Locations of transmission security needs. (Source: NYISO)
Some areas of New York could face transmission violations as soon as next year and capacity shortages are likely by 2019 — one year earlier than expected — according to NYISO’s latest Reliability Needs Assessment.
“These reliability needs are generally driven by recent and proposed generator retirements or mothballing combined with load growth,” the report says.
Transmission security violations could occur as soon as next year in Rochester, Western & Central New York, the Capital Region, the Lower Hudson Valley and New York City.
Generation resources needed to keep reserve margins above 17% will fall short in about 2019 and get worse from then on, the document states. This is a year earlier than the ISO’s 2012 assessment predicted. “The most significant difference between the 2012 RNA and the 2014 RNA is the decrease of [New York’s] capacity,” the new assessment says.
This summer’s Installed Capacity Reserve was at 122.7%, well above the 117% margin reserve requirement. But the new report shows the ISO’s 2019 margin as 2,100 MW less than what was expected in the 2012 report. The change resulted from increased load growth and a decline in capacity resources and special-case resources — end-use resources that can be interrupted on demand.
The NYISO Management Committee approved the analysis, the first step in assessing the state’s reliability needs from 2015 to 2024, on Aug. 27. The Board of Directors will review the report in October, after which the ISO will issue requests for solutions from transmission operators and developers.
Additional generation plants could delay the shortfall beyond 2019, NYISO said.
Some of the transmission constraints in western New York would be mitigated by the repowering of the mothballed Dunkirk power plant. State regulators and plant owner NRG have agreed on a plan to convert the former coal plant to 435 MW of natural gas-fired electricity in late 2015.
NYISO also expects market rule changes, such as the creation of a new capacity zone in the Lower Hudson Valley, to entice generation owners to add additional capacity in Southeastern New York. Opponents say the zone represents a windfall for existing power plant owners, who will benefit long before any new generation plants are built.
The ISO said generation capacity could be reduced more than expected as a result of the Environmental Protection Agency’s Mercury and Air Toxics Standard, which takes effect next year, and proposed caps on carbon emissions.
Compared with the previous assessment, the new report predicts the following for 2019:
Capacity resources decline by 874 MW (724 MW upstate and 150 MW in SENY)
Baseline load forecast increases by 250 MW (497 MW higher upstate and 247 MW lower in SENY)
Special-case resources drop 976 MW (685 MW upstate and 291 MW in SENY).
The Market Implementation Committee last week approved the following changes recommended by the Credit Subcommittee:
Risk Documentation Requirements – Remove the requirement that officer certifications be notarized and allow electronic submissions. Eliminate the requirement for annual submissions of risk policy documentation; PJM will accept certification that no substantive changes have been made since the last submission.
Peak Market Activity (PMA) Exclusions – Spot market energy, transmission congestion and transmission loss charges resulting from virtual transactions will be excluded from the peak market activity (PMA) credit requirement. Virtual transactions have their own credit screening rules. Screened export transactions also will be excluded from the PMA. The PMA is used to set baseline credit requirements for members based on historical activity.
Virtual and Export Transactions Credit Requirement Timeframe – Reduce the credit requirement timeframe for export transactions to two days from four days. The MIC approved a similar change in August for virtual transactions. (See PJM MIC OKs Settlement, Credit Changes.)
Demand Bid Volume Limits – PJM will establish a daily demand bid limit for each load-serving entity by transmission zone. Bids would be limited to the LSE’s calculated zonal peak load reference point for the day plus whichever value is more, 30% of the reference point or 10 MW. The 30% limit was based on analysis showing that the largest two-day-ahead zonal forecast shortfall from January 2013 through March 2014 was 28%.
PJM said the need for such limits was illustrated by the default of People’s Power & Gas in January. Due to an input error, the company entered a demand bid about 100 times the retailer’s load. Because demand bids are currently unlimited, bids exceeding actual load act as a decrement bid but lack the protections of the virtual transaction credit screen and minimum participation requirement.
Sampling to Replace Outdated Studies for
DR in Synchronized Reserve Market
The MIC heard a first read on proposed rules that would allow use of statistical sampling to calculate the performance of residential demand response resources providing synchronized reserves. The sampling would apply to homes without meters reporting data hourly or in shorter intervals.
The samples will be stratified to group like resources by characteristics including end-use device (e.g. air conditioners, water heaters), curtailment measures (50% cycling, 100% cycling, thermostat set point) and geography.
The sampling results would have to show an error rate of less than 10% at a 90% confidence level.
The sampling would replace outdated studies such as the Deemed Savings Estimate Report, which is based on data from 2001–2005 from zones in Maryland and New Jersey. Since then, PJM’s footprint has grown to include Kentucky and Chicago, and air conditioners and other appliances have become much more efficient.
