After days of near misses, the ERCOT grid registered a new all-time demand peak of 74.5 GW on Monday as Texas continued to bake in heat extreme even for the Lone Star State.
Monday’s peak, coming during the interval ending at 5 p.m., smashed the old mark of 73.5 GW, set in July 2018. ERCOT initially broke the record during the hour ending at 4 p.m., when load hit 74.2 GW, almost 700 MW above the 2018 mark.
As the temperatures have soared, so have energy prices. Systemwide settlement prices hit $6,537.45/MWh for the 15-minute interval ending at 3 p.m. on Monday, after first hitting quadruple figures during the 2 p.m. interval.
ERCOT has recorded eight of its 12 highest peaks since Wednesday. Earlier this month, the grid operator set records for August demand (about 73.1 GW) and weekend demand (71.6 GW and 71.9 GW on Saturday and Sunday, respectively).
| Apex Clean Energy
A ridge of high pressure settled over Texas last week, funneling hot air from the Western U.S. into the southern Great Plains. The National Weather Service has issued several heat advisories during that time, the latest for all Southeast Texas on Monday calling for heat indexes between 108 and 113 degrees Fahrenheit. Houston hit 100 F for the first time this year on Thursday, and Bayou City, Dallas and San Antonio are expected to stay above 100 into this Wednesday.
ERCOT has been able to meet demand without resorting to the emergency measures it warned it might have to take. The grid operator has an 8.6% reserve margin and 78.9 GW of available capacity. (See ERCOT: More Capacity, but Emergency Ops Still Expected.)
“ERCOT expects to have adequate generation to serve customers during this hot spell,” spokesperson Leslie Sopko said last week. The grid operator survived Monday’s high demand with about 3 GW of operating reserves.
ERCOT has issued heat warnings for the Dallas area that prevent utilities from cutting off power for delinquent bills. Houston utility Reliant Energy asked customers to reduce their electricity usage from 2 to 6 p.m. on both Monday and Tuesday.
Last week, real-time prices peaked systemwide at more than $2,400/MWh on Aug. 5.
Day-ahead power prices for Monday were above $220/MWh in the North hub Friday, the highest since reaching $300/MWh the day before the record peak last July. The hub’s next-day prices were at $38.50/MWh on Aug. 5.
CARMEL, Ind. — MISO’s new Integrated Roadmap format didn’t fare well with members, judging by their comments at a special workshop Friday.
The Integrated Roadmap is a list of market improvements prioritized partly by the Independent Market Monitor’s and stakeholders’ preferences. It replaced MISO’s previous Market Roadmap earlier this year.
MISO expects to complete the prioritization and identify which market improvements it will seek in 2020 by early November, after it melds its ranking with stakeholders’ and the IMM’s.
Multiple stakeholders complained that the new procedure is chaotic and hard to follow, with several asking MISO to explain in detail how it tallies results from stakeholder voting.
This year MISO divided issue voting by which stakeholder committee would work through a possible proposal. The Market Subcommittee had the most projects to rank, while the Planning Advisory Committee and the Reliability Subcommittee had just one issue each.
MISO market strategy team member Christov Churchward, who joined MISO in June when roadmap ideas were already under discussion, led the stakeholder results presentation. Eight market improvement proposals submitted in spring were part of this year’s consideration. (See Steering Committee Advances Roadmap Suggestions.)
Despite the confusion, stakeholders rated a multiday market forecast, interconnection queue streamlining, better modeling of combined cycle generators, changing the process for deploying demand response during capacity emergencies and dynamic transmission line ratings as priorities. MISO’s ongoing resource availability and need project also earned a top spot from stakeholders.
The draft ranking released in spring closely tracked stakeholders’ prioritization, though MISO additionally assigned importance to integrating distributed energy resources and electric storage resources.
The RTO removed the Friday presentation from its public website after the meeting to correct errors. As of Monday, it had not been reposted.
Monitor David Patton has long advocated for temperature-adjusted line ratings in MISO, where most transmission owners do not adjust their facility ratings to reflect ambient temperatures and wind speeds. Patton has said temperature-adjusted ratings could have saved the RTO about $172 million in production costs over 2017 and 2018.
Xcel Energy’s Kari Hassler said it remains difficult to get the roadmap’s “parking lot” projects elevated to any importance. The parking lot — projects on indefinite hold — currently holds about two dozen market improvements deemed low priority.
“They’ve been low priority for several years. I don’t know if they ever get out of the parking lot, or get pushed somewhere else; maybe the basement?”
After a beat: “Oh wait, we’re in the basement,” Hassler laughed, referring to the workshop’s physical location in MISO’s Carmel, Ind., headquarters.
“Lower level!” multiple MISO staffers and stakeholders jokingly corrected her.
Short-term Reserves
Meanwhile, MISO continues to target an end-of-the-year filing to create a short-term reserve product. The RTO expects short-term reserves will clear $4 million in revenue annually when it goes live in 2021. It also estimates an approximate $5 million annual net production benefit when the reserves are used. Part of the savings comes from MISO operators having to take fewer out-of-market actions, for which it must make revenue sufficiency guarantee payments. (See “Short-term Reserve Filing Coming Shortly,” MISO Market Subcommittee Briefs: July 11, 2019.)
Stakeholders have asked if MISO’s savings estimates are based on real generating units and resources, with some asking why the RTO would pin its hopes on a 30-minute product when generators seldom offer through its 10-minute supplemental reserves program. However, Market Design Adviser Bill Peters said he’s spoken to owners of some facilities that can deliver within 30 minutes, but not 10 minutes.
CARMEL, Ind. — The MISO Board of Directors’ Markets Committee agreed to fund the RTO’s share of its seams coordination analysis with SPP and received a briefing on FERC’s call for cold weather reliability standards Thursday.
