A Department of Energy-funded study concludes that PJM has the best alignment of electric and natural gas infrastructure among U.S. regions on the Eastern Interconnection.
The draft “baseline assessment” conducted for the Eastern Interconnection Planning Collaborative analyzed the electric-gas structure for PJM, TVA and four RTOs on nine measures, including tariffs, pipeline connections and storage capacity.
PJM was judged to have favorable conditions for six of the categories, with two neutral and one — pipeline/local distribution company penalties — negative. Unsurprisingly, the report found ISO New England has the most challenges.
The report noted that PJM has benefited from access to new shale gas supplies in addition to conventional producing regions in the Gulf of Mexico and the West.
Gas-Fired Capacity
The study identified 161 gas-capable power plants larger than 15 MW in PJM with an installed capacity totaling 78.7 GW (43% of PJM’s total ICAP).
New gas-fired generation is largely replacing coal plant retirements in Eastern MAAC and Southwestern MAAC, “while elsewhere in PJM continued reliance will be on mainly coal units, even taking into consideration the continued retirements of coal capacity,” the report said.
Slightly more than half of the generating capacity is located behind local distribution company citygates, with the remainder supplied by interstate pipelines.
LDCs
As elsewhere in the country, most of PJM’s generators supplied by local pipelines have interruptible service.
“The majority of gas-fired generation behind the citygate has chosen interruptible service in light of the high cost of local facility improvements to provide firm transportation service,” the study found. “Hence, the majority of gas-fired generation at the local level behind [citygates] is furnished on a non-firm basis, exposing gas-fired generation to curtailments or interruptions during cold snaps or outage contingencies.”
For those LDCs that provide firm service to generators, it is generally the lowest priority firm service. Several of the LDCs serving generation in PJM have supply or transportation rates specifically for gas-fired generation, but most do not.
Due to state regulations, LDCs in eastern PJM generally require gas-fired generators on interruptible contracts to have dual-fuel capability. Dual-fuel requirements are much less common in LDCs in western PJM and MISO, the study found.
Interstate Pipelines
Two companies, Transco and Texas Eastern, supply about half of the gas-fired capacity on interstate pipelines. In total, 13 of the 28 interstate pipelines that traverse PJM serve generation.
Sixty-four generators are supplied by interstate pipelines, including five with access to more than one provider and one that also has access to LDC gas.
Only 13 generators hold firm mainline transportation contracts in their own names, 10 of them with sufficient volumes to fuel more than half of their nameplate capacity. Most generators rely on gas marketers for supplies.
PJM, like MISO, NYISO and ISO-NE, does not require generators to hold firm transportation. “The competition inherent in electric markets, in which generators must clear based on price, may discourage the inclusion of incremental costs associated with firm transportation in bid structures, even where such costs could be recoverable under market rules,” the report said.
Next Steps
Comments on the draft — the first of four “targets” that EIPC is studying — are due March 14.
Later studies will:
Evaluate the capability of the natural gas systems to meet gas demand over the next decade (target 2);
Identify contingencies on the natural gas system that could hurt electric system reliability, and vice versa (target 3), and
Review the operational and planning issues affecting the availability of dual fuel-capable generation (target 4).
Comments on the target 2 sensitivities are due today.
EIPC will hold a stakeholder webinar March 21 to discuss the results from target 2 and begin work on target 3. A “mid-point” stakeholder meeting June 25 and 26 will discuss on-going work in targets 3 and 4.
PJM’s plan to implement new demand response rules in time for the May capacity auction is in doubt following a Federal Energy Regulatory Commission order requiring the RTO to provide more information to support its proposal.
The March 6 deficiency notice (ER14-822) shows that commission staff is taking seriously state regulators’ and curtailment service providers’ objections to changes in the speed and granularity with which DR would be deployed.
PJM has 15 days to respond to the order, which lays out 10 questions regarding the dispatch and compensation of DR. PJM had requested the commission approve the changes effective March 15.
