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December 17, 2025

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MRC/MC Preview

Below is a summary of the issues scheduled to be brought to a vote at the Markets and Reliability and Members committees Thursday. Each item is listed by agenda number, description and projected time of discussion, followed by a summary of the issue and links to prior coverage in RTO Insider.

RTO Insider will be in Wilmington covering the discussions and votes. See next Tuesday’s newsletter for a full report.

Markets and Reliability Committee

2. PJM Manuals (9:10-9:30)

Members will be asked to endorse the following manual changes:

  1. Manual 11: Energy & Ancillary Services Market Operations and Manual 15: Cost Development Guidelines will be revised to correct a typographical error. The words “mileage ratio” will be replaced with “mileage” in Section 3.2.7 of Manual 11 and Section 2.8 of Manual 15, where the calculation of adjusted regulation performance cost is described. There is no change in PJM’s calculations, which have been correctly using mileage as it is defined by PJM.
  2. Manual 14A: Generation and Transmission Interconnection Process will be revised with the addition of a new section 1.14 regarding interim deliverability studies.
  3. Manual 14D: Generator Operational Requirements will be updated as part of an annual review and include changes reflecting North American Electric Reliability Corp. standard MOD-025-2.
  4. Manual 18: PJM Capacity Market will be amended to include details of the processes regarding maintenance outages for Annual Demand Response.

3. FTR/ARR Senior Task Force (FTRSTF) Problem Statement, Issue Charge and Charter (9:30-9:40)

Members may be asked to vote on changes in the scope of the Financial Transmission Rights Senior Task Force. The task force was formed to evaluate the causes for FTR underfunding and determine whether the current FTR and auction revenue rights processes to improve FTR funding levels. The proposed changes include an examination of the role of virtual transactions on revenue adequacy and proposed solutions by the Market Monitor.

4. Credit subcommittee Items (9:40-10:00)

Members will be asked to approve the following changes recommended by the Credit Subcommittee. The changes were approved by the Market Implementation Committee Sept. 3:

  • Risk Documentation Requirements – Remove the requirement that officer certifications be notarized and allow electronic submissions. Eliminate the requirement for annual submissions of risk policy documentation; PJM will accept certification that no substantive changes have been made since the last submission.
  • Peak Market Activity (PMA) Exclusions – Spot market energy, transmission congestion and transmission loss charges resulting from virtual transactions will be excluded from the peak market activity (PMA) credit requirement. Virtual transactions have their own credit screening rules. Screened export transactions also will be excluded from the PMA. The PMA is used to set baseline credit requirements for members based on historical activity.
  • Virtual and Export Transactions Credit Requirement Timeframe – Reduce the credit requirement timeframe for export transactions to two days from four days. The MIC approved a similar change in August for virtual transactions. (See PJM MIC OKs Settlement, Credit Changes.)
  • Demand Bid Volume Limits – PJM will establish a daily demand bid limit for each load-serving entity by transmission zone. Bids would be limited to the LSE’s calculated zonal peak load reference point for the day plus whichever value is more, 30% of the reference point or 10 MW. The 30% limit was based on analysis showing that the largest two-day-ahead zonal forecast shortfall from January 2013 through March 2014 was 28%.

PJM said the need for such limits was illustrated by the default of People’s Power & Gas in January. Due to an input error, the company entered a demand bid about 100 times the retailer’s load. Because demand bids are currently unlimited, bids exceeding actual load act as a decrement bid but lack the protections of the virtual transaction credit screen and minimum participation requirement.

5. Cap Review Senior Task Force (CRSTF) (10:00-10:30)

Members will vote on proposed changes to the $1,000 energy market offer cap.

Cost-based incremental energy offers would be limited to production costs as defined by Cost Development Guidelines plus 10% with no cap. Market-based offers would be limited to the greater of the cost-based offer or the offer cap for 30-minute notice demand response. Adders for frequently mitigated units (FMUs) and associated units (AUs) would not apply above $1,000/MWh. Market-based offers must be less than or equal to cost-based offers when cost-based offers are greater than the 30-minute DR offer cap.

The proposal won 63% support at the Cost Review Senior Task Force. If it does not win a two-thirds vote at the MRC, members may vote on an alternative proposal by Old Dominion Electric Cooperative and the Delaware Public Service Commission. It would allow offers above $1,000/MWh during Maximum Emergency Generation Alerts but would not allow the offers to set LMPs.

Members also will consider sunsetting the task force.

6. Capacity Senior Task Force (CSTF) (10:30-10:45)

Members will consider a proposed transition mechanism related to changes requiring more operational flexibility from DR providers. The change would allow curtailment service providers to designate previously cleared megawatts as “non-viable” — unable to meet the 30-minute-lead-time requirement. CSPs would be relieved of their obligations and have their capacity payments reduced.

The transition mechanism was developed to comply with the Federal Energy Regulatory Commission’s May 9 ruling on the DR changes (ER14-822).

Members also will consider sunsetting the Capacity Senior Task Force.

