VALLEY FORGE, Pa. — The PJM Market Implementation Committee endorsed two fuel-cost policy (FCP) packages — including one authored mid-meeting — that would consider the market impacts of breaking the rules and adjust penalties accordingly.
The first package, compiled by a group of stakeholders, won 87% support and will advance to the Markets and Reliability Committee as the main motion next month. The plan reduces penalties when a market seller self-identifies violations of its FCP and provides safe harbor for situations of noncompliance that weren’t contemplated by the policy. The plan would also expand the use of temporary FCPs. (See PJM MIC Briefs: Nov. 13, 2019.)
PJM’s Glen Boyle, however, questioned how the plan would apply penalties, noting that existing language could allow for duplicate benefits. The plan would fully penalize units that clear the day-ahead market or run in real time on a cost-based offer and are either paid day-ahead/balancing operating reserves or have cost-based offers above $1,000/MWh. If a market seller self-identifies noncompliance to PJM and the Independent Market Monitor, the penalty is reduced 75%.
“There could be a scenario under this proposal where a cost-based unit running on its cost-based schedule is the marginal unit setting price and still getting a discount on the penalty,” he said. “I think that position is a little tough to justify.”
Adrien Ford of Old Dominion Electric Cooperative acknowledged that the scenario could occur but said it wasn’t a big enough risk for stakeholders to consider modifying their plan.
“Knowing whether or not there was an impact is tough, so we are coming up with something to indicate that there might have been an impact,” she said. “I think what you’re pointing out is a thin risk that there could be an impact and it wouldn’t be assigned. It is likely that a marginal unit would be paid DA/balancing operating reserves and caught by the impact test. There’s no perfect test, but we think this is a pretty good one.”
The PJM Industrial Customer Coalition and Calpine offered revisions to the first package that they said would address Boyle’s concerns. When it wasn’t accepted as a friendly amendment, the two stakeholders proposed the alternate language as a second package on which the MIC would vote. The revisions clarify that the full penalty would be imposed if a unit is marginal in the day-ahead or real time on its cost-based offer. A unit committed on its price-based schedule that later fails the three-pivotal-supplier test during its minimum run time or hours of its day-ahead commitment would also not incur the full impact factor unless the other conditions for market impact were met. About 81% of the committee endorsed these small language tweaks too.
The Monitor withdrew its package in support of PJM’s own set of revisions, which only won 29% support from the MIC. The RTO also rescinded an alternative package that offered its own version of an impact factor.
Parameter-limited Schedules
PJM and the Monitor presented their divergent views to the MIC on the implementation of parameter-limited schedules (PLS) and whether governing document revisions are needed.
According to PJM, Tariff and Operating Agreement language errors introduced with the implementation of Capacity Performance means that the RTO’s practice regarding PLS contradicts its own rules and conflicts with other governing documents. The Monitor said, however, that PJM should simply follow the language set out in the Tariff instead of revising the document to fit its current practice.
“What we want to do is make sure the Tariff reflects what’s in that manual,” PJM’s Adam Keech said. “The Tariff conflicts with what’s in the manual, and the manual is the correct implementation.”
According to the Monitor, however, the compliance issue rests solely with PJM’s misinterpretation of the Tariff. The RTO’s current implementation of PLS does not mitigate the exercise of market power, as it was intended to do, the Monitor said.
Both the Monitor and PJM discussed their viewpoints with the MIC at the request of the MRC on Dec. 5. The conversation will continue Dec. 19 when the MRC considers Tariff changes authored by PJM to align PLS with the manuals.
Border Rate Manual Revisions
The MIC endorsed revisions to Manual 27: Open Access Transmission Tariff Accounting that would reflect FERC’s recent order on border rate calculations (ER19-2105).
In June, PJM transmission owners submitted a filing that updates the yearly border charge to prevent network integrated transmission service (NITS) customers — network load located outside the RTO’s boundaries but served from within — from subsidizing border and non-zone service rate customers who use transmission service through and out of PJM. (See Settlement Hearing Set for PJM Border Dispute.)
FERC accepted the TOs’ filing subject to refund, with an implementation date of Jan. 1, 2020, but also set a paper hearing and settlement procedures for involved parties to work out their differences over the proposed methodology behind the rates.
PJM’s Market Settlements Development Department said the manual revisions will move forward but acknowledged that refunds will be issued if changes to the methodology are approved in a settlement.
The New England Power Pool Markets Committee continued its crammed schedule to complete the Energy Security Improvements (ESI) proposal at its expanded two-day meeting last week and entertained the possibility of adding a third day to its monthly meetings through March 2020.
ISO-NE has four months to file a long-term fuel security mechanism under FERC’s second extension since its original order last July (EL18-182). The new deadline is April 15, 2020, and the Participants Committee likely will vote on the new market construct at its April 2 meeting. Stakeholders will learn of any schedule additions by the first week of January.
ISO-NE economist Chris Geissler and Todd Schatzki of Analysis Group presented new central case results.
“To date, we have been successful at implementing all the enhancements we had planned, and the good news is that we plan no further enhancements,” Schatzki said. “There may be some small changes to considering how resources on the margins participate, but no major changes.” [Although NEPOOL rules prohibit quoting speakers at meetings, those quoted in this article approved their remarks afterward to amplify their presentations.]
Planners are depending on new revenue streams, such as day-ahead options and forecast energy requirement (FER) payments to motivate generators to stock up on fuel oil or LNG for the winter or arrange for barge or truck delivery of fuel during pipeline constraints.
Load costs will increase under ESI versus current market rules under all three winter scenarios evaluated, according to Analysis Group. | Analysis Group
The analysis found that load costs will increase under ESI versus current market rules under all three winter scenarios evaluated because of FER payments and the net cost of day-ahead energy options.