Several of the questions focus on “Pre-Emergency” dispatch of DR and the reduction in the default response time from two hours to 30 minutes. The commission also asked about PJM’s proposal to make DR offer prices contingent on the speed of resources’ response and how that stratification compares to current rules for generators.
In addition, FERC asked PJM to explain how it will weight factors such as location and minimum notification time in deciding which resources to dispatch.
Changes Summarized
Current rules require PJM operators to provide two hours’ notice before dispatching DR. Under the proposal approved by PJM stakeholders in December, resources will be dispatchable in 30 minutes unless they can demonstrate they are physically unable to do so.
The new rules, which were backed by a 70% vote of the Members Committee Dec. 9, also would limit the Emergency DR designation to resources using back-up generators that are subject to environmental permits. Other resources will be known as Capacity DR. In addition, the minimum event duration will be reduced from two hours to one hour and the strike price will be reduced. (See Members OK DR Dispatch Rules after Late Amendments.)
Cost Concerns
In response to protests by CSPs EnergyConnect and Comverge, FERC asked PJM to defend its claim that day-of sub-zonal dispatch will “not impose prohibitive costs on demand resource providers.”
The proposal would allow PJM to call for curtailments immediately after defining a sub-zone, with most resources expected to respond within 30 minutes.
In a Feb. 4 filing, EnergyConnect and Comverge said that automated equipment needed to meet the 30-minute lead time could run “well into six figures.”
“The average size of a Demand Resources customer is less than 0.5 MW. In the upcoming 2014-15 delivery year, capacity prices are approximately $46,000/MW year, or an average of $23,000 per customer.” Thus it would take years to recover payback of those investments, the companies said.
Barriers to Entry?
The CSPs and the PJM Industrial Customer Coalition also raised equity concerns, pointing out that only about half of the RTO’s combustion turbines have start times of less than 30 minutes and that combined cycle and steam units require much longer lead times.
“Thus, overly restrictive rules that drive Demand Resources out of the market would invariably only lead to the reliance on and retention of older, less flexible, fossil fuel steam plants with hours and perhaps days of notice times required for startup,” Comverge and Energy Connect said. “It is difficult to understand how changes of this sort … could benefit the market.”
EnerNOC, in a Feb. 11 filing, said PJM’s proposed exemptions to the 30-minute start time were too narrow, calling them a “transparent attempt to erect a market barrier” to DR.
Must-Offer Requirement
Meanwhile, Market Monitor Joseph Bowring has asked FERC to impose on DR a must-offer requirement similar to that for generation resources, saying PJM’s proposal doesn’t go far enough in addressing disparities between the competing resources. Several generation-owning utilities have also called for such a requirement.
EnerNOC said a must-offer requirement is unnecessary because the new rules making most DR “pre-emergency” resources will provide PJM sufficient flexibility.
While generators’ must-offer requirement acts as a protection against withholding, EnerNOC said, DR participants don’t have an incentive to withhold. “Demand Resource participants are load, and as such do not have an interest in raising prices,” EnerNOC said.
Impact on BRA
FERC’s deficiency notice raises questions about whether the proposed changes will be implemented in time for the May 12-16 Base Residual Auction.
The proposal would mandate the 30-minute dispatch beginning delivery year 2015/16. CSPs would be able to choose among 30-, 60- and 120-minute dispatch for DY 2014/15.
All other provisions would be effective for 2014/2015.
Stakeholders reacted warily last week to a proposal that would allow PJM dispatchers to cut interchange ramp limits to reduce price volatility and uplift.
Dispatchers can limit ramp to protect reliability under current rules, but the action has been “very rarely, if ever,” taken, PJM’s Lisa Morelli told the Market Implementation Committee last week.
Short Term Solution
Morelli said that using ramp to control price volatility and uplift is one of the short-term solutions being considered by an MIC sub-group charged with finding ways to better capture operator actions in market clearing prices. The Energy and Reserve Pricing and Interchange Volatility Sub-Group has met four times since its creation by the Markets and Reliability Committee in November. (See MIC to Consider Real-Time Pricing Changes.)
