Page 1349 – RTO Insider

July 24, 2018October 31, 2023

Massachusetts Seeks Input on Energy Plans

By Michael Kuser

WESTFIELD, Mass. — Massachusetts officials last week held three hearings across the state to get public input ahead of a September release of the statutorily mandated Comprehensive Energy Plan (CEP).

The state’s Department of Energy Resources is preparing the plan to project the state’s 2030 energy demands for electricity, transportation and thermal conditioning and help it meet its greenhouse gas emissions targets. The state’s Global Warming Solutions Act (GWSA) requires a 25% reduction in emissions by 2020 from the 1990 baseline and an 80% reduction by 2050.

The state accounts for 45% of electricity demand in New England.

Morin | © RTO Insider

“This report is really looking at supply and demand of energy going forward,” DOER Deputy Commissioner Joanne Morin said on July 19. “The CEP is going to demonstrate the modeling, the impact and required balance in pursuing these goals simultaneously, and looking at different pathways that we could take with our energy future.”

State lawmakers are now considering legislation to increase the state’s renewable energy and reduce high-cost peak demand. Earlier this year, two senators touted a goal to achieve 100% renewable electricity by 2035 and to make the heating and transportation sectors 100% powered by renewables by 2050.

Hopkins | © RTO Insider

Asa Hopkins of Synapse Energy Economics, the DOER’s consultant on the energy plan, sought feedback on its assumptions and analysis of 2030 scenarios.

“Have we got it right or have we got it wrong? Should we be designing these policy features in some different way?” Hopkins asked.

The public has until July 31 to submit comments at the CEP website.

“That’s not much time for public comment,” said Rosemary Wessel, director of “No Fracked Gas in Mass,” a program of the Berkshire Environmental Action Team.

Wessel also complained about what she called a lack of transparency in clean energy data, saying the DOER shows state emissions data only up to 2014. She also said the DOER website “has become much harder to use.”

Several audience members murmured their agreement to the website assessment, and Morin said, “I’ll have to follow up on that.”

Soft or Hard Push?

Hopkins’ study included a status quo scenario and also analyzed the impact of adjusting “key levers,” including efficiency, renewables and electrification via electric vehicles and heat pumps.

Under the status quo or “sustained policies” scenario, renewables would supply 45.5 TWh in 2030, or about 35% of electricity in the region, with Massachusetts hitting its 25% renewable portfolio standard target. Under a “high renewables” scenario, the amount increases to 38% (49 TWh), with all of the increment serving Massachusetts, which would get about half its electricity from Class I renewables in 2030, Hopkins said.

Massachusetts CEP Comprehensive Energy Plan Electrification

2030 electric consumption is projected at 11% above 2018 under aggressive policies leading to high electrification in New England. | Synapse

“We’re looking at electrification, which in the case of electric vehicles, is associated with a substantial increase in efficiency, as it is with heat pumps, so there’s a common thread there,” Hopkins said. “There are distinctly more heat pumps in Massachusetts than there are EVs, but more people consciously see EVs than see heat pumps.”

Because they’re moving heat rather than generating it, heat pumps have efficiencies well over 100%.

“A typical seasonal average in Massachusetts would probably be well over 200%, and for a heat pump water heater it will go up well over 300%,” Hopkins said. A 300% efficient heat pump produces three units of heat for every unit of energy, Hopkins explained.

The “high electrification and high renewables” scenario includes a “clean peak” idea to incentivize generation or energy dispatch to be available to meet winter and summer peaks without emissions.

The scenario for increased efficiency, electrification and renewables would reduce the average commercial building’s heat energy by 25% or more with the state getting 50% of its electricity from renewables, Hopkins said.

Enhancing both electrification and renewables would push wind and solar growth to 33.7 TWh in 2030, while natural gas use would be 29% lower than today.

System demand graph shows results under aggressive policies leading to high electrification in New England. Regional demand increases 13% by 2030 but most of the increase is powered by renewables (+165%). Gas generation drops (-25%). | Synapse

“Once those clean peak resources are there, it’s not like they’re only there on the peak day; they also run all the rest of the time around the year and are impacting what’s going on with dispatch of different resources,” Hopkins said.

Massachusetts has a goal of 300,000 EVs on the road by 2025 and 1.7 million in 2030. Hopkins said the state can probably only reach 160,000 EVs by 2025 under current policies but could exceed its EV goals by enhancing all policy levers.

Several people asked about energy storage and whether EVs can act as batteries for the grid.

“The place where storage makes a difference is on an hourly basis,” Hopkins said. “One learning from this is that what you assume about the load shape of when all those 1.2 million or 1.7 million EVs are charging, it really matters a lot. And what you assume then about when those batteries will charge and discharge really matters a lot.”

If peaks are in the afternoon and you have everyone charge their cars overnight, “you create a giant super-peak at 3 in the morning,” Hopkins said. “That’s probably not the actual path forward, but things we learn there can flow into policy development.”

Solar Woes

Robert Camus, a Granby selectman and member of the town’s energy committee, said that if the state wants to increase solar energy by 50% by 2030, it should change policies to promote local ownership of solar farms.

“The SMART [Solar Massachusetts Renewable Target] program awards Eversource [Energy] and National Grid so much each year, but there’s no differentiating between a private landowner and a municipality,” Camus said. “If the municipality was to have the solar field, versus a private landowner, you’d have a lot more advantages.”

Attendees of one of three public hearings last week on Massachusett’s Comprehensive Energy Plan. | © RTO Insider

If a private landowner makes a deal with a solar developer, the money goes to one individual, he said.

“If you go to the municipality, every taxpayer in that town gets a share of the money, which would decrease the demand of the municipalities on the administration every year for money for schools, infrastructure and everything else,” Camus said. “If the money goes to the taxpayer[s] of Massachusetts rather than to out-of-state developers, we can more enhance our own economic growth, because the money stays.”

He suggested that the SMART program devote 75% of its money to municipalities, leaving 25% for individual landowners.

Morin directed Camus to contact Michael Judge, director of DOER’s renewable energy division. The CEP is intended to complement another effort, the Clean Energy and Climate Plan (CECP), which talks about emissions targets and how the state is going to meet them, Morin said.

July 24, 2018January 15, 2025

SPP Markets and Operations Policy Committee: July 17-18, 2018

OMAHA, Neb. — Given a proverbial second bite of the apple, SPP stakeholders easily approved a revision request that requires non-dispatchable variable energy resources (NDVERs) to register as dispatchable variable energy resources (DVERs) within a multiyear transition period.

The Markets and Operations Policy Committee rejected the measure (RR272) during its April meeting. The Board of Directors/Members Committee tabled the request but asked for a review of RR272’s economic impact and that the Market Working Group build greater consensus among the membership. (See “Board Forced to Table NDVER Conversion Change,” SPP Board of Directors/Members Committee Briefs: April 24, 2018.)

