following a final order by a state siting agency rejecting the project. Supplemental projects are proposed by TOs and are not required for compliance with PJM’s reliability, operational performance or economic criteria. (See PJM Rebuffs Stakeholders on Supplemental Projects.)
At Segner’s request, the Markets and Reliability Committee last month agreed to delay a vote on revised transmission planning rules for 60 days to accommodate further discussion on the language. (See “Transmission Replacement Vote Deferred Until April MRC,” PJM MRC/MC Briefs: Feb. 21, 2019.)
“Certainly, we don’t object to having a broader discussion” at the March 22 meeting, she said Thursday. “We request the specific issues we listed for discussion in the delay motion to be part of the agenda for the March 22 meeting.”
Ed Tatum, vice president of transmission for American Municipal Power, said he was confused by the problem statement. He said there are many improvements AMP would recommend to the modeling process for adding or removing facilities, but that doesn’t seem to be what PJM wants to tackle.
“This is really more of PJM’s position on the MRC’s direction than a problem statement,” he said. “Stakeholders raised concerns that PJM should simply acknowledge that it has the same discretion to supplemental projects as it does to all other projects,” he continued. “It’s important to have a good understanding of the types of projects PJM has already removed from the plan.”
PC Chairman Ken Seiler said staff will “tighten up” the language of the problem statement based on stakeholders’ comments and present a revised draft at the March 22 meeting.
PJM Readies Package on Market Efficiency Rule Changes
PJM presented the first read on proposed rule changes developed by the Market Efficiency Process Enhancement Task Force.
Brian Chmielewski, PJM’s manager of market simulation, said the package that staff will present for a vote at the PC’s April 11 meeting changes how often the RTO will re-evaluate projects and shifts the long-term submission window and timing of the mid-cycle updates.
Chmielewski said the task force agreed PJM will not re-evaluate any projects once a certificate of public convenience and necessity (CPCN) has been issued or — in the case of states without such a process — once construction has begun. Under current rules, PJM reviews the costs and benefits of economic-based transmission projects annually to ensure they remain economical.
Both the costs and benefits of market efficiency projects costing more than $20 million will be re-evaluated annually if they lack CPCNs or are not subject to such requirements. Projects under $20 million will not be re-evaluated if the updated costs do not cause the benefit-cost ratio to fall below 1.25 based on the original benefits.
Segner said LS Power supported the language, noting her comfort level came with PJM’s qualifiers for how the process changes under different state regulatory requirements.
“Essentially, if you are in a state that needs a CPCN, the state grants it or they don’t, and the re-evaluation stops at that point,” she said. “If your permits are more municipality-driven … the test for states that don’t have a CPCN process is physical construction because the focus of stopping the re-evaluation is tied to the construction at the physical site.”
PJM attorney Pauline Foley agreed and said the distinction between the two divergent processes “puts us in a lot better place than we are today regarding when re-evaluation can cease.”
The task force also proposed shifting the long-term window back two months to January-April from November-February to align it with MISO’s processes. If approved, both RTOs would post economic drivers in January.
The mid-cycle model refresh would be made in late April to allow project proposers extra time to analyze their projects under the revised case prior to a final submission.
The changes were the result of the task force’s “Phase 2” discussions.
Staff will seek PC and MRC approval of the changes in April, with Members Committee endorsement of Operating Agreement revisions scheduled for May. PJM wants the new rules effective Aug. 1 for the 2020/21 long-term window.
Chmielewski said the task force is considering a third phase of discussions after failing to reach consensus on two other proposals:
Evaluating regional targeted market efficiency projects to address historical congestion using the same criteria as used in interregional TMEPs; and
Changing the 1.25 benefit-cost threshold to measure energy benefits separately from capacity benefits.
Revisions from Order 845
PJM says it has met, or is close to meeting, changes required by FERC’s Feb. 21 ruling clarifying Order 845.
In Order 845-A, the commission ruled on 12 requests for rehearing or clarification of the 2018 rulemaking intended to improve the transparency and timeliness of the generator interconnection process. (See ‘Boring Good’ Rulemaking Seeks to Clean up Order 845.)
PJM’s Susan McGill briefed the PC on four Tariff or manual changes it has finalized and said an additional six changes will be presented to the PC in April. The RTO faces a May 22 deadline for its compliance filing.
Among the changes will be new definitions and clarifications and a new Tariff section for nonbinding dispute resolution procedures including interconnection customers.
Offshore Interconnection Rights Meetings Begin in April
PJM will commence a series of stakeholder meetings on offshore wind development and merchant transmission beginning April 16.
Suzanne Glatz, PJM’s director of infrastructure planning, said the first meeting will consist of education about the RTO’s current process, followed by three months of exploration into alternative options before returning to the PC in August for endorsement of proposed changes.
