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October 31, 2024

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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.

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Appeals Court Scolds FERC over West Deptford Interconnection Dispute

The D.C. Circuit Court of Appeals vacated the Federal Energy Regulatory Commission’s ruling in a dispute over interconnection costs in PJM, calling the agency’s action “the very essence of unreasoned and arbitrary decision-making.”

At issue is whether the developers of a generating plant in West Deptford, N.J., should be liable for transmission improvements ordered before the developers entered PJM’s interconnection queue.

West Deptford Energy joined the queue in 2006 and was informed it would be assessed $10 million for improvements PJM ordered as a result of previous projects, including one that was later cancelled. In 2008, PJM won FERC approval to change the section of its Tariff that related to liability for prior transmission upgrades.

If the 2008 Tariff applies, West Deptford will not be liable for the cost; if the 2006 Tariff controls, West Deptford will have to pay the bill.

FERC ruled that West Deptford must pay “since, at the time when West Deptford entered the PJM interconnection queue, that provision was the one that established its financial responsibility.”

But the commission referred to the 2008 Tariff in ruling that West Deptford’s request for auction revenue rights was “not ripe.”

“The question in this case is, when a utility filed more than one rate with the commission during the time it was negotiating an agreement with a prospective customer, which of the two filed rates governs: the rate at the time negotiations commenced or the rate at the time the agreement was completed?” the court said (Case No. 12-1340).

“West Deptford argues that, as a matter of practice, the commission has used the rate on file at the time the agreement was finalized. The commission is of the view that it can pick and choose which rate applies on a case-by-case basis.”

The court vacated the commission’s ruling against West Deptford, saying it “has provided no reasoned explanation for how its decision comports with statutory direction, prior agency practice or the purposes of the filed rate doctrine.”

It ordered FERC to provide an “explanation consistent with” the court’s ruling.

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PJM Expense Rate Unchanged in 2015 Budget

budgetPJM expects to spend $276 million in 2015, a 2% increase over 2014, according to a preliminary budget outlined to members last week. The spending plan will result in a charge of $0.32/MWh, a rate that hasn’t changed since 2011.

The budget anticipates revenues of $283 million, a $1 million reduction from PJM’s 2014 forecast. PJM plans $30 million in capital spending, unchanged from 2014. Nearly two-thirds of the spending is for enhancements to existing applications and systems.

The Finance Committee will consider the budget Sept. 17, with the Board of Managers making the final decision on the plan Oct. 30.

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Split Panel Recommends Lifting $1,000 Offer Cap

A PJM task force has recommended lifting the $1,000 cap on cost-based energy offers, but the margin suggests the proposal may have a tough time winning final stakeholder approval.

The proposal would limit cost-based incremental energy offers to production costs allowed under the cost development guidelines plus a 10% adder up to a maximum of $90/MWh. Adders for frequently mitigated units (FMU) and associated units (AU) would not apply above $1,000/MWh.

To mitigate market power, market-based or price-based offers would be required to be less than or equal to cost-based offers when cost-based offers are greater than $1,000/MWh.

The proposal was the only one of three to win majority support in a vote of the Cap Review Senior Task Force. But its 57% support is below the two-thirds threshold needed to win endorsement by the Markets and Reliability Committee, where sector-weighted voting often results in less support than in lower committees.

Two other proposals failed to win backing from more than 25% of the task force.

One would keep the $1,000 offer cap but create a review process allowing PJM and the Independent Market Monitor to approve costs above it without a waiver from the Federal Energy Regulatory Commission. Cost offers exceeding $1,000 would be compensated via uplift with no 10% adder.

The third proposal would allow recovery of incremental, start-up and no-load costs and day-ahead gas costs based on an index. All offers would be reviewed after the fact. The 10% adder would decline as the cost offer rises, being eliminated above $1,000/MWh. Cost-based offers greater than $1,000/MWh also would not include FMU/AU adders.

Stakeholders agreed to consider lifting the cap after some gas-fired generators reported that their operating costs exceeded $1,000/MWh when natural gas prices spiked during January’s extreme weather. (See Effort to Lift Offer Cap Advances After Debate.)

At a presentation before the MRC Thursday, Carl Johnson, representing the PJM Public Power Coalition, expressed concern that two of the proposals, including the one recommended by the task force, propose using a gas index instead of actual gas costs.

“One or two units with higher prices because of pipeline constraints could set LMPs,” he said. “When we take the $1,000 [cap] away we have the opportunity to exacerbate the error.”

Raghu Sudhakara of Rockland Electric said eliminating the cap would raise market power concerns. “It incentivizes generators to move away from dual-fuel capability and more to spot gas pricing because they are guaranteed cost recovery,” he said.