During a conference call meeting, the committee unanimously approved MISO’s request to pay Potomac Economics $250,000 for its work on the seams project, which the monitoring firm will conduct with the SPP Market Monitoring Unit. The joint analysis will seek to identify issues that may be preventing the RTOs from reaching agreement on an interregional transmission project. (See RSC, OMS Approve Monitors’ Seams Study.)
The first phase of the study — requested by the Organization of MISO States and SPP’s Regional State Committee — will wrap up by the end of 2019.
MISO Independent Market Monitor David Patton told board members he was fairly certain study costs would not exceed $250,000.
“It’s a lot of work, but we’ve taken the time to map out what we’re going to be doing. We have a high degree of confidence” costs will stay within the quarter-million dollars, Patton said.
The study has the potential to become a springboard for several past unaddressed State of the Market recommendations, he said.
“If you remember my recommendations, a lot of them are labeled ‘externally dependent,’ meaning MISO needs cooperation with an outside RTO. I view this as a way to facilitate consensus on [MISO-SPP] issues that have been around for a while,” he said.
Patton also said he expects the report will detail recommendations for MISO and SPP, with descriptions of benefits. It’s also possible that Patton and the SPP MMU may disagree on recommendations, OMS President Daniel Hall said.
“I want to commend the seams committee and OMS and the RSC for bringing up these issues,” Director Trip Doggett said. “This is very timely.”
Cold Snap Revisit
The committee also heard MISO’s perspective on last month’s FERC/NERC report on the arctic front that traveled through MISO South and SPP in January 2018. (See FERC Calls for Cold Weather Reliability Standard.)
MISO Executive Director of System Operations Renuka Chatterjee said a number of challenging conditions, including generator outages, a missed weather forecast and record-shattering load — not just MISO’s Midwest-South transfer flow limit — contributed to the winter emergency.
In prior meetings, MISO staff called the report fair and deemed the recommendations sensible, though they said MISO was still reviewing them. (See “MISO Says Winter Standards Reasonable,” MISO Reliability Subcommittee Briefs: Aug. 1, 2019.)
“When you have a significant event that the temperatures are so far below normal … it becomes the new standard,” Chatterjee said. She said the event, like 2014’s polar vortex, will be used as lessons learned and a new example of extreme operating conditions in planning.
MISO President Clair Moeller said the RTO will pay more attention to “localized weather events” in load forecasting in the future.
“Having lived through the 2011 ERCOTevent, I would say these conditions were exactly what we experienced,” said Dogget, a former ERCOT CEO.
Doggett urged MISO to work with its southern generation owners to make sure equipment is winterized. But he also commended MISO operators on their communication during the event.
MISO will hold a winter readiness workshop with its stakeholders in October. The RTO is also circulating a winterization survey through Sept. 15 among its generation owners to get a better idea of cold weather preparations.
CARMEL, Ind. — For the first time, MISO has found a loss-of-load risk outside of summer months, and the RTO said it may be more evidence of the need for seasonal capacity supplies.
“We believe at least exploring a seasonal resource adequacy construct based on this is appropriate,” MISO planning adviser Davey Lopez said at a Resource Adequacy Subcommittee meeting Wednesday.
However, Lopez said MISO will conduct more analyses, probably through the end of the year, before it says for sure whether it needs seasonal resource accreditation or a seasonal capacity auction.
“We have done some analysis that shows material risk of loss of load outside of summer,” Lopez said at the July Resource Adequacy Subcommittee meeting, referring to six loss-of-load expectation (LOLE) sensitivity case studies MISO had recently completed. Three cases emulating poorly planned generation outages showed risk in September, while two cases assuming no load-modifying resource (LMR) participation in addition to the outages found risk in December, January and February.
MISO’s current LOLE study assumes all outages are ideally planned and LMRs are available outside of summer, when they’re not required.
At the RASC meeting Wednesday, some stakeholders said MISO’s analyses were unconvincing because it assumed the worst possible circumstances when searching for new loss-of-load risk.
Of MISO’s last 10 maximum generation emergency events, Lopez said, only one has occurred in summer. Since 2016, the RTO has not completed a year without a maximum generation warning or event, amassing 10 emergency events and three warnings that didn’t culminate in emergency declarations.
Customized Energy Solutions’ David Sapper asked why MISO only used its current resource mix in the study and did not incorporate projected mixes.
Lopez said MISO would perform more sensitivities with different mixes, some pulled from its ongoing renewable integration impact assessment. (See MISO: Grid Can be Stable at 40% Renewables.)
MISO maximum generation warnings and events | MISO
Capacity Accreditation
To capture its newly discovered risk outside of summer, MISO plans to make changes to its capacity accreditation process.
Lopez said MISO may move to an “available capacity” paradigm instead of installed or unforced capacity measurements. The new measure of a unit’s capacity might involve the use of a historical availability component based on a unit’s prior economic or emergency maximum offers in the real-time markets, or an effective outage rate that includes a unit’s planned and forced outages.
But Lopez also said MISO might forgo a seasonal accreditation if its load-serving entities can show via a retroactive performance evaluation that installed capacity can meet actual load during peak hours. Some stakeholders said the suggestion sounded very similar to PJM’s Capacity Performance rules.
Lopez said MISO will make capacity accreditation changes first to fit the auction’s annual format, then refile its accreditation proposal to fit a seasonal capacity auction, if needed. The RTO’s proposal to implement a seasonal capacity auction has been pushed back to the 2022/23 planning year, as some stakeholders are asking it to create a cost-benefit analysis.
“Anything we do accreditation-wise, we don’t want to unwind if we implement a seasonal auction,” Lopez said.