MWG Chair Richard Ross, of American Electric Power, began discussion of the change by noting he was one of the few people in the meeting room wearing a tie.

“I’m not trying to make anyone nervous,” he quipped. “But if you get unruly, I’ll take the tie off.”

There was no need. The measure passed with more than 81% approval, almost 20 points better than it fared in April. It was opposed by only two transmission owners (Empire District Electric and Omaha Public Power District) and eight transmission customers with various ties to renewable energy. Seven transmission customers abstained.

“We wanted to see this happen, sooner than now,” said Southwestern Public Service’s Bill Grant. “This is a compromise we can live with. It took a lot of work to get to this point, but we’ve moved to a point where most people are happy.”

Staff shared its analysis of RR272’s economic effects, which compared the conversion of NDVERs to DVERs against a base case using real-time security-constrained economic dispatch data. They found the conversion resulted in improved congestion management and, with it, better convergence of real-time and day-ahead prices. That resulted in about $15,000 in additional monthly real-time energy payments to converted NDVERs and about $20,000 in additional revenue to other resources.

The data also indicated a significant reduction in the number of operating hours with negative pricing.

The MWG revised the proposal to exempt run-of-river hydro not capable of following dispatch instructions and to provide additional time for certain NDVERS to convert. They now face a deadline of either Jan. 1, 2021, or the 10-year anniversary of a resource’s original commercial operation date.

Market Monitoring Unit Executive Director Keith Collins said he supports the proposal, saying the benefits come from “an increase in prices at locations that are primarily non-dispatchable.”

“We’re investing upgrades for controls we don’t own, which increases the [power purchase agreements] for our customers. That’s not something we’re keen on,” said Empire’s Aaron Doll. “Our specific limitation is contractual language that limits curtailments to a certain amount in a 24-hour period. The dispatch signal puts us in bad spot pretty quickly. Anything short of providing an exemption for entities with contract language that precludes curtailment is not something we can support.”

The MOPC also approved RR266, which would model a joint-owned unit (JOU) as a single resource in market-clearing decisions, while performing an after-the-fact allocation of revenues based on ownership shares. Other JOU shares would be used for settlement purposes, and each share would exist only in the context of settlements where final clearing results are split based on the submitted ownership share percentages.

The change is contingent upon final approval by the Regional Tariff and Operating Reliably working groups. Nebraska Public Power District and Oklahoma Gas & Electric’s Transmission and Electric Services divisions opposed the measure, citing problems with the language.

“We have a couple of JOU situations we manage fine ourselves,” said OG&E-Transmission’s Greg McAuley. “We’ll continue to pound the table as it relates to some of these administrative costs.”

Stakeholders approved against minimal opposition three other revision requests brought forward by the MWG:

- RR306, which would minimize potential gaming opportunities identified by the MMU. The change allows market-committed resources that have a minimum run time extending beyond initial reliability unit commitment or day-ahead commitment periods to be eligible for make-whole payments after their initial commitment period.
- RR304, which streamlines the process by which frequently constrained areas are re-evaluated, in order to make adjustments in a timely manner.
- RR312, which would calculate the FERC Schedule 12 rate based on current data. The change aligns the collections of revenue against the customers’ megawatt-hours being assessed.

SPP Prepared for January’s ‘Big Chill’

Staff’s update on what they call “The Big Chill,” the abnormally frigid temperatures Jan. 17-18 that led to heavy north-south transfers of MISO flow across SPP’s system and a maximum generation alert in MISO South, caused one member to recall his scouting days.

“I wouldn’t call this an emergency event,” said MOPC Chair Paul Malone, of NPPD. “It was pretty well known we would have severe weather over a wide area. That begs for proper planning. As the Boy Scout motto says, ‘Be prepared!’”

“Let’s just say, some people are surprised every day by what happens,” said SPP COO Carl Monroe, “and some people were surprised that day.”

MISO exceeded its 3,000-MW regional dispatch limit on transfers between its North and South regions over the SPP system during the event and was forced to make emergency purchases from Southern Co.

SPP Vice President of Operations Bruce Rew said the RTO never had to issue an emergency alert, as it was never short of generation. “It was uncomfortable for us,” he said. “We have to make sure it doesn’t happen again.”

David Kelley, SPP’s director of seams and market design, credited SPP’s and MISO’s neighboring reliability coordinators with helping to prevent load shed and keeping the lights on during the event. He said recent discussions among the Regional Transfers Operating Committee (RTOC), a six-person group comprising two representatives each from SPP, MISO and joint parties to a 2016 settlement agreement, centered on better understanding the non-firm, available nature of MISO’s north-south flows and their effects on neighboring entities. (See SPP, MISO Reach Deal to End Transmission Dispute.)

“Anything over 1,000 GW is on a non-firm, as-available basis. To us, that means SPP’s service should not be in jeopardy of load shed,” Kelley said. “When this event happens again, and will happen again, we’ll be prepared.”

Kelley said staff has also met with FERC staff to “ensure FERC had a clear understanding of what happened that day,” given “very inaccurate statements that found their way into the media.” (See SPP Seeks FERC Meet in MISO Tx Dispute.)

Kelley also briefed the MOPC on a proposed interregional project with Missouri-based Associated Electric Cooperative Inc., a new 345/161-kV transformer at AECI’s Morgan Substation near Springfield and the rebuild of a 161-kV line.

The project’s regional cost allocation was rejected by FERC last year. (SPP would be responsible for 89% of the $13.75 million in engineering and construction costs). SPP staff have since developed data that indicate the project would yield the region $17 million in load ratio share benefits by eliminating the need for upgrades at City Utilities of Springfield’s John Twitty Energy Center and also reduce day-ahead market uplift costs.

“We feel like we’re in much better shape,” said Kelley, who met with FERC staff on July 12. “They look forward to seeing our next filing.”

Kelley said that filing should be made in late July or early August.

Stakeholders Endorse $47.4 Million in Near-term Tx Work

The MOPC endorsed the Transmission Working Group’s recommendation to approve the Integrated Transmission Planning process’s 2018 near-term assessment portfolio, a package of 13 transmission projects with an estimated cost of $47.4 million

However, when taking into account four withdrawn projects from previous assessments that cost a total of $53 million, the portfolio has a net cost of -$5.6 million.

Several of the Kansas and Missouri projects are being driven by the retirement of about 1.9 GW of 50- to 60-year-old generation later this year and in early 2019.

The projects will solve 101 reliability needs. They include a new 345-kV, 50-MVAR reactor at City Utilities’ Brookline substation, a project originally identified as an interregional project with AECI.

OG&E’s Travis Hyde, who chairs the TWG, noted SPP approved nearly $8 billion in construction between 2006 and 2014. With the strategic shift to maintaining “an economical, optimized transmission system,” he said, the RTO has since approved just more than $1 billion in base plan funded investment.

Staff developed a summary presentation of the assessment using a story map tool.