In the “frequent” stressed conditions scenario — based on the winter of 2013/14, with its multiple, short cold snaps — total payments by load would increase 10.7% to $4.58 billion, with $480 million in FER payments and $267 million in day-ahead option payments partially offset by a $144 million reduction in payments for energy and real-time operating reserves.
Under the “extended” stressed conditions case, based on 2017/18, with its one, long cold snap, load costs would increase $183 million (6.3%) to $3.075 billion.
The “infrequent” stressed conditions case, based on 2016/17, showed $1.83 billion in load costs, a $73 million (4.1%) increase.
“There’s just more dollars in the market under ESI to maintain fuel inventory than there are under current market rules,” Schatzki said.
Schatzki said he will brief the committee in January on how the incentives will work to encourage increased fuel procurements.
“If our meteorologists and the weather services we subscribe to tell us we’re in for a really cold February, then we’re probably going to take extra steps,” said Brett Kruse, vice president of market design at Calpine, describing how his company thinks about winter fuel supplies under the current market design. “Conversely, there are some times — it happened here not too long ago — where you get enough freezing on the rivers and the icebreaker breaks down, and then you could have a problem getting oil.”
“The more you stock up, the more acorns you have left over at the end of winter,” Schatzki said.
Market Design
ISO-NE principal analyst Andrew Gillespie presented a memo on how ESI will improve the markets’ ability to reflect scarcity and provide an alternative to out-of-market contracts such as the retention of the Mystic generating plant. He followed that with a summary of the market design and a discussion of what officials call the “misaligned incentives problem.”
Gillespie also continued the discussion on setting the strike price for day-ahead energy call options and whether it can be “shaped” across the day to minimize the number of hours in which it is less than the day-ahead energy price. The alternative would be two prices, one for all peak hours and a second for off-peak hours. He also discussed applying a “bias” to adjust the strike price reduce the number of hours with a close-out charges to be applied during settlements.
The RTO is asking the Analysis Group to quantify the impact of applying a bias would have on the incentives to the marginal unit for options.
“This presentation is not an ISO proposal,” Gillespie said. “The ISO is evaluating these issues, and today we are sharing our current thinking and looking for feedback.”
FirstLight Proposal
Tom Kaslow of FirstLight Power Resources presented his company’s position that the strike price — intended to estimate the marginal price of energy to meet the next day’s forecasted load plus operating reserves — needs to vary by hour, just as marginal energy prices do.
Estimating the strike price too low could be inefficient and result in higher-than-needed day-ahead reserve costs, he said, while setting the price too high could mean little connection between the resources providing energy and those acting as reserves in real time.
Because the region lacks an hourly futures market, Kaslow said, the hourly day-ahead LMPs for two days prior (day T-2) could be used to set strike prices.
Part of the day-ahead energy price would be reflected in the FER payment (FERP); thus, the hourly day-ahead reserve strike price would be the day-ahead LMP plus the FERP rate for day T-2 in that hour.
Energy Options vs. DA Reserves
One of ISO-NE’s lead analysts, Hanhan Hammer, presented on why the RTO is proposing to settle day-ahead reserve awards as options on real-time energy, rather than as a forward sale of real-time reserves. “Unlike the day-ahead energy market designs, the reserve market designs of the nine ISOs/RTOs are not standardized,” Hammer noted.
Seven of the nine ISOs and RTOs in North America have reserve awards in their day-ahead markets, the exceptions being ISO-NE and Ontario’s IESO. | ISO-NE
The RTO’s proposal will mean stronger incentives to arrange fuel than the alternative, Hammer said, because the day-ahead energy options tie financial consequences to the price of energy in real time, addressing the “misaligned incentives.”
“Seven out of the nine ISOs and RTOs [in North America] have reserve awards in their day-ahead markets,” Hammer said, the exceptions being ISO-NE and Ontario’s Independent Electricity System Operator. Some ISOs and RTOs co-optimize energy and reserves in the day-ahead market, and some procure reserves separately from energy.
Geissler looked at how total consumer costs and producer revenues would change with a day-ahead forward reserves design.
The analysis studied day-ahead and real-time reserve prices from NYISO and MISO to assess potential market impacts. The data showed NYISO has higher reserve prices in the day-ahead than in real time, as its design allows participants to submit priced offers for reserves in the day-ahead market but does not allow priced real-time offers. Average prices for 30-minute reserves in West New York were $4.16/MWh in the day-ahead and 41 cents/MWh in real time in 2018.
NYISO’s design allows participants to submit priced offers for reserves in the day-ahead market but does not allow priced real-time offers. | NYISO
Applying NYISO’s day-ahead premiums to New England reserve needs pencils out to an annual increase in reserve costs of $61.6 million.
“This is meant to be illustrative rather than in any way definitive,” Geissler said. “I would urge caution about taking any specific number like $62 million and saying this is what it’s going to cost, because that’s a ballpark figure.”
Geissler also presented on how ESI motivates resource owners to make cost-effective fuel arrangements before the day-ahead market is cleared, and does so without a forward market component.
FCA 15 Bid Submittal Processes
The RTO’s assistant general counsel for markets, Chris Hamlen, presented a memo outlining potential changes to the Forward Capacity Auction 15 delist bid submittal process to accommodate the timing of NEPOOL votes on ESI and the possible early sunset of the inventoried energy program.
Internal Market Monitor Jeff McDonald and Mark Karl, vice president of market development and settlements, wrote the memo, which notes that FCA 15 retirement and permanent delist bids are due March 13, 2020, a month before the ESI filing deadline. ISO-NE will request FERC approval to waive the FCA 15 deadline if the ESI market design is revised afterward.
If the waiver is granted, and a “non-clerical” revision is made to the ESI market rules after the delist bid deadline, participants that have submitted retirement or permanent delist bids will be given the option to update their bids or withdraw them.