7. RPM: Capacity Import Limits – CTRs and ICTRs (10:45-11:00)

Members will vote on a problem statement and issue charge proposed by H-P Energy Resources to consider allowing qualifying transmission upgrades (QTUs) for capacity import limits. PJM instituted the limits on capacity imports in the May 2014 Base Residual Auction. (See Major Rule Changes Reduced Imports, DR.)

QTUs are currently allowed to increase the Capacity Emergency Transfer Limit (CETL) into locational deliverability areas (LDAs).

8. Transparency of TO Calculations (11:00-11:10)

Members will consider closing an issue relating to the transparency of the calculations transmission owners use for allocating energy, capacity and transmission costs. PJM has created a webpage listing the methodologies transmission owners use for calculating total hourly energy obligations (THEO), peak load contributions (PLC) and network service peak loads (NSPL).

The issue arose because some TOs have not filed tariffs disclosing the methodology they use. Some members complained that the lack of transparency made it difficult to ensure they were being properly charged. (See TOs Will Disclose Calculation Methodologies.)

Members Committee

2. CONSENT AGENDA (1:20-1:25)

  1. Members will consider proposed revisions to the Operating Agreement clarifying the definition of supplemental transmission projects. Under the proposed revision, a supplemental project is one that is not a state public policy project and is not required for system reliability, operational performance or economic criteria.

The change removes a reference to supplemental projects as “Regional RTEP” (Regional Transmission Expansion Plan) projects. It also clarifies that any reliability upgrades required as a result of the supplemental project are considered part of that project and are the responsibility of the entity sponsoring it.

  1. Members will be asked to endorse proposed Tariff revisions extending the deadlines for electric distribution companies (EDCs) to submit Power Meter and InSchedule data. The changes would allow load reconciliation data to be included in the calculation of balancing operation reserve deviation charges.
  2. Members will be asked to endorse proposed Reliability Assurance Agreement revisions to allow EDCs to submit corrections to peak load contribution and network service peak load assignments until noon on the next business day. The changes, which will also be reflected in Manuals 18 and 27, are intended to aid Pennsylvania EDCs squeezed by new Pennsylvania Public Utility Commission deadlines. (See PJM MIC OKs Settlement, Credit Changes.)

3. CREDIT SUBCOMMITTEE ITEMS (1:25-1:45)

See MRC agenda item #4, above.

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PJM Board Orders Filing on Capacity Parameter Changes

PJM’s Board of Managers will seek approval of changes in capacity auction parameters despite load-serving entities’ requests that it delay action pending consideration of staff’s Capacity Performance proposal.

The board ordered staff to file changes resulting from the Triennial Review of the parameters with the Federal Energy Regulatory Commission by the Oct. 1 deadline set by PJM’s Tariff.

In a letter to stakeholders late Wednesday, CEO Terry Boston said the board had endorsed staff’s proposed changes in the shape and position of the capacity demand curve, which a PJM analysis indicated could add $1.5 billion to annual capacity costs.

The board ordered staff to revise the proposal to retain the backward-looking energy and ancillary services (E&AS) offset rather than a forward-looking methodology staff had proposed. The board also decided to use the Independent Market Monitor’s proposed labor cost estimates in the calculation of the cost of new entry (CONE) instead of those recommended by PJM’s consultant, The Brattle Group.

In letters to the board last month, stakeholders representing load interests said the board shouldn’t consider the parameter changes — which failed to win stakeholder consensus Generators: Capacity Performance Unrealistic, Unfair.)

“Given the importance of the [Reliability Pricing Model] parameters in maintaining investment in infrastructure to sustain reliability over the long term, the board believes updates to these parameters are required,” Boston wrote. “The report presented by the Brattle consulting firm indicates the current variable resource requirement (VRR) curve shape does not properly reflect the varying importance of procuring capacity as the system becomes shorter or longer and that a more responsive curve shape is required.

“It is also clear that the cost of new entry values are outdated and require updates.”

E&AS

The PJM Power Providers (P3 Group), American Electric Power, Dayton Power and Light and FirstEnergy Service all urged the board to file the curve changes without delay. But they expressed concerns over staff’s proposal to switch to a forward-looking E&AS offset.

AEP, Dayton and FE said staff’s proposal lacked enough details to warrant adoption. “We would support ongoing dialogue about the merits of a forward-looking E&AS for implementation at a future date although we are not persuaded that the time is ripe for making this change,” they said.

The P3 Group said it would consider a forward-looking offset. But it said staff’s proposal “incorrectly calculates the future revenues expected by a generator and fails to recognize the necessity for making parallel reforms to use a consistent methodology for developing market seller offer caps.”

Dynegy, which urged the board to delay action on the parameter changes, also cited the “mismatch” between the forward-looking offset and the backward-looking offer cap. Dynegy also said the proposed offset could be distorted by illiquid forward markets and potential gaming of futures contracts.

Labor Costs

The board’s selection of the Monitor’s labor cost estimate ($4,179/MW-year for 2018) represents a 10% increase over the Brattle estimate ($3,788/MW-year).

In his letter, Boston acknowledged that the Triennial Review “has been a complex and, at times, contentious set of issues with strong feelings on all sides.” He said the board’s action was intended to “ensure long-term reliability at a reasonable cost.”

