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December 12, 2025

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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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Duke, ECP Deals Boost PJM Rank

By Ted Caddell

Dynegy, which emerged from bankruptcy just two years ago, announced Friday it will nearly double its capacity with the purchase of about 12,400 MW of generation from Duke Energy and private equity firm Energy Capital Partners.

If approved by regulators, the deal would rank Dynegy just behind Calpine, the third-largest competitive generator in the U.S.

Dynegy would gain about 9,000 MW in PJM, boosting it to more than 10,700 MW and eighth in generation share in the RTO.

The $2.8 billion Duke agreement includes 11 generating units in the Midwest and Duke Energy Retail, Duke’s competitive retail energy business in Ohio, Pennsylvania and Michigan — adding to Dynegy’s existing retail business in Illinois. The $3.45 billion deal with Energy Capital Partners is for 10 units in the Midwest and New England.

dynegy

Growth in New England

In addition to making it a major player in PJM, the transaction will give Dynegy a larger foothold in ISO-NE.

Dynegy could briefly dislodge Exelon from the top of the New England generation market share rankings as a result of its ECP acquisition and Calpine’s announcement yesterday that it will buy Exelon’s Fore River Generating Station, an 809-MW combined-cycle plant near Boston, for $530 million. (See related story, Dynegy Becomes New England Player Overnight.)

Dynegy would drop to fifth after the scheduled 2017 retirement of ECP’s 1,510-MW Brayton Point coal generator.

“The addition of these portfolios transforms Dynegy by adding considerable scale in the PJM and New England markets,” Dynegy President and CEO Robert Flexon said. Dynegy said it expects the deals to close by the end of the first quarter of 2015.

Investors reacted favorably, with Dynegy’s shares jumping 18% on the news before settling at $32.58 Monday, an 8% gain.

Merchant Generation, Retail Sales 

Dynegy currently has about 13,200 MW of generation: 7,042 in MISO; almost 2,700 in CAISO; 1,780 in PJM; 1,064 in NYISO; and 540 in ISO-NE.

Dynegy is betting on two sectors — merchant generation and retail sales — that other players have been exiting or de-emphasizing.

Duke signaled its intention to pull out of the merchant generation business in February, days after the Public Utilities Commission of Ohio refused the company’s request to bill regulated customers $729 million to make up for a shortfall between its plant operating costs and plunging wholesale power prices.

PPL announced in June it would spin off its generation unit in a deal with Riverstone Holdings, leaving it with a pure rate-regulated business model.

Exelon agreed in May to buy Pepco Holdings Inc. for $6.83 billion, seeking to increase its regulated rate base.

Duke is not alone in souring on the competitive retail business. Dominion Resources agreed in March to sell its business serving 600,000 retail customers to NRG Energy. FirstEnergy Solutions said this month it will stop pursuing sales to residential and small and mid-size commercial customers.

Dynegy, however, sees retail sales as a “natural hedge for our generation,” spokeswoman Katie Sullivan said.

Back from Bankruptcy

Founded in 1984 as a gas trading company, Dynegy has had a turbulent history. It survived several Enron-era scandals, near-bankruptcy in 2002 and attempted takeovers in 2010.

In its high-flying days, it owned plants in a dozen states and six foreign countries. When it emerged from bankruptcy in October 2012, it was down to 16 power plants in six states.

The company began to rebuild its merchant fleet last year, buying St. Louis-based Ameren Corp.’s five coal-fired plants in Illinois.

Dynegy is betting on economies of scale with the Duke and ECP acquisition. It expects to realize fuel cost and maintenance savings of $40 million and operational management savings of $200 million. It says these deals will drop its overhead cost 35%, from $1.67/MWh to $1.10/MWh.

The deal will also allow it to take advantage of a $3.2 billion net-operating-loss carry-forward that it says will yield $480 million in tax savings on future earnings.

Its free cash flow yield on the new assets will be 36%, the company said, refilling its coffers for perhaps more acquisitions in the future.

The company will finance the acquisitions with $5 billion in unsecured notes and $1.25 billion in equity and equity-linked securities, including $200 million in common stock issued to ECP.

Bullish on PJM, New England

Dynegy said it is bullish on both the PJM and ISO-NE markets. Plant retirements will translate into tighter reserve margins and higher energy and capacity prices, it says, particularly in New England.

“New England is not getting any new builds,” Flexon said in a conference call with stock analysts Friday. Retiring Brayton, as the current owners had planned, “puts pressure on that marketplace also.”

Capacity payments represent 11% of Dynegy’s current gross margins. With the new acquisitions, capacity payments will represent 25%, as it more than quintuples its generation in PJM and ISO-NE.

