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December 10, 2025

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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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Federal Briefs

The Bureau of Ocean Energy Management cut the size of a proposed offshore wind field near Kitty Hawk, N.C., last week and located it farther off the coast. The agency previously identified the proposed area for commercial wind generation at 877,837 acres, but the new map shows it reduced to 122,405 acres. OEM also relocated the area from six miles offshore to 27 miles.

The decision was a victory for groups that had opposed the initial plans, including the town of Kitty Hawk, the National Park Service and the World Shipping Council. Identifying the lease area is one of the first stages of commercial wind development. No confirmed construction plans have been announced.

More: The Virginian Pilot

Maryland Wind Leases Go to US Wind

MdWindLeaseAreaSourceBOEMUS Wind won two leases for nearly 80,000 acres of wind-energy plots off the Maryland coast. The Bureau of Ocean Energy Management last week awarded US Wind the rights to the North Lease area (32,700 acres) and South Lease Area (46,970 acres.) Together, they are known as the Maryland Wind Energy Area, which lies about 10 miles off Ocean City. US Wind outlasted two competitors with its provisionally winning bid of $8.7 million. It has a year to file a site assessment plan with the bureau. If approved, it will have 4.5 years to submit a construction plan. US Wind is a subsidiary of Italian renewable energy company Renexia.

More: U.S. Department of the Interior

EPA: U.S. City Air Getting Cleaner

The nation’s urban air is getting cleaner, thanks to the Clean Air Act Amendments of 1990. The Environmental Protection Agency said last week that the Urban Air Toxics Report shows a 66% reduction in benzene, 60% reduction in mercury in coal-fired power plants and an 84% decrease in lead. “This report gives everyone fighting for clean air a lot to be proud of because for more than 40 years we have been protecting Americans – preventing illness and improving our quality of life by cutting air pollution – all while the economy has more than tripled,” said EPA Administrator Gina McCarthy.

More: The National Law Review

FERC Approves Clean Line Through Tennessee

CleanLIneLogoSourceCleanLineThe Federal Energy Regulatory Commission allowed a company that wants to build a transmission line from Oklahoma to Tennessee to negotiate power rates and bilateral agreements. Clean Line Energy said FERC has approved its planned 700-mile “Plains & Eastern” line. The direct-current transmission line would carry wind power from the Oklahoma Panhandle to western Tennessee, connecting with the Tennessee Valley Authority’s system. “This confirms what we’re already doing with our open solicitation from those wanting to use our line and we can now move forward with specific negotiations,” Mario Hurtado, co-founder and executive vice president of development for Clean Line, said last week.

More: Chattanooga Times Free Press

Journalists Claim EPA Blocking Access to Scientists

A coalition of journalists and scientific groups says the Environmental Protection Agency is blocking media access to independent science advisers, according to a letter the group sent to EPA chief Gina McCarthy. The group complains that the agency requires that members of its Science Advisory Board pass on media requests to the EPA press office, which usually doesn’t allow interviews of the scientists. “The EPA wants to control what information the public receives about crucial issues affecting Americans’ health and well-being,” Society of Professional Journalists President David Cuillier said. “The people are entitled to get this information unfiltered from scientists, not spoon-fed by government spin doctors who might mislead and hide information for political reasons or to muzzle criticism.”

The agency denied blocking access. EPA spokeswoman Liz Purchia said in a statement that “transparency and openness are key operating principles” for the agency, noting that the Science Advisory Board meetings and documents are accessible to the public and the press. “There are no constraints on members of the SAB testifying or speaking to the public in their personal or professional capacity, or taking questions related to administrative SAB matters,” she said.

More: E&E Publishing

DOE Study Says U.S. 2nd in Wind Energy

The U.S. ranks second in installed wind capacity, enough to meet 4.5% of total electrical demand, according to a Department of Energy report issued last week. The DOE says the U.S. wind-energy market remains strong, and that the U.S. could double electricity generation from renewable sources by 2020. The reports put total installed wind capacity at 61 GW. China ranks first with 91 GW.

More: Department of Energy

Army Working to Meet Renewable Energy Goals

armylogoSourceArmyThe Army is forming a permanent office to identify, award and complete renewable energy projects, it said last week. Amanda Simpson, executive director of the Army Energy Initiatives Task Force, said the Army will have 25 renewable energy projects under way next year. The Task Force will become the Army’s Office of Energy Initiatives in October and aims to get 1 GW of renewable energy online by 2025. Simpson said there are already 13 projects in development, including an 18-MW solar plant at Fort Huachuca, Ariz., and 90 MW of solar at Fort Stewart, Ga.

More: Federal Times

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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.