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December 8, 2025

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State Briefs

PSC Gives Go-Ahead for Out-of-State Tx Ownership

The Public Service Commission has ruled that out-of-state companies can build and own transmission lines in the state, clearing the way for PJM to move forward with a solicitation process to upgrade lines delivering power from New Jersey’s Artificial Island nuclear complex. (See related story, Two of 4 Artificial Island Finalists Offer Cost Caps.)

The PSC’s opinion clarifies ambiguities in state law. One of four companies seeking to upgrade the transmission lines, Northeast Transmission Development, asked the PSC to make a determination.

PJM’s effort to upgrade the lines is the first time the transmission operator used FERC’s Order 1000 solicitation process, but it advised the four project finalists to seek a PSC opinion to resolve the legal uncertainty.

More: The News Journal

INDIANA

Court Rules Duke Fees for Gas Plant Wrong

The Court of Appeals has ruled that state regulators should not have allowed Duke Energy to recover $61 million from customers for costs of building the Edwardsport coal gasification plant. The court ruled that the Utility Regulatory Commission didn’t conduct a comprehensive analysis before awarding the fees to Duke.

More: The Indianapolis Star

MARYLAND

Exelon Facing Mounting Demands for Approval of Pepco Takeover

ExelonA group wants half of Pepco’s profits to be linked to performance standards in exchange for approval of its planned merger with Exelon.

The newly formed Coalition for Utility Reform wants the Public Service Commission to require “half of the merged entity’s profit to be determined by its ability to meet standards related to cost minimization, reliability, customer satisfaction, carbon reduction and environmental stewardship, distributed energy resources, customer control, and innovation.”

“This broad coalition recognizes that the current utility system is broken,” said Montgomery County Councilmember Roger Berliner, who filed the petition. The coalition plans to become an official intervener in the case.

Another group called PowerUpMontCo is asking for “a multi-billion dollar investment of capital into the infrastructure to bring Pepco’s long-neglected and dilapidated distribution system up to top-quartile service performance levels.”

Pepco shareholders are meeting to vote on the merger today.

More: BethesdaNow; The Washington Post

Woman Challenges Pepco on Meter Charge Issue

PepcoA retired attorney from Chevy Chase is challenging Pepco’s rules requiring customers who don’t want a smart meter to pay a charge.

Deborah A. Vollmer, who fears that smart meters cause health problems and a loss of privacy, has refused to pay the opt-out fees. Pepco charges customers who decline a smart meter a $75 up-front fee plus $14 month. About 1,060 customers have declined to get the meters installed, but Vollmer is the only one who refused to pay.

Jonathan Libber, president of Baltimore-based Maryland Smart Meter Awareness, likened the opt-out fees to “protection money” that businesses pay to the mob. The organization seeks to educate the public about the potential dangers of smart meters and wireless devices generally.

More: The Gazette

NEW JERSEY

Christie Names 2 to BPU Posts

Richard Mroz (Source: University of Delaware)
Richard Mroz (Source: University of Delaware)

Gov. Chris Christie named a Republican attorney and longtime friend as president of the Board of Public Utilities last week.

Richard Mroz, former chief counsel for Gov. Christine Whitman’s administration, would replace Dianne Solomon as head of the five-member board. Christie and Mroz were classmates at the University of Delaware. Christie previously named him to the Delaware River & Bay Authority in 2012.

Christie also nominated seven-term state Assemblyman Upendra Chivukula to fill a vacancy on the BPU. Chivukula, a Democrat, would step down from the legislature if confirmed to the utilities board.

The state Senate is expected to act on the nominations this week.

More: NJ.com

NORTH CAROLINA

Coal Ash Law Goes in Effect Without McCory’s Signature

A new law requiring more stringent management of coal-ash ponds at power plants went into effect last week without Gov. Pat McCrory’s signature.

Lawmakers approved the bill last month in response to public uproar after a dam at one of Duke Energy’s coal ponds failed earlier this year, spilling 39,000 tons of ash into the Dan River. State law calls for the governor to either sign the law or veto it within 30 days.

McCrory, a former Duke employee, did neither. The governor said he thinks the bill violates his power and the state constitution and that he will ask the state’s Supreme Court to review it.