Last month, the committee approved a problem statement to consider granting merchant transmission developers capacity interconnection rights (CIRs) for offshore wind. (See “PC Moves Forward on Offshore Interconnection Rights,” PC/TEAC Briefs: Feb. 7, 2019.)
Current rules allow merchant transmission developers to obtain transmission injection and withdrawal rights for DC facilities or controllable AC facilities connected to a control area outside the RTO. Under the problem statement, stakeholders will consider allowing merchant transmission developers to request CIRs, or equivalents, for non-controllable AC transmission offshore.
$15M Project to Solve High-voltage Alarms in Dayton Zone
Berner told the Transmission Expansion Advisory Committee on Thursday that PJM and Dayton Power & Light planners have identified a $15 million solution to address excessive high-voltage alarms in the utility’s zone. The utility has logged approximately 19,000 alarms over the last two years.
The alarm-to-minimum-load-hour ratio nearly doubled between 2017 and 2018, Berner said, with 327 alarms over the two years at 345-kV buses.
PJM said the problem is attributable in part to plant retirements, which have left the zone with only peaking plants.
The RTO said that after exhausting all typical operating procedures, Dayton is frequently forced to switch out equipment to avoid long-term damage from high-voltage exposure — a practice it finds unsustainable and ineffective.
The solution will be the installation of three 100-MVAR reactors with a projected in-service date of Dec. 31, 2021. They will be located at the 138-kV Miami, Sugarcreek and Hutchings substations.
Alarms by 138-kV substation, January 2017 to December 2018, for Dayton Power & Light | PJM
End-of-life Project for London-Dulles Junction
Dominion Energy plans to rebuild a 4.4-mile-long section of the 230-kV #2008 line between Loudon and Dulles Junction in Virginia to eliminate corroding towers.
PJM said removing a section of the line would cause 241 MW of load to be on radial and 311 MW of load to be dropped by a failed breaker contingency at the Reston substation.
Line #2008 will share the towers of line #2173, double-circuit structures that currently have an empty arm.
Dominion also plans to retire the 8.44-mile-long line #156 from Loudoun to the Bull Run substation and cut and loop a 230-kV line into the substation to prevent thermal violations. Three 230-kV breakers would be added to accommodate the upgrade.
The plan also removes two 230-kV transformers and a 115-kV capbank at the Loudoun substation; removes a 115-kV capbank at the Bull Run substation; and removes a 230-kV line switch from line #295 at the Bull Run substation.
The project is expected to be in service by the end of 2023.
Separately, Dominion canceled a $2.7 million project to add three 500-kV breakers at the Mt. Storm substation after the manufacturer indicated existing breakers are capable of 44 kA.
LS Power’s Segner said PJM should evaluate whether the Loudon-Dulles Junction project would address any regional needs and should be subject to the Order 1000 competitive process.
She cited the August 2018 D.C. Circuit Court of Appeals ruling ordering FERC and PJM to reconsider how they allocate the costs of high-voltage transmission projects developed to satisfy individual utilities’ planning criteria. The court ruled in a case prompted by Old Dominion Electric Cooperative, Dominion Energy Services and Virginia Electric and Power Co., which had challenged FERC’s approval of a PJM Tariff revision that resulted in the RTO assigning all the costs for two transmission projects proposed by the companies to the Dominion zone (17-1040, 17-1041). (See DC Circuit Rejects PJM Tx Cost Allocation Rule.)
The commission has not acted on the remand order.
“Because the matter is remanded to FERC, we need to wait and hear what FERC is going to say on this issue,” PJM’s Foley responded. “So, we’re on hold. … When the commission finally addresses this issue, we will implement what it decides.”
Dominion, ATSI Supplemental Projects Presented
Dominion gave the TEAC a presentation on several supplemental project needs:
A new Paragon Park substation to support existing data center load and a new data center campus in Loudoun County with a total load in excess of 100 MW;
A third, 84-MVA distribution transformer at the Poland Road substation in Loudoun County to address customer load growth and contingency loading for the loss of one of the existing two transformers; and
The replacement of the aging Chesterfield Tx#9 and Peninsula Tx#4 224-MVA, 230/115-kV transformers.
Dominion also presented proposals to:
Install a 1200-A, 40-kAIC circuit switcher and associated equipment to feed the fourth transformer at the BECO substation in Loudoun County ($750,000); and
Interconnect the new Buttermilk substation with line #2152 (Cumulus-Beaumeade) and line #2170 (Roundtable-Pacific), and install line switches, circuit switchers and bus work for the new transformers ($11 million).
