Stakeholders will attempt to develop more accurate measurement and verification of residential demand response under a problem statement approved by the Market Implementation Committee last week.
PJM currently measures load reductions for much of its residential DR based on data that was compiled more than a decade ago in Maryland and New Jersey.
PJM’s Shira Horowitz said the data is no longer representative because of the growth of PJM’s footprint, changes in DR programs and increases in the energy efficiency of air conditioners and other appliances.
The old data were collected based on legacy “direct load control” (DLC) programs. Residential demand response now includes use of smart meters and programmable thermostats.
Some stakeholders questioned why PJM wants the review to include firm service level (FSL) and guaranteed load drop (GLD) programs in addition to DLC.
“I’m not seeing any concerns with the other two verifications,” said one stakeholder. “I’m struggling with why we want to expand this past DLC programs.”
Pete Langbein, of PJM, said the RTO wants to take a holistic approach to the issue.
“Residential [DR] is unique. We’re not dealing with a few thousand customers, we’re looking at millions,” he said. “From PJM’s standpoint, we don’t think we should limit this to DLC.”
Residential demand response supplies about 1,000 MW of capacity in PJM.
Among the many questions about the pending EPA carbon rules on existing generation are how state implementation rules will mesh with regional compliance approaches and what role RTOs such as PJM will play.
Paul Sotkiewicz, chief economist, PJM
PJM stands ready to help, Paul Sotkiewicz, PJM’s chief economist, told a Bipartisan Policy Center forum last week.
The economies of scale that RTOs have brought to unit dispatch, planning and other grid functions can also help reduce the costs of complying with the greenhouse gas rules, Sotkiewicz said.
“We can reflect the cost of environmental retrofits. It makes sense to piggyback on the existing infrastructure,” he said.
While it will be up to state officials to decide what the RTO role is and whether they want to participate, states that go it alone, he said, “are leaving money on the table.”
Two visions for how RTOs might take part were sketched out earlier this year. In January, PJM and other RTOs asked the EPA to allow states to meet the greenhouse gas rules through regional caps and to include a “safety valve” to maintain reliability.
ISO/RTO Council
The ISO/RTO Council (IRC) said that it usually doesn’t take policy positions on EPA regulations, but that it wanted to ensure EPA officials “recognize the relationship between proposed environmental rules, electric system reliability and economically efficient dispatch.”
The council’s seven-page proposal asks the EPA to allow states to adopt State Implementation Plans (SIPs) based on “a regional measurement mechanism for determining compliance.” The group also said the EPA’s regulations should include a process to mitigate reliability impacts of the regulations.
MISO Role Envisioned
In February, The Brattle Group and Great River Energy, a cooperative in MISO, proposed that RTOs build the carbon emission limits into their markets instead of making individual generators or states meet them.
Jeanne Fox, commissioner, New Jersey Board of Public Utilities
For the states that joined MISO or other regional operators, “It doesn’t seem like much of a stretch to add carbon management to that plate,” said Jon Brekke, vice president of Great River.
The proposal would have RTOs and ISOs translate EPA emission reduction limits into targets for their regional power markets. The reductions would be met by applying an RTO- or ISO-administered carbon price to generation and refunding the revenues to load serving entities based on consumption levels.
“This not a social cost of carbon … this is an economic signal,” said Brekke, who added that it would avoid stigma as a “tax” because the funds would go to LSEs rather than government.
Asked after the forum whether MISO was willing to take on the market-clearing role envisioned in the plan, Brekke responded: “We know that MISO is willing to facilitate a discussion that’s state-led.”
The idea of a regional solution is “getting traction,” he added. “Whether it’s our approach or another is secondary.”
RGGI Redux?
A top Delaware official, meanwhile, pitched the nine-state Regional Greenhouse Gas Initiative (RGGI) as a “plug-and-play” solution that other jurisdictions could adopt.
Collin O’Mara, secretary, Delaware Department of Natural Resources and Environmental Control
Carbon emissions in RGGI states have dropped by nearly 52% since 2005, thanks to energy efficiency and fuel switching — as well as the lackluster economy.
Current emission levels are 45% below RGGI’s 2013 cap, said Collin O’Mara, secretary of the Delaware Department of Natural Resources and Environmental Control. Participating in addition to Delaware are Connecticut, Maine, Maryland, Massachusetts, New Hampshire, New York, Rhode Island and Vermont.
Money collected through RGGI is reinvested in energy efficiency and renewable energy giving every expenditure a multiplier effect twice or triple the investment he said. (New Jersey Gov. Chris Christie, however, used some of the revenues to balance his budget before pulling the state out of the program in 2011.)
Rather than calling it cap and trade, however, O’Mara suggested a less politically combustible name: “budget and invest.”
New Jersey’s Democratic-controlled legislature has tried on several occasions to pass legislation reversing Christie’s decision, but it has been defeated by vetoes. “I don’t see [rejoining RGGI] happening in the near future,” said New Jersey Board of Public Utilities Commissioner Jeanne Fox.
Seams
The PJM-MISO seam has vexed both regions for years, but when it comes to GHG compliance it could be a boon, Sotkiewicz said.
State implementation plans for the four states split between PJM and MISO — Michigan, Illinois, Indiana and Kentucky — could manage emission allowances across RTO borders, he said.
“Rather than seams being a problem it actually creates fungibility between different regional compliance programs,” Sotkiewicz said. “Rather than being a barrier, per se, it almost becomes an opportunity.”
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.
