PJM is planning a system-wide drill Sept. 23 to simulate simultaneous physical attacks on critical substations, cyber attacks and the loss of supervisory control and data acquisition (SCADA).
The drill will assess PJM’s and transmission operators’ readiness to respond to nation-state sponsored attacks.
It will incorporate lessons learned from the North American Electric Reliability Corp.’s GridEx II, an exercise that drew participation from 200 organizations, including PJM, in November. Some participants complained that the GridEx “injects” were introduced too rapidly and that communications between participants didn’t use real-world methods. (See Grid Exercise `Like a Disaster Movie.’)
“GridEx was a good exercise, but sometimes they used communication paths that were not traditional,” said LeRoy Bunyon, PJM manager of business continuity planning. He said the PJM drill will feature communication “not between planner and planner, but operator to real operator.”
According to a presentation to the Operating Committee last week, the drill will test the communication channels between PJM and transmission owners and their ability to respond to attacks by implementing emergency procedures.
Bunyon said PJM will participate using its Dispatcher Training Simulator and asked transmission owners to consider simulator use, as well, instead of using the drill as a tabletop exercise. He asked transmission owners to designate planners to help develop drill materials and conduct training.
Fuel procurement and environmental limitations are the top obstacles to increasing the flexibility of PJM’s generating fleet, according to survey results released last week.
About 83% of generator operators responding to the survey said they are operating to the limits of their plants’ flexibility. Of the remaining 17%, most cited fuel and emissions limits, with insufficient compensation “a distant third,” PJM said.
The survey was developed in response to what Adam Keech, manager of wholesale market operations, said was a decline in generation flexibility over the last decade.
PJM’s Eric Hsia told the Market Implementation Committee last week 20% of those who said their units were being offered as flexibly as possible reported their flexibility has decreased over time. Among the reasons cited were compensation rules that discourage investment in aging plants, lack of fuel, emission limits and “additional risk of tripping.”
PJM’s next step will be one-on-one meetings with companies to get more details. Hsia said some of the fuel issues are already being addressed by the Gas-Electric Senior Task Force.
Bethlehem SPS (Source: Calpine and PJM Interconnection LLC)
Calpine announced a special protection scheme that will allow the outage of the Blooming Grove-Bushkill 230-kV line July 1 to accommodate construction of the Susquehanna-Roseland 500-kV line. According to a presentation to the Operating Committee Tuesday, the SPS also takes into account the expected retirement of the Portland coal units, scheduled for June 1.
The SPS calls for the trip of Unit 8 at Calpine’s Bethlehem station to relieve potential congestion from the loss of either of the two Steel City-Quarryville 230-kV lines. The SPS is expected to end in summer 2015 with the completion of the Susquehanna Roseland 500-kV line.
New Line Designations at Breinigsville
Breinigsville line designations (Source: PPL and PJM Interconnection LLC)
PPL announced new line designations coming out of its new Breinigsville substation. PPL plans to reuse the 5044 designation, currently used for the 500-kV Wescovsville-Alburtis line, for the Wescosville-Breinigsville 500-kV line. It would then christen the Breinigsville-Alburtis 500-kV line as 5058.
The new Breinigsville substation is designed to protect against excess voltage drop on 138-kV lines between Wescosville and Seigfried, excess transformer load at the Wescosville substation, and maximum allowable load drop if the Wescosville-Trexlertown #1 and #2 lines are lost.
The project is expected to be completed in May 2015.
The Federal Energy Regulatory Commission last week rejected Consolidated Edison Co.’s attempt to avoid paying for a major transmission upgrade in northern New Jersey but suggested it might order PJM to recalculate the company’s bill.
FERC’s ruling (ER14-972) approved PJM’s cost allocation for 111 baseline reliability upgrades included in the RTO’s Regional Transmission Expansion Plan (RTEP), including 17 eligible for regional cost allocation under Order 1000.
Only one of the projects, a $1.2 billion project upgrade to address thermal overloads and short circuit problems in the PSEG transmission zone outside New York City, was challenged. (See PJM: Con Ed Protest over PSEG Upgrade Groundless.)