American Transmission Systems Inc. presented a plan to rebuild 1.5 miles of the Perry-Ashtabula-Erie West 345-kV tap line as a double circuit at a cost of $23.7 million. The current three terminal lines are prone to misoperations with lengthy fault locating analyses and restorations. The company said the existing transmission relay communication equipment is approaching its end of life and is difficult to maintain and repair.
CARMEL, Ind. — MISO foresees a “modest probability” it will declare a systemwide maximum generation event this spring.
The RTO last week said such a scenario would culminate from both high loads and forced outages, and it stressed that the need for emergency procedures will be “impacted by the availability of resources,” such as wind generation, capacity imports, stranded capacity and load-modifying resources.
MISO predicts a 101-GW peak this spring and says it has 150 GW of resources, including load-modifying resources, available to cover demand and outages. Last spring, total outages in the RTO in April neared 50 GW, the highest level in the last five years.
NOAA spring prediction | NOAA, MISO
The National Oceanic and Atmospheric Administration forecasts average temperatures in MISO Midwest and higher than normal temperatures in MISO South during the season.
Speaking at a March 7 Market Subcommittee meeting, Manager of Probabilistic Resource Studies Ryan Westphal said the forecast indicates a good chance of a “normal spring for the north part of the footprint.”
MISO has projected it has a probable 103.3 GW worth of generation capacity in March, 95.2 GW in April and 105.1 GW in May.
Westphal said the RTO expects May to have the highest chance of systemwide maximum generation event procedures.
Meanwhile, in preparation for summer, MISO will hold readiness drills for members to review emergency operation procedures on April 18, April 25, May 2, May 9, May 16 and May 23. It will also hold its annual summer readiness workshop on April 23.
CARMEL, Ind. — MISO last week revived the idea of implementing a seasonal capacity auction as part of its multipronged resource availability and need (RAN) initiative but promised to gather more data on resource flexibility before defining long-term solutions.
Seasonal Auction Revival
MISO planning adviser Davey Lopez said he’s observed a shift from stakeholders criticizing a two-season capacity auction to becoming open to analysis of possible benefits, including better capacity availability and price signals. Lopez also said stakeholders indicate the most support for a four-season construct. However, stakeholders still support holding a single auction rather than performing auctions in different seasons, he added.
But whether that single auction would be conducted simply with seasonal inputs, encompass four separate seasons or be four auctions performed simultaneously remains to be seen, Lopez said. MISO said it will work on seasonal design elements through the end of the year.
“I think by the end of the year we’ll have at least some results on here’s what a seasonal auction would look like and here’s what the results will be,” Lopez said at a March 6 Resource Adequacy Subcommittee meeting.
But representatives from Xcel Energy, DTE Energy and Madison Gas and Electric said they still favored MISO’s erstwhile monthly auction design. The RTO switched from monthly voluntary auctions to an annual voluntary capacity auction in 2013.
MidAmerican Energy’s Greg Schaefer said the monthly auction was a lot of work that yielded unclear price signals.
“Rather than leaping from once per year to 12 times per year, let’s try something intermediate,” Schaefer urged.
But some stakeholders say price signals are no better in MISO’s current capacity situation.
“With the current annual construct, we don’t have a price signal … we have a price that is essentially zero,” Coalition of Midwest Power Producers’ Mark Volpe said.
Many stakeholders said MISO must come prepared with study results that show a seasonal capacity auction will solve potential capacity shortfalls.
“From our perspective, the case has yet to be made, and the analysis has yet to be exhausted,” WPPI Energy’s Steve Leovy said. He also argued that MISO shouldn’t proceed with a seasonal auction unless the RTO’s loss-of-load expectation (LOLE) study shows risks outside the summer season.
MISO Independent Market Monitor Michael Chiasson said the current annual capacity market design prohibits some resources unavailable in the summer from entering the market at all.
“So those are essentially lost resources from a capacity value perspective. This sort of flexibility should increase the number of capacity resources. … That will make our market a lot deeper … and more economically efficient,” Chiasson said.
“Assuming that the LOLE can be edited, [we still] need to be careful about summer and winter compared to the spring and fall,” Minnesota Public Utilities Commission staff member Hwikwon Ham said, emphasizing that MISO should still recognize that summer and winter risks will continue to be more pronounced than those in spring and fall.
“I need to remind people we’re in a planning reserve sharing group. And if we go to seasonal accreditation, what’s the point of being in the MISO?” Consumers Energy’s Jeff Beattie said. “The bottom line is we need to show value in this; otherwise we’re going to … be in a ‘Groundhog Day’ situation,” Beattie said in reference to MISO’s proposed, three-year forward capacity auction design that was rejected by FERC in early 2017.