MISO’s share of Dynegy’s total generation will fall to 29% from 53% as a result of the expansion in PJM and New England. But Flexon was also optimistic about the company’s prospects in the Midwest, saying 2015 through 2017 “should be a really peak time for the MISO marketplace” due to plant retirements.

Fuel Diversity

Once Brayton Point is closed, Dynegy will have reduced the share of coal-fired generation in its fleet to 45% from 53%. The company said the 3,800 MW of coal-fired plants it is acquiring, excluding Brayton Point, are all “environmentally compliant.”

About 7,000 MW of the acquisition are natural gas-fired plants, including 5,000 MW of modern, low-heat-rate, high-capacity-factor combined-cycle plants.

Julien Dumoulin-Smith, a utility analyst at UBS Securities, said the deals are positive for Dynegy’s long-term growth and will provide protection from a takeover by another company.

“The transaction propels Dynegy to among the largest IPPs in the industry, likely no longer a take-out target,” he said. “Strategically, the deal adds substantial diversification to a portfolio both overly levered to the MISO market, as well as some further diversification from coal.”

Dumoulin-Smith didn’t see much problem getting regulatory approval for the deals. “As for execution of the transaction, we do not anticipate any significant hurdles, with only very limited market overlap across any of the contemplated portfolios.”

William Opalka contributed to this article.

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PJM Members Split over MRC/MC Meeting Site

pjm

PJM stakeholders often divide into factions, but the split that emerged in a Members Committee discussion Thursday had nothing to do with long-running battles over demand response, capacity market rules or uplift. Rather, the issue was where these battles should be fought.

For the last two months, Members and Markets and Reliability committee meetings normally held at the Chase Center in Wilmington, Del., were relocated to PJM’s Conference and Training Center in Valley Forge, Pa., to avoid traffic tie-ups resulting from repairs to a highway bridge in Wilmington. With the bridge now reopened, the two senior committees are scheduled to return to Wilmington in September.

But some stakeholders — and PJM staff — would like to abandon Wilmington and hold the meetings in Valley Forge, where lower-level meetings have been held since the CTC was completed in July 2012.

Supporters of the CTC location cited its proximity to PJM staff, only some of whom regularly attend the MRC/MC meetings. Chief Financial Officer Suzanne Daugherty said PJM spends about $150,000 annually to hold meetings at the Chase Center, not including staffers’ mileage payments and travel time.

Others, particularly those whose companies are based south of Philadelphia, said Wilmington was preferable because of its location near an Amtrak station. Valley Forge lacks mass transit and requires those outside the Philadelphia area to make a long drive or rent a car after flying or taking a train into the city.

Ed Tatum of Old Dominion Electric Cooperative said the trip to Valley Forge can take him at least five hours by car. Moving all meetings to Valley Forge, he said, could result in “a cottage industry of people who live in this [Philadelphia] area and only get to the home office once a month.”

Tatum said any decision should consider not only PJM’s costs but members’ travel costs.

Lisa Moerner of Dominion Resources said “there is no good option to get to Valley Forge” from her Richmond, Va., base. “Wilmington is much easier for those coming from the south,” she said.

Marji Phillips of Direct Energy suggested using the Cira Centre, next door to Philadelphia’s 30th Street Station.

PJM officials said they would explore their options, including one suggestion that it offer shuttle buses to transport members to the CTC from a nearby train station.

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PJM MRC/MC Briefs

Markets and Reliability Committee

The Markets and Reliability Committee approved the following with little debate or discussion on Thursday.

Manual Changes Approved

  • Manual 12: Balancing Operations. Updates Section 4.5, “Qualifying Regulating Resources,” for clarity, accuracy and consistency, including a description of current regulation testing procedures; consolidates “PJM Actions” from previous subsections into Section 4.5.
  • Manual 14B: PJM Region Transmission Planning Process. Adds language describing easily resolved constraints for Capacity Emergency Transfer Limits (CETL) to match that in the Tariff. (See MRC / MC Approvals.)
  • Manual 11: Energy & Ancillary Services Market Operations. Conforming revisions, adding references to “pre-emergency” demand response. (See PJM Wins on DR, Loses on Arbitrage Fix in Late FERC Rulings.)

Supplemental Transmission Projects

The committee approved Operating Agreement revisions defining supplemental transmission projects, as recommended by the Regional Planning Process Senior Task Force. (See PJM’s `To Do’ List.)

Settlement, Credit Changes

Members OK’d manual and Tariff revisions extending the deadlines for electric distribution companies (EDCs) to submit Power Meter and InSchedule data. The changes are intended to address problems with reporting output for non-utility generators. (See PJM MIC OKs Settlement, Credit Changes.)