The MRC asked for the implementation of initial changes in time for this summer, leaving too little time to consider any changes that require a FERC filing, lengthy stakeholder discussion or software changes, Morelli said.
The volume of interchange often increases when LMPs are high, but it is difficult to forecast. If generation or DR has already been called and cannot be cancelled, more interchange than expected creates excess reserves, which suppress energy and reserve prices and increase uplift.
During the Jan. 7 polar vortex, for example, operators forecast 5,665 MW of imports at 2 p.m. but received almost 3,000 more than that (see chart).
Scenarios
Morelli said the limits could be reduced when operators have dispatched demand response or additional internal generation in maximum generation emergency actions. Changes in ramp limits would be communicated to market participants through banner notifications in ExSchedule or other real-time communications tools, with monthly reports explaining the reasons for the adjustments.
To create “more transparency,” Morelli said the sub-group is developing guidelines for how and when operators might change the ramp limits.
Market Interference?
The proposal alarmed some members, who questioned the propriety of PJM taking actions that could impact market participants.
“It doesn’t seem that appropriate for PJM to be in the market,” said Bruce Bleiweis of DC Energy. “An RTO or ISO shouldn’t be making changes in the market that change the outcomes for participants.”
Jung Suh, of Noble Americas Energy Solutions, said he worried about “overeager use” of the tools by operators.
Another stakeholder said that although he supports efforts to reduce uplift, he is concerned that individual operators may react differently under similar situations, creating uncertainty for market participants. “Saying that the operator will figure it out is not very reassuring because we’re reformulating price formation,” he said. Such actions usually require a Tariff change, he noted.
Adam Keech, director of wholesale market operations, said PJM will draft manual changes to try to answer stakeholder concerns about how operators would exercise their discretion.
“But the expectations that we’re going to have some kind of written rule set when operating conditions are never the same … might be a little bit of a stretch,” he said. “If it’s too prescribed it’s useless … because whatever situation you’re trying to describe never shows up.”
Next Steps
PJM officials want to bring changes to a vote at the April MIC meeting to meet the summer target. “It is a fairly aggressive timeline,” Morelli said. “We do acknowledge that the best solution may be a longer term solution.”
The Regional Greenhouse Gas Initiative’s latest carbon allowance auction, where prices rose by one-third after the allowance supply was tightened by 45%, shows “how market-based programs cost-effectively reduce carbon pollution, while driving investments in a clean-energy economy,” according to Collin O’Mara, secretary of the Delaware Department of Natural Resources and Environmental Control. The $4 clearing price in RGGI’s March 5 auction was the highest since the auction began in 2008. PJM states Delaware and Maryland are members of RGGI; New Jersey dropped out in 2011.
$1 Billion Undergrounding Plan Set to Start This Year
Mayor Vincent Gray signed a bill authorizing a $1 billion plan to bury feeder lines in an effort to improve reliability in the District, where many neighborhoods are often struck with weather-caused outages. The five- to seven-year program is to be funded mostly by Pepco, with some help from the District. The Pepco surcharge and an initial three-year work plan require Public Service Commission approval and the legislation must undergo the 30-day congressional review period that all D.C. laws require. Pepco said work would begin by late this year.
Cities Struggle With Costs of Prairie State Campus
The cities of Naperville and Batavia are poised to raise electricity rates sharply because of the high costs they are saddled with for the Prairie State Energy Campus, the coal plant whose cost ballooned from $2 billion to $5 billion. The plant is selling power into a market fueled by the low price of natural gas. Some people have suggested trying to band together with other municipalities that also own shares of the plant, or having the state help deal with the cities’ burden.
In Naperville, a city councilman acknowledged the “bad news” of a rate hike but said “with a 6% increase we’re still going to beat ComEd on the residential market.” Batavia’s rate could jump as high as 16%.
