PJM: Demand Response Price Cap Too High

PJM officials told members Thursday they may seek to lower the price cap on emergency demand response as a result of their review of the July 14-19 heat wave.

The comments came as PJM gave its most detailed explanation yet regarding the heat wave, with a lengthy presentation and answers to 64 questions submitted to officials after earlier presentations last month.

The more than two-hour presentation, which concluded the Markets and Reliability Committee meeting, seemed to exhaust most members’ questions. The Wilmington meeting room gradually emptied like a baseball stadium late in a lopsided game; by the end of the pre-Labor Day meeting, less than half of the members remained.

Much of the focus of the discussion was on PJM’s actions in the ATSI zone, where officials created a temporary interface July 17 to reflect the actions they were taking to ensure reliability.

July 18, 2013 Load vs. All Time Peaks (Source: PJM Interconnection, LLC) — (Source: PJM Interconnection, LLC)

PJM deployed emergency demand response in the zone on July 15, 16 and 18. During hours ending 16 through 18 on the 18th, DR set prices at $1,800/MWh, based on PJM rules that cap bids and offers at $1,000/MWh plus two times the reserve penalty factor (currently $400/MWh).

“The offer cap for emergency DR is probably too high at $1,000 when you add the two times the penalty,” said PJM Vice President of Market Operations Stu Bresler. Bresler recommended the limit be reduced to less than $1,000 plus only the primary reserve penalty. The cap “should be just short of [the price of] primary reserves,” Bresler said.

DR also was dispatched in the PJM, PPL and AEP South Canton zones on July 18 but did not set prices there. DR provided 92% to 102% of its obligations, depending on zone, PJM said.

Summary of Answers

Many of the 64 questions submitted in writing were repetitive or had been addressed in previous presentations to the members. (See Imports, Not DR, Caused Heat Wave Price Crash.)

Below is a summary of several key questions and answers. Unless otherwise attributed, direct quotes are from PJM’s written responses to member questions.

ATSI Interface

Q. Why did PJM create the pricing interface for the ATSI zone and not for AEP’s overloaded South Canton transformer? Was the interface necessary for dispatching demand response?

A. PJM created the ATSI Interface because its controlling actions were taken to address multiple post-contingency overloads in the area in addition to reducing load on the South Canton transformer. “Because a zonal action was being taken to limit imports into the zone in aggregate, the ATSI Interface provided the price signal that most appropriately reflected system conditions.”

PJM didn’t need the interface to call on Emergency DR. Without the interface, however, “other transmission constraints may have bound but the price impacts would have likely been inappropriately more localized.”

Some members said PJM should document in its manuals the process for adding localized interfaces in the future. PJM said it acted without giving members prior notice because of the urgency of the situation. But officials said they are “open to discussing a process that allows ample time for stakeholders to be notified of such new interfaces provided that it allows for flexibility for unforeseen system conditions to be priced accurately.”

South Canton Transformer

Q. What was the quantity and general characteristics (size, fuel-type, reason for outage) of the generator outages that resulted in the overload on the South Canton transformer? (Different quantities have been reported in different presentations, leading to some confusion as to the actual amount of generation that was unavailable).

A. PJM said it could not provide specifics on the generator outages, which totaled about 2,700 MW north and east of South Canton. “The response to this request would contain market sensitive information that PJM is not able to provide.”

Q. What is the limit on this transformer? What are the details of the transmission upgrade that will relieve the limit?

A. PJM was using a 95-degree normal rating of 1718 MVA, based on data submitted by AEP in November. The rating was raised to 1852 MVA on July 17 after AEP informed PJM that the rating submitted in November was incorrect. Officials said they don’t know the reason for the error.

AEP is scheduled to replace a disconnect switch on the transformer (RTEP project b1972) by October 4, which will increase the unit’s ratings to 2713 MVA (summer normal)/2922 MVA (summer emergency).

Operations

Q. Why did TVA issue a TLR 5b on July 15?

A. “TVA issued a TLR 5b [transmission loading relief] for a unit trip that caused an overload on their system. Both Firm and non-Firm contracts were curtailed as a result.”