Stakeholders also endorsed NorthWestern Energy’s sponsored upgrade of less than 4 miles of new 115-kV line in Aberdeen, S.D., and a working group recommendation to approve the 2019 ITP’s needs sensitivity scope addressing study results affected by Lubbock Power & Light’s potential exit from the system.

RC Efforts in West Absorb MWTG Integration

Monroe told members that the integration of the Mountain West Transmission Group has been “subsumed” in the debate out West over who will provide reliability coordinator (RC) services — a debate that involves SPP.

The RTO said in June that it plans to offer RC services in the Western Interconnection, matching an earlier announcement by CAISO. Not coincidentally, Peak Reliability said last week it will wind down its RC role by the end of 2019. (See related story, Peak Reliability to Wind Down Operations.)

SPP’s Carl Monroe (c), NPPD’s Paul Malone, NE Texas Electric Co-op’s Jason Atwood, GDS Associates’ Jack Madden anchor the MOPC’s head table. | © RTO Insider

“There’s still interest in [joining SPP],” Monroe said. “The importance of making sure RC is provided, and in an efficient and reliable way, has subsumed their work right now.”

SPP’s efforts to integrate Mountain West were dealt a blow in April when Xcel Energy announced it was withdrawing from the Rocky Mountains group and its efforts to join the RTO. (See Xcel Leaving Mountain West; SPP Integration at Risk.)

Monroe said there have been no changes to the Mountain West’s initial proposal to join SPP, adding he hopes to be able to provide “what kind of a footprint we would have with RC services” by Sept 1.

“As we work through the process, our intent is to meet the goals of what we normally do through contract service, which is providing benefits back to the members themselves,” he said.

MRO’s Patrick Welcomes New Entities

Midwest Reliability Organization CEO Sara Patrick introduced herself to SPP members, many of whom were among the 100 registered entities that joined the organization after the SPP Regional Entity’s recent dissolution. (See SPP RE Ending Compliance Monitoring, Enforcement Activities.)

Patrick said all compliance monitoring and enforcement program (CMEP) data was successfully transferred from the SPP RE to MRO on July 3, and that all entities in its expanded footprint are now using MRO’s webCDMS portal.

Patrick gave credit to the SPP RE’s staff in a “well-coordinated” transition and data transfer. The $1.5 million in transition costs will be recovered by transferring assessments from the SPP RE to MRO, she said.

The MRO’s board of directors last month approved a $4.3 million increase, reflecting the expanded footprint. Patrick said the budget will result in $4.8 million in savings, when compared to the combined MRO and SPP RE budgets.

The board also agreed to add four new directors next year, including two regional directors from the SPP RE’s footprint.

MOPC Sends Two Initiatives Back

The MOPC declined to take action on a pair of work efforts, asking that both be returned to the stakeholder process for further clarification.

Following an update on SPP’s prioritization process for revision requests and project proposals, stakeholders debated potential improvements to the process before the committee’s leadership said it would return to the next meeting in October with ideas on how to proceed.

Stakeholders complained about a lack of transparency, the amount of information they had to deal with and not knowing where decision-making authority lies. Staff said it stopped the quarterly meetings because of a lack of feedback.

Several members familiar with ERCOT’s stakeholder process suggested the Texas grid operator’s Protocol Revisions Subcommittee (PRS) as a good model to follow. Tenaska’s John Varnell, who once chaired the PRS, said if members listened in on the group’s meetings, “You will see how we can do better at this process.”

“That’s one thing that ERCOT does quite well,” said Golden Spread Electric Cooperative’s Mike Wise, who sits on ERCOT’s MOPC equivalent, the Technical Advisory Committee.

“[The PRS] does a really good job of ensuring financial stability or accountability. [Members] debate [revision requests] quite substantially before they ever enter in the queue for approval at the TAC. Many of us want this to be like what we have at ERCOT. It puts more decision-making in the hands of the stakeholders, rather than SPP.”

Grant, who headed the task force that developed the prioritization process, called for more stakeholder involvement in the process. He reminded the committee that the task force hasn’t been disbanded.

“If we’re going to spend the time and effort to improve the process, we need better participation and more dedication to the issue,” he said. “It doesn’t matter what we set up if the stakeholders aren’t going to participate in the process.”

The MOPC also sent back a Credit Practices Working Group (CPWG) revision request, saying it needed more information and noting the Finance Committee had tabled the request. The CPWG reports to the committee.

The CPWG’s RR311 would change the way reference prices are used to estimate the settlement exposure of transmission congestion rights (TCRs). The group’s analysis of a two-year period indicated its proposed methodology would have reduced collateralization in the TCR market by $124 million to $327 million, and more than doubled under-collateralization from $17 million to $39 million.

Staff recommended tabling the change, saying it needed more analysis in light of a market participant’s recent default in PJM’s financial transmission rights market. (See “Credit and Default,” PJM MRC/MC Briefs: June 21, 2018.)

“It sounds like the hesitancy to move forward is lack of understanding of what’s happening in the PJM situation,” said Kansas City Power & Light’s Denise Buffington.

Given that the CPWG has yet to gain approval from the Finance Committee and the Regional Tariff Working Group, stakeholders agreed to send CPWG RR311 back to the working group so that it can be properly shepherded through the stakeholder process.

Members Endorse RRs, Process Language Change

Members endorsed language changes to improve efficiency of the revision request process by reducing the time it takes to gain approval for a change and removing duplicate references that cause unnecessary changes.

The proposal (RR291) would allow a revision with approved “normal status” to progress through the stakeholder process while its primary working group waits on the impact analysis. It would also revise language to reference the applicable documents as SPP revision request documents and remove their multiple references.

The MOPC’s consent agenda, which passed unanimously, included nine revision requests and a new baseline cost estimate for SPS’ 115-kV loop rebuild in West Texas. The project’s original cost of $28.4 million was reduced almost 23% to $21.9 million.

- BPWG RR307: Clarifies that partial service may be offered to short-term transmission service requests when the full amount requested cannot be granted.
- CTPTF RR279: Modifies the competitive project proposal process to allow a re-evaluation request before awarding a notice to construct.
- MWG RR177: Clarifies references to NERC standards in the Integrated Marketplace’s protocols and the Tariff’s Attachment AE, the marketplace’s governance, to eliminate confusion over whether entities are performing obligations for market or NERC standard reasons. Also modifies the attachment’s definition of operating reserve to that defined in the Tariff.
- MWG RR277: Corrects language in Attachment AE to accurately reflect the settlement formula for the auction revenue rights daily amount by reversing the sequence of the source and sink.
- MWG RR310: Adds three reporting requirements to comply with FERC Order 844: zonal make-whole payment reports, resource-specific make-whole payment reports and operator-initiated commitment reports. Also requires public posting of transmission constraint penalty factors; circumstances if violation relaxation limits (VRLs) could set prices; and procedures for temporarily changing VRLs in the Tariff.
- ORWG RR309: Removes section 7.3.1 (FAC-011-3 System Operating Limits Methodology) from SPP’s planning criteria and places it in a separate document for reliability coordination purposes.
- RTWG RR278: Corrects Attachment O’s Addendum 1 to include only current and applicable interregional coordination agreements and an update link to the joint operating agreement with MISO.
- RTWG RR315: Removes references to the SPP RE in the governing documents.
- RTWG RR314: Adds clarifying language to the ITP manual addressing ambiguity in the base reliability and short-circuit model builds.