Either option will need to be exercised within a week following the Participants Committee’s April 2020 vote on the market rules, in order to afford the Monitor time to complete its review within the Tariff-prescribed deadlines. The RTO intends to file this waiver request in early January 2020 and will request an order prior to the March 13 deadline.
NESCOE Intent on EER Revisions
The New England States Committee on Electricity’s director of analysis, Jeff Bentz, refined his presentation and answered stakeholder questions from last month’s MC meeting on NESCOE’s proposal for Tariff revisions regarding energy efficiency resources and related capacity obligations during scarcity conditions.
FERC ruled in May 2014 that energy efficiency capacity performance payments should be calculated only for capacity scarcity conditions occurring during peak hours (ER14-1050).
Bentz said that NESCOE still intends to propose a Tariff change that would implement Shaping Option A from the Demand Resources Working Group’s final report issued in July.
“We really do think that Shaping Option A better aligns with the implementation of ISO New England’s original [Pay-for-Performance] design, which is a no-excuses concept,” Bentz said.
Order 841 Compliance
Day Pitney attorneys Sebastian Lombardi and Rosendo Garza briefed the MC on FERC’s ruling conditionally accepting ISO-NE’s Order 841 compliance filing (ER19-470). The commission required additional changes, saying the RTO’s Tariff revisions hadn’t adequately dealt with the application of transmission charges to electric storage resources. (See Storage Plans Clear FERC with Conditions.)
The RTO’s next compliance filing is due Jan. 21, with requests for rehearing on the FERC order due Dec. 23. NEPOOL plans to request an extension on the filing; absent an extension, the proposed market rule changes would be voted on by the MC at its Jan. 14-15 meeting.
Forward Certificate Transfers in GIS
The MC agreed to a request from NEPOOL Counsel Lynn M. Fountain to instruct the Generation Information System Operating Rules Working Group to consider changes to the GIS operating rules. Fountain said the changes are a “way of making a manual system right now a little less so.”
Among other things, the changes would allow batch uploading for forward certificate transfers and improve data sorting.
Officer Changes
The committee re-elected Vice Chair Bill Fowler, president of Sigma Consultants, to continue in his role in 2020. No other members of the committee expressed an interest to be considered as a candidate.
AUSTIN, Texas — Bedecked in his best Lone Star-themed tie over the objections of his wife — “But this is about Texas!” he protested — former FERC and Texas Public Utility Commission Chairman Pat Wood III reunited last week with friends, college classmates (Texas A&M, Class of ’84) and others who helped him deregulate Texas’ electricity market and pave the way for strengthening NERC’s compliance function.
Wood, who delivered a keynote address during Texas Reliability Entity’s annual meeting on Dec. 11, was greeted with “whoops” from fellow Aggies and hugs from everyone else. Hopping from one subject to another, he reminded his audience that the “R” in ERCOT stands for “reliability,” and he recalled a bygone ERCOT slogan: “Reliability through markets.”
“That’s the point. Markets are not just to serve customers with better service, better outcomes and less money. We want a system that does what we’ve taken for granted, that stays on at 60 MHz,” Wood said, pointing at the ceiling lights overheard. “Reliability has a real deep component to it. The reliability of our market has been the story for the last quarter-century of our state.”
As chair of FERC from 2001 to 2005, Wood played a leading role in the commission’s response to the California energy crisis, Enron’s bankruptcy and the 2003 Northeastern power blackout. The latter event led to mandatory reliability standards and the Electric Reliability Organization, now NERC and its six regional entities.
“Now we have a much bigger and broader approach to reliability,” he said. “You’re the six cops on the beat who oversee that, for the whole United States.”
As the principal for Wood3 Resources, Wood’s focus is now on competitive generation, independent transmission, energy storage and other new power technologies. As he did in the 1990s in Texas, he still emphasizes the importance of competition.
“We’ve got to eliminate the barriers to entry, similar to the big things we did on wind,” Wood said, referring to the buildout of transmission lines that have fostered ERCOT’s 22 GW of wind capacity. “We’ve got to integrate this clean, carbon-neutral attribute. … I’m a big fan of letting markets solve that problem, but we’ve got to coordinate that with the market we have.”
Wood is still proud of the energy-only market he helped create. He said sending price signals through scarcity pricing “on hot days is the right place to be long term,” predicting that ERCOT’s “9-ish percent [reserve margin] is probably the new normal.” (See ERCOT Sees 10.6% Reserve Margin for 2020.)
“One big reason is we’re not paying for that extra slug of 20% more power,” Wood said, alluding to RTO reserve margins of 20 to 25%. “That model worked in the 20th century. This model is enabled by the market. It’s demand responsive. Real-time pricing signals are going on all the time. That’s a pretty big tool, something I didn’t have when I was a regulator.”
He lamented that he couldn’t rely on storage as a market tool either.
“We do now. The cost of batteries has come down to where it’s feasible to store power,” Wood said. He said the prices still need to drop, but in the meantime, he has a battery on his Houston house that he gets to “geek out on.”
In the end, it’s all about the people, the affable Wood said.
“The thing that makes this so magical is the people,” he said. “I’m blessed to be part of this ERCOT power family for my career.”
Walker Raises Concerns with NERC Representation
During the Member Representatives Committee meeting, Public Utility Commission Chair DeAnn Walker raised what she said was her “continued concern” that a NERC committee is doing away with its regional delegates and potentially denying ERCOT a vote.
The Compliance and Certification Committee, which advises the NERC Board of Trustees on all facets of the ERO’s compliance monitoring and enforcement program, is revising its charter to eliminate its six regionally allocated seats and replace them with six at-large seats.
“I’m not sure why that’s occurring, though I’m sure there’s a good reason I’m not aware of,” Walker said. “While I understand ERCOT is a very small region, it is ultimately a very important region, to not only Texas, but the United States. I can’t fathom there’s not someone qualified from this region.
“The elephant in the room, it’s clear at least to me, is that the Eastern region drives a lot of decisions, especially with standards,” she said.