The TLR cut 3,381 MW of imports to PJM, including 29 MW of firm imports.

Marji Philips, of Hess, questioned whether TVA could have avoided the TLR by redispatching its generation but decided against doing so because the TLR was cheaper. “TVA had a reputation for leaning on the system,” she said.

PJM CEO Terry Boston, former executive vice president of system operations for TVA, said that TVA’s problem was caused when a MISO generator that was providing counterflow reduced its output. As soon as the MISO unit returned, TVA’s problem was cured, Boston said. “It did not look like a market issue. It looked like a transmission issue,” Boston said.

Officials said they are working to improve their coordination with TVA. They said the incident raised questions about PJM’s control over external resources that are block scheduled and not pseudo-tied.

“We don’t have authority to reduce the output of external resources to relieve constraints,” Bryson said. The plants could keep running and sell their energy to other customers, he said.

Price Formation

Q. Was Shortage Pricing invoked? If not, why considering that a Maximum Emergency Generation was invoked?

A. “In this case, a Shortage event did not occur; reserves are not monitored in individual transmission zones such as the ATSI zone, and actual primary reserves were not less than the reserve requirement in either Mid-Atlantic and Dominion (MAD) or RTO. In real-time, hot weather procedures, including alerts of reserve shortages, are communicated to the market via Emergency Procedure messages.”

Demand Response

Q. Does Operations have any biases about using DR? Don’t want to use it? Want to use it? Want to use it to get practice? Feel DR is cumbersome so don’t like to use it?

A. “There are operational characteristics of the current DR products (2 hour lead time, majority only available in emergency, etc.) that make DR difficult for the operators to use efficiently and PJM has initiated stakeholder discussions to adjust these characteristics. The vast majority of Emergency DR is long lead.”

Reserve Sharing Agreements

Q. What actions will PJM take to support a neighboring RTO that is short of its reserves and how does this action impact PJM LMPs and charges (for instance, would PJM curtail DR/load Max Emergency Generation to support a neighboring RTO)?

A. PJM has reserve sharing agreements with the Northeast Power Coordinating Council (including NYISO and ISO-NE) and with Virginia-Carolinas (VACAR) (including Duke Energy Carolinas, Progress and South Carolina Electric & Gas).

“The nature of these agreements are `good utility practice.’ They are not requirements to provide reserves at all times. A company may elect to not respond if they cannot provide. Because responding to a request is not required, PJM does not rely on shared reserves and does not include them in reserve calculations for scheduling and dispatch.”

Bryson added: “We cover our needs from the ancillary markets. When our internal markets are not sufficient we can call on external reserves. We don’t rely on external reserves to meet NERC compliance requirements.”

Financial Transmission Rights (FTRs)

Q. What happened to balancing congestion and Financial Transmission Rights revenues on July 18?

A. Balancing Congestion costs for more than three hours totaled about $238,000, approximately 0.2% of total of FTR revenue inadequacy in July. “It wasn’t huge but it wasn’t insignificant,” said Bresler.

During the three hours of congestion, the day-ahead market flow averaged 8% higher than real-time. “Day-ahead congestion on [the] South Canton transformer and lower load resulted in reduced flows into the ATSI zone in the Day-ahead market, although not completely down to the Real-time level.”

Forecasting

July 18 Load vs. Summer Peak Forecast Load (Source: PJM Interconnection, LLC) — (Source: PJM Interconnection)

Q. How did peak loads compare with PJM’s forecasts?

A. PJM’s hourly integrated peak load during the July 2013 heat wave was 158,156 MW, which occurred on July 18 for hour ending 17. The Day-Ahead Load Forecast for that hour was 157,033 MW (99.2% of actual load).

The 50/50 Projected Seasonal Peak Load Forecast from the January 2013 Load Forecast Report was 155,553 MW (98.3% of actual).

September 3, 2013

Energy Storage Vies for Capacity Role

PJM would create rules allowing batteries, flywheels and other advanced energy storage technologies to participate in its capacity market under a problem statement presented to the Markets and Reliability Commission on first reading Thursday.