Jim Benchek of FirstEnergy said he’d like to see the task force continue to work on a rule change that applies to market-based offers, even if it is unable to reach consensus for the coming winter.

Market Monitor Joe Bowring said he believed the task force’s proposal addressed market-based offers by saying they cannot exceed cost-based offers.

The Monitor’s proposal, which failed to win consensus in the task force, would have permitted cost-based offers to exceed $1,000 while excluding the 10% adder. Price-based offers would be limited to no more than cost-based offers.

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State Briefs

PSC Delays Vote on Delmarva Reliability Plan

The Public Service Commission delayed a vote on Delmarva Power & Light’s infrastructure improvement plan until Exelon completes its acquisition of Delmarva’s parent company, Pepco Holdings Inc. PSC staff was critical of Delmarva’s five-year, $397 million plan to improve its distribution system, calling it too expensive, considering the utility’s good reputation for outage management. The commission said it would consider the plan three months after the merger’s close, which the companies anticipate in the second or third quarter of 2015.

More: The News Journal

ILLINOIS

Sierra Club Files New Challenge to FutureGen

FutureGenSourceWikiThe controversial $1.65 billion FutureGen clean-coal demonstration project is facing new challenges, despite recently receiving approval to charge consumers for the yet-to-be-built project’s output. The Sierra Club has refiled a complaint with the state Pollution Control Board, saying the project needs additional permits because it is a plant retrofit, rather than completely new construction. The plant, which would capture carbon dioxide and then dispose it underground, is supported by a $1 billion federal economic stimulus grant. Under the American Recovery and Reinvestment Act, that money must be spent by the end of September 2015. But FutureGen CEO Ken Humphreyssays investors won’t commit financing while the air permit challenge is unsettled.

More: Midwest Energy News

Fossil Plants to ICC: We’ve Done Our Part

A group of owners of coal- and gas-fired power plants told the Illinois Commerce Commission that they’ve already taken about all the steps they can to reduce carbon emissions, and that the new Environmental Protection Agency’s carbon emission rule should be aimed elsewhere. Dean Ellis, a Dynegy official, said installing emissions-control equipment makes plants less efficient and isn’t the answer. An NRG official agreed. “A more cost-effective approach for Illinois is likely to include the voluntary [switch to natural gas] of inefficient coal plants, augmented by the competitive development of renewable energy, energy efficiency and distributed energy resources,” said Barry Matchett, NRG’s director of external affairs. The ICC is developing regulations to ensure that Illinois can meet the new EPA standards.

More: Chicago Tribune

INDIANA

IPL to Convert Aging Plant to Natural Gas

IndianaPowerandLightLogoSourceIPLIndianapolis Power & Light will ask state regulators to allow it to convert the last unit of an aging coal-fired power plant in Indianapolis to natural gas as part of the effort to help the state meet recent Environmental Protection Agency emissions mandates. The company said it will ask the Utility Regulatory Commission to allow it to increase rates to recover some of the costs of converting a 427-MW unit at its Harding Street Station. It estimates fuel conversion and the cleanup of the coal ash pond would add about $1 to the average customer’s monthly bill. The local chapter of the Sierra Club has been advocating for the company to stop burning coal at the plant, saying it has long been Indianapolis’ biggest polluter.

More: The Courier-Journal

KENTUCKY

Energy Secretary: Meeting EPA Rules will be Expensive

Energy and Environment Secretary Len Peters said the state’s draft answer to meeting new Environmental Protection Agency carbon emissions mandates will be expensive, if it’s even possible. Peters said current technology to capture carbon emissions is not yet economically feasible, undercutting the federal agency’s statements that the rules are reasonable. It is particularly challenging in Kentucky, he said, because much of the area’s generation is from burning coal. The EPA cap for coal-burning plants is 1,100 pounds of carbon dioxide per MWh. State officials say that the state’s best-performing plant emits 1,750 pounds per MWh.

More: Lexington Herald-Leader

MARYLAND

Exelon Asks for PSC Approval on Pepco

Exelon’s proposed acquisition of Pepco Holdings Inc. took another step forward last week when the Chicago-based energy giant filed its formal application with the Public Service Commission. The $6.8 billion merger would add PEPCO, Atlantic City Electric and Delmarva Power & Light to Exelon’s stable of utility companies it already owns: BGE, Commonwealth Edison and PECO. Exelon CEO Christopher Crane said the Maryland review could take up to 15 months. The acquisition also requires approvals by several other states and the Federal Energy Regulatory Commission.