“We appreciate stakeholder concerns regarding the pending Capacity Performance discussion, but it is important to recognize that the installed reserve margin (IRM) calculations and the Brattle analysis already assume a higher standard of resource performance than was observed last winter,” Boston said.

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Generators: Capacity Performance Unrealistic, Unfair

Generators said yesterday that PJM’s expectations for its Capacity Performance product are unrealistic and its proposed penalties unduly punitive.

The remarks came during a nearly four-hour meeting in which PJM staff answered stakeholders’ questions and Market Monitor Joe Bowring provided details on the sensitivity analyses the Monitor is conducting on the proposal.

Capacity Performance resources would be required to guarantee their availability during Hot and Cold Weather Alerts and Maximum Emergency Generation Alerts. The resources would need to demonstrate they can produce their committed installed capacity for 16 hours for each of three consecutive days.

Resources would be allowed to include in their offers a risk premium based on the 7% pool-wide EFORd.

“To allow a premium above that would undo the incentives,” Chief Economist Paul Sotkiewicz explained. “There would be no incentive for [generator owners] to do anything [to improve performance]. They would just take a flier and hope they don’t get called.”

Jason Cox of Dynegy said PJM is attempting to make generators shoulder all risks, despite widely acknowledged challenges to obtaining gas during the coldest days of the winter.

“It sounds like PJM is not asking for a 7% EFORd unit, they’re requiring a 0% EFORd unit,” said Cox, citing the requirement that units be able to refill oil tanks during a polar vortex. “That seems unrealistic to me.”

PJM officials said they are taking steps to improve gas-electric coordination. PJM’s Chantal Hendrzak said staff is considering allowing generators to make intra-day changes in cost-based schedules to protect generators from having to accept the risk of gas-price volatility. Stakeholders also are considering changes in the $1,000/MWh offer cap, which some generators said their costs exceeded in January.

Non-performance Penalties

Capacity Performance resources that fail to deliver during the alerts would face a penalty based on the hourly LMP and the size of their shortfall. PJM proposed capping the penalties at 2.5 times the resource’s capacity revenues for the year.

Wind Chill Vs. Forced Outages (Source: PJM Interconnection LLC)Generation owners would be permitted to avoid or reduce penalties by producing uncommitted megawatts from a non-CP unit. The netting would be based on the value of the power replaced — reflecting the different LMPs of the two units — not by the volume.

PJM wants 85% of the summer peak demand met by Capacity Performance, with the remainder coming from existing Annual Capacity (renamed “Base Capacity”), Extended Summer and Limited Demand Response offerings.

Jason Minalga of Invenergy said generators unwilling to assume the risk of non-performance as a Capacity Performance resource would be “crowded out” of the market because of the 15% cap on non-Capacity Performance resources.

“Correct,” replied Andy Ott, PJM executive vice president for markets. “That’s an incentive to become Capacity Performance.”

“This is completely asymmetric,” responded Minalga, citing what he called the “heavy administrative” role of the RTO and Market Monitor in approving capacity auction offers.

James Wilson, consultant to state consumer advocates, said PJM’s assumption that no Base Capacity would be available during the winter peak was “overly conservative” and would result in excessive costs to load.

“We know [that assumption is] not right,” Wilson said. He suggested the use of a probabilistic analysis to estimate how much would be available.

PJM’s Tom Falin said the assumption was based on the risk at the 95% percentile of load. ”That’s the only level at which risk occurs,” he said.

Monitor’s Analysis

Bowring said he hopes to provide stakeholders next week with results from sensitivity analyses on how PJM’s proposal might affect clearing prices and quantities.

The Monitor said the analysis will look at three ways generators might improve their performance to meet PJM’s requirements:

  • Securing firm gas service (estimated at $180/MW-day)
  • Having dual-fuel capability with five days’ storage capacity ($48 to $165/MW-day)
  • Five-day firm no-notice gas service ($10/MW-day, annualized)

To address withholding concerns, Bowring recommended capacity providers be required to submit “coupled” offers with different prices for Performance and Base products.

Schedule

Stakeholders will have until Sept. 17 to submit written comments on the proposal. The next meeting on the initiative is scheduled for Sept. 24.

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UTC Trading Falls Following FERC Order

PJM Polling Members on Next Step

Up-to-congestion trading plummeted by about two-thirds this week following a Federal Energy Regulatory Commission order that could result in sharply increased costs for traders.

On Aug. 29, the commission ordered a Section 206 proceeding to determine whether PJM is improperly treating UTCs differently than increment offers and decrement bids in the interpretation of a forfeiture rule and in the application of uplift charges.

UTC Trading Volume Drops (Source PJM Interconnection LLC)UTC traders have pulled out of the market since Monday, when news of the proceeding was published in the Federal Register — triggering the clock on potential charges that UTC traders could face as a result of the FERC proceeding.

PJM saw both the volume of bids and MWh offered and cleared drop. Less than 500,000 MWh cleared yesterday, down from about 1.8 million the day before FERC’s order.