The proposal was introduced by Janette Kessler Dudley of Demansys Energy, which aggregates commercial and industrial customers for participation in the regulation market.

Dudley said the purpose of the problem statement is to establish enrollment procedures. Because advanced storage technologies — which also include thermal storage and compressed air — are still being developed, rules should not be limited to current products, she said.

In its second performance assessment of PJM’s capacity market, The Brattle Group recommended the RTO develop such rules: “Although the primary driver behind the development of these devices is to provide additional ancillary services to balance the grid, these resources could also participate in RPM.”

To do so, Brattle said, PJM will have to incorporate different ways for calculating capacity values. “Storage devices may be able to provide two types of capacity products: (1) an annual product, for devices that can sustain their capacity value for at least 10 hours; and (2) a limited product for devices that can sustain their capacity value for at least 6 but less than 10 hours.”

John Brodbeck, of Pepco, said he agreed PJM should consider the issue. “But we’re busy and here it is August. I don’t think there should be any changes” expected before the next base capacity auction in April, he said.

Energy storage received a boost from the Federal Energy Regulatory Commission in July with an order requiring PJM and other transmission providers to consider speed and accuracy in acquiring regulation resources. The order will make batteries, flywheels and other emerging technologies more competitive against slower-responding gas- and coal-fired generators in the regulation market. (See FERC Rule Boosts Storage, Renewables.)

September 3, 2013

Quick-Fix Transmission Upgrades OK’d

Constraints that can be quickly and cheaply resolved would be included in the Regional Transmission Expansion Plan (RTEP) under a proposal the MRC endorsed Thursday after a lengthy discussion. The proposal was approved over the objections of five members.

The new rules require PJM staff to identify — before posting the planning parameters for each Base Residual Auction — Locational Deliverability Areas in which the Capacity Emergency Transfer Limit is less than 1.15 times the Capacity Emergency Transfer Objective.

Upgrades that raise the ratio above 1.15 would be added to the RTEP if they cost less than $5 million and can be completed within 36 months or prior to June 1 of the Delivery Year. Projects that duplicate upgrades whose cost is already assigned to an interconnection customer would be excluded.

Roy Shanker, representing NextEra and LS Power, said the proposal could result in PJM spending millions on upgrades that produced inconsequential improvements to the system. Shanker said the 1.15 trigger could result in spending to relieve theoretical constraints that don’t actually result in price separation in the auction.

“Where else do we allow spending of $5 million with no evaluation of benefits, the potential for zero benefits, and guaranteed returns to [transmission owners]?” Shanker asked in a presentation analyzing the change.

Marji Philips, of Hess, said Shanker had identified a flaw in the proposal. “I don’t want to pay for something if there’s no benefit.” Philips later voted in favor of the change, however.

Walter Hall, of the Maryland Public Service Commission, said the issue should be sent to the Capacity Senior Task Force for further debate.

Others were not persuaded by Shanker’s argument. “We did not find it compelling and we don’t agree with the math,” said Ed Tatum, of Old Dominion Electric Cooperative.

Bill Schofield, representing the New Jersey Public Power Coalition, noted the volatility of CETL calculations. “We understand that the upgrade might have no immediate impact. But the probability is that it would provide value over its life,” he said. “We weighed the risk… We judged that this is a valid way to save load — consumers — a significant amount of dollars.”

Susan Bruce, representing the PJM industrial Customer Coalition, agreed with Schofield. “We think that the benefit certainly outweighs the cost.”

“This isn’t to block transmission from getting built” but to ensure it’s needed, Shanker responded. He suggested PJM first run the auction and if the results showed a constraint, it re-run the auction assuming a transmission upgrade.

Jason Barker, of Exelon, said his company was “agnostic” until seeing Shanker’s presentation. He suggested PJM conduct a risk-adjusted analysis before approving such upgrades.

PJM officials said those suggestions were not workable.

“We can’t do a cost benefit analysis,” said PJM Executive Vice President for Operations Mike Kormos. “That’s the problem.”

PJM Executive Vice President for Markets Andy Ott said adding the two-step process would extend the auction by at least a week. “It’s just the nature of the complexity of the auction.”