— Tom Kleckner

July 24, 2018

Little Work Needed to Comply with Order 845, MISO Says

By Amanda Durish Cook

CARMEL, Ind. — MISO staff say the RTO is mostly up to speed with a recent FERC order aimed at increasing the transparency of the generator interconnection processes — but they continue to tackle issues related an overbooked queue.

Compliance with Order 845 largely involves inserting FERC-directed language and existing Business Practices Manual text into the Tariff, MISO said last week.

MISO FERC Order 835 interconnection — Supino | © *RTO Insider*

“Most of the compliance directives we already comply with in some shape or form,” counsel Chris Supino told stakeholders at a July 17 Interconnection Process Task Force meeting. He said MISO is “early” in its compliance plan and plans to share draft Tariff language in September.

“Most of these are fairly administrative; some we’ll have some more discussion around,” Supino said.

FERC issued the order in April, setting out 10 new rules intended to increase the transparency and timeliness of RTO generator interconnection processes. (See FERC Order Seeks to Reduce Time, Uncertainty on Interconnections.) MISO in mid-May joined an ISO/RTO Council request to extend the original Aug. 7 filing deadline, which FERC pushed out to Nov. 5.

Supino said most of MISO’s remaining work will focus on a new requirement to post quarterly summary statistics on its queue, including the number of withdrawn projects, completed projects and delayed projects; the proportion of studies completed by Tariff deadlines; and average study completion time.

MISO is now also obligated to file informational reports for four consecutive quarters if it misses deadlines on 25% or more queue studies during two consecutive quarters. The reports must explain reasons for the delays, steps taken to minimize them and the total number of employee and consultant hours spent on studies during the quarter.

Supino told stakeholders:

MISO generally complies with a directive to list specific study processes and assumptions because it already posts study models for review on its nonpublic Open Access Same-Time Information System. It will examine how the directive interacts with its existing nondisclosure agreements and whether it should issue more NDAs in order to share the models with a broader group.
The RTO will revise its generator interconnection agreement to give customers the option to build interconnection facilities and standalone network upgrades regardless of whether a transmission owner can meet a customer’s proposed in-service dates. It will also likely leverage its existing alternative dispute resolution language used for settlements to apply to members’ queue disputes.
MISO’s net zero interconnection option should cover a directive to allow customers to utilize or transfer surplus interconnection service at existing generating facilities. Net zero permits customers to transfer existing interconnection rights to a new generator at the existing point of interconnection, provided the total interconnection does not exceed the original service limit granted in the interconnection queue.
MISO will revise procedures to allow interconnection customers to request service lower than their generating facility capacity.
The Tariff will be updated to include a definition of permissible technological advancements to generators that it can accommodate without a change being considered a material change, something FERC has left up to the RTOs. Instead of listing every permutation of acceptable changes, MISO will instead develop a standard to study changes.

Further GIP Alterations

Meanwhile, MISO is once again tinkering with its proposal to make generation owners more accountable for site control earlier in the interconnection queue.

MISO is now proposing to require that interconnection customers have 90% site control at the time of application based on a per acre format, with 50 acres/MW for wind generation, 5 acres/MW for solar, 1 acre/MW for battery storage and a flat 50 acres for conventional generation. All generation types must provide a detailed site map showing turbine layout. All generators would be required to demonstrate 100% site control by the second decision point of the queue.

Apex Clean Energy’s Swaraj Jammalamadaka asked whether it is fair to require generation developers to hold that amount of land especially if MISO’s queue studies become delayed.

“It’s not a bad thing to have site control, but is this reasonable?” he asked.

WEC Energy Group’s Chris Plante also questioned whether the flat 50-acre requirement for conventional units was a reasonable standard. Neil Shah, MISO manager of resource interconnection, said the requirement was based on SPP standards, but staff are open to stakeholder suggestions.

MISO last month softened its original stance that developers should provide evidence of 100% site control before their projects can enter the queue and unveiled a plan to increase the deposit due upon entry from the current $100,000 to anywhere between $500,000 and $2 million in cash, depending on project size. (See “MISO Softens Site Control Requirements in Queue Streamline,” MISO Planning Advisory Committee Briefs: June 13, 2018.) Now, the cash deposit option will only apply to projects that demonstrate regulatory restrictions to procuring site control.

MISO also still plans to remove its dynamic stability, short-circuit and affected-system analyses from the first phase of the definitive planning phase. Staff said the revisions are needed because the overbooked queue currently contains almost 93 GW of prospective generation.

“It’s in a glut, or it’s clogged, and everyone, MISO included, needs to do something,” Shah said.

Revised Milestones

MISO also plans to revise the queue’s existing milestone payment and refund structure to include a percentage of upgrades identified in affected-system studies and introduce more monetary risk for customers who keep unprepared projects in the queue.

The RTO plans to keep its current format of a $4,000/MW initial payment upon entering the DPP with two subsequent milestone payments based on a percentage of upgrade costs. However, MISO now proposes to introduce upgrade costs found in affected-system studies that occur during the phase two system impact study. The third milestone payment will now consist of 10% of necessary network upgrades and another 10% of costs associated with needed upgrades uncovered in the affected-system study. The two combined percentages are a departure from MISO’s existing third milestone payment of a flat 20% of network upgrades.

Multiple stakeholders said MISO’s proposal will make milestone payments more burdensome and riskier to stakeholders by adding the affected studies element.

Jammalamadaka pointed out that MISO cannot control the outcome of affected system studies, which to date have shown inconsistent findings.

“That more money should be a percentage of something that’s predictable,” Jammalamadaka said.

Milestone refunds will also be slightly altered under the plan. MISO will offer to refund 50% (instead of the current 100% ) of the second and third milestone payments if a project opts to withdraw at the corresponding decision points. Projects that do not elect to withdraw at a decision point risk losing their entire milestone payment even if they fail to complete a GIA.

Shah said none of the refund changes will affect the penalty-free withdrawal options that MISO built into its queue overhaul last year. Penalty-free withdrawals are allowed in MISO if network upgrade costs increase too dramatically from one phase to another in the DPP.

“We want to make sure the new rules accomplish the goal of moving projects and incentivize the not-ready projects to get out as early as possible and potentially not even enter the queue,” Shah said. “We want ready projects to progress through the process. We want non-ready projects to drop out as soon as possible. This is our intent with this proposal, and we want to process the queue as quickly as possible.”