Report: Dereg Saved Users $37B Since ‘98 Restructure
Electricity deregulation has saved Illinois customers as much as $37 billion over 16 years, a new business-sponsored report says, putting the per-household saving at $3,600. The report said competition, retail choice and access to broader markets produced their desired effects. The Citizens Utility Board agreed that consumers have benefited but questioned whether market mechanisms should be credited, pointing out that “the law included built-in rate cuts to correct the problems of the past system,” including costs of expensive nuclear plants.
In a report that promotes the “community choice aggregation” model to further renewable energy, the World Wildlife Fund and other groups say Illinois leads by far among CCA states in choosing renewable energy. Ninety-one communities in the state are buying 100% renewable, through renewable energy credits, according to the report, “Leading From the Middle.” Of the handful of other states with community choice aggregation, Ohio has two cities, Cleveland and Cincinnati, that provide 100% renewables through RECs.
Edwardsport Troubles Continued Into February, Running Only at 4%
Edwardsport IGCC Plant (Source: Duke)
Duke Energy’s Edwardsport IGCC plant has continued to run at a small fraction of its capacity, and the company is assessing the nature of the mechanical problems to determine whether they should be charged to shareholders or ratepayers.
January’s output from the $3.5 billion, 618 MW integrated gasification combined cycle plant was only 4% of capacity, as the facility suffered numerous mechanical failures. Continuing problems, plus maintenance work, cut February production, too, but that month’s output will not be reported until the end of March.
The Citizens Action Coalition said it would file a complaint soon about the January problems. The plant, billed as an efficient way of generating electricity through coal gasification, was plagued with cost overruns. It was originally to cost $1.9 billion, but costs ballooned to $3.5 billion. In late 2012, state utility regulators capped the amount Duke could collect from ratepayers for construction at about $2.6 billion, with Duke having to cover about $900 million itself.
The Public Service Commission levied its largest penalty to date against an electricity retailer, fining Starion Energy $350,000 for multiple violations of laws and regulations, including “slamming” customers, failing to get licensing in some jurisdictions and engaging in false marketing and sale practices, including thousands of violations of the state’s Door-to-Door Sales Act. The PSC also told Starion to let customers know they can switch to other suppliers, and to report every six months about all customer complaints. The commission said the company’s variable-rate customers saw significant increases in their costs “for reasons that were unrelated to energy prices in PJM.” It expressed concern that customers may not be fully informed about variable-rate calculations as it acknowledged that the PSC has no direct authority over Starion’s pricing policies.
The PSC said it did not revoke Starion’s license because of measures the retailer has taken to improve its consumer-protection operations.
Bill Would Allow Turbines, Panels on Preserved Land
Renewable energy could get a big boost from legislation that would allow wind, solar and biomass projects on property set aside as farmland, adherents say. Critics argue, however, that “We simply can’t afford … to lose a single acre of farmland.” The bill, which the governor supports, would allow renewable energy facilities on up to five acres of land whose development rights a landowner has committed to the state preservation program. Generation facilities on the land could help Maryland reach its goal of sourcing 20% of its power from renewables by 2022. And income from the facilities could help farmers stay in business, supporters say. A developer called Apex Clean Energy, for example, is aiming for a 100 MW wind project that would use some of the 5-acre parcels for turbine placement.
Metal Lodged in Palisades Vessel Is No Risk: Entergy
Palisades Power Plant (Source: Entergy)
A 5-by-12-inch piece of metal from a broken impeller blade is stuck tightly in Entergy’s Palisades nuclear plant reactor vessel but does not appear to be a safety risk, the company said. It cannot be removed so far, and Entergy plans, at this point, to leave it in place. The Nuclear Regulatory Commission is monitoring the situation at the plant, which was shut for refueling and maintenance when the metal piece was discovered. The NRC will not let the plant restart until it is satisfied with Entergy’s evaluation of the situation.
Introduction of a bill to raise the state’s renewable energy requirement to 30% by 2020 has restarted debate about a renewables goal. Wind and solar advocates were disappointed when in 2011 Gov. Chris Christie retained the Board of Public Utilities’ 22.5% requirement, after Gov. Jon Corzine had proposed raising it to 30%. Now, amid some calls from renewable interests for an 80% target, the 30% target is being revived in a bill introduced by state Sen. Linda Greenstein. Her measure also calls for the BPU to set an energy efficiency portfolio standard for electricity and gas, and to require suppliers to develop “efficiency first” plans.