PSEG Short Circuit Solution (Source: PJM Interconnection, LLC)
The project will convert Public Service Electric and Gas Co.’s Bergen-to-Linden 138 and 230 kV transmission line to 345 kV and add a second 345 kV transmission line between those points.
PJM’s cost allocation assigned $629 million of the cost to Con Edison under the Con Ed-PSEG “wheel,” in which PSEG takes 1,000 MW from Con Ed at the New York border and delivers it to Con Ed load in New York City.
Also challenging the cost allocation for the project is Linden VFT LLC, which owns a 315-MW merchant transmission facility that interconnects both PJM and NYISO. Linden said its RTEP bill would increase by $2.5 million annually as a result of the project.
FERC rejected Con Ed’s contention that it was not liable for the project because the reworked transmission grid would change its delivery point from that specified in its contract with PJM.
But the commission said it wanted more information on how PJM performed the distribution factor (DFAX) analysis that determined Con Ed’s share of the cost.
Con Ed says it was unfairly assessed almost 83% of the $762.6 million assigned through DFAX for its 1,000 MW wheel while PSEG was assessed only 7%, despite load of 11,000 MW. Con Ed said the cost distribution for the project is “grossly disproportionate to the relative loads” of the two companies.
“We cannot determine from this record whether the issues raised by Con Edison are generic issues related to the implementation of Solution-Based DFAX or are specific assumptions relating to this project,” the commission wrote.
Thus it ordered PJM to submit a compliance filing within 30 days “explaining and justifying the specific assumptions relating to the PSE&G Upgrade.”
Rules covering how PJM reallocates load when a load serving entity defaults can’t be found in the RTO’s manuals because, well, it doesn’t happen much.
But the collapse of two retail marketers after a spike in wholesale power prices during January’s arctic cold showed that load reallocation rules are needed, PJM officials told the Market Implementation Committee last week.
While there are mechanisms for collecting from other PJM members the $2 million in unpaid bills the two retailers left behind, what happens to the load the two companies had been serving is not clearly laid out in PJM’s rules.
Michelle Souder, of PJM’s member relations department, said PJM will add a new Section 3.2.4 to Manual 33: Administrative Services for the PJM Interconnection Agreement that covers this eventuality.
The new rules specify that PJM will notify the electric distribution companies delivering power to the retailer’s customer of the need to reallocate the load “as soon as such default is evident to PJM” and no later than the day the LSE is declared in default.
PJM will notify the EDCs by 10 a.m. the day after declaring an LSE in default whether the LSE has provided the funds to return to good standing. EDCs will not be required to reverse the load reallocation even if the LSE cures the default.
The manual language will be shared with the MRC later this month and presented to both groups for endorsement in May.
Bid Volume Limits
PJM is also considering a rule change that the RTO said would likely have reduced the size of the retailers’ January defaults.
PJM’s Hal Loomis outlined a proposal to prevent LSEs from entering day-ahead demand bids that are more than 20% and more than 10 MWs above their peak load forecast for the day.
“This would provide a way to keep inappropriately high demand bids from clearing,” including those resulting from data entry errors, said Loomis.
Had the proposal been in effect Jan. 7, at least 4% of demand bids would have been rejected, PJM said.
PJM will gauge the Credit Subcommittee’s interest in developing such a limit based on results of survey that closes today.
PJM transmission planners have identified $148 million in grid upgrades that could be required if the B.L. England Generating Station is unable to proceed with its natural gas repowering plan.
Natural Gas Pipeline Route A (Source: Southern Jersey Gas)
Plans by Rockland Capital to convert two coal-fired units to natural gas have been on hold since the New Jersey Pinelands Commission rejected a proposed 15-mile natural gas pipeline through the protected region in January.
B.L. England units 2 and 3, totaling 300 MW, must repower with natural gas by 2016 or face closing due to tightening emissions rules. The $400 million repowering plan would extend the life of the plant, built in 1963 on Great Egg Harbor Bay, for another 40 years.