Attorney Ruta Skucas, who represents the Financial Marketers Coalition, had predicted the drop last week, saying that the market faced months of uncertainty while the case is pending.

The commission, which ordered — but did not schedule — a technical conference on the issue, said it expects to rule within five months after post-technical conference pleadings are submitted.

At a meeting of the Energy Market Uplift Senior Task Force yesterday, some stakeholders said the uncertainty could stretch out for years as occurred in MISO before it won FERC approval for its uplift rules, the Revenue Sufficiency Guarantee.

One trader told the task force he may have to resort to layoffs due to the uncertainty. “We’re not going to hemorrhage money waiting around” for a ruling, he said.

“Our traders have stopped trading as of yesterday,” said another.

But there was no consensus on how to avoid what one stakeholder called “the four years of paralysis” that MISO suffered.

Adam Keech, director of wholesale market operations, said PJM would like stakeholders to reach consensus on the UTC uplift issue so that the RTO can make a Section 205 filing before FERC weighs in. “We have this opportunity here to try to get ahead of it and try to influence FERC’s long-term interpretation on cost allocation,” he said. “I think that would be PJM’s preference.”

Some stakeholders, however, warned that in attempting a narrow Tariff filing, stakeholders might lose the opportunity for trade-offs that would be necessary for a broader, long-term solution.

Barry Trayers of Citigroup Energy said the task force should continue to follow the work plan it had before FERC’s order. “These are big questions and it’s very interwoven,” he said.

Noha Sidhom, general counsel for Inertia Power, said she was doubtful stakeholders would be able to reach a narrow agreement quickly, noting previous stakeholder efforts on the issue had been time-consuming and “very contentious.”

FERC’s order (EL14-37) came in response to a PJM filing in June defining UTCs as virtual trades and seeking to subject them to the RTO’s Financial Transmission Rights (FTR) forfeiture rule.

Assistant PJM General Counsel Steven Shparber said FERC’s “refund effective date” of Sept. 8 could apply to any rule changes regarding the FTR forfeiture rule. “Another plausible reading is that it also could apply to any uplift payments” later allocated to UTCs, he said.

Shparber said PJM does not plan to ask FERC for clarification on what would be covered under the refund. But he said “that could change” depending on the impact on market activity.

Lacking consensus, PJM will poll members beginning today on how they want to proceed. The options will range from seeking an expedited 205 filing to suspending EMUSTF’s work pending the outcome of FERC’s inquiry.

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PJM Under Scrutiny at FERC Uplift Hearing

By Rich Heidorn Jr.

upliftWASHINGTON – When the Federal Energy Regulatory Commission held a technical conference on capacity markets last year, many commenters pointed to PJM as the source of best – if imperfect – practices.

At FERC’s workshop yesterday on uplift and price formation, it was NYISO and MISO that speakers pointed to as the most forward-thinking.

PJM, meanwhile, was a target for criticism from market participants smarting over the $600 million uplift bill from January’s polar vortex.

A FERC staff report released last month said that PJM’s uplift ranked second among organized markets from 2009 to 2013, with charges increasing from about $0.50/MWh to more than $1/MWh over that period. (See FERC: PJM Uplift Ranks High Among RTOs, ISOs.)

Two dozen speakers discussed the causes and impacts of uplift, along with ways to reduce it, during the daylong session. All four FERC commissioners attended at least part of the forum, part of a broad inquiry on price formation that will continue Oct. 28 with a session on offer-price mitigation and offer-price caps (AD14-14).

Asked whether the workshops would lead to a rulemaking, Chairman Cheryl LaFleur said, “We’re keeping an open mind. We don’t have a predetermined next step.”

Robert Weishaar, representing the PJM Industrial and Load Coalition, said FERC “needs to restore public confidence in the existing uplift rules.”

“We still don’t know why we had an extreme blowout in January,” when as much as 22% of PJM’s generators failed to operate. He called for changes to PJM’s force majeure provisions, saying “you could drive a truck through them.”

Uplift Hurts Retailers

Although uplift represented only 1% of PJM’s total cost per MWh in 2013, energy retailers and financial traders said yesterday it has a much larger impact on their businesses.

Peter Fuller, New England director of regulatory and market affairs for NRG Energy, which serves 3 million retail customers, said uplift is “hugely damaging to our efforts to provide pricing predictability.”

Because uplift is not hedgeable, retailers have to estimate the costs, said Elizabeth Whittle, representing the Retail Electric Supply Association. “That works until you have a January 2014 polar vortex.”

In January, PJM had $177 million of uplift for deviations and $387 million for reliability resulting from operators’ conservative operations.

“If you were really good at [minimizing] deviations you could avoid” those charges, Whittle said. But there was no way to avoid reliability charges, she said. “The impact on retail [load-serving entities] was devastating.”

Other Impacts

Mark Smith, vice president of government and regulatory affairs for Calpine, said uplift discourages generation owners from making investments to make their units more flexible, such as reducing minimum run times.