The state Court of Appeals upheld the Utilities Commission’s 2012 approval of Duke Energy’s purchase of Progress Energy. Orangeburg, S.C., and NC WARN had challenged the approval.
Duke Energy was considering its response to a ruling last week by a Wake County Superior Court judge that the company must stop groundwater pollution from its coal ash storage sites immediately. The decision reversed one by the North Carolina Environmental Management Commission.
In other action following the Feb. 2 ash spill from Duke’s Dan River plant, the state Department of Environment and Natural Resources said it would inspect all of Duke’s ash ponds this week and told the company to provide engineering and emergency-action plans, with maps showing flood impacts if the ponds’ dikes fail. A 2009 state law did not require utilities to provide such information, but the state says it now believes the data is necessary.
PUC Staff: Let AEP Collect 62% of 2012 Storm Costs
Staff of the Public Utilities Commission recommended that American Electric Power be allowed to recover $57.5 million, or 62%, of the costs for restoring its system after the derecho and other storms struck in the summer of 2012. Large-customer groups have agreed to a recovery package with AEP, but Ohio Consumers Counsel, which represents residential users, has not signed on. A PUC decision is likely in late spring.
Free Flow Power Pursues Hydro Projects on Muskingum
Map of Muskingum River Projects (Source: Free Flow Power)
Free Flow Power’s proposal to install 23 MW of nameplate capacity in run-of-river hydropower facilities at six existing dams on the Muskingum River continues to generate anxiety among some residents. A plant at the Lowell dam would hurt Buell Island property values, recreation, ecology and more, some say. Free Flow has been meeting with residents, as well as with the Ohio Historic Preservation Office, and comments are being taken at the Federal Energy Regulatory Commission until March 15. FERC is to produce an environmental assessment by December.
Free Flow says it is in advanced development on similar projects totaling about 175 MW at existing dams on the Monongahela, Ohio, Allegheny and White rivers in Ohio, Pennsylvania, West Virginia and Indiana.
Retail supplier IDT Energy will refund about $2 million to customers who have complained about extraordinarily high energy bills in this winter’s extreme cold snaps, when wholesale power prices caused some retailers’ costs to spike. The company received 10 times the bill complaints that it had experienced before, just as the Public Utility Commission received more bill complaints since the end of February than in all of last year. IDT will undertake the rebates and other forms of credit voluntarily, it said.
AEP Units Ask 4.4% Hike, Transfer of Mitchell Share
American Electric Power utilities in the state are seeking a 4.4% rate increase to cover their annual expanded net energy cost. Appalachian Power and Wheeling Power asked the Public Service Commission for a $68 million increase in the net energy cost to account for the difference between the amount currently being collected and projected spending through the next annual filing period. The utilities also asked for authority to transfer half-ownership in the 1,600 MW Mitchell plant to Wheeling Power from AEP Generation Resources by June 30. They also propose to establish energy conservation measures.
AEP had wanted to transfer half of Mitchell to Appalachian Power, but the Virginia Corporation Commission blocked the move last year.
Lobbyists from Exelon Corp. have descended on Illinois lawmakers, warning that current energy prices and renewable energy subsidies could force them to shut down three nuclear stations in the state.
“If we do not see a long-term path to sustainable profitability for a particular unit, then we will consider all options available to us, including unit shutdowns,” reads a memo that is part of a presentation lobbyists are using. “We are looking for solutions, and we are talking about this now both to let you know what we are up against, and to avoid any surprises later.”
The presentation does not name any particular plants in Exelon Nuclear’s six-plant Illinois fleet, but one consultant in the state energy industry said the Exelon lobbyists are naming the Quad Cities, Clinton and Byron plants as those most at risk.