MISO has said typical operating margins are “comfortable for the majority of daily peak hours but tighten May through September.” The RTO also said most systemwide ramping occurs in the final two hours prior to peak from November through April, when it typically relies more on coal generation to navigate the winter.
“We’ve got declining margins, a changing fleet and an increasing reliance on new supply and load-modifying resources,” MISO CEO John Bear explained during the July Informational Forum. Those changes signal the increasing need for an “availability margin” versus a reserve margin, he said, meaning MISO would take more care to ensure that its reserves are actually on hand when needed.
VALLEY FORGE, Pa. — Electric distributors want PJM transmission owners to reveal more about how they decide when it’s time to replace infrastructure at “the end of its life,” a phrase some stakeholders consider too vague, instead preferring the term “asset management.”
PJM stakeholders clash over how to handle old, obsolete transmission. | NYPA
The war of the words came to a head at Thursday’s Planning Committee meeting when American Municipal Power and Old Dominion Electric Cooperative presented a problem statement and issue charge to draft Operating Agreement language to address their concerns about the amount of information TOs provide during supplemental project decision-making.
“You say you’re willing to share it with the federales and the states,” AMP Vice President of Transmission Ed Tatum said. “There’s no reason you can’t share it with the people who are paying for it — who are the reason you’re doing it.”
TOs said they didn’t object to shining a light onto their analyses, per se, but believe new rules governing increased planning coordination belong in manuals, not the Tariff or OA.
Alex Stern, manager of transmission strategy for Public Service Electric and Gas, presented an alternative problem statement and issue charge. He said using the phrase “asset management” over “end of life” is consistent with acceptable industry terminology and, more importantly, FERC decisions.
“FERC talks about ‘asset management,’ ‘asset activity’ and ‘asset condition’ outside the RTO transmission planning process as opposed to fixed, arbitrary and subjective ‘end of life’ transmission planning criteria dictating replacement,” Stern later told RTO Insider. “It’s about employing reasonable asset management procedures and performing reasonable analysis of asset condition to ascertain whether the asset remains useful.”
Joining PSE&G in sponsoring its alternative was Dayton Power & Light, Exelon and PPL. AMP rejected the TOs’ request that it accept their language as a friendly amendment, leaving the second proposal to stand as its own motion.
The AMP/ODEC posting followed a Monday afternoon special session of the PC that further deepened the chasm between stakeholders over how to prioritize projects in the Regional Transmission Expansion Plan. Some members, led by LS Power, believe PJM should take more authority over supplemental projects — some of which include transmission maintenance and the replacement of end-of-life equipment — currently under the sole purview of TOs. (See Tensions Boil over on PJM’s Supplemental Projects.)
Supplemental projects are those that PJM considers necessary to address local TO reliability concerns that are not required for compliance with grid criteria governing system reliability, operational performance or economic efficiency. The RTO only conducts reliability planning studies to ensure the projects won’t upset the grid’s balance.
John Horstmann, director of RTO affairs for DP&L, said the AMP problem statement also excluded mention of:
Supplemental projects for new customer load or increases to existing loads;
Supplemental projects to treat load-serving entities comparably to incumbent TO retail customers; or
Emergency projects required within one year (confirmed by studies performed or approved by PJM planning staff).
TO staff, in some cases, can also provide insight and expertise on local transmission projects that PJM planners — who view the system through a more regional lens — may not know, Horstmann said. “The reality of it is, the transmission is old and it’s not old in a nice linear fashion,” Horstmann said Thursday, noting that only 30% of the system is less than 40 years old. “There’s a big lump of old stuff out there, and its only getting older. … I kind of think we are not recognizing the elephant in the room to some extent: The stuff is old and is going to need to be replaced.”
“We agree with that. We fully get it,” Tatum said. “We’ve seen the studies done. We are just saying that if you are doing it, show how you’re doing it. We are paying for it, so show us.”
The PC spent nearly an hour debating the truncated timeline of both problem statements appearing on the agenda and AMP’s request for endorsement after a first read. The debate exposed tensions stemming back to manual language — sponsored by AMP and endorsed at the Markets and Reliability Committee in January — that PJM rejected as contrary to FERC rulings. (See PJM Rebuffs Stakeholders on Supplemental Projects.)
PJM’s decision spawned special PC sessions to craft new language targeting the supplemental planning process more generally.
Spending on supplemental projects has tripled over the last 13 years, accounting for 62% of the submitted RTEP project costs since January 2017, according to an analysis from AMP. In 2018, AMP found, TOs added $5.7 billion in supplementals and just $1.5 million in baseline projects into the RTEP.
Tatum said Thursday that TOs have proposed an additional $3.4 billion in supplementals so far in 2019, exceeding the baseline total.
“This is nothing new,” he said of the dispute. “The fact of the matter is, people, we’ve been talking about this a long time, and if there’s no hope under the sun of something being able to move forward, then we need to take that as it is.”
Other stakeholders wondered if the two problem statements could become one — an idea Tatum and ODEC rejected outright.
“This is not a bad problem statement and issue charge; it’s just not what we are talking about,” he said of the TOs’ initiative.
Stern disagreed, saying there is room for collaboration “so long as there is a genuine desire to explore opportunities for consensus.”
“That’s what the stakeholder process is supposed to be targeted at doing,” he said.
Tatum said that if the PC opts against the problem statement, AMP and ODEC will take the document to the MRC. Stern said he felt stakeholders expressed support for continuing the talks at the PC.
“There’s many other ways to get this in front of FERC,” Tatum said. “But in my heart of hearts, I believe the way to really do it is to give the PJM stakeholder community the opportunity to weigh in on it so the commission can have a complete record. And that is via the MRC and [Members Committee] on Operating Agreement language.”