Beattie noted that Consumers is relying on MISO’s reserve sharing characteristics while its Ludington pumped storage facility is on an extended outage for major upgrades. He said when the facility returns, Consumers will repay the reserve-sharing debt with nearly 2 GW in storage capacity.
Consumers has said MISO moving to a two- or four-season construct would be “a step back” in the RTO’s value to stakeholders unless it also devises a method for monthly true-ups, similar to NYISO’s practice.
“A seasonal construct with a minimum of two seasons with forward monthly true-ups has been proven to be FERC-acceptable for many years,” Consumers said in comments to MISO.
Mississippi Public Service Commission consultant Bill Booth asked how a seasonal auction construct would impact MISO’s annual must-offer requirements for resources.
“It may be a little premature to talk about must-offer requirements … but I think, yeah, we’d have to address the must-offer requirement in some form or fashion,” Lopez said.
MISO Director of Resource Adequacy Coordination Laura Rauch said the RTO may find it needs a higher percentage must-offer requirement but a lower overall megawatt requirement for fall, when outages spike and weather becomes volatile.
“There will be impacts across the board that we’ll have to analyze,” Rauch said.
Lopez said outages in particular will be a consequential variable for a seasonal auction. He also said MISO will have to examine seasonal auction inputs, including the loss-of-load target, planning reserve margins, local reliability requirements and capacity import and export limits. Resources, including wind and solar generation, would also need accreditations that vary by season.
Lopez said MISO will likely devise hypothetical seasonal inputs and study them against annual auction values based on a summer peak.
Data on the Way
MISO this week committed to more internal study on its system to gather more data to support future long-term RAN solutions, including the possible seasonal capacity auction.
At a March 7 Market Subcommittee meeting, MISO market design adviser Dustin Grethen said the RTO will conduct an analysis to provide “visibility into availability and flexibility.”
“So a lot of buzzwords there,” Grethen said, smiling. “We’re really going to be digging deep into availability and flexibility. What are the system needs and characteristics that MISO has? … We need to make sure we have good empirical evidence for the things we’re proposing.”
MISO said it will assess multiple years of hourly, real-time location-specific values for load, reserves and net-scheduled interchange. It will use those data sets to look into changing needs for energy, ramp and reserves in MISO regions and in load pockets throughout the year. Grethen said MISO will also examine its past forecasts and the “final disposition” of all megawatts that were potentially available to meet system needs. The goal is to quantify MISO’s uncertainty and resource flexibility, he said.
Grethen also said stakeholders have made “many calls” for MISO to develop a multiday market forecast as part of the RAN project. He said MISO will have to complete its data-gathering and future discussion before such an addition is made. Discussions on a multiday forecast are currently on hold until early 2020, according to the RTO’s Market Roadmap list of possible market changes.
Xcel Energy’s Kari Hassler asked MISO to not assume in its new analyses that coal and nuclear resources continue in their must-run capacities, as incentives to continue operating such generation are vanishing.
“Please don’t assume that all of your must-run resources will continue to run that way,” she told Grethen, who took notes.
“Waiting for data is not the answer. Volatility is a given; uncertainty is a given. We have to work under that assumption instead of waiting for data. To me, that’s a very dangerous proposition,” the Minnesota PUC’s Ham said.
Ham also said as long as distributed energy resources aren’t visible to MISO, its data collection will continue to be incomplete. He said MISO should aggregate DERs and let them into the market in order to alleviate some uncertainty.
Grethen said MISO hasn’t been sitting on its hands waiting for data and pointed to its three “stopgap” Tariff filings aimed at freeing up 5 to 10 GW of capacity this spring. MISO has two near-term filings awaiting FERC action as part of the short-term piece of the three-phase RAN project, one to subject demand response to annual capability testing and one to impose new generator accreditation penalties for planned outages taken with fewer than 120 days notice and during “low-margin, high-risk periods.” (See MISO LMR Capacity Rules Get FERC Approval.)
History on Repeat?
As part of RAN, MISO is also mulling modeling both nonoptimized planned outages and resource lead times in its annual LOLE study, and an investigation into how resources are accredited before the 2020/21 Planning Resource Auction. MISO’s current LOLE doesn’t account for either variable. Lopez also said MISO will continue to evaluate its capacity accreditation for the PRA over the next several months.
However, MidAmerican’s Schaefer said he didn’t see why MISO was considering modeling sub-optimized scheduled outages in the LOLE when it has a Tariff filing out for FERC approval aimed at improved scheduling.
“It doesn’t make sense that we’re telling FERC we can do better. … We just can’t blindly tell FERC that history will repeat itself when we’re telling FERC that history won’t repeat itself,” Schaefer said.