Oncor’s Martha Henson does represent Texas RE on the CCC. Texas RE CEO Lane Lanford theorized that one of the reasons NERC has moved away from regional representation is because of a lack of qualified candidates from the regions.
“Unfortunately, in some regions, they didn’t send [the most] qualified people,” he said. “One thing the MRC needs to think about is that when we send people [to NERC], we need to send people who add to the conversation.”
NERC Trustee Ken DeFontes, who attended the meeting, said it was not the board’s intention “to diminish ERCOT’s influence.” He noted that the newly formed Reliability and Security Technical Committee is drafting a charter to ensure NERC has good representation in the at-large seats. That committee will number 34 members, including 10 at-large seats.(See Elections Underway for New NERC Panel.)
The MRC’s Brad Cox, with Tenaska Power Services, and Venona, with Occidental Power Services, will represent Texas RE on NERC’s Member Representatives Committee.
“I think it’s important there’s good representation from all the regions, not just Texas,” DeFontes said.
DeFontes: Texas ‘Closer to the Edge’
DeFontes reflected on the industry’s rate of change and NERC’s focus on anticipating the future “so we have further time to prepare for it.” However, he is still getting acclimated to ERCOT’s single-digit reserve margin.
“You do live closer to the edge than what I’m used to, but you do a fantastic job of managing it,” he said. “This is an example of how the grid is changing and how we have to adapt.”
Board Re-elects Chair, Vice Chair
The RE’s Board of Directors approved the re-election of Fred Day as chair and Milton Lee’s nomination as vice chair for 2020, Day’s last year as chairman. The directors also approved Delores Etter’s re-nomination and former BP America senior executive Crystal Ashby’s nomination to three-year board terms. Ashby will replace Vice Chair John Coughlin, a board member since 2012.
The board also approved the MRC’s recommended BAL-001-TRE-2 standard, which sets interconnection steady-state frequency within defined limits.
Texas Reliability Monitor Director Joseph Younger told the directors that the PUC is expected to approve Texas RE for another four-year contract as the ERCOT region’s reliability monitor. The RE was the only entity to submit a bid (49246).
“I would say our chances are favorable,” Younger said.
The Monitor worked with the PUC to assess 11 settlement penalties through the first three quarters of the year, Younger said.
Texas RE also plans to renew its regional delegation agreement, which expires at the end of 2020. It hopes to receive NERC approval by September, and then file with FERC.
SPP’s internal Market Monitoring Unit last week released a whitepaper detailing a study of generator self-commitments in the market, yielding further evidence that the self-commitment of generation exerts downward pressure on marginal clearing prices.
The MMU said that while the practice can’t be eliminated, it can be “substantially” reduced.
“A smaller distortion will likely help market participants make better short-run and long-run decisions, which tends to coincide with improved profit maximization. Enhanced profit maximization combined with effective regulation and monitoring will likely lead to ratepayer benefits in the form of cost reduction,” the Monitor said in its report, “Self-committing in SPP markets: Overview, impacts, and recommendations.”
The MMU recommended that SPP’s market design be modified to include one additional day of optimization and that the RTO and its stakeholders reduce the incidence of self-commitments to improve price formation and market efficiency.
“Simply eliminating self-commitment without any additional changes could result in an increase in total production costs,” the Monitor said. “When lead times were shortened to reflect an additional day in the market optimization and self-commitment was eliminated, producers were paid more and production costs declined.”
The study echoes recent work conducted by the Sierra Club and the Union of Concerned Scientists. The environmental groups have both studied regulated utilities’ practice of self-committing coal plants, which they say is costing ratepayers hundreds of millions of dollars. (See Enviros, States Question Coal Self-commitments.)
The MMU analyzed offer behavior from March 2014 to August 2019. It ran two simulation series of a week per month for the year leading up to August in which it resolved past market cases.
The study found prices and production costs were “systematically lower” when at least one self-committed unit was marginal. In almost all cases, the MMU said, self-committed generators had lower revenues because of negative congestion prices, while market-committed generators typically had a more balanced congestion profile.
Resources with long lead times and/or high start-up costs tended to be self-committed instead of market-committed, the Monitor said.
The simulations assumed all generation was offered in market status, and that generation offered in market status can be started economically by the day-ahead market.
Board Appoints Stakeholder Group Chairs
The Board of Directors on Dec. 9 appointed chairmen for eight of SPP’s stakeholder groups:
Grant Wilkerson, Evergy, Business Practices Working Group
Alan Klassen, Evergy, Operating Reliability Working Group
Robert Pick, Nebraska Public Power District, Regional Tariff Working Group
John Allen, City Utilities of Springfield, Reliability Compliance Working Group
Jim Jacoby, American Electric Power, Seams Steering Committee
Phil Clark, Arkansas Electric Cooperative Corp., Security Working Group
Brad Hans, Municipal Energy Agency of Nebraska, Supply Adequacy Working Group
Nathan McNeil, Midwest Energy, Transmission Working Group
The chairs were nominated to two-year terms that begin in January by the Corporate Governance Committee. The CGC annually accepts member nominations for about half the stakeholder group chairs.
The board also approved changes to 13 stakeholder groups’ charters during a conference call otherwise reserved for a review of membership surveys and corporate metrics. The board’s evaluation by directors and members resulted in a split, with average scores dropping for half the 12 questions and rising for the other six.
Asked to list issues of focus for the board next year, members settled on CEO succession, expansion in the West and effective implementation of the Holistic Integrated Tariff Team’s (HITT) recommendations.
Seams Group Lays out 2020 Work Priorities
The Seams Steering Committee on Wednesday determined its work priorities for 2020, with a prime focus of providing policy direction as cost allocations are determined for seams projects that don’t qualify as interregional projects. The item was a carryover from 2019, when it was tabled to wait on the HITT’s recommendations.