CARMEL, Ind. — MISO and its Independent Market Monitor are making several changes to market mitigation procedures — most of which will increase the Monitor’s authority to invoke mitigation and issue penalties.
At the Monitor’s behest, MISO has agreed to refine Tariff language that only revokes make-whole payment eligibility when a market participant has been “determined to be manipulating or gaming” the RTO’s market.
IMM David Patton seeks to have the Tariff clarify that MISO — and the Monitor — aren’t required to “establish the intent of the market participant to manipulate or game” the market in order to rescind eligibility for make-whole payments, but need only identify the participant has been “unduly extracting” payments.
MISO will also more strictly monitor generation shift factor (GSF) cutoffs for lower-voltage constraints that tend to have fewer competing suppliers. While the IMM will continue to monitor resources with a GSF of 6% or higher for areas at or above 345 kV, the GSF cutoff will drop to 4% for areas between 138 and 345 kV and even to 3% for areas at or below 138 kV.
Entergy representatives questioned whether the lower GSF cutoffs would lead to over-mitigation of generators.
“This just identifies more appropriate resources to be screened,” MISO Director of Market Design Kevin Vannoy said during a Market Subcommittee meeting Thursday.
Patton also said he’d like to remedy a “flaw” in MISO’s Tariff where non-capacity resources are excluded from physical withholding mitigation even if they have market power.
He said the rule should not be considered an extension of MISO’s must-offer rule, which he doesn’t believe is strong enough anyway.
“If MISO were to propose to eliminate the must-offer, I wouldn’t fall on my sword to save it. I believe in markets, that prices should motivate people to want to offer,” Patton said at the Market Subcommittee meeting in July.
Patton said the expansion of physical withholding penalties would apply only in “clearly” uneconomic behavior from units. Suppliers without market power will not be beholden to the new rule and are not under an obligation to offer, he said.
The Monitor also wants to raise the threshold for determining impacts to market clearing prices from $10/MWh to $50/MWh.
“The $50 impact threshold is just much too high,” Patton said.
Most ancillary service products price below $10/MWh anyway, Patton added, with market clearing prices generally ranging from $1 to $15/MWh.
Patton said he doesn’t expect the $50 threshold to result in more mitigation; rather, the change serves to close a rule gap.
MISO intends to file the bundle of changes with FERC later this month or in September.
If you’re a regular with RTO Insider, Greentech Media and the like, you’ve likely read the accusation that PJM is screwing batteries (motive a mystery).1
Here’s the backstory. PJM has a capacity market that basically requires that a generator or equivalent resource be “on call” 24 hours a day throughout the year. This Capacity Performance construct arose after the 2014 polar vortex, when it turns out a lot of generators were getting paid for capacity that wasn’t actually available when needed.
So CP basically says you as a generator must be available 8,760 hours a year unless you’ve been preapproved for doing maintenance or refueling. FERC in 2015 found this just and reasonable “because it creates the same expectations for all Capacity Performance resources (i.e., the expectation that such resources will be available to provide energy and reserves when called upon), without regard to technology type.”2
The Big Gift Horse
Flash forward to late last year when, in a big gift horse to the battery industry, PJM proposed that batteries only must provide capacity 10 hours a day, giving them a pass on the other 14 hours in a day. In other words, batteries would have to provide capacity for less than half the time as other dispatchable resources.
Now, the battery industry didn’t take this big gift horse lying down.
No. Instead it argues that somehow PJM screwed it.
Its arguments to FERC are all over the map, but the driver is that batteries don’t make economic sense unless you require an even smaller supply/discharge obligation like four to six hours. Of course, the economics of a resource should have nothing to do with its value as a resource.3
The Latest Salvo
The battery industry’s latest salvo is a study by its consultant purporting to show that there could be up to 4,000 MW of batteries in PJM providing only four hours a day of capacity without reducing overall system reliability.4
Assuming the study is valid now and for the future, the obvious question is “so what?”
Why should only batteries get the privilege of having to provide capacity for just four hours a day and be excused from the other 20? Every generator in PJM would like to get that same privilege and avoid capacity commitment for 20 hours. It would be the height of discrimination to award that privilege to only one technology such as batteries.
By the way, the battery industry says that four hours are what batteries are “technically capable of,” invoking that phrase from FERC Order 841. Of course, batteries also are “technically capable of” a 10-hour duration, as well as a one-hour duration and, frankly, a one-minute duration.
So, should a 10-MWh battery set up to discharge in one minute be given a capacity rating of 600 MW? Nonsense.
More Problems
The problems with batteries go beyond the minimum number of commitment hours. We need to remember that this minimum is a calculation based on maximum output over the period. Maximum output assumes the battery is fully charged when emergency conditions begin.
This is an unrealistic assumption. The economics of a battery are based in part on multiple revenue sources (aka “value stacking”). If used for energy arbitrage, the battery is charging when its operator thinks prices are relatively low and discharging when its operator thinks prices are relatively high. If used for frequency regulation, the battery is charging or discharging in response to the signal (and it can never be fully charged, or it couldn’t charge in response to the signal).
The upshot of this is that a battery is seldom “full,” meaning it’s able to provide its committed capacity when called upon. So at any given time, it’s unlikely to provide its committed capacity for the supposedly committed hours.
The problem is likely to be acute during peak periods when energy prices are relatively high. Battery owners will be looking to discharge during the peak afternoon hours. And they’ll all be doing the same thing at the same time.
So if there’s an emergency later in the day, not just one battery but all of them will have no or little charge left. And if they start charging during that emergency, they will make matters worse by appearing on the system as more load to be served.
Where does that electricity come from? Cue the pixie dust.
And here’s another problem. Battery advocates assume that over any 24-hour period, batteries can recharge to be prepared for the next day. And in a 100% renewable scenario, they necessarily assume that there are solar and wind renewable resources available to do that day after day as needed.