Sampling is a way to improve accuracy without the cost of installing one-minute meters on every participating household, PJM said.
The rule would take effect June 1, 2015 with a transition mechanism for resources that cannot meet new requirements for delivery years 2016 through 2018.
Pricing Interface Ordered at Warren, Pa.
PJM instituted a closed-loop interface at Warren, Pa., in the Penelec zone to set real-time LMPs for when operators take actions to address voltage problems. The interface, effective Sept. 2, is being modeled in the day-ahead market and financial transmission right auctions and is expected to help minimize FTR underfunding. There is no end date.
PJM also provided additional details about the Black River interface that took effect Sept. 1. PJM’s Joe Ciabattoni said the interface, which was instituted to address voltage or thermal issues resulting from a transmission outage, is unlikely to be implemented before it expires Oct. 31 because of forecasts for mild temperatures.
“Ninety-five-plus degree days is what this is targeted for,” Ciabattoni said. “I highly doubt we’ll use it.”
In response to calls for more transparency, Ciabattoni said PJM will notify members whenever it is “seriously considering” adding a new pricing interface. “We do a lot of thinking about things that don’t go anywhere,” he explained.
PJM Gains $200K in Settlement Adjustments
PJM will receive a net $212,000 from MISO as a result of two market-to-market settlement adjustments.
The cancellation of a scheduled outage on the Monticello–East Winamac 138-kV line on July 7 and 8 resulted in a recalculation of firm-flow entitlements and a refund from MISO to PJM of $733,611. A modeling error by PJM resulted in incorrect calculations regarding the Pleasant Prairie–Zion 345-kV line for several days in June. PJM will refund $521,193 to MISO.
The D.C. Circuit Court of Appeals vacated the Federal Energy Regulatory Commission’s ruling in a dispute over interconnection costs in PJM, calling the agency’s action “the very essence of unreasoned and arbitrary decision-making.”
At issue is whether the developers of a generating plant in West Deptford, N.J., should be liable for transmission improvements ordered before the developers entered PJM’s interconnection queue.
West Deptford Energy joined the queue in 2006 and was informed it would be assessed $10 million for improvements PJM ordered as a result of previous projects, including one that was later cancelled. In 2008, PJM won FERC approval to change the section of its Tariff that related to liability for prior transmission upgrades.
If the 2008 Tariff applies, West Deptford will not be liable for the cost; if the 2006 Tariff controls, West Deptford will have to pay the bill.
FERC ruled that West Deptford must pay “since, at the time when West Deptford entered the PJM interconnection queue, that provision was the one that established its financial responsibility.”
But the commission referred to the 2008 Tariff in ruling that West Deptford’s request for auction revenue rights was “not ripe.”
“The question in this case is, when a utility filed more than one rate with the commission during the time it was negotiating an agreement with a prospective customer, which of the two filed rates governs: the rate at the time negotiations commenced or the rate at the time the agreement was completed?” the court said (Case No. 12-1340).
“West Deptford argues that, as a matter of practice, the commission has used the rate on file at the time the agreement was finalized. The commission is of the view that it can pick and choose which rate applies on a case-by-case basis.”
The court vacated the commission’s ruling against West Deptford, saying it “has provided no reasoned explanation for how its decision comports with statutory direction, prior agency practice or the purposes of the filed rate doctrine.”
It ordered FERC to provide an “explanation consistent with” the court’s ruling.
PJM expects to spend $276 million in 2015, a 2% increase over 2014, according to a preliminary budget outlined to members last week. The spending plan will result in a charge of $0.32/MWh, a rate that hasn’t changed since 2011.
The budget anticipates revenues of $283 million, a $1 million reduction from PJM’s 2014 forecast. PJM plans $30 million in capital spending, unchanged from 2014. Nearly two-thirds of the spending is for enhancements to existing applications and systems.
The Finance Committee will consider the budget Sept. 17, with the Board of Managers making the final decision on the plan Oct. 30.
A PJM task force has recommended lifting the $1,000 cap on cost-based energy offers, but the margin suggests the proposal may have a tough time winning final stakeholder approval.
The proposal would limit cost-based incremental energy offers to production costs allowed under the cost development guidelines plus a 10% adder up to a maximum of $90/MWh. Adders for frequently mitigated units (FMU) and associated units (AU) would not apply above $1,000/MWh.
To mitigate market power, market-based or price-based offers would be required to be less than or equal to cost-based offers when cost-based offers are greater than $1,000/MWh.
The proposal was the only one of three to win majority support in a vote of the Cap Review Senior Task Force. But its 57% support is below the two-thirds threshold needed to win endorsement by the Markets and Reliability Committee, where sector-weighted voting often results in less support than in lower committees.