Taken together, the three stations generate 5,243 MW, employ 2,300, have an annual payroll of $193 million and pay more than $51 million in taxes.
That consultant, who asked not to be named, said Exelon was using industry-wide figures, and not plant-specific financials, in their briefings.
“It is not clear to me whether these plants are losing money, or just not making enough money,” he said.
All Illinois Plants Unprofitable?
According to an analysis by the Chicago Tribune, all six of the plants in Exelon’s Illinois nuclear fleet have been unprofitable over the past five years. The Tribune examined hourly power prices and plant production and concluded that all six plants failed to meet capital and operational costs since 2008.
Exelon spokesman Paul Adams last week confirmed that the company had held “informational” meetings with lawmakers but wouldn’t answer specific questions about plant profitability or discuss which legislators participated. “The company has not asked lawmakers for a fix,” he said.
In a prepared statement, Exelon said that while it hasn’t targeted any plants for closure, the prospect was not unthinkable.
“We have no current plans to close any of our nuclear units prior to the end of their federally licensed operating lives, with the exception of Oyster Creek [in New Jersey], which we’ve agreed to close in 2019,” the company said. “That said, the combined effect of low wholesale power prices and the unintended consequences of current energy policies is challenging the economics of several of Exelon’s Illinois nuclear units.”
It added, “It is too soon to discuss specifics and the company has not asked Illinois officials to provide a state remedy for the current market conditions affecting nuclear plants.”
CEO Chris Crane told analysts in an earnings call in February that the company’s nuclear stations, especially in the Midwest, were getting squeezed by low energy prices, as well as competition from subsidized renewables and low-cost natural gas generation. (See Exelon May Close Nukes.)
Presentation
Exelon lobbyists are using a 20-page presentation outlining what they say are conditions that threaten the profitability of its nuclear generating stations in Illinois.
Chart from Exelon PowerPoint to Illinois Legislature: Impact on Carbon Goals (Source: Exelon)
“Some of our plants, particularly in Illinois, face severe economic headwinds because of low power prices and the unintended consequences of current energy policies, and it is not certain that we will be able to run them much longer,” one part of the presentation reads. “We have one plant that leads the nation in virtually every operational, safety and reliability category. Yet it cannot consistently earn a profit.”
The presentation doesn’t identify that plant, but it seems to be a reference to the Byron Generating Station, a two-reactor, 2,346-MW plant that had a 96.2% capacity factor in 2013 — the highest among the Illinois plants and the second highest in its entire fleet. (Limerick Nuclear Generating Station, in Londonderry Township, Pa., came in first with 96.3%.) Byron’s net generation for the year was 19.5 million MWh, eclipsed only by the Braidwood station.
Clinton Generating Station’s 2013 capacity factor was the lowest in Exelon’s fleet, at 87.7%.
Exelon has asked the Nuclear Regulatory Commission to extend the licenses of the Byron plant — due to expire in 2024 and 2026 — by 20 years.
Grand Prairie
Byron Generating Station (Source: Exelon)
While Exelon is telling some lawmakers that Byron may be targeted for shut down, just three months ago sister company Commonwealth Edison filed a proposal with the Illinois Commerce Commission to build a 60-mile transmission line from Byron station to Wayne, Ill., just west of Chicago.
The 345 kV Grand Prairie Gateway Project, which has already won PJM’s approval, would provide a third west-to-east transmission line across ComEd’s territory, relieving transmission congestion across northern Illinois.
ComEd spokesman David O’Dowd said Friday that the Grand Prairie transmission line is still considered a high-priority project. Pending ICC approval, the project should be completed by 2017, the company said.
Analyst Reaction
In a presentation to PJM’s General Session in February, Julien Dumoulin-Smith, a utility analyst at UBS Securities LLC in New York, noted that Exelon’s Quad Cities plant went from running at zero hours of negative pricing in 2006 to 101 hours of negative pricing in 2013, with an average negative price of $15.35 per MWh. Quad Cities’ average LMP price plummeted from $41.02 in 2006 to $25.36 in 2013.