This is another unrealistic assumption. There are prolonged periods of little solar and wind generation. Last summer in PJM for example, for more than three weeks, there was relatively little solar and wind generation. Solar and wind generation averaged about 10% of their combined nameplate capacity of 9,694 MW.5 This chart shows the hourly generation:
For more than three weeks last summer, PJM’s solar and wind generation averaged only 10% of their combined nameplate capacity of 9,694 MW. | PJM
Absent traditional resources, where does the generation come from to charge batteries every day? Cue more pixie dust.
Hawaiian Punch
We got a little taste of the problems from Hawaii last month. Here’s the headline:6
“Island-wide outage on Kaua’i: Clouds block solar recovery after generator’s cable failure”
Basically, with clouds blocking the sun, the Kaua’i Island Utility Cooperative had to rely on its battery systems, but doing that discharged the batteries in the afternoon, so they weren’t available in the evening, when of course solar generation wasn’t available either. Rolling blackouts were necessary.
This is not to knock the cooperative, but rather to show that increasing reliance on renewable resources and batteries presents new challenges.
Media Fantasies
Misleading information is rampant in the media. Just yesterday, The Wall Street Journal ran a story “Giant Batteries Boost Wind and Solar Plans,” including a statement that the utility ScottishPower generates “all of its power from renewable sources after selling its last fossil fuel assets in January.” The implication is that this utility is reliably serving its customers exclusively with renewable sources.
The reality is that ScottishPower’s generation unit has sold off non-renewable assets. ScottishPower continues to serve its retail customers by purchasing capacity and energy from others. For example, in the referenced January asset sale, ScottishPower is purchasing natural gas capacity back from the asset buyer.7 The last reported fuel mix for ScottishPower’s retail sales shows that 73% of its supply is coal and natural gas, 10% is nuclear and only 15% is renewable.8
A Dose of Reality from MIT
NPR recently ran an interview with Yet-Ming Chiang, professor of materials science and engineering at MIT, who founded several battery companies. This part of the interview is especially instructive:9
“SHAPIRO [NPR]: I know the cost [of batteries] has been prohibitive for a long time, and it’s been coming down recently. When do you think this technology will actually be reasonably affordable in a lot of places?
CHIANG: Yes, I think the answer to that question really depends on what the variability in the electricity generation is that we need to cover. Is it just a few hours of the day, for instance in Arizona, or is it a few days or up to a week, right? Today, an electric vehicle battery pack using lithium-ion batteries costs us about $200/kWh. Over time, we can see that dropping to 100 or somewhat less than that.
But with lithium-ion batteries, it’s difficult for me to imagine the cost getting down to, let’s say $10 or $20/kWh. It turns out that’s the price range we need for storing electricity for the grid over several days. And in order to accomplish that, we really need to look at other battery materials other than lithium-ion batteries.”
So the key takeaway, from this MIT battery expert, is that we don’t know, at present, how to economically and reliably replace traditional resources.
The Answer isn’t Special Treatment
The answer isn’t to give batteries a pass on reliability criteria because they facilitate green energy. Support for green energy ends when blackouts begin. That’s when the torches and pitchforks come out.
VALLEY FORGE, Pa. — PJM staff told the Market Implementation Committee on Wednesday that they will not file waivers for upcoming capacity auction deadlines and will instead rely on FERC to issue an order on its minimum offer price rule (MOPR) before the end of the year.
Pat Bruno, senior engineer for PJM’s capacity market operations, said it’s unlikely the commission would respond in time even if staff submitted a waiver for the upcoming Sept. 1 deadline in the 2023/24 Base Residual Auction. The next round of deadlines comes in December, he said, at which point FERC will have “hopefully” issued a ruling.
Last month, FERC halted the 2022/23 capacity auction scheduled for this month, refusing to “rule prematurely” on PJM’s request for clarification that if it ran the BRA using the existing MOPR that the commission would also agree to enforce any new rates prospectively, saving the auction from being rerun (EL16-49).
The last-minute directive from FERC came just hours after PJM staff told the Markets and Reliability Committee they would move ahead with the auction as planned. The RTO confirmed it would comply with FERC’s guidance — though it was the commissioners themselves who expressed frustration about their role in creating market uncertainty for participants. (See FERC Halts PJM Capacity Auction.)
‘Winter is Coming’ … Along with Gas Contingency Plan (Hopefully)
Thomas DeVita, senior counsel for PJM, told stakeholders that staff are preparing to file a revised gas contingency proposal with FERC by October, with hopes that the commission will give its approval by December.
“Winter is coming,” he warned repeatedly, reiterating stakeholder concerns about surviving a third cold weather season without a cost recovery plan for generators forced to switch fuel supplies at PJM’s discretion.
On Feb. 19, FERC rejected the member-approved mechanism that would have implemented a process for market sellers seeking cost recovery for certain gas contingencies associated with the RTO’s instruction to temporarily switch to an alternative fuel or fuel source because of pipeline breaks or the loss of compressor stations (ER19-664). The proposal included nine categories of switching costs, such as park-and-loan service charges and overrun charges. (See FERC Rejects PJM’s Gas Pipeline Contingency Proposal.) The commission also argued that the conditions for switching belong in the Tariff — not just business manuals — and gave PJM a chance to revise the proposal over the spring and summer.
DeVita said FERC staff dropped some hints about how to tweak the filing for better success the second time around. (See PJM Revisits Gas Pipeline Contingency Plan.) He said staff discouraged the RTO from submitting an itemized list of switching costs, as it did in the first filing, and instead focused on procedures surrounding “explicit authorization” to switch between pipelines and any new limitations on the amount of gas burned after the switch occurs.