“We’re not changing too many things here,” said MISO Resource Utilization Director Vikram Godbole. “If you’re not willing to put money up for your project, maybe you don’t belong in the [definitive planning phase], I’m sorry to say. We’re designing a process for real and ready projects.” Godbole added it would be impossible to eradicate all speculative projects from the queue.

Shah said MISO hopes to file the new queue milestone details by the latter half of September.

Some stakeholders indicated that they might contest the filing with FERC.

MISO’s Patrick Brown reminded stakeholders that the RTO will collect two more rounds of feedback on the proposal, including a discussion before the Planning Advisory Committee.

“This is not set in stone. This is wet cement here. I think it’s a little premature to talk about contesting the filing,” he said.

Brown pointed out that MISO estimates it currently has a 20% completion rate of prospective projects that enter the queue. He said MISO is trying to “thin the herd to the most viable projects” and said he hopes the RTO can achieve a 50% completion rate of queue entrants in the future.

July 24, 2018

FERC Grants KCP&L Greater Missouri’s Dividends Petition

By Tom Kleckner

FERC last week found that KCP&L Greater Missouri Operations’ proposed payment of dividends complies with the Federal Power Act (EL18-146).

The commission found that Greater Missouri had clearly identified the source of its proposed dividends and that “nothing in the record indicates that the dividends will be excessive.” FERC found that the dividends would be “generally consistent with the amount and timing of the dividends” the utility has traditionally paid to its parent Great Plains Energy.

ferc kcpl federal power act — KCP&L’s Slate Creek Wind Project | *KCP&L*

The commission said that, “consistent with prior precedent,” the issuance of dividends would not harm GPE. It conditioned its approval on the utility’s compliance with its capitalization and credit rating commitments.

Greater Missouri filed the petition in May, saying it had deferred income tax assets and liabilities related to its regulated operations and significant deferred income tax assets for net operating losses (NOLs) generated prior to it’s acquisition by GPE in 2008. The utility said last year’s Tax Cuts and Jobs Act required it to revalue all of its deferred tax assets and liabilities in December based on the lower 21% corporate tax rate, and to revise its assumptions regarding the use of certain tax credits and NOLs.

The utility recognized a $111.6 million one-time, non-cash charge to income tax expense, approximately 1.6 times its average net income from 2014 through 2016 ($71.4 million). The charge caused Greater Missouri to have an accumulated deficit in its retained earnings account, which, according to FPA Section 305a, restricted the utility’s ability to pay dividends to GPE.

Section 305a forbids any public utility’s officer or director to receive “for his own benefit” any security issued or to share in any of the proceeds from any funds properly included in the capital account. The commission said a key concern was “corporate officials raiding corporate coffers for their personal financial benefit.”

FERC used a three-factor analysis to determine whether the proposed dividends payment violated the FPA. The commission considered whether: (1) the utility clearly identified the dividends’ sources; (2) the dividends would be excessive; and (3) the proposed dividends would have an adverse effect on the value of shareholders’ interests.

GPE recently acquired Kansas-based Westar Energy. (See Westar-Great Plains Merger Wins Final Approval.)

July 24, 2018

MISO Files Revised Upgrade Funding Provisions

By Amanda Durish Cook

CARMEL, Ind. — MISO has submitted a pre-emptive Section 205 filing to retain the option to allow new generators to self-fund interconnection transmission upgrades after the D.C. Circuit Court of Appeals vacated related FERC orders from 2015, stakeholders learned last week.

MISO facility construction transmission upgrades — Blackwell | © *RTO Insider*

“We asked for the commission to issue an order within the requisite 60 days,” MISO counsel Mike Blackwell said during a July 17 Interconnection Process Task Force meeting.

MISO policy previously allowed incoming generators to self-fund new construction regardless of whether transmission owners wanted to fund the construction themselves. FERC in 2015 directed the RTO to remove the option for a TO to elect to fund the interconnection upgrades.

The D.C. Circuit in January vacated FERC’s decisions on the self-funding option, saying the commission didn’t consider complaints from Ameren and five other TOs who claimed the policy forced them to accept “risk-bearing additions to their network with zero return” and essentially act as “nonprofit managers” of network “appendages.” The TOs had argued the Federal Power Act and Constitution prohibits FERC from forcing them to construct and operate generator-funded network upgrades. The case was remanded back to FERC. (See MISO Awaits FERC Following Remand on Tx Upgrade Funding.)

MISO made two separate filings July 5: one to reflect the vacatur (ER18-1964), and the other to propose a revised option that removes the requirement that an interconnection customer must consent before a TO can fund an interconnection upgrade (ER18-1965), a move intended to preserve the option for generators to self-fund upgrades. If FERC agrees, the change would apply to MISO’s generator interconnection agreement, Facility Construction Agreement and Multi Party Facility Construction Agreement.

Fallout Undetermined

Blackwell said a FERC decision on MISO’s filing could affect GIAs dating back to 2015. In both early July filings, the RTO committed to working “with parties to GIAs executed since June 24, 2015,” over the next three months to “establish a process for reviewing and revising those agreements to reflect the legal consequences.”

Wind on the Wires’ Rhonda Peters asked if the impacts of the decision could render some past GIAs uneconomic.

“MISO’s intent is merely to bring its Tariffs up to a state that’s as current as possible. We haven’t analyzed the financial impacts for specific interconnection projects,” Blackwell said of the proposed revision.

Peters also asked what would happen if the terms of an upgrade change after it is already funded. Blackwell said he would consult MISO staff on the consequences of such a scenario before attempting to answer the question.

In its filing, MISO warned FERC that not accepting its agreement amendments in a timely manner could have dire consequences: “MISO estimates that agreements already in process contain millions of dollars of affected systems upgrades. … These agreements (and the parties to them) would be subject to significant confusion and uncertainty if the commission does not act promptly to accept this filing, and delays associated with such confusion and renegotiations of agreements of this magnitude could implicate the timely construction of these upgrades.”

July 22, 2018

ERCOT Shatters Demand Records as Texas Bakes

By Tom Kleckner

Hell may be hotter, but it has nothing on Texas these days.

A high-pressure system that has swamped much of the state with triple-digit temperatures has triggered numerous heat advisories and led to all-time systemwide peak records in ERCOT.

ercot demand records — Sunday’s forecasted highs | *National Oceanic and Atmospheric Administration*

The grid operator broke its previous high for system demand on Thursday, when load topped out at 73.3 GW between 4 and 5 p.m. That was more than 2 GW over the previous record of 71.1 GW, set in August 2016.

All told, demand surpassed the old record nine times last week as temperatures reached 110 degrees Fahrenheit and heat indexes were as high as 115. On Sunday, ERCOT set a new weekend demand record of 71.4 GW between 5 and 6 p.m., breaking the old mark set last July by almost 3 GW after surpassing it three times on Saturday.