Michael Schnitzer, representing Entergy Nuclear Power Marketing, said that by suppressing LMPs, uplift provides the wrong incentives for demand response and fast-ramping resources. “You’re missing price signals on cold days” that would spur dual-fuel generation and pipeline expansions, he added.

Financial Trader Leaves PJM

Wesley Allen, CEO of Red Wolf Energy Trading, said his small financial trading firm has abandoned the PJM market due to fears that up-to-congestion trades might soon be assessed uplift charges.

FERC last week ordered a review of PJM’s rules regarding UTCs, questioning why they — unlike increment offers and decrement bids — were not being assessed for uplift. (See related story, FERC Orders Review of UTC Rules, page 4.)

Allen, who spoke on behalf of the Financial Marketers Association, said PJM and ISO-NE unfairly charge uplift to virtual trades that don’t cause the problem. NYISO doesn’t charge uplift to virtuals, while CAISO, ERCOT and MISO net their virtuals, essentially eliminating their exposure, Allen said.

Allen compared uplift to a “gas guzzler” tax. In MISO, you get charged the tax if you drive a big sport utility vehicle, Allen said. “In PJM, they don’t care if you ride a bike. They don’t care if you take the bus. Everybody pays.”

Allen said PJM’s uplift charges dwarf the profits on virtuals, which average less than $1/MWh.

While uplift may be small for many, “for virtual traders it’s huge,” Allen said. “There’s just no other way around it.”

Transparency

Allen echoed PJM Market Monitor Joe Bowring’s call for more transparency on the causes and recipients of uplift.

Bowring said transparency could result in market-based solutions in some locations where individual generators receive millions in uplift payments. PJM had 19 generating plants receiving more than $10 million and 33 receiving at least $5 million in 2013, the 33 representing 82% of total uplift for the year.

Bowring has called on PJM to identify the generators receiving uplift, but PJM officials said they are prevented from doing so by confidentiality rules and would require a FERC order giving them approval. (See PJM Won’t Name Uplift Recipients.)

“The fact that we’ve had massive payments to the same units suggests that the market doesn’t know about it or is not reacting,” Bowring said. Transparency “is the only solution we can think of. If it remains secret, the market cannot self-correct.”

John Rohrbach, director of regulatory and market affairs for ACES, said confidentiality was intended to protect competition. “To the extent it is preventing competition from occurring, that is something that should be addressed.”

But David Patton, Market Monitor for NYISO, MISO and ISO-NE, questioned what solutions would result from transparency.

The upper peninsula of Michigan has been a persistent cause of uplift in MISO, he noted. “Everybody sort of knew what was happening. But nobody is going to do anything about it because there’s no product that someone can make a profit off of. You need products and you need pricing. Transparency alone I think will have limited impact.”

Role for RTEP

Bowring also said PJM should consider uplift when developing its Regional Transmission Expansion Plan. “As far as I can tell [uplift fixes] are not incorporated into RTEP,” he said.

Stu Bresler, PJM vice president of market operations, said the RTO can address such issues in the RTEP. He cited the RTO’s decision to add two transformers at the Wylie Ridge substation to eliminate use of Transmission Loading Relief procedures.

Planners “consider these uplift payments even if they’re not captured in LMP,” Bresler said. “It’s another signal that the system is chronically constrained.”

Bowring was not satisfied. “I don’t think it’s being done adequately now,” he said. “It’s not going to solve all uplift, but it can address those persistent problems when there’s a transmission solution.”

Bowring and Bresler also squared off over the issue of closed-loop interfaces, which PJM has begun using in the last year to capture in LMPs operator actions taken to address voltage problems. The RTO has also used them to get sub-zonal demand response to set price, which Bowring called an “inappropriate use of a closed-loop interface.”

Bowring also said the interfaces can have unintended consequences on Financial Transmission Rights funding and virtual bidding.

What other RTOs are doing:

Speakers pointed to NYISO’s “hybrid pricing” as a strategy that has reduced uplift. MISO recently won FERC approval for a new initiative, Extended LMP, which builds on the NYISO model.

Patton said he has recommended that MISO also introduce a local reserve product. RTOs also should change their hourly settlement policies to align them with the five- or 15-minute dispatch procedures, he said.

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Dust Settled, LaFleur Sees Improved Morale at FERC

lafleur
FERC Chairman Cheryl LaFleur in her office. Photo courtesy of FERC.

With a disruptive confirmation process behind her, Federal Energy Regulatory Commission Chairman Cheryl LaFleur said she believes morale at the agency is improving as she attempts to make progress on priority issues before she turns over the gavel to Norman Bay in April.

In an interview with RTO Insider last week after her return from a late August vacation, LaFleur said she is happy that the leadership succession is now clear. “After more than a year of uncertainty,” she said “now there’s clarity that I’m chairman.”

LaFleur said it was hard to judge the impact that the failed nomination of Ron Binz and the bruising confirmation of Bay had on the agency’s 1,500 staffers. “But I think people have a little spring in their step knowing we’re past that stage.

“We talk a lot about the commissioners, but you know there’s a body of employees at FERC that maybe don’t get enough love. I think their efforts are what keeps this place moving along.”