“$5 million is a very small number. [Shanker’s proposal is] so far from practical that we said, `Thanks for your comment. Let’s move on.’”

August 27, 2013

Investors Plan MD Plant, Acquire PA Project

Panda Power Funds, a Texas-based private equity fund, last week announced two big investments in PJM, proposing a 859 MW natural gas-fired power plant in southern Maryland and purchasing rights to a planned 829 MW natural gas generator in rural northern Pennsylvania.

Planned Liberty Power Plant (Source: Panda Power)

The fund announced Aug. 22 that it had completed the acquisition and financing of Moxie Energy’s planned Liberty combined-cycle generating station in Bradford County, Pa. The fund said it is the first new generator developed to take advantage of its proximity to the Marcellus Shale gas formation. Construction will begin immediately, and commercial operations are scheduled to begin by early 2016, the company said.

The announcement came a day after the fund announced plans for the 859 MW Mattawoman generator in Prince George’s County, Md., a suburb of Washington, D.C.

Founded in 2010, the fund has invested in three combined-cycle power plants currently under construction in Texas, and a 20 MW photovoltaic solar farm in Pilesgrove Township, N.J., which was completed in 2011.

Todd W. Carter, president and senior partner, said the Liberty project was one of several opportunities the fund considered in PJM. The Liberty plant will use Siemens’ H-class gas turbines, which claim operating efficiencies of 60% and will be cooled by air rather than water. Panda Power will be the majority owner of the project with Moxie Energy retaining a minority share.

Drawing of Planned Mattawoman Plant (Source: Panda Power)

The Mattawoman plant will use recycled municipal waste water for cooling. Pending approval of the Maryland Public Service Commission, the fund hopes to begin construction by early 2015 with completion by mid-2017.

More: Panda Power Funds, The Washington Post

August 27, 2013

Monitor’s Mid-Year Report: Prices Up, Coal Gains on Gas

Energy prices and coal generation rebounded in the first half of 2013 as natural gas costs increased, PJM’s Market Monitor reported in its mid-year report.

The load-weighted average LMP was $37.96 per MWh, up nearly 22% from the first half of 2012 as natural gas in eastern PJM briefly spiked at more than $6/MMBtu.

Average Day-Ahead LMP 2008-2013 (Source: Monitoring Analytics LLC) — (Source: Monitoring Analytics LLC)

While LMPs were up compared with 2012, and also higher than 2009, they remained lower than 2008, 2010 or 2011.

Fuel Mix

Coal prices were flat in the first half of the year, leading to an 11% increase in generation by coal-fired units and an 18% drop in generation from gas units. Coal units provided 44% of total generation with nuclear units responsible for 35% and gas units almost 16%.

Coal represented 58% of real-time marginal resources in the first half of the year, a slight drop from 2012, while natural gas represented almost one-third of marginal resources, up from 30% in the first six months of 2012. Wind, which was not on the margin in the first two quarters of 2012, represented almost 6% of marginal resources in 2013.

Load

Average real-time load increased by about 2% from the first six months of 2012 while average day-ahead load, increased by almost 12%, driven by the continued growth of up-to congestion transactions.

Hourly Avg. Up to Congestion Bids (Source: Monitoring Analytics LLC) — (Source: Monitoring Analytics LLC)

Virtual bids dropped by one-quarter year-over-year. Physical companies — utilities and customers which primarily take physical positions in PJM markets — increased their share to 75.5%, up from less than 64% in 2012.

Market Competiveness

The monitor’s evaluation of market fundamentals was unchanged from the 2012 report, with only the regulation market results not judged competitive.

The monitor judged the regulation market results “indeterminate.” It found the market structure not competitive because one or more pivotal suppliers failed the three pivotal supplier test in 90% of the hours for the first six months. However, participant behavior was considered competitive due to PJM rules that require competitive offers when the three pivotal supplier test is failed.

PJM made several changes to the regulation market in 2012, including new optimization methods.

“It is too early to reach a definitive conclusion about performance under the new market design because important parts of the design are inefficient and because there is not yet enough information on performance,” the monitor said.