The ISO came up short of another record Monday, but cracked 73 GW for the second and third times during the intervals ending at 4 and 5 p.m. System load also exceeded the 2016 record during the intervals ending at 3 and 6 p.m.

Demand has exceeded 70 GW every day since July 16. The grid operator in spring projected a peak demand of 72.97 GW in August, assuming normal weather conditions.

Through it all, ERCOT has met demand without issuing conservation appeals. Staff in spring said it would have as much as 78.2 GW of capacity available, with a planning reserve margin of 11%. (See ERCOT Gains Additional Capacity to Meet Summer Demand.)

“Everyone in the ERCOT market — from our operators to generators to transmission providers to retailers — is doing what they can to keep the power on for consumers,” said ERCOT spokesperson Theresa Gage.

Dallas/Fort Worth International Airport set a daily record for the third day in a row Saturday at 109, while Waco has broken its daily record five consecutive days, topping out at 109. Lubbock in West Texas saw a daily low of 81 on Thursday, the first daily low in the 80s in more than 100 years of record-keeping, according to The Weather Channel.

Houston and Dallas both opened cooling centers over the weekend for residents without access to air conditioning.

A jet stream is expected to shift the high-pressure dome to the West this week, cooling Texas temperatures down into the 90s.

“We fully expect to keep hitting new demand records as summer 2018 continues,” ERCOT said in a written statement.

Real-time hub average prices peaked at $1,922.20/MWh on Thursday in the 15-minute interval ending at 4 p.m. Wednesday’s high price of $2,281.95/MWh in the West zone was the highest seen since August 2015, when they hit $2,233/MWh, according to Bloomberg data.

Several retail providers have asked their customers to reduce their usage between 2 and 6 p.m. Cirro Energy, Reliant Energy and Xcel Energy have all offered conservations tips to their customers.

July 22, 2018

NARUC Talks Innovation at the ‘Water-Energy Nexus’

By Rich Heidorn Jr.

SCOTTSDALE, Ariz. — It used to take SUEZ in North America four years to apprentice an operator at its Boise, Idaho, water utility, with its 90 “pressure planes” (service territories), 80 tanks and 60-plus source wells.

But after developing an algorithm based on 10 years of supervisory control and data acquisition throughout its network, SUEZ created a system that sets the optimal setting for every pump and integrates data from its power utility to determine the best time to run them.

The result: a 10% reduction in the water company’s energy demand and a $350,000 rebate from the power company.

But that wasn’t the biggest achievement, David Stanton, SUEZ’s president of utility operations and federal services, told the National Association of Regulatory Utility Commissioners’ Summer Policy Summit last week. Stanton was invited to speak at Monday’s general session by NARUC President Jack Betkoski, who has made the “water-energy nexus” the centerpiece of his year as head of the state regulators.

“Because we’re capturing knowledge in the system, we now can train operators within six months,” Stanton said. “So we’re actually solving what I think is a much more systemic big problem” — an aging workforce.

Stanton said the new system illustrates his company’s need to “reinvent” its information technology. “Traditionally we talk about technology in the context of physical assets. But more and more I’m thinking that the data … that’s coming is going to change the physical technology asset that we want to deploy dramatically. So we really have to solve for data innovation first.”

That means not using enterprise resource planning (ERP) systems like SAP and Oracle for managing big data. “You need ERPs for financials and maybe billing, but you want an innovative environment … that is safe and secure and isolated from your ERP. The future of IT has much more to do with the sources of data and operations than it does big back-office ERPs.”

‘Benchmark Like Crazy’

Four years into what Stanton called the company’s “smart utility” program, he shared his lessons learned.

“We benchmark like crazy. Everything we do that we like, we go find somebody that’s already done it and does it really well. And we go worldwide with the benchmarking.”

Left to right: Arvizu, Stanton and Distal | © *RTO Insider*

SUEZ implemented innovations “at scale” but at one regional utility at a time, Stanton said. “And then once it worked, we hopscotched that out to other regions.

“We never went out and did everything at once, and as a result, we were running 12 or 14 projects around our utility footprint nationwide. … We never bet the ranch on one idea. If something didn’t work, we could throw it out.”

But getting other regions to buy in was a problem, Stanton said. “A lot of utilities run their regions with a strong president or general manager for each region. Getting them to work together … is like a ‘Game of Thrones’ type of activity.

“Once we had enough of these project implementations working, I made 50% of the bonus of each leader dependent on their ability to get what they implemented adopted by the other utilities. So half their bonus all the sudden was based on, ‘If I do it your way for your project, you have to do it my way for my project. We’ve got to work this out.’

“In two weeks, we had everything worked out. We had heard for years that New York couldn’t do it like New Jersey. … So that solved the cultural problem almost overnight.”

‘First Customer’ Syndrome

Also appearing on the panel was Oded Distel, founder and director of Israel NewTech, a program in the country’s Ministry of Industry, Trade and Labor that supports research in the water and renewable energy sectors. Distel described how Israel overcame the reluctance of utilities to become the “first customer” for new technologies.

“We encourage utilities … and tech companies to come together. They form a joint project for the first implementation of a new technology and then the government supports those projects. The money is not huge but … the guy who has to make the decision — the head of the utility, the chief engineer — feels that he’s not alone. He’s part of a national effort. … If something fails, he’s not left there alone to pay the price,” Distel said. “The influence over the utilities was amazing. All of the sudden, they opened up, and they started thinking and having discussions in a totally different manner.”

Dan Arvizu, recently appointed chancellor of New Mexico State University, told regulators about his experience as director of the National Renewable Energy Laboratory between 2005 and 2015.

“Even though our public policy at the federal level — and many times at the state level — aspired to do certain things, the technology was typically ahead of the policy, and the finance was way behind,” he said.

He offered his own advice for innovating: “You need to think big, you need to try small, you need to fail fast and then regroup and then try and scale again.”

And he had a warning for utilities about the new customer choices that will become available from the falling prices of renewables and energy storage. “If utilities are not on the forefront [of the transformation], they could become obsolete,” he said.

July 22, 2018

Gas Industry Plays Defense at NARUC Meeting

By Rich Heidorn Jr.

SCOTTSDALE, Ariz. — The natural gas industry found itself on the defensive at the National Association of Regulatory Utility Commissioners’ Summer Policy Summit last week as panelists debated pipelines’ resilience and ability to withstand cyberattacks.

naruc cybersecurity natural gas — Massello | © *RTO Insider*

During a panel ominously titled “Handling and Preparing for Attacks on the Natural Gas Network from Rising Cyberthreats,” Rebecca Massello, of the Interstate Natural Gas Association of America (INGAA), noted there were no gas outages during last winter’s “bomb cyclone” for generators with firm service.