The committee also approved manual and Reliability Assurance Agreement changes recommended by the Market Settlements Subcommittee allowing EDCs to submit corrections to Peak Load Contribution and Network Service Peak Load assignments until noon on the next business day. The changes are intended to aid Pennsylvania EDCs squeezed by new Pennsylvania Public Utility Commission deadlines. (See PJM MIC OKs Settlement, Credit Changes.)

Members Committee

The Members Committee approved a “back stop” mechanism for acquiring black start services through transmission providers when PJM solicitations fail to obtain service for a zone. Members also approved minor Tariff and manual changes relating to the compensation of black start units. Both sets of changes were approved by the MRC July 31. (See MRC Briefs.)

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FERC: PJM Uplift Ranks High Among RTOs, ISOs

upliftPJM has consistently had among the highest uplift rates among RTOs and ISOs, according to a Federal Energy Regulatory Commission report released last week.

The FERC staff report found 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. Only NYISO was consistently higher.

The report also found that:

  • Some resources and regions, such as PJM’s Dominion-Virginia and Delmarva zones, receive a disproportionate volume of uplift payments. PJM had among the highest concentrations of uplift payments, with 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.
  • Uplift payments are closely related to differences between coal and natural gas prices and divergences between day-ahead and real-time prices.
  • The volatility of uplift costs varies across RTOs and ISOs. It has risen in three of the five markets studied, including PJM.
  • A lack of transparency on the location of uplift credits and the reasons they are incurred are inhibiting market participants from making investments that could reduce the costs.

Sept. 8 Workshop

The report was intended to frame issues for discussion at FERC’s Sept. 8 workshop on uplift payments in energy and ancillary service markets (AD14-14).

FERC had said in June that it would convene a series of workshops to consider rule changes regarding uplift, price caps and other issues affecting price formation in PJM and other RTOs and ISOs.

The commission said its inquiry was prompted by comments made at recent technical conferences on capacity markets and the grid’s response to the recent severe winter. The workshops will consider ways to address limitations in RTO market software that prevent RTOs from modeling all system parameters, such as voltage constraints and generator operating constraints. (See FERC to Tackle RTO Uplift, Price Formation.)

Among those scheduled to speak at the conference are PJM Market Monitor Joe Bowring; Stu Bresler, PJM vice president of market operations; Jason Cox of Dynegy; Wesley Allen, representing the Financial Marketers Coalition; Judith Judson, representing the Energy Storage Association; Harry Singh of J. Aron & Co.; and Bob Weishaar of the PJM Industrial Customer Coalition.

Uplift Tab: $5.5 Billion

upliftThe report said uplift in PJM, NYISO, ISO-NE, CAISO and MISO totaled $5.5 billion in the 2009-13 period.

While the report noted the charges were a small fraction of energy costs, it said “a failure to make the causes transparent and to price them into the energy and ancillary services markets can undermine the effectiveness of price signals and efficient system utilization and mute investment signals. Volatile uplift charges may also create financial uncertainty for customers, depress liquidity and reduce market efficiency.”

PJM market participants have complained that uplift costs create unnecessary risk because they are unpredictable and not hedgeable.

The persistence of uplift in regions such as the Delmarva Peninsula “may indicate that market pricing is consistently failing to fully capture costs associated with committing and dispatching those resources or the existence of market work-arounds,” the report added. It noted that one PJM generating plant received at least $60 million in uplift annually in four of the five years studied.

The report said added transparency would aid development of solutions to reduce uplift. “For instance, knowing that the vast majority of uplift in a particular import-constrained zone is related to the provision of reactive power could make clear to market participants that the zone is reactive power deficient. This could lead to proposals to address reactive power compensation and potentially send a price signal to enhance reactive power capability. On the other hand, knowing that a majority of uplift in a particular zone is related to local ‘reliability’ could suggest that the model is not incorporating certain constraints or the operators are conservatively committing units to address generic concerns,” the report said.

PJM’s Market Monitor 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. The Monitor says the prohibition against disclosure of market-sensitive information should not apply to uplift. (See PJM Won’t Name Uplift Recipients.)

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ATSI Black River Interface to Take Effect Sept. 1

PJM will create a temporary pricing interface in the ATSI Black River area as a result of a transmission outage. The interface will capture in LMPs operator actions taken to relieve thermal or voltage problems resulting from high loads.

Most of the load buses defining the BLKRIVER closed-circle interface are in the ATSI transmission zone. It will be modeled in the day-ahead market if operators know they will be deploying sub-zonal load management before market deadlines. It will not be modeled in Financial Transmission Rights markets.

The interface will be effective Sept. 1 through Oct. 31, 2014, when the transmission outage is scheduled to be completed.