PJM officials told the Transmission Expansion Advisory Committee last week they have identified $148 million in line upgrades, transformers and substation work to address N-1-1 thermal and voltage violations.
Some of the upgrades were already expected based on the retirements of BL England’s unit 1 and diesels.
The upgrades would use existing rights of way, and include an upgrade of 40 miles of 138-kV line, thought to be the oldest existing in the Atlantic City Electric territory.
Christie Hits Back?
Meanwhile, in what some see as delayed reaction to the Pineland Commission’s rejection, Gov. Chris Christie last week vetoed minutes of the commission’s March meeting, effectively killing staff salary raises.
“This is round one in laying the political groundwork to replace commissioners and reverse the pipeline rejection,” Bill Wolfe, state director of Public Employees for Environmental Responsibility, told NJ Spotlight.
Environmentalists see the pipeline route as violating Pinelands-protection rules, but Christie and others believe the pipe is necessary to clean up the England plant and keep it active in the state’s tight power supply market.
WASHINGTON — EPA Secretary Gina McCarthy told no secrets Monday as she continued her charm offensive in advance of the agency’s long-awaited greenhouse gas rules for existing power generators.
The proposed regulations are due to be released June 1, and McCarthy, the star attraction at a Bipartisan Policy Center forum, knew she wasn’t allowed to spill the beans in advance.
“I know I can’t be tellin’ what the rule says, so kick me if you think I’m starting to get on the verge,” she joked to BPC President Jason Grumet.
Instead, she continued her promises to provide states “flexibility” and to honor reliability concerns. She also made clear that the rulemaking to be released in about 50 days will not be the final word.
EPA Secretary Gina McCarthy
McCarthy, deputy Janet McCabe and other agency officials have won widespread praise for their outreach to state regulators, including a shout-out yesterday from Colette Honorable, president of the National Association of Regulatory Utility Commissioners (NARUC).
But McCarthy, an earnest, plain-spoken former state environmental regulator with a strong Boston accent, acknowledged that the warm and fuzzy feelings may evaporate once the details are released.
“I think we’re presenting a little bit of a rosy picture. I think everyone realizes that I’m a stark realist. I know the challenge we’re having,” she said near the end of her session, before being hustled out a side door away from reporters. “The only thing I really hope when this proposal goes out is that people will look at it and say ‘EPA listened.’”
Mission accomplished said Honorable, who shared the stage with McCarthy at the Grand Hyatt hotel.
“Gina has certainly been no stranger to NARUC,” she said, playfully noting the contrast between McCarthy’s accent and her own Arkansas drawl. “She’s fearless… It really has been a pleasure to engage with her.”
Informed by Further Discussion
The proposed GHG rules — now undergoing an interagency review — will leave “lots more room for improvement,” McCarthy said. As a result, she promised, the final rule will be “informed by further discussion” in the comment process.
“I think many times we get criticized because there’s so much change between the proposal and final. That’s when I dance in the streets. Because I think that is exactly as it’s supposed to be, because you’ve put concrete ideas on — instead of lofty discussions — and you start digging in to what really matters to people, which is all the details.
“It needs to be incredibly smartly crafted … to make sure it provides the flexibility that states need while continuing to provide the impetus for the carbon reductions we need,” she added. “States that are out in front can continue to be there and get rewarded for that and recognized for that while states that haven’t yet gone down this road can craft a way to do that in a time frame that will be meaningful for them.”
RTO Involvement
RTOs such as PJM “are going to have to be a strong voice” in the final rule, McCarthy said, “because the president has made clear … nothing we can do can threaten reliability.”
Honorable agreed that “certainly the regions will have a role to play.
“The nuance here is … who’s on first,” she added. “The states … are the sole entities with jurisdiction over things such as resource adequacy. We can’t allow utility regulators to check that duty.”
Not an Aspirational Goal
McCarthy made clear that while states will be given flexibility, the rule will be “federally enforceable. It is going to be a requirement.
“We are going to be looking at the state plans to determine whether or not they are conforming with the guidance and getting us significant carbon pollution reductions … We’re going to make them cost effective. We’re going to make them make sense. We’re going to recognize that different regions … are in different places [regarding compliance].
“But we’re not going to rely on an aspirational goal that if an individual resource planning goes well then that things should happen in a way that we want.”
Don’t Reinvent the Wheel
That’s fine by the states, said Honorable. “We’re not saying let everything count. But we’re saying let’s not reinvent the wheel,” she said. “We aren’t saying, let’s throw it all against the wall and see what sticks.”
NARUC President Collette Honorable
McCarthy and Honorable led off the day-long conference, which also featured panels including economic and environmental regulators from New Jersey, Ohio, Delaware, Michigan and other states, and representatives from Dominion Resources and PJM. Several PJM staffers were among the hundreds watching from the ballroom or via webcast.
The panelists discussed the roles of energy storage, energy efficiency, combined heat and power, nuclear energy and carbon capture under the new rules. (RTO Insider will have more on the conference in next Tuesday’s newsletter.)
Elizabeth (Libby) Jacobs, chair of the Iowa Utilities Board, was one of several speakers who acknowledged the hard work is yet to come.
“Check with me … in July to see if we’re all still singing Kumbaya,” she said.
PJM officials have identified several changes they’d like to make before next winter, including winter start testing for generators and better controls on generation imports (see related story, PJM May Offer Firm Fuel Premium.) Executive Vice President for Operations Mike Kormos said Tuesday that the RTO also needs to improve its tracking of dual-fuel generators.
Based on their presentations at the FERC technical conference on winter 2013-14, here’s how MISO and the Northeast RTOs are planning to cope with winter 2014-15.
MISO Capacity
MISO officials had been warning as recently as last November that they faced a capacity shortfall of as much as 5 to 7 GW in 2016-17 due to the loss of coal-fired generation.
In January, however, officials said a survey of load-serving entities had cut the projected shortfall to 2 GW. Since then, MISO has reduced the projected shortfall further to 500 MW, Eric Callisto, chairman of the Wisconsin Public Service Commission and president of the Organization of MISO States, told the conference.
FERC Commissioner Philip Moeller noted that the projection assumed a 0.75% decrease in demand.
“The number that surprised me most was residential going up, but industrial down,” Moeller said. “But if it turns around, as we hope it does, then your assumptions start getting shaken real quickly.
“The ‘load is flat’ [assumption] gave us a little pause,” Callisto responded. “But I don’t think that it is too far from that.” He said MISO is seeking an independent verification of the load forecasts.
In addition to the capacity concerns, MISO said it is looking for ways to ensure demand response doesn’t distort price signals.
ISO-NE
ISO-NE says plant retirements will make next winter even more challenging unless temperatures are unusually mild.
Salem Harbor Power Station, a 720 MW coal- and oil-fired generating plant, and the 604 MW Vermont Yankee nuclear plant are scheduled to close this year, eliminating more than the amount of capacity procured through this year’s winter reliability program.
ISO-NE says its biggest change for next winter is the “Offer Flexibility” project, which will allow generators to update their offers in real-time to reflect changing fuel costs. The initiative, which takes effect in December, was approved by FERC in October (ER13-1877).
The ISO is also working with stakeholders to change uplift allocation and to increase incentives for load to bid into the day-ahead market — an effort to improve the accuracy of its day-ahead commitments.
ISO officials also expect benefits from a FERC order approving ISO rules requiring oil units to maintain fuel inventories. If that rule proves insufficient, the ISO says it will consider other measures, including incentives for dual fuel units.
The biggest potential improvement, however, won’t be any help for next winter.
“Just one more big [natural gas] pipe would help a lot,” said ISO New England’s Vice President of System Operations Peter Brandien. “Even if we make pipeline investments now, I’ll probably have to get through three or four more winters” without it.
NYISO
NYISO says it is considering market rule changes to address concerns over generator de-rates and problems obtaining fuel supplies.
It will also run planning scenarios to evaluate dual fuel inventory capability and fuel replacement rate capabilities under sustained cold weather conditions.
Improving operator awareness of their generators’ fuel status and pipeline system conditions is also on the ISO’s to-do list.
It also says it will “coordinate” with PJM and ISO-NE, if either RTO considers raising its $1,000/MWh bid cap. (See Stakeholders Preview Offer-Cap Debate.)
In October, the state Public Service Commission approved a contingency plan to respond to the potential closure of the 2,045 MW Indian Point nuclear power plant. The PSC’s order includes building and upgrading transmission and a plan to improve the energy efficiency of larger power users.
PJM wasn’t the only place the winter of 2013-14 made its mark in the record books.
MISO, the Southwest Power Pool and NYISO also hit all-time winter peaks during January’s polar vortex, while ISO New England came up just short.
January 2014 holds eight of PJM’s top 10 winter demand days, including the top spot, 141,846 MW, set Jan. 7. Many areas in MISO, meanwhile experienced their coldest winter in two decades.
PJM and other regions called on demand response, emergency energy purchases, and public appeals for conservation. On Jan. 7, PJM dispatched about 2,000 MW of DR during the morning and evening peaks while NYISO called on 900 MW. PJM also called on more than 2,500 MW of DR Jan. 23 and 28. ISO-NE’s winter procurement program provided 21 MW of demand response on five occasions.
None of the RTOs or ISOs cut firm load.
Natural Gas Prices
While power demand wasn’t as high later in January, natural gas prices hit record highs in some eastern markets that supply PJM, New York and New England. On Jan. 22, prices at Transco Zone 6 (non-NY) peaked at $123/MMBtu, while prices at Transco Z6 NY and Transco Z5 reached $120/MMBtu.
Most other U.S. gas price hubs traded below $6/MMBtu during the coldest days, although Henry Hub hit $7.92/MMBtu in February, the highest since Hurricane Ike in September 2008.
Generator Outages
The RTOs struggled not only because of record demand but also because of mechanical failures and fuel supply problems. More than one-quarter of the installed capacity in PJM and MISO was idled on Jan. 6 and 7.
Fuel supply problems were responsible for more than half the outages and derates in NYISO, three-quarters of those in SPP and all of those in ISO-NE, according to FERC.
In contrast, lack of fuel was responsible for only one-quarter of the lost generation in PJM. About 5,000 MW of combustion turbines failed to start when called in early January.
Late in January, gas curtailments and start failures for combustion turbines both declined in PJM. Frozen coal and a lack of gas and oil caused outages of as much as 8,000 MW, however.
In much of the country, insufficient fuel oil and coal supplies kept plants from operating.
Barge deliveries were hampered by weather and an inability to transport through shallow water. Ice and sustained cold closed barge operations for a time on the Allegheny River.
Trucks and drivers were also in short supply. At ISO-NE’s request, the governor of Massachusetts approved extended hours for truck drivers transporting fuel.
MISO was challenged by an explosion on the TransCanada pipeline Jan. 25 and limited rail capacity, which pinched coal supplies.
“Some [coal] companies said they were only getting half of what they ordered,” Eric Callisto, chairman of the Wisconsin Public Service Commission, told the FERC technical conference. Some plants “were down to a 10- or five-day supply this winter.”
Rail deliveries “were an ongoing concern years ago,” he added. “It still is.”
Commissioner Tony Clark suggested that one reason that railroads are struggling to complete coal deliveries “is directly related to the lack of pipeline capacity for oil products. Railroads are using all their power to getting oil out” of the region from increased oil production. “It is all interconnected,” Clark said.
Drivers of High Prices Changed
In early January, high prices were driven primarily by record loads, which forced PJM and other operators to dispatch their most expensive generators. LMPs crested at $2,000/MWh for some hours in PJM and MISO while average real-time prices during ranged between $300-$700/MWh during peak hours.
ISO New England had energy market costs of $5.05 billion this winter, almost equal to the $5.2 billion spent in all of 2012. Almost two-thirds of average daily real-time prices were above $100/MWh, versus less than 30% in the winter of 2012-13.
Like PJM, NYISO also won FERC approval for a waiver to lift its $1,000/MWh energy offer cap. Although natural gas prices in NYISO quadrupled from December to January, power prices increased only 176% as oil displaced gas.
Rarely used oil-fired generators were called into service and some dual-fuel units switched to oil due to high gas costs or uncertain supplies.
On many days, oil-fired generation was more economical to dispatch than natural gas units, a rare occurrence since the arrival of cheap shale gas.
In New England, where natural gas prices nearly doubled from the previous winter, oil was ISO-NE’s fuel of choice for more than half of the winter, including 23 days in January. The ISO’s “winter reliability program” funded inventories of 2.7 million barrels of oil, and the ISO burned 1.9 million barrels of that. “We ran oil units hard,” said Peter Brandien, vice president of system operations.
In NYISO, oil-fired generation was cheaper than gas for eight days in December and 18 in January. Oil-fired generation was able to obtain sufficient fuel deliveries at rates close to their oil-burn rates for only short periods, however.
The phenomenon was seen across the country as well. NRG Energy reported burning 1.1 million barrels of oil in January versus 800,000 in all of 2013.
Uplift
In addition to high LMPs, the severe weather was reflected in uplift as generators sought reimbursement for costs not captured in energy prices and ancillary product sales.
In PJM, uplift for January totaled about $540 million, more than two-thirds what the RTO spent in all of 2013. Most of the uplift came between Jan. 21 and 29.
ISO-NE had uplift of $73 million in January, more than half its 2013 total.
The winter’s high gas and power prices have busted budgets and left state regulators and consumer advocates scrambling for answers.
“Our sources of emergency funding [for low income customers] are running out, arrearages are going up,” Maryland Public Service Commissioner Lawrence Brenner told the FERC technical conference Tuesday. “It’s a bad situation.”
Paula Carmody, head of the Maryland Office of People’s Counsel, said many retail electric customers with variable rate plans saw their bills jump as much as four-fold. Customers don’t understand the terms of their contracts and what would trigger rate hikes, she said.
Citing PJM’s high outage rates in January, Carmody called on FERC to investigate whether generator operators had properly maintained their units. PJM should examine whether it has sufficient incentives for maintenance and penalties for nonperformance, she said.
She also echoed the call by the Consumer Advocates of PJM States for an investigation into whether market manipulation or withholding contributed to the high prices. “There needs to be a thorough review of potential market power abuse,” said Carmody, who acknowledged she had no evidence of improprieties. “Either address it or take it off the table.”
The PJM Market Monitor told FERC in a filing last week that seven generators that sought reimbursement for operating costs above the RTO’s $1,000/MWh offer cap had inflated their claims. The Monitor’s report concluded that all but $9,118 of the nearly $584,000 in requested make-whole payments should be rejected. (See Stakeholders Preview Offer-Cap Debate.)
FERC officials told the conference Tuesday that the commission’s Office of Enforcement has found no evidence of manipulation or withholding to date. Although staff is continuing its review, its preliminary conclusion is that natural gas spot prices were driven by “high demand, pipeline flow restrictions, covering of physical short positions and concern for pipeline penalties.”
Enforcement Tools
FERC’s Division of Analytics and Surveillance, created in 2012, uses computer algorithms to analyze public and non-public data for anomalies that could suggest market manipulation.
Among the sources screened are market data from PJM and other RTOs, including offers, uplift and outages; Financial Transmission Rights holdings; e-Tags; transactions on the Intercontinental Exchange; Electronic Quarterly Reports; and Form 552, which records natural gas trades.
Staff also used its recently granted access to the Commodity Futures Trading Commission’s Large Trader Report to identify companies’ financial incentives at volatile trading hubs.
The screens, built by division staff based on market rules and known manipulative schemes, generated multiple alerts in January and February for New England, the Mid-Atlantic, the Midwest and California, FERC said.
Enforcement staff responded by conducting discussions with RTO and market monitoring officials. It also issued data requests to some companies and conducted “dozens” of interviews with generators, gas suppliers and traders to gather intelligence on operations and bidding behavior.