LaFleur was appointed acting chairman in November to replace Jon Wellinghoff. After LaFleur and Bay were confirmed by the Senate in July, President Obama removed the “acting” title from LaFleur. She will serve as the panel’s head until April 15, when Bay, formerly FERC’s director of enforcement, will become chair.

The unusual arrangement was the result of a deal by the White House to win support for Bay’s confirmation. Some senators were angry that Obama had signaled his intent to appoint Bay immediately as chairman over LaFleur, who has served on the commission since 2010. The last five FERC chairmen served a median of 30 months before becoming chair.

The removal of the acting title allowed LaFleur to promote David Morenoff to general counsel, a position he had been serving in an active capacity for nearly two years.

LaFleur declined to say whether she received any assurances from Bay that he would keep Morenoff on next year.

“I did discuss it with Norman. I discussed it with all my colleagues. But it was my decision,” she said.

“When Norman is chairman he’ll make such decisions as he makes. That’s not for me to say [whether Morenoff will remain]. I don’t think David will stop being terrific.”

PJM Capacity Proposal

LaFleur said she was unable to comment about the specifics of PJM’s Performance Capacity proposal, which will be submitted for FERC approval later this year. (See related story, PJM Members, Monitor Skeptical of Capacity Market Overhaul).

Instead, she pointed to FERC’s April 1 tech conference. “We talked conceptually about whether there were ways to price more fuel security into the electric product,” LaFleur said. “This is one of the hardest parts of the gas-electric coordination – that the gas and electric industries attract capital differently.”

EPA Carbon Rule

LaFleur said conversations with state commissioners suggests many states are open to regional collaboration as a way to reduce the cost of complying with the Environmental Protection Agency’s proposed cap on carbon emissions from existing generation.

“I do think we will see some regional collaboration in some places,” she said, noting the carbon trading systems in California and the Regional Greenhouse Gas Initiative, which includes New York, the members of ISO-NE and Maryland and Delaware in PJM.

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Operating Committee Briefs

PJM is considering identifying transmission operators that are chronically tardy in submitting outage tickets, officials told the Operating Committee last week.

PJM released an analysis that showed transmission operators submitted less than half of their outage tickets on time in the first seven months of 2014. Only 51% of tickets under the one-month rule (outages of five days or less) and 44% of tickets under the six-month rule (outages exceeding five days) were submitted on time. The late outage notifications repeated a pattern seen in 2013.

Many transmission operators were also slow to notify PJM when they cancelled outages. PJM had three days or more notice for only 54% of cancellations. About 42% of the notifications came the day of or one day before the scheduled outage.

PJM shared only aggregate data with the committee, with no individual TOs identified. But Mike Bryson, executive director of system operations, said the identities may be made public in the future to address “habitual” late filers.

Dave Pratzon of GT Power Group noted that NYISO recently began assessing TOs for uplift costs resulting from late outage notifications and cancellations. “Suddenly, performance got a lot better,” Pratzon said.

NYISO spokesman Ken Klapp said the ISO’s day-ahead congestion residual balancing shortfalls are allocated 100% to the transmission owner of the line that is out of service. “From a market design perspective, this approach creates a financial incentive for transmission owners to minimize transmission outages,” he said.

In total, PJM received 11,342 outage notices in the first seven months, a 7% increase over the same period in 2013. About 9% of the outages in 2014 resulted in congestion, PJM’s Lagy Mathew said.

New Frequency Response Rule Requires Improved Performance by Generators

operating committeePJM will begin contacting generation operators this fall to ensure the RTO’s compliance with a new frequency response reliability standard that takes effect April 1.

Standard BAL-003, approved by the Federal Energy Regulatory Commission in January, measures primary frequency response 20 to 52 seconds after the start of an event. The rule establishes a minimum frequency response obligation for each balancing authority, provides a uniform calculation of frequency response, establishes frequency bias settings and encourages coordinated automatic generation control (AGC) operation. (See FERC OKs Rules on Geomagnetic Disturbances, Frequency Response.)

In 2013, non-nuclear steam units provided more than 90% of generator frequency response, PJM senior engineer Brad Gordon said during a presentation to the OC. Units scheduled for retirement or considered at risk were responsible for about 20% of generator response. “That’s something we need to address and to monitor,” Gordon said.

Gordon said PJM will be looking more closely at individual generator performance and requesting generators other than nuclear units to set their dead bands to ≤36 MHz with a maximum 5% droop. “We have performance. We’re not sure where it’s coming from,” he said.

PJM to Wait on SPP Decision on Combined-Cycle Model

PJM wants more price certainty before it considers moving ahead with more sophisticated modeling of combined-cycle plants.

Currently, combined-cycle generators must be entered into eMKT as either a combustion turbine or steam unit. Neither option captures these plants’ true capabilities, which can vary greatly based on unit configurations and use of duct burners.

PJM is considering software from Alstom that officials initially thought would cost about $1 million.

Southwest Power Pool has a prototype of the Alstom model in production but balked at moving into full-scale implementation after the projected price tag rose to $7 million, PJM’s Tom Hauske told the OC last week. “That’s significantly more than what we thought this might cost,” Hauske said.