“What history shows is that pipeline outages are very rare, and when they do occur they’re localized in nature. And I want to tell you, that’s not by accident,” said Massello, director of security, reliability and resilience for the group, which represents interstate pipelines. “It’s actually inherent in the way the system is designed and the way it has continued to evolve over time. Today we have more supply diversity than ever before, with natural gas regions all over the country. We also have more looping lines and multiple pathways to reroute gas in the event there is an incident.”

“Interconnects and multiple pipeline feeds support system resilience, help with contingency planning and keep disruptions localized,” said Kimberly Denbow of the American Gas Association, which represents local distribution companies. “Because of the way natural gas utilities must operate, blackouts … and rolling brownouts are not operationally feasible. We build resilience on the front end.”

Paul Stockton, managing director of security and risk management firm Sonecon, said he’s less concerned about weather than Chinese and Russian hackers.

Stockton, former assistant secretary of defense for homeland defense and Americas’ security affairs, quoted Director of National Intelligence Dan Coats, who told a think tank earlier this month that the Department of Homeland Security and FBI “have detected Russian government actors targeting government and businesses in the energy, nuclear, water, aviation and critical manufacturing sectors.”

“The warning lights are blinking red again” the way they were before the Sept. 11 attacks, Coats said.

Gas Industry Cybersecurity

Denbow pushed back on suggestions that the gas industry is vulnerable because it lacks the mandatory cybersecurity rules of the electric sector.

“The argument that natural gas systems lack resilience because they lack cybersecurity regulations is unfounded,” she said, calling gas industrial control systems “our crown jewels.”

She said the industry’s cybersecurity procedures are informed by standards, including the Transportation Security Administration’s pipeline security guidelines, the National Institute of Standards and Technology cybersecurity framework, American Petroleum Institute standards and the Department of Energy’s cybersecurity capability maturity model. AGA in 2014 helped create a downstream natural gas information sharing and analysis center (ISAC), which is now located on the floor of the electricity ISAC in D.C.

Communications Disruptions

Stockton cited retired boxer Mike Tyson’s often repeated adage that “‘Everybody has a plan until they get punched in the mouth.’

“I think that’s true for information sharing,” Stockton said. “In a blue-sky day like today — no event going forward — everybody’s sharing better and better. … If there is an attack by a major state on the energy sector represented here, you bet we should assume that adversaries will go against Internet-based communications, public switched telephones — none of that stuff is gonna work. Power companies and natural gas companies have pretty good [communications] inside their own company — push-to-talk radios, things like that. But between sectors: nada, nothing” will work.

Stockton said regulators should identify single points of failure such as multiple utilities using the industrial control systems of the same vendor. “That’s why I’m a big fan of fuel diversity for electric generation,” he said. With nuclear and coal in addition to renewables and gas, he said, “it’s much harder for the adversary to take everything down simultaneously.”

Solutions

Stockton, a consultant for Exelon, which is seeking subsidies for its struggling nuclear plants, says state regulators should help define attributes of fuel resilience and create a “design basis threat” for the electric and gas sectors, like that issued by the Nuclear Regulatory Commission.

“You can fly a 747 into [a nuclear plant] and the containment vessel can survive,” Stockton said. “That’s no accident: There’s a design basis threat that they have to meet.”

(Stockton overstated the NRC’s requirements. In 2009, the commission required all new nuclear plants to ensure their reactor containments could withstand a crash by a large commercial aircraft. But it rejected proposals that existing reactors be retrofitted with similar protections. “Deliberate attacks by large airliners loaded with fuel, such as those that crashed into the World Trade Center and Pentagon, were not analyzed when design requirements for today’s reactors were determined,” the Congressional Research Service wrote in a 2014 report.)

Stockton said industry should prepare for threats like Timothy McVeigh’s 1995 truck bomb attack in Oklahoma City and the coordinated hijackings by al-Qaeda terrorists on Sept. 11, 2001.

“Folks, Russia is not going to attack a single gas pipeline and expose themselves to retaliation. They’re going to try and take down the energy sector. It will be a comprehensive attack.”

Gas industry representatives urged against overreacting to what Massello called the “fear and uncertainty and doubt [of scenarios that haven’t] happened before.”

“Rather than try to fix portions of the system that are not broken, let’s hone in on those areas where concentrated problem-solving will yield measurable results,” said Denbow, who noted that the leading cause of pipeline disruptions is third-party excavation damage.

“For as long as gas utilities must contend with third-party excavators who hit our lines and disrupt our systems, gas control operators will continue exercising their training with respect to rerouting gas supplies and with respect to workarounds, resort[ing] to manual operations when necessary and minimizing the impact to firm service and residential customers,” she said. “This is what they do on a daily basis. This is not new to us.”

In a second panel (“What Does the Future Hold for Gas-Electric Interdependencies and Where Does Resilience Fit In?”), Todd Snitchler, director of market development for the American Petroleum Institute, had a similar message.

“We can’t underestimate the importance of getting this right, but I think we have to keep in balance … to be realistic in our assessment,” he said. “There is a long track record of successful performance.”

In the same panel, Kathleen Barron, Exelon’s senior vice president of federal regulatory affairs and wholesale market policy, said it was too soon to discuss concerns over the potential cost of resilience efforts.

“Our perspective is all this conversation about what’s the remedy, who gets paid, is your interest aligned with mine … is really premature. The question we need to answer is … based on a reasonable set of assumptions, what we should be planning for.”

Referring to PJM’s current fuel security study, she said, “Once that evaluation is done, and we figure out what our vulnerabilities are, then we can figure out how we should … adjust the market rules to accommodate them.” (See Stakeholders Debate PJM Fuel Security Scope.)

Moderator Angela O’Connor, chair of the Massachusetts Department of Public Utilities, disagreed. “I don’t think that any part of that conversation is premature,” she said.

Departure from Markets?

Amanda Frazier, vice president of regulatory policy for Vistra Energy, said it is “disheartening … that the conversation has switched and there’s so much discussion around moving away from markets in the name of resilience.”

“I would dispute the narrative that there’s any particular fuel source that is at risk of extinction,” she said, noting that half of the active nuclear plants receive regulated rates of return. “If all of the subsidized and unsubsidized but at-risk merchant nuclear plants closed tomorrow, we would still have 80% of our civilian nuclear plants up and operating,” she said.

While Vistra’s 10-K securities filing mentions catastrophic events as a material risk, “we mention regulatory intervention in about six different ways … because those are what really keep us up at night: Are the regulators [and] politicians going to continue to support competitive markets, which have delivered resilient and reliable electric generation across this country?”

Pennsylvania Public Utility Commissioner John Coleman said regulators’ decisions have become more complex “as we’ve added in all the other fuel source attributes into this dialog.”

“I hope that we have the intellectual horsepower in this room and within the NARUC community to be able to solve this. … The drama around all of these discussions need[s] to go down a level. … I am confident that we have the ability to figure that out without having external forces trying to dictate how this is going to work.”