“I think Exelon is dead serious,” Dumoulin-Smith told Crain’s Chicago Business last week. “Their willingness to withstand losses is going to be tested if they don’t do something.”
According to the Tribune analysis, the Quad Cities and Byron plants experienced negative pricing 8% and 7%, respectively, of their operating hours during 2012.
Carbon Price
The presentation left with lawmakers cites the rising role of low-cost natural gas-fired generation, renewable subsidies and transmission constraints. It also cites the lack of a federal price on carbon, which would improve nuclear’s competitiveness against gas and coal.
“Renewables are important, however, the subsidies they receive are an unfair factor that make it difficult for Nuclear to be competitive in the same market place,” one slide says.
“Energy policy frameworks in the U.S. do not compensate nuclear energy either for its carbon-free output or its unrivaled reliability,” it goes on. “Unless we fix that gap, the U.S. is going to lose nuclear plants. We need more emission-free electricity in Illinois and the U.S., not less. Getting rid of the cheapest, most reliable source of electricity in America today makes no sense.”
The current lobbying push, according to the Illinois energy consultant, is conditioning.
“Right now, they are just laying the groundwork by telling everybody they have a problem,” he said. “It is like tenderizing meat. And then, we’ll see when the solution presents itself, or when the solution is presented by them.”
PJM won’t seek additional compensation for black start generators in the face of stakeholder opposition, officials told members Friday. Instead, members of the task force studying the issue will be polled to determine their next step.
Two proposals that would have boosted payments to existing units failed to win a two-thirds vote from stakeholders Feb. 27 as the Markets and Reliability Committee split along supply-load fault lines. (See Stakeholders Reject Pay Hike for Black Start Units.)
Some stakeholders contend existing black start generators should receive additional compensation to encourage them to continue providing the service.
But PJM Executive Vice President for Operations Mike Kormos told the System Restoration Strategy Task Force Friday that the Board of Managers will not act unilaterally on any pay increase because there is no evidence that the current compensation is causing an exodus.
“They don’t see a reliability concern,” Kormos said. “Quite frankly, the equity issues are not that clear.”
He added, “That’s not to say [the board’s view] won’t change. That’s why I’m hesitant to say cut the discussion off.”
One proposal, which would have increased annual payments for a 20 MW CT to $71,600, from the current $51,000, won only 60% support in the MRC vote. An alternative, which would have boosted compensation for the same unit to $312,500, also fell short, with only 45% support.
Task force chair Chantal Hendrzak said she will send a poll to task force members March 12 to determine next steps. Hendrzak said the poll will seek to gauge sentiment for reevaluating a PJM proposal considered by the task force, which would have boosted pay for a 20 MW CT to $65,000.
The poll also will ask about a narrower proposal that would not change the base compensation but would broaden the units that could receive compensation.
It would allow:
compensation for storage of fuel other than oil;
automatic load rejection units — plants that can disconnect from the grid during a blackout — to recover the costs of complying with NERC cybersecurity standards; and
energy-only units to receive compensation.
One member representing a generation owner expressed doubt that the work would be productive. “I don’t think loads are going to vote for anything [that increases compensation],” said AEP’s Brock Ondayko.
Public Service Enterprise Group chairman and CEO Ralph Izzo doesn’t see the electric industry moving to a largely distributed-generation future. The utility network is the most efficient way to provide power, Izzo said in an E&E TV interview. But energy efficiency should be paramount, he said, and he sees the utility of the future as an energy services provider. “I would like to see us expand way beyond the meter to be someone who provides energy services that help customers lower their bills, first and foremost,” Izzo said. “Secondly, to the extent that people still require electricity – because even though you use less of it, you still will require it – we’re the most reliable provider of that electricity possible.”
Izzo also discussed PSE&G’s $3.9 billion Energy Strong effort and described “a whole host of problems” with the Federal Energy Regulatory Commission’s Order 1000 on transmission planning and cost allocation.