In the draft language presented Wednesday, staff added “pre- or post-contingency” into the switching process triggered by a manual load dump and removed a requirement that generators must have documentation of unauthorized switching costs before filing for cost recovery at FERC. A reference to opt-in and opt-out intraday offers was also removed.
Staff also added the following paragraph to the proposal, meant to ease members’ concerns about the vague definition of switching costs: “PJM will commit to analyze, assess and address through a stakeholder process whether adequate compensation exists for any future operating instructions associated with gas switching that fall outside of the criteria established in this Tariff filing. Such analysis will also consider the mechanisms through which such compensation shall be obtained.”
Independent Market Monitor Joe Bowring asked DeVita whether PJM’s proposed language would permit companies to include the cost of penalty gas in their offers and therefore charge customers for the much higher cost of power that would result. Bowring pointed out that if the pipeline approved the use of the gas, it should not be treated as penalty gas. PJM indicated that the issue needed to be clarified.
Bowring also noted that the gas contingency procedures did not have a clear requirement that PJM take other emergency actions prior to the contingency, including calling on demand-side resources.
DeVita said the language is on track for endorsement at the September MIC and MRC meetings, with filing scheduled for Oct. 15.
Opportunity Cost Calculator Vote Delayed
Stakeholders delayed votes on several options for a more unified opportunity cost calculator after confusion over the implications of proposed changes left many unsure of how to move forward — if at all.
Bob O’Connell, executive director of regulatory affairs and compliance for Panda Power Funds, sponsored a motion to vote on three packages, drafted in consultation with Dominion Energy, that would streamline PJM’s calculator to varying degrees. (See PJM Stakeholders Push Unified Opportunity Cost Calculator.)
During a first read of the plans last month, O’Connell said the first package makes small changes that don’t force PJM to rewrite its calculator. The second revises PJM’s modeling process to mimic the Monitor’s, which many stakeholders prefer for its reliability. The third consolidates the former package into one single calculator, “eliminating all compliance risk,” O’Connell said.
Under current procedure, market participants can either use PJM’s calculator in Markets Gateway or the Monitor’s modeling system to build energy cost offers with appropriate adders that help ensure a generator will recoup opportunity costs when its resources have limited run hours for environmental reasons and are scheduled outside of their most economic operating intervals. Some of these opportunity costs arise when regulatory agencies impose environmental run-hour restrictions, physical equipment limitations trigger operational restrictions and force majeure events constrain access to fuel.
The problem for O’Connell and other stakeholders, however, is the riskiness associated with PJM’s calculator, which is designed to give market participants more control over submitted data and, therefore, more opportunity for operator error. PJM staff said the majority of stakeholders — perhaps up to 98% — use the Monitor’s calculator already, with just two choosing to use the RTO’s within the last year.
“When I look at the Market Monitor’s calculator, I view that as very little compliance risk,” O’Connell said. “The only issues we have are — are we being honest and forthright with the information we provide to the Market Monitor, and did we copy and paste correctly? From my [compliance] perspective, something like the IMM’s calculator is preferable.”
Glen Boyle, manager in PJM operations analysis and compliance, pushed back against the simplified explanation of the Panda/Dominion proposals, noting that the calculator changes being suggested raise “serious concerns” — including those that would set aside hours from the performance assessment interval.
“There’s already a process in [PJM Manual 13] where if you start to run out hours, you can put those remaining into max emergency,” he said. “FERC was very clear in its order on opportunity costs. Only things related to environmental, insurance carrier and [original equipment manufacturing] should be in the calculator. We agree with that, and some of these things shouldn’t be included.”
O’Connell said the changes deserved further consideration.
“If you look at the situation right now, there’s sort of a disconnect between actions a company takes to put a resource into max emergency versus assumptions that are made in the capacity market,” he said. “This serves to link them more closely. … [It’s] an expectation [of] how market participants should behave with respect to a decision that they are getting down to too few hours. Really, the status quo lacks that linkage.”
He did, however, agree that the goal of “getting to one calculator” took priority over approving changes and agreed to drop those elements from the third proposal in the interest of moving forward — prompting Bowring to question the necessity of voting on a plan that appears to require PJM to make its calculator mirror the Monitor’s.
“If the point is to force PJM to create a calculator exactly like ours, then I believe that’s a demonstrable waste of time and money,” he said. “It seems to me you have what you want here.”
O’Connell agreed that there was no reason to force PJM to spend money to modify their calculator and that the Monitor’s calculator addressed the requirements of members.
MIC Chair Lisa Morelli suggested delaying the votes until the September meeting so that stakeholders could take more time to review the changes contained within.
Modeling Units with Stability Limitations
Stakeholders unanimously endorsed a problem statement and issue charge from Panda that address concerns over proposed revisions to Manual 10 that would require generators to use outage tickets for stability-related limitations, possibly encouraging price distortion. (See “Generation Outage Revisions Delayed,” PJM OC Briefs: May 14, 2019.)
O’Connell told the MIC last month that PJM’s decision to remove supply from the market to address stability constraints will result in some units committing at price-based offers, rather than cost. (See “Modeling Units with Stability Limitations,” PJM MRC Briefs: July 10, 2019.) Under the RTO’s rules, only the affected generator would know of the constraint, O’Connell said, therefore gaining a competitive advantage over other units and possibly incorporating greater mark-ups into their offers.
As a solution, O’Connell suggested PJM implement a closed-loop interface around the affected resource that restricts the output to below the stated stability limit — and that it must be used in each of the RTO’s markets. He also encouraged PJM to publicize stability limits on OASIS prior to contacting the affected generator.
The MIC will work on possible solutions during the committee’s meetings over the next few months.