October’s market-to-market summary | SPP
The SSC will also guide staff through coordinated system plan studies in developing seams projects with MISO and Associated Electric Cooperative Inc. It will also continue to facilitate design and development of a new type of transmission project, coordinated with MISO, to address historical market-to-market (M2M) congestion.
Staff reported that M2M settlements in October resulted in $3.65 million accrued in SPP’s favor. Permanent and temporary flowgates were binding for 1,068 hours during the month.
SPP has incurred $67.2 million in M2M settlements since the process began in 2015.
Sunflower’s Hestermann Elected WIRES President
Sunflower Electric Power’s Tom Hestermann has been elected president of WIRES, an international trade association that promotes investment in the high-voltage grid.
Hesterman, Sunflower’s manager of transmission policy regulations, succeeds National Grid’s Brian Gemmell.
“The critical importance of a robust and resilient grid multiplies” as transportation and heating move toward an electrified future and states continue to pursue aggressive renewable portfolio standards, Hestermann said. “WIRES will redouble our efforts to educate and advocate for advancements in North America’s transmission infrastructure.”
Other elected officers include: President-elect Brian Drumm (American Transmission Co.’s federal regulatory relations & policy and associate general counsel), Vice President David Weaver (Exelon Utilities’ vice president of transmission strategy), Treasurer Kelly Pearce (American Electric Power’s transmission asset strategy & policy managing director), and Secretary Dan Prowse (Manitoba Hydro’s Hydro Connections Department transmission access officer).
INDIANAPOLIS — Energy storage systems will inevitably take hold in MISO as costs decline, but the outlook for technologies outside lithium-ion batteries is less certain, storage experts told stakeholders Wednesday.
The experts were speaking on a panel convened by MISO’s Advisory Committee in lieu of the usual “hot topic” discussion where members sound off on current issues during committee meetings. The AC was unusually quiet during the event, instead electing to hear the panel of outsiders talk battery storage.
“Today we’re focusing on batteries. What are they going to look like in 10 years? What are the limits? When do they become commercially viable at scale?” moderator and MISO Vice President of Strategy and Business Development Wayne Schug said in opening the panel.
“Storage becomes very valuable when incremental capacity is scarce and expensive,” Brattle Group Principal Judy Chang said. She said she expected batteries to become cost-competitive when they serve capacity at peak times.
“I would say that utilities are beginning to explore storage with pilot programs,” Chang said of MISO’s situation, predicting that more storage will be constructed “when capacity is needed.”
MISO’s interconnection queue currently contains more than 2.5 GW of battery storage.
Consultant Mathew Roling said the rollout of battery storage in MISO would probably occur on a state-by-state basis, and battery solutions would be packaged with other technology or generation and not simply be standalone batteries.
National Renewable Energy Laboratory analyst Paul Denholm said four-hour batteries are close to becoming cost-competitive with peaking combustion turbines. Batteries’ ability to provide peaking capacity is especially heightened when they are paired with solar generation, he said.
Paul Mitchell, CEO of Indianapolis-based Energy Systems Network, said that while MISO hasn’t experienced much growth in battery storage systems, that will soon change.
“I think it’s finally going to come in full force,” he said, adding that “the biggest barrier remains the cost.”
Mitchell said battery storage costs aren’t quite as low as traditional generation, and current, 20-year storage contracts that promise to deliver energy at $300/kWh on average are essentially bets on the future value of storage systems — and they might be too optimistic.
“That’s putting a lot of trust in the future costs of energy storage systems. … That might be controversial to say,” he added.
MISO stakeholders in attendance participated in live polling during the panel, predicting that solid-state and vanadium redox flow batteries might emerge as the next dominant technologies.
Mitchell said he’s often privy to the innovations taking place at the Battery Innovation Center on Naval Support Activity Crane in southern Indiana. He cautioned that solid-state batteries right now are “teeny tiny” and nowhere near ready for factory manufacture. He said lithium-ion would continue to be the reigning battery option for at least the next five years.
“I think it’s going to take these technologies a long time to scale up … for the mass market of vehicles or in the grid,” he said.
Roling said the industry might be overlooking the benefits of pumped hydro storage in the rush to embrace battery storage.
“It’s water. It’s good for 100 years. It’s so natural it hurts,” he quipped.
Chang also pointed out that the environmental benefits of storage are system-dependent and only beneficial when batteries absorb and discharge energy from lower-emitting resources, displacing higher-emitting resources.
Roling said that unless MISO states become “anti-carbon,” battery storage in the footprint would never become cost-competitive. He said batteries would need “that social aspect” to be commercially viable.
To that, Chang pointed out that customers are increasingly calling for zero-carbon generation sources.
In another live poll, a majority of attendees predicted utility-scale batteries would become cost-competitive in MISO in about five to 10 years.
Stakeholders asked if storage might be able to flatten a potential duck curve before it even occurs.
Chang said the question was probably premature, as she believed wind would continue to dominate over solar generation in the footprint.
“I do think it’s unique here. I don’t think it’s the same as the West,” Chang said. “I don’t think we’re going to see the duck curve as quickly as in Texas or California. I think we have to be careful about taking one region and applying it to another.”
Below is a summary of the issues scheduled to be brought to a vote at the PJM Markets and Reliability Committee meeting Thursday. Each item is listed by agenda number, description and projected time of discussion, followed by a summary of the issue and links to prior coverage in RTO Insider.
RTO Insider will be in Valley Forge, Pa., covering the discussions and votes. See next Tuesday’s newsletter for a full report.
Consent Agenda (9:10-9:15)
PJM will ask for endorsement of revisions to:
B. PJM Manual 13: Emergency Operations, incorporating event analysis updates.
C. PJM Manual 14D: Generator Operational Requirements, adding guidance associated with distributed energy resource ride through.