In its response to the 2012 report, released in May, PJM took issue with the monitor’s criticism of the market.

“PJM believes there is ample evidence of competitive market behavior in the regulation market and the IMM conclusion is based on the IMM’s disagreement with opportunity cost calculation rules that were endorsed by members and approved by the FERC.”

Recommendations

In addition to summarizing changes in prices and other metrics, the monitor’s new report called for increased transparency and added several new recommendations on the energy market, operating reserves, demand response, ancillary services and Financial Transmission Rights. (See Market Monitor Recommendations)

The monitor called for additional transparency regarding constraints affecting energy prices, and on unit retirements, “in order to permit new entrants to address reliability issues.”

It also said the market needs better information about the reasons for operating reserve charges. “Data on the units receiving operating reserve credits and the reasons for those credits should be made publicly available to permit better understanding of operating reserve levels and to facilitate competition for providing the same services,” the monitor said.

The monitor also called for action to address what it called the failure of capacity market prices to reflect fundamentals, including “better [Locational Deliverability Definitions], the effectiveness of the transmission.

August 27, 2013

PJM Small Hydro Potential: 1.5 GW

Who says Congress can’t pass energy legislation? Two bills approved with bipartisan support and signed by President Obama this month may open PJM to new generation from a renewable energy source many thought was fully exploited: hydropower.

Non Powered Dams w/Potential Capacity Greater than 1 MW (Source: DOE) — (Source: US Department of Energy)

The legislation streamlines regulations on small hydropower sites, which advocates say could unlock 12 GW of capacity at existing, non-powered, dams — about 1.5 GW of it in PJM.

A 2012 Department of Energy report identified the powering of non-powered dams as low-hanging fruit that could increase current U.S. hydropower capacity — 2,500 dams generating 78 GW — by 15%.

The report identified 80,000 non-powered dams (NPDs) including canal locks and those used to provide water supplies. The top 100 sites could add 8 GW of capacity with the top 10 facilities responsible for 3 GW.

PJM has nearly 150 non-powered dams with potential of at least 1 MW. The top 10 prospects total nearly 500 MW, one-third of PJM’s potential; seven of the top 10 are on the Ohio and Allegheny Rivers in Pennsylvania (see chart below).

Top Non-Powered Dams in PJM (Source: DOE) — (Source: US Department of Energy)

“Many of the monetary costs and environmental impacts of dam construction have already been incurred at NPDs, so adding power to the existing dam structure can often be achieved at lower cost, with less risk, and in a shorter timeframe than development requiring new dam construction,” said the report, done for DOE by the Oak Ridge National Laboratory.

The report did not consider the economic feasibility of developing each site, but added, “The abundance, cost, and environmental favorability of NPDs, combined with the reliability and predictability of hydropower, make these dams a highly attractive source for expanding the nation’s renewable energy supply.”

Two bills signed by President Obama Aug. 9 should make it easier to develop the potential of these sites.

The Hydropower Regulatory Efficiency Act (H.R. 267), amends the Public Utility Regulatory Policies Act of 1978 (PURPA) to exempt dams up to 10 MW from the licensing requirements of the Federal Energy Regulatory Commission (up from 5 MW). It also amends the Federal Power Act to relax regulations on conduit hydropower facilities — manmade water conveyances used for agricultural, municipal, or industrial consumption — of up to 40 MW.

Also under the law, DOE will study ways that existing pumped storage facilities can be upgraded to support intermittent generators and enhance grid reliability.

The second bill, the Bureau of Reclamation Small Conduit Hydropower Development and Rural Jobs Act (H.R. 678), authorizes the U.S. Bureau of Reclamation to develop small hydropower projects at existing canals, pipelines and other manmade waterways.

August 27, 2013

Company Briefs

Duke Energy Carolinas reached a settlement with stakeholders on a revised energy efficiency plan that will add programs for multifamily housing and commercial customers.

The agreement with the Environmental Defense Fund and the North Carolina Utilities Commission’s consumer advocates includes a $400,000 bonus if the company increases energy savings by more than 1% in any year.