Price Formation
The MIC continues its review of how prices are formed every five minutes in PJM based on a problem statement and issue charge created by the Monitor and approved by the MIC in June.
Catherine Tyler of IMM Monitoring Analytics provided education on the relationship between the megawatt dispatch and price signals sent to generators by PJM systems for each five-minute interval. Tyler explained that the signals should be for the same point in time but are not. She said the practice is inconsistent with basic economic logic and creates incentive issues for generating units that are given price signals inconsistent with dispatch signals and are paid in a manner that does not match their dispatch instructions. This is the case for both energy and reserves.
Manual Revisions Endorsed
The MIC endorsed the following revisions to PJM manuals:
Manual 11 (Energy & Ancillary Services Market Operations): Revisions will document procedures for addressing missing historical performance scores in the regulation market and also clarify that the reserve requirements used in the market clearing process are based on the potential largest single contingencies that are communicated by PJM operations and modeled in the markets clearing software. Scheduled for MRC first read later this month and endorsement in September.
Manual 18B (Energy Efficiency Management & Verification): Updates to conform with Tariff revisions that detail energy efficiency rules issued by authorized relevant electric retail regulatory authorities and those dealing with seasonal capacity resources.
Manual 27 (Open Access Transmission Tariff Accounting and Manual 28 – Operating Agreement Accounting): Revisions include language to comply with electric storage participation mandates from FERC Order 841-A.
VALLEY FORGE, Pa. — PJM staff on Thursday unveiled to the Planning Committee a proposed new fee structure for a more involved cost-containment process.
The proposal suggests charging a $5,000 nonrefundable flat fee to all developers who submit competitive projects. Itemized study costs will be added as necessary. Mark Sims, PJM’s manager of infrastructure coordination, said the intent is to bill projects that incur the extra expense. Late payment and nonpayment conditions have yet to be determined.
Sims previously told the PC that PJM’s old tiered approach, approved in 2014, doesn’t account for the increased cost of the new comparison framework that involves an independent consultant’s review and legal and financial analyses. (See “New Fee Structure for Cost Containment Needed,” PJM PC/TEAC Briefs: June 13, 2019.)
Sims said PJM will host a special PC workshop on Aug. 29 to discuss this structure in more detail, which will eventually be added to Manual 14F.
Cost Allocation Dispute Leaves Tariff Changes in Limbo
PJM staff said required Tariff changes covering cost allocation for transmission projects remain in limbo as the RTO waits on FERC to respond to a motion to address a remand related to the issue.
Pauline Foley, PJM’s associate general counsel, said transmission owners made the motion after the D.C. Circuit Court of Appeals “set aside” a 2016 FERC ruling that allowed transmission projects driven by local planning criteria to be exempt from competitive bidding. (See FERC Sides with Incumbent TOs; OKs Limits on Competition.)
On clarification, the court, citing its original opinion, said it held “‘only that FERC did not adequately justify its approval of the [Tariff] amendment at issue.’ Nothing in the opinion prevents FERC on remand from attempting to ‘provide a better justification for its approval of the Tariff amendment.’”
Petitioners Old Dominion Electric Cooperative and Dominion Energy filed motions for an order on remand arguing that the court’s decisions leave no doubt that the 50/50 cost allocation for regional facilities is in effect pending further action by FERC. LS Power commented that it is appropriate for the commission to bring the matter to an end.
FirstEnergy, Dominion Solutions
Dominion proposed the following solutions for several proposed supplemental projects in Virginia:
Cut an existing 230-kV line between Roundtable and Buttermilk substations. Construct a 1.8-mile, 230-kV loop to Lockridge substation. At Lockridge, install four 230-kV breakers to terminate the two lines. Install two 230-kV circuit switchers and any necessary high-side switches and bus work for two initial transformers (five ultimate). Cost estimate is $35 million and in-service date is July 31, 2022.
Install a 1,200-amp, 50-kAIC circuit switcher and associated equipment (bus, switches, relaying, etc.) to feed the new transformer from the existing 230-kV bus No. 5 at Beaumeade. Cost estimate is $750,000, and in-service date is March 31, 2020.
Re-conductor Cochran Mill-Ashburn 230-kV and Ashburn-Beaumeade 230-kV line segments using a higher capacity conductor, as well as upgrade the terminal equipment to achieve a rating of 1,572 MVA. Cost is $15 million and in-service date is June 1, 2023.
FirstEnergy solutions for Pennsylvania projects include:
Replace line trap and substation conductor at the Shawville 230-kV substation and replace line relaying, line trap and substation conductor at the Shingletown 230-kV substation. Cost is estimated at $900,000 with an in-service date of Dec. 1, 2020.
Replace line relaying, line trap and substation conductor at Elko-Shawville 230-kV Line 546/666 and Elko 230-kV substation. Replace line relaying and line trap at Shawville 230-kV substation. Estimated cost $1.3 million, with an in-service date of June 15, 2020.
Replace the Homer City North 345/230/23-kV transformer and associated equipment with 345/230/23-kV, 336/448/560-MVA transformer. Estimated cost is $6.6 million, and in-service date is Dec. 31, 2021.
Rebuild and reconductor approximately 33 miles of wood pole construction for the Armstrong-Homer City 345-kV line. Estimated cost of $138 million and in-service date of Dec. 31, 2023.
The Texas Public Utility Commission last week asked for more information on eight small municipal utilities’ appeal of ERCOT’s definition of transmission operator (TO) (48366).
The PUC directed the State Office of Administrative Hearings to return ERCOT’s order to the commission so that it could solicit feedback from stakeholders in a docket. Given legal briefs and other information, the commission would then be able to dismiss the ruling and open a rulemaking or project.
PUC staffer Stephen Journeay offers advice to the commission.