PSE&G Workers Hurt, Woman Killed in NJ Gas Explosion
Fire officials in Ewing Township, N.J. said they were not informed of a gas leak before an explosion that killed a resident and injured seven PSE&G workers March 4. Two townhomes were obliterated and 55 others were damaged by the explosion and fire, many so badly they will have to be razed.
A PSE&G crew had been summoned to the townhouse development after a contractor reported hitting a gas line while performing electrical repairs. The utility workers had been at the scene for about 45 minutes when the explosion occurred.
Fire officials said they would have evacuated the area had they been informed of the leak. The New Jersey Board of Public Utilities is investigating the actions of PSE&G and the contractor. The board can levy fines if state regulations were violated. The Occupational Health and Safety Administration (OSHA) is also investigating.
Public Service Enterprise Group will spend about $12 billion in capital investments, mainly in transmission, over the next five years. The operating utility, Public Service Electric and Gas, will spend $10 billion over that time, 20% more than the previous five years, mostly for PJM-mandated transmission upgrades to relieve projected system overloads and maintain reliability, PSEG announced at its annual investor conference in New York City.
This year, operating earnings from the regulated business will be about 55% of earnings, Chairman and CEO Ralph Izzo said, and the utility’s capital spending program will lead to double-digit earnings growth over the 2013-2016 period.
The Market Implementation Committee approved an issue charge directing the Demand Response Subcommittee to consider ways to allow residential customers to participate in the synchronized reserve market through demand response.
Comverge’s Frank Lacey, sponsor of the initiative, said residential DR will only be economical as a synchronized reserve resource if members approve an alternative to one-minute direct metering, which can cost upwards of $1,500 per unit.
Dave Pratzon, of GT Power Group, said that after discussions with Lacey he was satisfied that “not metering certain customers would be appropriate if the customers are very homogenous in nature so that DR response is going to be [predictable].”
Another question the subcommittee will consider is whether to limit eligibility to direct load-controlled properties.
PPL announced a special protection scheme to prevent overloads on its Susquehanna-Jenkins 230 kV transmission line.
According to PPL’s presentation to the Planning Committee last week, the protection would be activated under NERC N-1-1 contingencies, for example the loss of both the Susquehanna-Lackawanna 500 kV line and Mountain-Lackawanna 230 kV lines.
The scheme would trip the Stanton #1 and #2 breakers at Jenkins five minutes after the Susquehanna-Jenkins line exceeds 100% of its emergency rating and one minute after it exceeds its loadshed rating.
The scheme will be removed following the rebuild of Susquehanna-Jenkins (RTEP project b2269), which is scheduled for completion in summer 2018.
PJM will conduct training April 17 for transmission developers who want to submit proposals in the RTO’s second “market efficiency” window in November. The session will educate developers on how PJM calculates the benefits of improvements to reduce transmission congestion.
PJM officials acknowledged the need for training after selecting only one of 17 proposals submitted in the first market efficiency window last year. It was a disappointing beginning for those who had hoped FERC Order 1000 would unleash competition in transmission development. (See PJM to OK Only 1 of 17 Congestion Relief Proposals.)
Five of the projects were rejected because the congestion developers targeted had been addressed by other transmission projects or generation, while another nine projects failed to clear the 1.25 benefit-to-cost threshold.
Three projects passed the cost-effectiveness screen, but because they all addressed congestion in the same area, only one proposal was approved.
At last week’s Transmission Expansion Advisory Committee meeting, PJM officials outlined the data and assumptions that will be used to identify areas of the grid that could benefit from “economic” upgrades.
The assumptions are to be finalized by May, with preliminary results from the congestion analysis in June. After incorporating stakeholder feedback on the model, PJM will open the proposal window in November.
The draft “baseline assessment” conducted for the Eastern Interconnection Planning Collaborative analyzed the electric-gas structure for PJM, TVA and four RTOs on nine measures, including tariffs, pipeline connections and storage capacity.
Two companies, Transco and Texas Eastern, supply about half of the gas-fired capacity on interstate pipelines. In total, 13 of the 28 interstate pipelines that traverse PJM serve generation.