More: Greensboro News & Record

OHIO

DPL Sells Share of Plant to Duke Energy Kentucky

The Public Utilities Commission approved Dayton Power and Light’s plans to sell its 31% share of the 650-MW East Bend coal-fired power plant to Duke Energy Kentucky. PUCO agreed that the transaction will allow both utilities to better serve their customers.

Duke Energy will be sole owner of East Bend, giving it a hedge against the 2015 retirement of its 163-MW plant at Ohio’s Miami Fort Station. The sale needs the approval of the Kentucky Public Service Commission, which is expected by the end of the year.

More: Utility Dive

AEP Spending $21M on Tx Upgrades for Shale Gas

American Electric Power plans a $21 million transmission-system upgrade to provide more power to two large oil and gas pipeline companies that are expanding operations in the state’s shale-gas region. The Public Utilities Commission has approved the project, which will upgrade the 69-kV line in Jefferson and Harrison counties to 138-kV.

AEP says it is responding to requests for more power from M3 Midstream and Access Midstream Partners. Shale-gas drilling has increased demand for electrical power at a rate unseen in the past.

“Most industrial load you can plan 18 to 24 months in advance,” said Dan Recker, AEP’s managing director of transmission engineering. “This is much faster than that. They were needing [electric] service in weeks instead of several months, and that really presented some challenges from a process standpoint.”

More: Columbus Business First

PENNSYLVANIA 

PUC Approves PPL’s New Time-of-Use Program

The Public Utility Commission has approved PPL’s pilot time-of-use program that is aimed at inducing customers to shift their energy use to off-peak hours to help meet the state’s energy-efficiency mandates.

The PUC approved PPL’s plan, which allows customers to sign up with third-party suppliers to get electricity at rates that adjust between off-peak and on-peak hours. The plan goes into effect Dec. 10.

The time-of-use rates should help PPL to comply with Act 129, a 2008 law that requires the state’s largest electric distribution companies to develop conservation plans to reduce consumption and shift load from peak hours.

More: Lehigh Valley Business

Pike County L&P, PUC Agree on New Rates

The Public Utility Commission approved a settlement allowing Pike County Light & Power to increase revenue by 12.8% or $1.25 million, less than the $1.7 million the company originally sought.

The boost will increase rates for a typical residential customer by 16.2%, or from $93.06 a month to $108.10. The company has about 4,600 customers in Pike County in Northeastern Pennsylvania.

More: Public Utility Commission

VIRGINIA

Utility’s Plan for Surcharge Irks Home Solar Customers

Appalachian Power’s plans to assess a fee on residential customers who have solar power systems has irked renewable power advocates.

The utility’s “standby charges” would cost customers with solar or wind systems connected to the grid about $3.77 per kilowatt per month. The fee would apply only to customers with systems rated between 10 kW and 20 kW, fairly large by residential standards.

State law allows for the charges if a utility can justify them, but some argue that Appalachian hasn’t proven its case. Appalachian says that customers with larger solar power systems are benefitting from the grid but aren’t paying to maintain the system.

More: The Roanoke Times

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FERC Commissioners at Odds over ISO-NE Capacity Auction

Clark, Bay Would Throw Out Results

The Federal Energy Regulatory Commission yesterday called for changes in ISO-NE’s capacity market rules, but split over whether it should reject the results from the ISO’s February auction due to unchecked market power.

Republican Tony Clark and Democrat Norman Bay called for FERC to reject the auction results, but Chairman Cheryl LaFleur and Republican Philip Moeller said the commission should seek only prospective changes in the auction rules. Because of the 2-2 deadlock, the 2017-18 auction results “became effective by operation of law” (ER14-1409).

In a separate docket (EL14-99), the commissioners unanimously ordered the ISO to defend its current auction rules or submit Tariff revisions creating a process for reviewing importers’ capacity offers and mitigating any market power. The commission set a 30-day deadline for the ISO’s response.

$3 Billion

The ISO’s eighth Forward Capacity Auction (FCA) resulted in a sharp price increase after nearly 3,000 MW of capacity submitted retirement requests. Fearing they would have less capacity offered than required, ISO-NE officials applied administrative price rules to the auction.

fcaNew resources in the Maine, Connecticut and Rest-of-Pool Capacity Zones will be paid $15/kW-month while existing resources in those zones will receive an administrative price of $7.025/kW-month. Both new and existing resources in the NEMA/Boston Capacity Zone will be paid $15/kW-month.