More: The Washington Post

MICHIGAN

PSC Approves $89.5M in Low-Income Grants

The Public Service Commission awarded $89.5 million in energy-assistance grants to 13 organizations, including $30.2 million to DTE Energy and Consumers Energy. The two utilities will use the grant money to help low-income households with energy costs. The grants are funded by a commission-approved charge on utility bills and $40 million in Low Income Home Energy Assistance Program funds from the state Department of Human Services. Most of the grant money is provided during the winter heating months.

More: Public Service Commission

Clear Solar Panels? MSU Scientists Say Yes

MichiganStateLogoSourceMSUScientists at Michigan State University have created a solar panel that is clear, opening the way for new uses, from self-charging smart phones to windows that capture solar energy while allowing light to penetrate. The new panel is called “transparent luminescent solar concentrator” and differs from earlier opaque solar panels. Small organic molecules, developed by Richard Lunt of MSU’s College of Engineering, absorb specific nonvisible wavelengths of sunlight, which are then converted to electrical energy.

“It opens a lot of area to deploy solar energy in a non-intrusive way,” Lunt said. “It can be used on tall buildings with lots of windows or any kind of mobile device that demands high aesthetic quality like a phone or e-reader. Ultimately we want to make solar harvesting surfaces that you do not even know are there.”

More: Michigan State University Today;Motherboard

NEW JERSEY

New PPL Tx Line Plan Facing Early Opposition

PPL’s ambitious plan to build a $4 billion to $6 billion transmission line to carry energy produced by new plants in Pennsylvania’s shale gas region is already attracting opposition. PPL bills the line, which would run from Pennsylvania to New York and New Jersey, and from Pennsylvania south to Maryland, as important to the company’s financial health and the regional power grid’s health. The proliferation of cheap shale gas has triggered a boom in new power plant construction, but the current transmission system isn’t robust enough to handle much more power.

The New Jersey Chapter of the Sierra Club says it will marshal forces to stop the line. “We have better places to invest our energy money” in or near New Jersey, state Sierra Club Director Jeff Tittel said. He said if money was spent on offshore wind, solar and energy-efficiency projects, “you wouldn’t need the power line.”

More: The New Jersey Herald

NORTH CAROLINA

McCrory Faces Heat Over Duke Stock Sales

Gov. Pat McCrory is facing criticism for failing to disclose that he owned Duke Energy stock during the start of the state’s coal ash spill controversy this past spring. McCrory, a former Duke employee, sold his stock in the days after more than 39,000 tons of toxic coal ash spilled into the Dan River. Although he has since filed updated ethics disclosures, the initial ethics forms didn’t note his Duke stock holdings or the sale.

McCrory’s attorney has said the failure to note the stock ownership and stock sale on the forms was an oversight. McCrory’s communications director, Josh Ellis, said the governor sold the stock in response to criticism from the media and environmental groups after the coal ash spill. “The stock was sold in response to repeated public requests via the media and to stop the constant, unfounded challenges of the governor’s character,” Ellis said.

More: News & Observer

NC to Duke: Give Us Coal Ash Cleanup Plans

The state Department of Environment and Natural Resources is pressuring Duke Energy to come up with a plan for removing coal ash from four plants. The request comes after Gov. Pat McCrory issued an executive order for Duke to file plans after the state legislature failed to approve an ash-disposal bill. The efforts come in the wake of a spill of 39,000 tons of coal ash from one of Duke’s ash ponds on the Dan River. The state ordered Duke to submit plans by mid-November for cleaning up ash retention areas at the company’s Asheville, Riverbend, Dan River and Sutton plants. Some environmental groups say the state’s action doesn’t go far enough, noting that Duke has ash sites at 10 other plants in the state.

More: The Charlotte Observer

OHIO

New Disclosure Rule to Show Renewables Cost

The Public Utilities Commission is working on a new rule to require electric utilities to include a distinct line item on customer bills that discloses the costs of renewable and energy-efficiency programs.  The requirement was part of Senate Bill 310, which froze renewable energy standards for two years. The issue has pitted lawmakers against utility companies. A workshop is to be held this week to discusss how the rule will be implemented.

More: Columbus Business First

WEST VIRGINIA

Moundsville Power Gets Another OK for Plant

moundsville_powerMoundsville Power received another approval for its planned 549-MW gas-fired plant. A split Marshall County Commission approved a payment-in-lieu-of-taxes agreement for the plant. Under the agreement, the commission would own the $615 million plant and lease it back to Moundsville Power, which would operate it. Moundsville would pay an estimated $1 million each year to the county in lieu of taxes. The company said it would begin construction next year.

More: The State Journal