E. Manual 27: Open Access Transmission Tariff Accounting, addressing the implementation of the annual calculation of the border rate and the impact on firm point-to-point transmission service charges.
1. FTR Product Range and Auction Process (9:15-9:35)
The MRC will consider the first round of financial transmission rights credit-related policy changes after a two-week deferral. (See “FTR Vote Deferred,” PJM MRC/MC Briefs: Dec. 5, 2019.)
PJM said the recommendations, initially presented at the committee’s October meeting, will improve its credit risk policies after the Financial Risk Mitigation Senior Task Force delegated a more holistic FTR market review and possible design changes to a separate Market Implementation Committee task force. (See “FTR Market Rule Changes,” PJM MRC Briefs: Oct. 31, 2019.)
But some stakeholders expressed concerns earlier this month about the ripple effect the revisions may have on market design. The MRC agreed to delay a vote in hopes of finding compromise and moving the changes ahead.
Stakeholders could endorse a new fee structure for competitive transmission proposals developed by PJM to better reflect the costs of its new comparative framework. (See “PJM Unveils Flat Fee Cost-containment Plan” in PJM PC/TEAC Briefs: Aug. 8, 2019.)
3. Comparative Cost Framework (9:45-10:05)
Along with the new fee structure, the MRC must sign off on corresponding Manual 14F language that memorializes the process, including the Independent Market Monitor’s role in reviewing proposals.
The language has been mired in wordsmithing after transmission owners objected to revisions that they said inappropriately capped certain costs. (See PJM TOs Wary of Cost Containment Rules.) There’s also been an ongoing debate over language codifying a collaborative role between PJM and the IMM in evaluating competitive proposals.
PJM deferred voting on both the fee structure and manual language at the Dec. 5 MRC meeting in order to further fine-tune language regarding these issues. (See “Comparative Cost Framework, Opportunity Cost Calculator in Flux,” PJM MRC/MC Briefs: Dec. 5, 2019.)
4. Real-time Values Problem Statement and Issue Charge (10:05-10:25)
Stakeholders will consider endorsing an issue charge that would address PJM-identified issues with the misuse of real-time values in parameter limited scheduling. (See “Real-time Values, Parameter-limited Schedules,” PJM MRC Briefs: Dec. 5, 2019.)
5. Governing Document Revisions for Parameter-limited Schedules (10:25-10:55)
PJM will seek endorsement of Tariff and Operating Agreement revisions that will correct language surrounding parameter-limited schedules (PLS) accidentally introduced with PJM’s Capacity Performance construct filing.
The RTO said the primary issue is that current language suggests that PJM can commit resources on their price PLS offer or cost-based offer during times that are in conflict with other sections of the Tariff and the OA.
The Monitor, however, says the PJM should modify the way it implements PLS to conform with the governing documents.
6. Modeling Generation Senior Task Force (MGSTF) (10:55-11:10)
The MRC will consider implementing near-term solutions of hourly differentiated segmented ramp rates at the recommendation of the Modeling Generation Senior Task Force.
The MGSTF developed the solutions to improve resource modeling for “complex resources” in PJM’s market clearing engines, including combined cycle units, coal units with multiple mills and pumped hydro.
7. Fuel Security Senior Task Force (FSSTF) (11:10-11:40)
The MRC will be asked to endorse recommendations from the Fuel Security Senior Task Force on next steps for potential governing document changes.
The task force, assembled in March, has been investigating what market responses to conditions could lead to fuel insecurity and assessing whether the current market construct is sufficient to cure the problem. (See PJM Stakeholders Reluctantly OK Fuel Security Initiative.)
The New York Public Service Commission on Thursday placed new restrictions and requirements on energy service companies (ESCOs) that they must honor and fulfill in order to sell to the state’s residential customers and small business owners (15-M-0127, 12-M-0476, 98-M-1343).
“This order to me is a reset,” PSC Chair John B. Rhodes said. “It clearly delineates what is no longer permitted on the foundational principle of protecting customers, and it acts against companies that have acted badly.”
The PSC said that “little has changed in New York’s retail energy market since 2014, when the commission observed that complaint rates related to ESCOs were high.”
In the past few years, the commission has waged a continual struggle to balance the idea of free markets and free choice with accountability for unscrupulous business practices. (See “PSC Continues Crackdown on ESCOs,” NYPSC Approves Higher Rates for Bitcoin Miners.)
DPS staff testify on the proposed ESCO regulations before the commission.
The commission and Department of Public Service staff recently concluded hearings before two administrative law judges, the transcripts of which total 4,233 pages.
The PSC’s order said that the non-ESCO parties, including the state’s Utility Intervention Unit, the attorney general, the Public Utility Law Project of NY (PULP), New York City and AARP, “all agree that the current retail access market does not benefit customers. Some argue the commission should shut down the market entirely, while others argue that the commission should implement systematic and substantial reforms to limit ESCO products and/or ESCO prices.”
DPS staff said that ESCO customers paid $1.2 billion more than utility customers would have paid for commodity service during the 36-month period ending Dec. 31, 2016.
“In general, the ESCO parties believe that little or nothing is wrong with the retail access market and argue that commission interference with ESCOs’ current access to customers is unwarranted,” the commission said. It added that last year saw ESCO customer numbers drop 12% compared to the previous year, to 2 million.
The ESCO parties included the National Energy Marketers Association, the Retail Energy Supply Association, Direct Energy, Agway, Constellation, Great Eastern Energy, Impacted ESCO Coalition and Infinite Energy.
The new regulations include enhanced eligibility criteria and increased scrutiny of business practices, more clear ESCO product and pricing information, and prohibitions on marketing gimmicks that lack energy-service-based value, such as sporting event tickets and gift cards.
The PSC also revoked the eligibility of Atlantic Power and Gas to participate in the state’s retail energy market after finding the company guilty of “a pattern of persistent disregard” for the commission’s consumer protections and “either unwilling or unable to observe the required business practices, even after having its eligibility to market to and enroll residential and nonresidential customers revoked in 2017” (16-M-0618).