July 22, 2018

2nd Load Shed of PJM’s CP Era Follows Closely on 1st

PJM on Wednesday ordered its second load-shed event since implementing Capacity Performance in 2015, less than two months after ordering the first. (See PJM Experiences First Load Shed in the CP Era.)

Both events were in the American Electric Power zone.

The July 18 event occurred on the border between West Virginia and Virginia, PJM spokesperson Jeff Shields said. An AEP equipment issue led to other equipment being taken out of service, which resulted in “severe” low voltages in the area around Bluefield and Princeton in West Virginia.

PJM called on AEP at 11:14 a.m. to reduce load in the area by 32 MW to return the voltages to acceptable levels. Keeping the voltages low would have risked “potential further voltage problems and equipment damage that could cause wider problems,” Shields said, but assured that didn’t include any potential for cascading outages.

The order lasted for 83 minutes until PJM canceled it at 12:37 p.m. after the equipment was returned to service. Approximately 13,000 customers were affected.

While both events trigger the significant performance-related bonuses and penalties introduced with CP, no resources were impacted by either incident. The May 29 event was caused by transmission equipment unexpectedly tripping offline in the area of several planned transmission line outages, causing constraints that had potential to cause a cascading outage. (See “Load Shed Details,” PJM Operating Committee Briefs: July 10, 2018.) Prior to these events, PJM last ordered load shedding during the 2013 heat wave.

PJM plans to review the most recent event at its Members Committee meeting on July 23.

— Rory D. Sweeney

July 22, 2018

PJM Unveils Locational Reserve Procurement Plan

By Rory D. Sweeney

VALLEY FORGE, Pa. — PJM on Tuesday rolled out a proposal to procure reserves on a more granular level, a move the RTO hopes will shift more generator revenues back into the energy market.

“I do think that, philosophically, energy is the primary product in these markets,” PJM’s Stu Bresler said at a July 17 meeting of the Energy Price Formation Senior Task Force.

pjm primary reserves ordcs — Stakeholders at last week’s EPFSTF meeting discussing the mechanics of PJM’s plan for reforming its energy market. | © *RTO Insider*

PJM is “not pricing reserves as well as we could,” Bresler said, adding that he expects the revenue distribution between energy and capacity markets to effectively work itself out if reserves prices are developed “as right as we can” make them.

The meeting began with PJM’s Cheryl Mae Velasco and Patricio Rocha-Garrido explaining that under current rules, a unit’s capacity can count as both synchronized reserves and more general primary reserves (which includes non-synchronized reserves), and that a unit would be compensated at a price that reflects providing each. For example, a unit can count as both $20/MW synch and $10/MW primary reserves and be paid a combined $30/MW. The amounts are calculated using “shadow prices” indicated by operating reserve demand curves (ORDCs) that are based on the probability of falling below the minimum reliability requirements for synch and primary reserves.

The shadow prices can vary extensively based on system circumstances, and even fall to $0/MWh, but the penalty factors are capped at $850/MWh. The payment, which is then also combined with a locational LMP, is designed to entice units to respond when called upon.

Shifting the Curves

PJM’s Angelo Marcino discussed staff’s thoughts on how the ORDC can be adjusted to give grid operators more operational flexibility but still make sure that activity is captured in the market. They had been considering developing an “extreme day” ORDC but are now looking at revising on a case-by-case basis to adjust the reserve requirement rather than the slope of the curve, he said. The changes would be classified as either “market” adjustments that are determined through PJM’s clearing engine or “out of market” adjustments that grid operators assign based on issues observed that are not modeled in the RTO’s software.

PJM would ensure real-time notification of the adjustments and be responsible for keeping a historical record of them.

PJM’s Lisa Morelli also discussed staff’s concerns that current reserve zone modeling of the RTO zone with the Mid-Atlantic Dominion (MAD) sub-zone “doesn’t always accurately reflect the constraints dispatch is most concerned with overloading,” which can exacerbate constraints and result in reserve prices that don’t accurately reflect system conditions.

PJM is recommending including nodal reserve pricing and flexible sub-zone modeling in the task force’s discussion. The RTO would define several reserve sub-zones but only tackle one at a time. They could be defined by three categories of constraints: reactive transfer interfaces; 345-kV or larger actual overload constraints; or contingency overloads exceeding the load dump limit on a facility that is 345 kV or larger. PJM would notify participants about their use as early as possible, but provide at least one day’s advance notice.

Each subzone would have its own ORDCs for synch and primary reserves that would remain consistent with the RTO-wide methodology. Staff confirmed that units that hadn’t been assigned for reserves and are offline for some other reason wouldn’t be eligible to receive primary reserve payments.

‘Philosophical Issues’

The proposal sparked discussion from stakeholders about the potential implications.

Susan Bruce, representing the PJM Industrial Customers Coalition, said she was “comforted” to hear that the issues the proposal is meant to address don’t happen often but said she has “philosophical issues” with the market ramifications.

“PJM benefits as a reserve-sharing concept,” she said.

Bresler’s comments about energy as a primary market prompted Roy Shanker, a consultant for several generators, to warn that when the energy and ancillary services markets become “large enough, the behavior of the demand curve has to be examined.”

Bresler agreed that the capacity market’s variable resource requirement demand curve and the energy market’s ORDCs are connected.

Bruce asked that PJM and its Independent Market Monitor attempt to find “areas of consensus” on the topic.

“As much as can be done to narrow those gaps, especially from a customer perspective, that would be highly valued,” she said.

Bresler said staff are “working pretty hard” with the Monitor to come to agreement and that “the sooner that happens, the better off we and the stakeholder community will be.”

PJM also remained noncommittal on Bruce’s request for simulations to see how the proposal shifts revenues between the capacity and energy markets.

“Certainly industrial customers are concerned given their high volume usage,” she said.

PJM staff expressed concerned that stakeholders would judge the proposals on the simulated outcomes rather than the logic of the methodology.

“We do want to have principled reasons for the changes we’re making,” Bruce said, but she added that insight into the potential impact “would be a useful tool … so we can make the right choices before it’s too late.”

James Wilson of Wilson Energy Economics, who consults for several member states’ consumer advocates, said he was interested in “understand[ing] the consequences at a nitty-gritty level, not at an aggregate level.”

Bresler said that could be helpful with the caveat that nothing can be extrapolated to suggest larger consequences.

The meeting concluded with PJM’s Vince Stefanowicz explaining the next steps for developing the real-time 30-minute reserves product. The operational justification and methodology for defining the procurement target were endorsed at the July meeting of the Operating Committee and are moving on to be considered by the Markets and Reliability and Members committees. (See “Real-time 30-minute Reserves,” PJM Operating Committee Briefs: July 10, 2018.)

The price formation task force will focus on pricing the reserve target and optimizing with other ancillary services, determining what resources are eligible and coordinating real-time dispatch, he said.

GT Power Group’s Dave Pratzon asked that the discussion include an analysis to identify why the reserve deficiencies are occurring in the first place.