Under the old program, Duke recovered the costs of the energy savings program as though they were an investment in a power plant. The new plan will use a shared-savings mechanism similar to that used by Dominion North Carolina Power and Duke Energy Progress.

The new offerings will be available in January if the commission, which held a hearing on the proposal Aug. 19, approves.

More: The Charlotte Observer, Charlotte Business Journal

Duke Energy Purchases San Francisco Solar Plant

Duke Energy Renewables has acquired the 4.5 MW Sunset Reservoir Solar Power Project from developer Recurrent Energy. The system’s almost 24,000 solar panels, mounted above the Sunset Reservoir, provides power for municipal facilities through a 25-year power purchase agreement with the San Francisco Public Utilities Commission (SFPUC).

More: Renewable Energy Focus

NRC Meets with Duke on Nuclear Plant Incident

The U.S. Nuclear Regulatory Commission met with Duke Energy Aug. 19 to discuss an October 2012 incident in which the failure of radiator fan belts caused a shutdown of the Robinson nuclear plant’s shutdown diesel generator.

An NRC spokesman said the poorly maintained fan belts could have meant the generator was not available during a loss of offsite power at the plant in Hartsville, S.C. The agency said it will announce any penalties over the incident at a later time.

More: Associated Press

Damage Suit Reinstated vs. NRG Coal Plant

NRG Energy Inc. must defend a lawsuit claiming that ash and contaminants from its coal-fired power plant in Springdale, Pa., damaged nearby properties, an appeals court ruled. The U.S. Appeals Court in Philadelphia reversed a lower-court decision dismissing the suit, rejecting NRG’s claims that the federal Clean Air Act pre-empts state law claims by property owners.

The residents claim that odors produced by the plant, 18 miles northeast of Pittsburgh, made them “prisoners in their own homes” while ash and unburned byproducts settled on their properties.

More: Bloomberg

Covanta Acquires NJ Waste to Energy Plant

Covanta Waste to Energy Facility in Camden, NJ (Source: Covanta Energy) — (Source: Covanta Energy)

Covanta Holding Corp. announced Aug. 19 it has purchased a 21 MW waste to energy plant in Camden, N.J. from a subsidiary of Foster Wheeler AG. The acquisition increased Covanta’s holdings in PJM to 15 generators totaling about 569 MW.

More: Covanta Holding Corp.

August 27, 2013November 2, 2023

State Briefs

ICC OKs Ameren Transmission Line

The Illinois Commerce Commission approved Ameren Transmission’s proposed $1.1 billion 345 kV transmission line across central Illinois.

The 380-mile Illinois Rivers line will run from Quincy to Terre Haute, Ind., with a branch line running north to Ipava. Construction is expected to begin by April 2015 and be completed in 2019.

The commission denied permission to build several new or expanded substations, saying Ameren had failed to prove the need for the facilities.

More: The News-Gazette

Village Officials Urge Rerouting of ComEd Transmission Project

Burlington, Ill., officials urged citizens to oppose Commonwealth Edison’s Prairie Gateway, a proposed 57-mile 345 kV line between the Byron nuclear plant and the Wayne, Ill., substation.

The Burlington village engineer provided officials and residents a briefing on the proposed line last week. “This town needs to make some noise…and encourage ComEd to go around this village,” said Burlington Trustee Mary Kay Wlezen.

Hundreds of people recently attended ComEd open houses on the project in South Elgin and DeKalb. The company is expected to file a request for a certificate of need with the Illinois Commerce Commission by the end of the year.

More: Elgin Courier News, ComEd

NEW JERSEY

Coal Plant Conversion Hinges on Pinelands Pipeline

Plans to convert a 447 MW coal- and oil-fired generator to natural gas hinge on regulators’ approval of a 22-mile gas pipeline through the New Jersey Pinelands. The proposed pipeline, which would run from Millville to Rockland Capital’s BL England electric generation facility near Atlantic City, has won approvals from the U.S. Army Corps of Engineers, the state Department of Environmental Protection and the state Board of Public Utilities.

Its final hurdle is the New Jersey Pinelands Commission, which will consider the proposal at its meeting tomorrow. Opponents say they fear the $90 million pipeline will open the protected region to additional infrastructure development.