Yes to Consolidated Billing for CDG
The commission also approved consolidating the utility bills of community distributed generation (CDG) customers, relieving project sponsors of the need to bill separately for the subscription charge and making it easier for consumers to see their energy benefits in one statement (19-M-0463).
The PSC has been developing the value of distributed energy resources (VDER) mechanism and promoting the growth of CDG for several years. (See NYPSC Refines Value Stack, Boosts Community DG.) CDGs allow customers not positioned to take advantage of rooftop solar installations to directly participate in renewable energy programs.
Thursday’s order directs utilities to automatically deduct the subscription charges a customer pays its CDG providers from the net renewable energy credits applied to the customer’s bill and send the money to the CDG project sponsor based on a percentage set by the sponsor.
“As this percentage must be below 95%, CDG members participating in consolidated billing will receive a guaranteed bill reduction, and therefore guaranteed monthly savings, of at least 5%,” the commission said.
The PSC held its regular monthly session in New York City on Dec. 12.
Several state utilities — Central Hudson Gas & Electric, Consolidated Edison, New York State Electric and Gas, Niagara Mohawk Power, Orange and Rockland Utilities, and Rochester Gas & Electric — submitted comments urging the commission to “consider whether such changes are warranted given the cost and time to implement and determine the proper mechanism for funding the transition to different billing mechanisms.”
The utilities argued that “a reasonable approach would provide for full recovery of all upfront and ongoing costs associated with implementing a new billing approach while also requiring the CDG host to pay for utility billing services.”
The commission also rejected National Grid’s proposal to compete for and acquire CDG customers and reduced the company’s proposed fee for consolidated billing by 90%, allowing the same 1% fee provided to other utilities.
The Alliance for a Green Economy, the Green Education and Legal Fund, and Joule Assets submitted comments in favor of consolidated billing, as did New York City and many smaller municipalities.
INDIANAPOLIS — MISO’s Board of Directors on Thursday unanimously approved a $4 billion transmission portfolio consisting of 480 projects.
The 2019 MISO Transmission Expansion Plan (MTEP) was passed to the board by the Planning Advisory Committee without any suggested edits. (See MTEP 19 Advances to MISO Board Committee.)
“This is the largest MTEP cycle to-date, excluding MISO’s 2011 [multi-value project] portfolio,” Executive Director of System Planning Aubrey Johnson said during a Dec. 10 meeting of the board’s System Planning Committee.
Top 10 most expensive MTEP projects | MISO
MTEP 19 Highlights
Six of MTEP 19’s top 10 most expensive projects are clustered near the Detroit and St. Louis areas.
Johnson said the Detroit area is experiencing enough load growth to warrant MTEP 19’s most expensive project, which includes several miles of aboveground 230-kV and underground 120-kV circuits and a pair of substations at $139 million.
ITC Transmission said several Detroit-area 120-kV underground cables are projected to overload in the future and the project will allow connection with DTE Electric loads in the city.
Other than the Detroit projects, nearly all the priciest projects are needed for reliability purposes.
However, formal approval of the interregional project must wait until at least March, along with MISO’s first-ever storage-as-transmission asset (SATA) project. The RTO has yet to finalize rules to govern either project.
MISO on Thursday filed a plan with FERC to permit storage facilities to provide transmission services (ER20-588). The RTO characterized the proposal as a “fundamental first step forward for the use of storage resources to maximize the reliability and efficiency of the electric system.”
The SATA plan would require that the assets be used only for transmission purposes, barring them from simultaneous participation in energy markets, but the 800-page filing contains a promise that MISO and its stakeholder community would soon begin exploring how storage devices could serve both transmission and market functions.
“Accepting these proposed revisions will allow for the immediate adoption of storage facilities to serve a transmission function in MISO. And in early 2020, MISO and its stakeholders intend to begin the process of addressing the issues related to using storage as both transmission assets and to provide market services,” the RTO told the commission.
Disagreement on Michigan Interconnection Project
Like last year, a stakeholder is once again disputing a small Michigan interconnection project for resembling distribution.
DTE Energy has said the $8.6 million, 120-kV city of Croswell interconnection project in eastern Michigan is more distribution than transmission in nature and should not be included in this year’s transmission buildout package. The company’s Nick Griffin said the line is “clearly radial” in nature.
Johnson said MISO analysis indicated the project should be classified as a transmission line.
“Our recommendation is to leave the project in inclusion in Appendix A,” Johnson told board members in November.
Johnson said the situation is similar to MTEP 18’s Morenci project, which Consumers Energy disputed. (See Michigan Regulators Intercede in MTEP Complaint.) The Michigan Public Service Commission has since reviewed the characteristics of the $21 million, 138-kV line near the Michigan-Ohio border and last month classified it as distribution, dropping it from MTEP eligibility.
“However, that determination is open to rehearing,” Johnson said.
Griffin said it would be “prudent” for MISO to delay approval of the Croswell line until FERC weighs in on the Morenci project. The project was nevertheless included in MTEP 19 approval.
Helena-to-Hampton Corners Heartburn
Johnson said MISO still stands firm that the Helena-to-Hampton Corners project cannot pass necessary robustness testing to be included as a MEP in this year’s package.
Renewable generation proponents had urged MISO to include the $36.1 million, 345-kV project, originally identified in this year’s Market Congestion Planning Study. The project was set to solve congestion in southern Minnesota at a 4.22:1 benefit-to-cost ratio, but MISO said the project quickly lost value once forecasted wind generation was removed from the equation.
INDIANAPOLIS — MISO’s Advisory Committee has decided not to pursue changes to how the RTO vets and selects its Board of Directors after more than a year of discussion and the creation of a special task team to explore the issue.