The ISO said total capacity costs for 2017/18 would be $3.05 billion, almost double the previous high ($1.77 billion in 2009).

Unlike other RTOs, ISO-NE’s capacity auction results are subject to commission review under the just and reasonable standard — the result of a 2006 settlement to address stakeholder concerns over the market design.

Clark and Bay issued a joint statement saying the auction results should be rejected and the matter set for a fast-track hearing and settlement procedures.

“Here, there is evidence suggesting the exercise of market power, and it is uncontroverted that the market power, if it existed, was not mitigated,” Clark and Bay said. “Moreover, it is possible that ISO-NE may have violated its Tariff in the way it conducted the auction. On this record, we do not believe that ISO-NE has carried its burden of establishing that the auction results are just and reasonable.”

LaFleur and Moeller said they would have approved the auction results because the ISO followed the rules previously judged just and reasonable.

“My objecting colleagues raise a valid point, that is, can an auction process that has previously been found to be just and reasonable produce results that are not just and reasonable? While such circumstances are not common, the answer is most certainly yes,” Moeller said in a statement. “However, in this case, while the prices resulting from FCA 8 were much higher than in prior auctions, the existence of very tight supply and demand fundamentals are primarily responsible for the FCA 8 results.”

After-the-Fact Ratemaking

In her statement, LaFleur said Clark and Bay’s position — that the commission not only determine whether the auction rules were followed but also assess whether the resulting rates were just and reasonable — would violate commission precedent and subject auction participants to “regulatory uncertainty or after-the-fact ratemaking.”

“I believe that respecting the established expectations of market participants as to the operation of the auction will be critical to the future ability of the FCM [Forward Capacity Market] to attract resources needed for reliability,” LaFleur said. “If market outcomes are accepted during times of excess capacity when the auction clears at the price floor, but the commission-approved auction rules are subject to retroactive revision when capacity is tight and market capacity prices are high, the long-term viability of the market is undermined.”

Even if the commission had authority to retroactively change the auction rules, LaFleur said, “The alternative approach begs the question of how to set the auction rates. Upon rejecting the existing, commission-approved auction rules, the alternative approach offers no guidance for establishing a just and reasonable replacement rate. This would be true whether the new rate were to be established by ISO-NE, the commission or a judge, because the only way to obtain a different rate is to change the underlying auction rules.”

Clark and Bay said LaFleur’s position “renders illusory the commission’s prior assurance [in approving the 2006 settlement] it would undertake a ‘thorough review of the final auction clearing prices.’”

“This alternative theory, to which we cannot subscribe, requires the commission to ignore the clear terms of the FCM settlement which the commission itself approved, and also requires the commission to accept as a fait accompli whatever price outputs are generated from the auction,” they wrote. “Under such a theory, not even allegations of unmitigated exercises of market power, nor referrals by a market monitor, could be taken into consideration by this commission, no matter the harm imposed on consumers.”

Unlike the first seven auctions, New England faced a capacity shortage entering FCA 8 after 3,135 MW of capacity, including the 1,535-MW Brayton Point generator, sought to retire before delivery year 2017-18. The retirement announcements came after the qualification deadline for new resources seeking to participate in the auction.

Instead of an expected surplus of more than 2,000 MW, the ISO went into the auction more than 1,000 MW short of its net Installed Capacity Requirement.

The ISO acknowledged that in “situations with limited excess supply, participants with a large amount of that supply are likely to recognize that they can be pivotal and set the auction price. Indeed, participants [in FCA 8] may have already been aware of the situation due to the publicly available information provided prior to the auction.”

Order to Show Cause

The commission’s Order to Show Cause is focused on rules specifying the Independent Market Monitor’s authority for reviewing offers from capacity imports.

The ISO’s Tariff requires its IMM to review import offers and reject any that the Monitor determines “may be an attempt to manipulate” the auction.

The commission said the Tariff limits the review to the qualification process, “and it only involves ensuring that the behavior of import resources was consistent with their actions in previous FCAs, rather than evaluating the bids of import resources for consistency with their net risk-adjusted going-forward costs, as is done for the offers of other resources.”

“Given the changing balance of supply and demand in New England,” the commission said, that provision “may be insufficient to ensure just and reasonable rates.”

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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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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.