SPP is attempting to conduct a cost-benefit analysis before deciding whether to proceed, Hauske said.

PJM’s Market Monitor told the OC last month that better modeling would allow operators to use combined-cycle units more efficiently but that it had been unable to quantify the benefits with any certainty. (See Combined-Cycle Model’s Cost, Benefit Uncertain.)

Bryson said PJM is waiting to see the results of SPP’s analysis before making a decision. “Right now we’re on at least a short holding pattern,” he said.

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Planning Committee Briefs

Stakeholders have expressed near unanimous support for new requirements for enhanced inverters serving solar generators and other asynchronous generation. All but one of 69 stakeholders polled said they support a requirement that enhanced inverters be able to automatically reduce active power in response to high system frequency or increase active power when system frequency is low.

The rule, which the Planning Committee will consider Oct. 9, would also require inverters to autonomously provide dynamic reactive support within a range of 0.95 leading to 0.95 lagging at inverter terminals.

Enhanced inverters must also adhere to North American Electric Reliability Corp. standard PRC-024 regarding voltage and frequency ride through and have the ability to limit ramp rates.

The rule would apply to inverter-based asynchronous generators with an interconnection service agreement or a wholesale market participation agreement. It would not apply to merchant transmission facilities, high voltage DC inverter-converter facilities, existing generation or generation already in the new service queue.

PJM hopes to win stakeholder approval in time to file the rule with the Federal Energy Regulatory Commission in February.

TOs to Present Criteria Changes to PC

Transmission operators will brief the Planning Committee on all future planning criteria changes under a new policy announced last week by PJM officials. Although TOs already file such changes with FERC, Paul McGlynn, general manager for system planning, said the new procedure is an effort to increase transparency.

The first TO to participate in the new procedure is Dominion Resources, which briefed Planning Committee members last week on its new method for determining the “end of life” for transmission infrastructure. Facilities will be considered at the end of their life when they become at risk for failure and continued maintenance or refurbishment is not a viable option to ensure system reliability.

The designation will depend on factors including the manufacturer’s recommended service life and the facility’s performance history.

Once an end-of-life designation has been assigned to a facility, its deletion becomes part of PJM’s base case for transmission studies.

PJM will order transmission upgrades to address any reliability problems caused by the facility’s removal — similar to the reliability analyses the RTO performs in response to generator retirement announcements.

No Change in Preliminary IRM Results

planning committeePJM expects to leave its Installed Reserve Margin at 15.7% for planning year 2018, unchanged from 2017.

A preliminary reserve requirement study shows the need for a 0.1% increase based on the PJM load shape and another 0.1% from capacity model changes. But these increases are offset by a 0.2% expected increase from imports under PJM’s capacity benefit margin.

The analysis shows a slightly lower loss-of-load expectation for the peak week — the third week of July — and slightly higher risk the following week than in 2017.

The PC will vote on the recommended IRM Oct. 9.

Planners Seek Info on DCB Line Protection Schemes

PJM planners are asking the PJM Relay Subcommittee to provide an inventory of all directional comparison blocking (DCB) line protection schemes on 500-kV lines. The request is in response to a stakeholder’s concern that DCB schemes are prone to overtrips that can cause system instability.

Officials said the initial inventory, due Sept. 30, will likely be followed by a request for information on such schemes on 345-kV lines.

PJM will simulate DCB overtrippings to determine their impact on system performance and may order baseline transmission upgrades as a result.

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NYISO Sees Capacity Crunch by 2019; Tx Problems in 2015

By William Opalka

nyiso

Locations of transmission security needs. (Source: NYISO)

Some areas of New York could face transmission violations as soon as next year and capacity shortages are likely by 2019 — one year earlier than expected — according to NYISO’s latest Reliability Needs Assessment.

“These reliability needs are generally driven by recent and proposed generator retirements or mothballing combined with load growth,” the report says.

Transmission security violations could occur as soon as next year in Rochester, Western & Central New York, the Capital Region, the Lower Hudson Valley and New York City.

Generation resources needed to keep reserve margins above 17% will fall short in about 2019 and get worse from then on, the document states. This is a year earlier than the ISO’s 2012 assessment predicted. “The most significant difference between the 2012 RNA and the 2014 RNA is the decrease of [New York’s] capacity,” the new assessment says.

This summer’s Installed Capacity Reserve was at 122.7%, well above the 117% margin reserve requirement. But the new report shows the ISO’s 2019 margin as 2,100 MW less than what was expected in the 2012 report. The change resulted from increased load growth and a decline in capacity resources and special-case resources — end-use resources that can be interrupted on demand.

The NYISO Management Committee approved the analysis, the first step in assessing the state’s reliability needs from 2015 to 2024, on Aug. 27. The Board of Directors will review the report in October, after which the ISO will issue requests for solutions from transmission operators and developers.

Additional generation plants could delay the shortfall beyond 2019, NYISO said.