The AC said Wednesday it would not recommend changes to expand the stakeholder voice on MISO’s Nominating Committee, declining all possible options laid out by the Board Qualification Task Team (BQTT). (See Task Team: Boost Member Role in MISO Board Selection.)
“The result was to maintain the status quo,” AC Chair Audrey Penner told members at a committee meeting Wednesday.
Penner said that while some stakeholders might have wanted to see change, she hoped members saw the value of what she called a high-functioning board.
Board Chair Phyllis Currie said she expected the AC would continue to periodically examine the board’s makeup.
“In this kind of organization, that conversation will come up time and time again,” she told Penner at the board’s meeting Thursday.
The BQTT in September released a list of options that included requiring state and federal regulators to observe a yearlong “cooling-off” period before becoming eligible for nomination to the board, possibly reserving one of the nine director seats for those with experience representing utility customer interests, and doubling the number of stakeholder representatives from two to four on the Nominating Committee that selects board candidates.
Another option would have rotated the sectors from which stakeholder participants are drawn for the Nominating Committee or reserved a designated seat for a member of the Organization of MISO States. A final option would have set aside one of the nine director seats for someone with recent experience representing electric utility customer interests.
Had the AC recommended any changes, they would have gone before the board’s Corporate Governance and Strategic Planning committees as suggestions only.
The BQTT was created in response to last year’s election of Minnesota Public Utilities Commission Chair Nancy Lange to the board while she was still serving on the commission. Some stakeholders questioned the independence of sitting regulators appointed to the RTO’s oversight body. (See MISO Members Uneasy over Board Nomination.)
OMS has also sent a short letter to the board conveying its “strong interest to be a regular and active participant in the Nominating Committee,” according to organization President Matt Schuerger. One of the Nominating Committee’s two stakeholder seats is typically reserved for an OMS representative. Schuerger said he expected regulator participation to continue shaping the board’s makeup.
INDIANAPOLIS — MISO’s Board of Directors will remain unchanged heading into 2020 after the same chairman and three incumbent directors were elected to retain their positions at last week’s final Board Week of the year.
Reporting results at the board’s meeting Thursday, MISO General Counsel Andre Porter said of 146 eligible voting members, 84 cast votes, easily passing the 25% voting participation quorum. Voting was held Sept. 1 through Nov. 26.
This year, the board also filled exiting Director Thomas Rainwater’s vacant seat with former New York Power Authority CFO Robert Lurie, who appeared at Board Week.
The meeting also saw directors vote unanimously to re-elect Phyllis Currie to a second year as their chairman.
“I tell a lot of my California colleagues that they could learn a lot by how MISO engages with stakeholders,” Currie said, accepting the position.
She opened the meeting by reminding staff and members of the RTO’s compliance hotline, where individuals can privately report suspected unlawful, unethical or inappropriate behavior.
In the latter half of 2020, MISO will hold a nomination and election to replace Director Baljit Dail, who has already exceeded his three-term limit; the Nominating Committee in 2017 waived his limit and allowed him to stand for an additional term. At the time, the committee cited MISO’s multiple new directors and Dail’s much-needed information technological experience as the reason for the waiver. (See “Committee Permits Consideration of Extra Term for Dail,” MISO BoD Briefs: June 22, 2017.)
Private Cloud Prepped for New Market Platform
MISO is wrapping up the third year of a seven-year effort to replace its market platform, this year establishing a private cloud-based server that will host the new platform’s modular server.
“We continue to accept market deliverables and find them acceptable,” Senior Director of Market System Enhancements Kevin Sherd told directors at a Dec. 10 meeting of the board’s Technology Committee.
Chief Information Security Officer Keri Glitch said MISO is still running two environments while it learns and discovers efficiencies in the cloud.
MISO will have spent about $20 million on the platform replacement this year, about $500,000 below budget because of a later-than-expected Storage Plans Clear FERC with Conditions.)
The RTO next year plans to make the cloud operational and test it using non-critical infrastructure protection data. By year’s end it will test the new market user interface with customers and begin uploading operations model data into its model manager, which is designed to be a singular repository for its many planning models.
The tasks are the major highlights of MISO’s 2020 to-do list. Vice President of Market System Enhancements Todd Ramey has said the RTO has about 200 deliverables it must complete over the year as part of the project.
“Two-thirds of the work is still in front of us,” said Ramey, who also reassured board members that MISO is “encouraged” by main vendor General Electric’s recent performance.
“We’re trying to be cautious and not too optimistic because … a lot of challenges lay before us,” he added.
MISO expects to introduce its new day-ahead market clearing engine on the private cloud in 2022.
Meanwhile, the RTO reported that it blocked 8.1 billion connections into its systems year-to-date in 2019, a 54% increase from last year. It also reported it had a 2.15% average click rate on phishing attempts in 2019, below the 5.3% industry average.
Glitch also said that over Aug. 22-26, MISO’s energy management system (EMS) experienced multiple slowdowns while trying to access its network-attached storage. “File transfer between EMS and market systems was interrupted during these slowdowns,” Glitch reported.
Glitch said that while MISO largely cleared up the problem, smaller, infrequent slowdowns persist. She said a small, dedicated team is working to identify the root cause of the problem.
MISO Slightly Overbudget in 2019
MISO expects to spend nearly $274 million in base operating expenses by year-end, exceeding its 2019 budget by about $1.3 million (0.5%).
CFO Melissa Brown said the overage is the result of MISO reclassifying some capital expenses as operating expenses.
MISO’s capital spending will likely reach $23.6 million, underbudget by $600,000 (2.7%).
The RTO has set a $337.6 million total operating budget and a $30.4 million capital expense budget for 2020.
MISO: We’re Going to Disney World!
MISO will break with tradition in 2020, holding its final Board Week of the year outside the footprint in Orlando, Fla., instead of near its headquarters in central Indiana.
MISO released a schedule of 2020 quarterly board meeting dates:
