DES MOINES, Iowa — The Mid-America Regulatory Conference (MARC) opened Monday with a study in local Iowa flavor and a grab bag of industry opinions gleaned from a round of questions styled after political interrogations in the spirit of state’s caucus activity.
Katie Greenstein, a chemist with Des Moines Water Works, opened the conference with a trumpet rendition of the national anthem.
“Fun fact about Iowa: We have more pigs than people,” Iowa Utilities Board Member Nick Wagner said in a welcome speech.
In lieu of speaker gifts, the event boasted corn kernel voting for four Iowa charities, similar to the Iowa State Fair’s famous polling for primary candidates. Wagner said all the charities would receive some level of donation.
Des Moines Mayor Frank Cownie regaled attendees with Saturday scenes from the fair, which not only boasted several presidential candidates but also Des Moines heavy-metal band Slipknot, along with their fan base, dubbed the “maggots.”
MARC also named Michigan Public Service Commissioner Dan Scripps its new president during the opening.
Lightning Round
With thunderstorms passing over the State Capitol, the first session of the conference was — aptly enough — a “lightning round,” in which Arkansas Public Service Commission Chairman Ted Thomas fired rapid questions at 14 industry players.
SPP General Counsel Paul Suskie fielded the first question, responding that, yes, the U.S. needs a singular energy policy, instead of a patchwork of subsidies. Suskie, a veteran of the wars in both Iraq and Afghanistan, also said national energy policy should consider the effects on other countries, referring specifically to oil impacts in the Middle East.
“I don’t know where those numbers are coming from,” Susan Williams Sloan, vice president of state affairs for the American Wind Energy Association, said in challenging an assertion by American Coalition for Clean Coal Electricity CEO Michelle Bloodworth that coal generation remains cheaper than bringing new wind resources online.
After that, Thomas jokingly asked panelists to cite research, if they could, within the time constraints.
Former FERC Commissioner Colette Honorable, now a partner with law firm Reed Smith, used her brief time to praise co-located resources — combinations of electric storage with either solar or wind generation — for its job-creating potential. However, she later noted she thought the industry was taking nuclear generation for granted for its reliability and zero-carbon attributes.
MidAmerican Energy CEO Adam Wright pointed out that his company raised rates one time in Iowa in 1999 and didn’t plan to raise rates again until about 2030, owing to steady coal and natural gas generation.
Wright also stressed the pressing need for cybersecurity, saying much of the onus was on employee vigilance because humans remain “surprisingly fallible.”
“We have employees pull an email out of the quarantine [folder] — and it’s got a warning on it — open it, say ‘OK’ to giving their passwords … and then they call the security desk to ask about [the email]. And they’re told, no, don’t do that, and the employee hangs up,” Wright said. “It’s insanity.”
He added that while it would be great if regulators greenlit cost recovery for utility cybersecurity, it remains a company responsibility to keep systems safe.
Thomas pivoted: “How about Order 1000? Is it working?”
“No,” ITC Senior Vice President Krista Tanner replied. “It’s created another level of bureaucracy and created hinderances where none existed before.”
Suskie also thought the promises of Order 1000 remain largely unfulfilled.
“We had one competitive project. … It went to the incumbent. The competitive component of competition is not working,” he said, also pointing to the litigation surrounding Texas’ recently passed right-of-first-refusal law and MISO’s Hartburg-Sabine project in that state. (See NextEra Takes Texas to Court over ROFR Law.)
When talk turned to China’s ever-increasing coal production, Honorable said the U.S. shouldn’t take that as permission to continue its own coal use.
“We can’t just say, ‘Oh they’re horrible, so we can be a little bad,’” Honorable said, adding that she was glad to see stepped-up carbon-reduction pledges from companies following the Trump administration’s withdrawal from the Paris Agreement on climate change.
New England utility regulators have gained a key ally in their call for an initiative to explore how the region’s wholesale energy market could be reshaped to accommodate the growth of state-sponsored resources.
The New England States Committee on Electricity (NESCOE) last month askedISO-NE to “dedicate market development and planning resources” next year to support states and stakeholders “in analyzing and discussing potential future market frameworks” compatible with the state energy and environmental laws that could alter the region’s resource mix.
The New England Power Generators Association (NEPGA) wholeheartedly agrees. In a letter to ISO-NE Tuesday, NEPGA President Dan Dolan said his group “strongly supports” NESCOE’s request to kick off the discussion and emphasized “the need to ensure that the future wholesale electricity market design preserves electric reliability, resource adequacy and other needed services in a robust competitive, market-based manner.”
NESCOE’s July memo noted New England adopted a wholesale market in the 1990s to ensure “market dynamics rather than regulatory orders” set electricity prices and to shift the risks of generation investment decisions from ratepayers to investors.
But the energy landscape has shifted drastically since then, with New England states boosting their renewable portfolio standards and mandating large solicitations of offshore wind. As a result, state-sponsored resources are expected to comprise more than half the generation participating in the ISO-NE market by 2027.
State-sponsored resources are expected to represent more than half the generation participating in the ISO-NE market by 2027. | NEPGA
NESCOE said the increasing reliance on resource procurements outside the ISO-NE market “make a conversation about the objectives of the wholesale markets, and what we are collectively asking it to do, sensible.”
NEPGA’s Aug. 13 letter says NESCOE’s request is similar to one NEPGA made last December, when it warned the RTO’s board of directors the region is “fast approaching a tipping point” as an increasing volume of state policy resources participating in the wholesale market leave competitive generators unable to recover their costs, putting them at risk of early retirement and forcing ISO-NE to rely on out-of-market mechanisms to keep vital resources online. (See FERC Approves Mystic Cost-of-Service Agreement.)
NEPGA said it was “unconvinced” by the board’s response to its letter: that ISO-NE would address the group’s concerns through its ongoing “energy security improvements” effort. (See ISO-NE Filing, Whitepaper Address Energy Security.)
“With the benefit of several months review of the ISO proposals and in light of the intention that such revenues would be considered a reduction to de-list bid offers, NEPGA remains unconvinced that [the energy security efforts] address the fundamental concerns of a lack of future competitive revenue opportunities for resources that provide reliability services,” Dolan said in the letter.
NEPGA suggested any discussions on market changes take place within the New England Power Pool (NEPOOL) committee process, which “would provide an important measure of structure and diligence to these efforts which, given their likely complexity, will require deliberate and long-term discussions and consideration in order to be fruitful.”
Dolan said the NEPOOL process would also foster “meaningful engagement on the paramount question of how to preserve and reinforce competitively produced reliability services in the region.”
The generator group said it agrees with NESCOE that initial meetings should be devoted to “certain threshold questions,” including “an agreement as to the scope of future efforts related to potential improvement to existing markets or even consideration of new competitive market designs.” NEPGA said it believes any problem statement should focus on maintaining ISO-NE’s “core function” of using competitive markets to ensure reliability and resource adequacy
“Articulation of this ‘problem statement’ is critical to the commitment to priority use of ISO-NE and stakeholder resources for these purposes,” Dolan said. “NEPGA offers that this should be completed prior to embarking on the deliberative process to analyze and discuss potential market design enhancements.”
NEPGA asked that ISO-NE work with NEPOOL and NESCOE to schedule a NEPOOL committee meeting in early 2020, adding that NEPOOL sectors and states should come to the meeting equipped with their own problem statements.
“This is a critical moment for the ISO, states & all invested stakeholders in New England to chart the path forward in a dramatically changing market. Just as NEPGA said nearly a year ago, if we’re going to have agency in our future, we must act — quickly!” NEPGA tweeted Wednesday.
SPP and MISO will hold a conference call Aug. 19 to discuss their interregional process and joint projects — of which there are currently none.
The RTOs’ staffs have already shared potential interregional solutions in their coordinated system plan study, having shortlisted seven projects, none of which have met the 5% minimum benefit threshold for each grid operator.
“But that’s not indicative that the process is flawed,” Adam Bell, the RTO’s interregional coordinator, told the Seams Steering Committee on Wednesday. “We would have ended up in the same place where we are now [with the previous process], after months and months of work to build the joint model.”
SPP and MISO have yet to agree on any interregional projects across their shared seam. | SPP
SPP and MISO have replaced the cumbersome joint model process by instead using their regional processes. Their inability to agree on a single joint project in three attempts has drawn increasing attention from state regulators in their areas. (See MISO-SPP Interregional Process Scrutinized at MARC.)
Bell said Monday’s Interregional Planning Stakeholder Advisory Committee call with MISO will not be without its benefits.
“We’ll have a discussion with MISO in the room about where it makes sense to go from here,” he said.
MISO Earns Positive M2M Settlement
Staff’s market-to-market (M2M) settlement report for June indicated MISO incurred nearly $2.4 million in payments from SPP, the ISO’s first positive month since last October.
June M2M Update | SPP
M2M payments typically flow in MISO’s favor during the summer months. Still, SPP has racked up $63.7 million in distributions since the two seams neighbors began the process in March 2015.
Temporary flowgates accounted for most of the M2M settlements, binding for 675 hours. That resulted in $2.3 million in settlements from SPP to MISO.
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 price offer 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.