Some of the transmission constraints in western New York would be mitigated by the repowering of the mothballed Dunkirk power plant. State regulators and plant owner NRG have agreed on a plan to convert the former coal plant to 435 MW of natural gas-fired electricity in late 2015.

NYISO also expects market rule changes, such as the creation of a new capacity zone in the Lower Hudson Valley, to entice generation owners to add additional capacity in Southeastern New York. Opponents say the zone represents a windfall for existing power plant owners, who will benefit long before any new generation plants are built.

The ISO said generation capacity could be reduced more than expected as a result of the Environmental Protection Agency’s Mercury and Air Toxics Standard, which takes effect next year, and proposed caps on carbon emissions.

Compared with the previous assessment, the new report predicts the following for 2019:

  • Capacity resources decline by 874 MW (724 MW upstate and 150 MW in SENY)
  • Baseline load forecast increases by 250 MW (497 MW higher upstate and 247 MW lower in SENY)
  • Special-case resources drop 976 MW (685 MW upstate and 291 MW in SENY).
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MIC Briefs

The Market Implementation Committee last week approved the following changes recommended by the Credit Subcommittee:

  • Risk Documentation Requirements – Remove the requirement that officer certifications be notarized and allow electronic submissions. Eliminate the requirement for annual submissions of risk policy documentation; PJM will accept certification that no substantive changes have been made since the last submission.
  • Peak Market Activity (PMA) Exclusions – Spot market energy, transmission congestion and transmission loss charges resulting from virtual transactions will be excluded from the peak market activity (PMA) credit requirement. Virtual transactions have their own credit screening rules. Screened export transactions also will be excluded from the PMA. The PMA is used to set baseline credit requirements for members based on historical activity.
  • Virtual and Export Transactions Credit Requirement Timeframe – Reduce the credit requirement timeframe for export transactions to two days from four days. The MIC approved a similar change in August for virtual transactions. (See PJM MIC OKs Settlement, Credit Changes.)
  • Demand Bid Volume Limits – PJM will establish a daily demand bid limit for each load-serving entity by transmission zone. Bids would be limited to the LSE’s calculated zonal peak load reference point for the day plus whichever value is more, 30% of the reference point or 10 MW. The 30% limit was based on analysis showing that the largest two-day-ahead zonal forecast shortfall from January 2013 through March 2014 was 28%.

micPJM said the need for such limits was illustrated by the default of People’s Power & Gas in January. Due to an input error, the company entered a demand bid about 100 times the retailer’s load. Because demand bids are currently unlimited, bids exceeding actual load act as a decrement bid but lack the protections of the virtual transaction credit screen and minimum participation requirement.

Sampling to Replace Outdated Studies for
DR in Synchronized Reserve Market

The MIC heard a first read on proposed rules that would allow use of statistical sampling to calculate the performance of residential demand response resources providing synchronized reserves. The sampling would apply to homes without meters reporting data hourly or in shorter intervals.

The samples will be stratified to group like resources by characteristics including end-use device (e.g. air conditioners, water heaters), curtailment measures (50% cycling, 100% cycling, thermostat set point) and geography.

The sampling results would have to show an error rate of less than 10% at a 90% confidence level.

The sampling would replace outdated studies such as the Deemed Savings Estimate Report, which is based on data from 2001–2005 from zones in Maryland and New Jersey. Since then, PJM’s footprint has grown to include Kentucky and Chicago, and air conditioners and other appliances have become much more efficient.

Sampling is a way to improve accuracy without the cost of installing one-minute meters on every participating household, PJM said.

The rule would take effect June 1, 2015 with a transition mechanism for resources that cannot meet new requirements for delivery years 2016 through 2018.

Pricing Interface Ordered at Warren, Pa.

micPJM instituted a closed-loop interface at Warren, Pa., in the Penelec zone to set real-time LMPs for when operators take actions to address voltage problems. The interface, effective Sept. 2, is being modeled in the day-ahead market and financial transmission right auctions and is expected to help minimize FTR underfunding. There is no end date.

The affected region is within the larger Seneca interface created in February. (See New Pricing Interface in PA Feb. 1.)

PJM also provided additional details about the Black River interface that took effect Sept. 1. PJM’s Joe Ciabattoni said the interface, which was instituted to address voltage or thermal issues resulting from a transmission outage, is unlikely to be implemented before it expires Oct. 31 because of forecasts for mild temperatures.

“Ninety-five-plus degree days is what this is targeted for,” Ciabattoni said. “I highly doubt we’ll use it.”

In response to calls for more transparency, Ciabattoni said PJM will notify members whenever it is “seriously considering” adding a new pricing interface. “We do a lot of thinking about things that don’t go anywhere,” he explained.

PJM Gains $200K in Settlement Adjustments

PJM will receive a net $212,000 from MISO as a result of two market-to-market settlement adjustments.

The cancellation of a scheduled outage on the Monticello–East Winamac 138-kV line on July 7 and 8 resulted in a recalculation of firm-flow entitlements and a refund from MISO to PJM of $733,611. A modeling error by PJM resulted in incorrect calculations regarding the Pleasant Prairie–Zion 345-kV line for several days in June. PJM will refund $521,193 to MISO.