More: CBS Philly

OHIO

Ohio Regulator, Foe of Coal Industry, says Gov. Forced Resignation

Environmental groups called on Gov. John Kasich last week to allow a top environmental regulator to keep his job. The Ohio Sierra Club, Ohio Environmental Council and other groups say George Elmaraghy should not have to resign from the Ohio Environmental Protection Agency, where he has served for 39 years.

Elmaraghy, who has headed the agency’s surface-water division since 2005, said that Kasich asked him to resign because of disputes with the coal industry. He said his last day is Sept. 13.

More: The Columbus Dispatch

PENNSYLVANIA

PA, Allegheny County Weigh Drilling in Forests, under Parkland

Opponents of gas drilling delivered more than 12,000 signatures to Pennsylvania Gov. Tom Corbett last week calling for public hearings on a proposal to permit gas exploration in Loyalsock State Forest, where Anadarko Petroleum Corp. and another drilling company own the mineral rights to about 19,000 acres.

More: Williamsport Sun-Gazette

Separately, Allegheny County (Pa.) Council is considering whether to allow gas drilling under county parkland. County officials are weighing an offer to extract natural gas under a county park from wellheads outside the park’s borders. The county could receive $40 million to $96 million under the proposal, the Tribune-Review reported. Opponents say the potential revenue is not worth the risk of polluting the parks.

More: Pittsburgh Tribune-Review

PUC Considers Fines for Electric Retailers

The Pennsylvania Public Utility Commission proposed penalties against two retail electric marketers accused of switching customers’ electricity suppliers without their consent.

IDT Energy, which markets power statewide, will pay a $39,000 fine under a proposed settlement that followed a PUC investigation into 21 consumer complaints against one of the company’s independent sales agents. AP Gas & Electric, which sells in FirstEnergy’s territory will pay $43,200 to settle allegations that it engaged in slamming and violated “Do Not Call” rules.

More: The Morning Call, Fierce Energy

Peco to Fast-Track Smart Meter Installations

The Pennsylvania Public Utility Commission approved Peco’s plan to install smart meters for all 1.6 million customers by 2014, five years earlier than originally planned. The plan will cost $282 million but will save $58 million by eliminating the need to maintain two different meter systems until 2019, Peco said.

More: The Philadelphia Inquirer

Groups ask Court to Stop Delaware Water Gap Power Line

Environmental groups last week asked a federal court judge to block PPL Electric Utilities Corp. from starting work on a transmission line through Delaware Water Gap National Recreation Area. The groups asked for an injunction to prevent construction until a lawsuit they filed in December is resolved.

The project is part of the Susquehanna-Roseland transmission line, a 145-mile span being built by PPL and Public Service Electric and Gas between PPL’s Susquehanna nuclear power plant and PSEG’s Roseland substation near Newark, N.J. PPL plans to begin construction in early September on the 4.3-mile section of the line that runs through the park.

More: The Morning Call

VIRGINIA

VA Hearing Examiner Favors James River Transmission Line

A State Corporation Commission hearing examiner recommended that the panel approve Dominion Virginia Power’s proposed 500 kV line over the James River. The examiner concluded the proposed line from the Surry nuclear power plant to Skiffes Creek is the most cost effective option for correcting reliability violations that will begin to occur in 2015 due to the retirement of Dominion’s Yorktown coal-fired generating plant.

The line is opposed by a number of companies and government officials, who contend it would destroy views and harm tourism in the Williamsburg historic region. James City County had asked to move the line downriver or bury it under the river.

More: The Virginia Gazette, Virginia State Corporation Commission

August 27, 2013

FirstEnergy Issues Coal Plant Layoff Notices as PJM Seeks Delay

FirstEnergy Corp. has begun sending layoff notices to workers at two Southwestern Pennsylvania coal-fired generating plants even as PJM notified the company it won’t complete transmission upgrades in time for the plants’ scheduled Oct. 9 shutdowns.