The Small Public Power Group (SPPG) — composed of utilities for the cities of Bartlett, Bridgeport, Farmersville, Goldsmith, Hearne, Robstown, Sanger and Seymour — is appealing the ERCOT Board of Directors’ 2018 rejection of a proposed change to the Nodal Operating Guide (NOGRR149).
“We will, of course, provide comments on the questions the commission [poses] and look forward to the discussion that follows,” Clark Hill Strasburger’s Tom Anson, legal counsel for SPPG, told RTO Insider.
The NOG requires every transmission or distribution service provider in ERCOT to either register as a TO or designate a representative on its behalf. The TOs communicate with ERCOT during emergency events and the management of load-shed activities, among other responsibilities.
NOGRR149 would have exempted municipal distribution service providers without transmission or generation facilities from having to procure designated TO services from a third-party provider if their annual peak load is less than 25 MW. SPPG developed the revision request in 2015 to settle the noncompliant status of six municipally owned utilities with loads of 9 to 21 MW. Goldsmith and Bartlett joined the proceeding later. The Technical Advisory Committee and its Reliability and Operations Subcommittee also rejected the change. (See “Small Public Power Group’s Appeal Again Meets Defeat,” ERCOT Board of Directors Briefs: April 10, 2018.)
Transmission and distribution operators AEP Texas and Oncor are the only two intervenors.
“When I looked at the docket and who intervened, I was shocked there were only the two intervenors,” PUC Chair DeAnn Walker said during the commission’s open meeting Thursday. “This has been a hard-fought issue at ERCOT where a lot of people put stakes in the ground, and they’re not putting them here, and I don’t understand why.”
“This commission can operate better in a project when we can hear from all the stakeholders and ask them questions,” Commissioner Arthur D’Andrea said during the commission’s debate over how to proceed.
The SPPG says its proposal would conform operating guides to the “existing factual situation.” None of the SPPG members is or ever has been in the ERCOT load-shed table, the group said, and the revision would not “in any way, affect the reliability of the ERCOT system.”
“Several SPPG members are so small, they are physically limited in their ability to comply with the relevant ERCOT requirements,” according to the group’s filing.
ERCOT has asked that the PUC deny the appeal because SPPG “has not demonstrated any legal basis for reversing the [board’s] decision to reject NOGRR149” and because it has not alleged “any credible violation of law.”
Walker said she wanted to ensure the commission was protecting its oversight of ERCOT.
“There are policy decisions made at the ERCOT board we don’t agree with. I believe we still have the authority to set that policy and the obligation to set that policy,” she said. “I don’t want to take away our oversight of those policy decisions.”
Walker Warns SPP Recs Could Raise Tx Costs
Walker briefed D’Andrea and Commissioner Shelly Botkin on the SPP Regional State Committee’s recent discussions and disagreements over the Holistic Integrated Tariff Team’s (HITT) recommendations. The RTO’s Board of Directors approved the 21 recommendations, despite some minor pushback. (See SPP Board Approves HITT’s Recommendation.)
Calling the conversations at the RSC “a whole lot of mess,” Walker said the three recommendations assigned to the committee will affect Texas because of changes to cost-allocation methodologies. The committee has until next July to:
propose how to decouple two transmission pricing zones under SPP’s Tariff, creating new, larger zones in one, and smaller sub-zones in the other;
evaluate the byway facility cost-allocation review process; and
charter a study of the generator injection rate (based on energy produced by resources without network or point-to-point service).
“While most of the utilities here [in Texas] support the decoupling, how those zones would [be] set up is important,” said Walker, the lone RSC member to vote against the HITT proposals. “Almost every recommendation I have seen has Texas paying more.”
Noting the HITT study was pushed by utilities in wind-rich areas concerned that their transmission spending was benefiting customers elsewhere, Walker said, “We’re not wind rich. We’re just under wind rich.”
“My concern is we end up at the end of the day with everyone else getting what they wanted and us needing to make a fight at FERC,” she said.
D’Andrea, who sits on Organization of MISO States’ board of directors, said some of the same discussions are being held there. OMS is currently working on long-term transmission planning principles, he said. “That conversation is almost impossible to have without cost allocation,” D’Andrea said.
SPS to Refund $14.5M in Fuel Costs
The PUC signed off on Southwestern Public Service’s request to refund its Texas retail customers $14.5 million for over-collected fuel costs from January 2016 through May 2018. SPS reached a unanimous settlement with commission staff, Texas Industrial Energy Consumers (TIEC) and the Alliance of Xcel Municipalities (AXM) (48718).
SPS has a separate docket before the PUC, in which it has asked permission to replace its two seasonal formulas used to determine its fuel factors with a single formula (49616).
The company said the move is necessary because its new 478-MW Hale Wind Project has changed its resource mix and because SPP’s market has affected its system-average fuel and purchased power costs. The new formula will ensure the wind facility’s benefits are passed on to customers “timely,” SPS said.
TIEC, AXM and the Office of Public Utility Counsel have intervened in the proceeding.
Residential customers will see about a 3.25% increase on their bill from June through September, or about $3.73/month for those using 1,000 kWh/month of electricity, the company said.
Broker Registration Forms OK’d
The commission approved electric broker registration forms to comply with Senate Bill 1497, which requires representatives paid for brokerage services to register with the state (49711).
The bill goes into effect Sept. 1. The PUC will maintain a list of registered brokers on its website.
Thoughts, Prayers for El Paso Victims
Chair DeAnn Walker shares the PUC’s thoughts and prayers for El Paso Electric employees affected by the Aug. 3 mass shooting.
Walker opened the meeting by extending thoughts and prayers on behalf of the commission to three El Paso Electric employees who she said had family involved in the city’s deadly Aug. 3 shooting. She said one of the employees lost their mother.