Mitchell Power Plant (Source: FirstEnergy)

FirstEnergy expects to lay off about 380 workers as a result of the closing the 370 MW Mitchell Power Station and 1,710 MW Hatfield’s Ferry Power Station.

However, PJM asked the company in early August to postpone the shutdown, saying it needed more time to complete transmission upgrades needed to maintain reliability in the plants’ absence.

“We are reviewing their request and will be responding to it,” First Energy spokeswoman Stephanie Thornton told RTO Insider last week. “That’s all I can say at this point.”

PJM’s Tariff requires generators to provide at least 90 days’ notice of plant closings to allow the RTO time to evaluate reliability impacts.

Generators that delay shutdowns for reliability reasons are entitled to compensation to recover operating costs. But the Tariff does not give PJM the power to block a plant shutdown.

PJM spokeswoman Paula DuPont-Kidd said PJM will provide details on the upgrades needed when it completes its review.

Hatfield's Ferry Power Plant (Source: FirstEnergy) — Hatfield’s Ferry Power Plant (Source: FirstEnergy)

FirstEnergy President and CEO Anthony Alexander told analysts on an Aug. 6 earnings call that neither plant cleared the last PJM capacity auction and that some of the individual units hadn’t cleared the auctions for several years. Alexander said the plant closings, which were hastened by environmental regulations, are part of a company-wide cost-cutting plan, which includes an additional 250 layoffs and reductions in medical and other benefits.

FirstEnergy said the two plants represented 10% of its generating capacity but about 30% of its cost to comply with the EPA’s mercury and air toxics standards (MATS). The closure will reduce FirstEnergy’s MATS compliance costs to $650 million from $925 million.

PJM asked FirstEnergy last year to continue operating three Ohio coal-fired power plants slated for closure, the Ashtabula, Lake Shore and Eastlake plants. The company agreed to keep those plants running until early 2015 under “reliability must-run” rules while it installs new transmission lines to maintain reliability.

August 27, 2013

Settlement on FE Coal Plant Still a Bad Deal: Consumer Group

FirstEnergy Corp. reached a settlement last week in a controversial bid to shift a coal-fired generator from its unregulated subsidiary to regulated utility Monongahela Power, but a consumer group says the reduced price is still a bad deal for ratepayers.

Harrison Power Plant (Source: FirstEnergy)

Under the settlement, Mon Power ratepayers would pay Allegheny Energy Supply Company about $800 million for the 80% of the 1,984 MW Harrison plant it doesn’t already own, a reduction from AE’s original asking price of $1.1 billion. The revised deal was signed by the staff of the West Virginia Public Service Commission, the Consumer Advocate Division, the West Virginia Energy Users Group and several trade unions.

FirstEnergy said the deal will provide rate stability by shielding Mon Power customers from “unpredictable spot market prices.” Residential customers would receive a 1.5% rate cut, the company said.

But the West Virginia Citizen Action Group filed a challenge to the settlement Friday, saying the purchase price is still far more than the $554 million value that Allegheny Energy assigned to Harrison before the company’s acquisition by FE in 2011. The acquisition also would leave Mon Power dependent on Harrison and a second coal generator — the 1,107 MW Fort Martin station, which was built five years before Harrison — for 90% of its power.

“West Virginia rate payers will be stuck with obsolete, highly expensive coal-fired electricity long after the market has moved on, thereby locking an already burdened industrial base into the least competitive fuel source on the planet,” CAG’s attorney wrote. The group said it would be cheaper and less risky for ratepayers to purchase power from the PJM market. (See: Natural Gas Group Seeks Voice in West Virginia Coal Plant Acquisition)

On July 31, Virginia regulators cited a lack of fuel diversity for rejecting AEP’s request to transfer a coal-fired plant from an unregulated subsidiary to its Appalachian Power utility.

Byron Harris, director of the West Virginia state Consumer Advocate, acknowledged that the FirstEnergy settlement did not give his office all that it sought. “Any settlement is by its nature a compromise,” he told The State Journal. “There are what we believe are benefits in the settlement.”

The West Virginia commission yesterday ordered parties in the case to agree by Thursday on a hearing date to review the settlement.

More: StopPATH WV, Daily Mail