Two other proposals failed to win backing from more than 25% of the task force.
One would keep the $1,000 offer cap but create a review process allowing PJM and the Independent Market Monitor to approve costs above it without a waiver from the Federal Energy Regulatory Commission. Cost offers exceeding $1,000 would be compensated via uplift with no 10% adder.
The third proposal would allow recovery of incremental, start-up and no-load costs and day-ahead gas costs based on an index. All offers would be reviewed after the fact. The 10% adder would decline as the cost offer rises, being eliminated above $1,000/MWh. Cost-based offers greater than $1,000/MWh also would not include FMU/AU adders.
Stakeholders agreed to consider lifting the cap after some gas-fired generators reported that their operating costs exceeded $1,000/MWh when natural gas prices spiked during January’s extreme weather. (See Effort to Lift Offer Cap Advances After Debate.)
At a presentation before the MRC Thursday, Carl Johnson, representing the PJM Public Power Coalition, expressed concern that two of the proposals, including the one recommended by the task force, propose using a gas index instead of actual gas costs.
“One or two units with higher prices because of pipeline constraints could set LMPs,” he said. “When we take the $1,000 [cap] away we have the opportunity to exacerbate the error.”
Raghu Sudhakara of Rockland Electric said eliminating the cap would raise market power concerns. “It incentivizes generators to move away from dual-fuel capability and more to spot gas pricing because they are guaranteed cost recovery,” he said.
Jim Benchek of FirstEnergy said he’d like to see the task force continue to work on a rule change that applies to market-based offers, even if it is unable to reach consensus for the coming winter.
Market Monitor Joe Bowring said he believed the task force’s proposal addressed market-based offers by saying they cannot exceed cost-based offers.
The Monitor’s proposal, which failed to win consensus in the task force, would have permitted cost-based offers to exceed $1,000 while excluding the 10% adder. Price-based offers would be limited to no more than cost-based offers.
The Public Service Commission delayed a vote on Delmarva Power & Light’s infrastructure improvement plan until Exelon completes its acquisition of Delmarva’s parent company, Pepco Holdings Inc. PSC staff was critical of Delmarva’s five-year, $397 million plan to improve its distribution system, calling it too expensive, considering the utility’s good reputation for outage management. The commission said it would consider the plan three months after the merger’s close, which the companies anticipate in the second or third quarter of 2015.
The controversial $1.65 billion FutureGen clean-coal demonstration project is facing new challenges, despite recently receiving approval to charge consumers for the yet-to-be-built project’s output. The Sierra Club has refiled a complaint with the state Pollution Control Board, saying the project needs additional permits because it is a plant retrofit, rather than completely new construction. The plant, which would capture carbon dioxide and then dispose it underground, is supported by a $1 billion federal economic stimulus grant. Under the American Recovery and Reinvestment Act, that money must be spent by the end of September 2015. But FutureGen CEO Ken Humphreyssays investors won’t commit financing while the air permit challenge is unsettled.
A group of owners of coal- and gas-fired power plants told the Illinois Commerce Commission that they’ve already taken about all the steps they can to reduce carbon emissions, and that the new Environmental Protection Agency’s carbon emission rule should be aimed elsewhere. Dean Ellis, a Dynegy official, said installing emissions-control equipment makes plants less efficient and isn’t the answer. An NRG official agreed. “A more cost-effective approach for Illinois is likely to include the voluntary [switch to natural gas] of inefficient coal plants, augmented by the competitive development of renewable energy, energy efficiency and distributed energy resources,” said Barry Matchett, NRG’s director of external affairs. The ICC is developing regulations to ensure that Illinois can meet the new EPA standards.
Indianapolis Power & Light will ask state regulators to allow it to convert the last unit of an aging coal-fired power plant in Indianapolis to natural gas as part of the effort to help the state meet recent Environmental Protection Agency emissions mandates. The company said it will ask the Utility Regulatory Commission to allow it to increase rates to recover some of the costs of converting a 427-MW unit at its Harding Street Station. It estimates fuel conversion and the cleanup of the coal ash pond would add about $1 to the average customer’s monthly bill. The local chapter of the Sierra Club has been advocating for the company to stop burning coal at the plant, saying it has long been Indianapolis’ biggest polluter.
Energy Secretary: Meeting EPA Rules will be Expensive
Energy and Environment Secretary Len Peters said the state’s draft answer to meeting new Environmental Protection Agency carbon emissions mandates will be expensive, if it’s even possible. Peters said current technology to capture carbon emissions is not yet economically feasible, undercutting the federal agency’s statements that the rules are reasonable. It is particularly challenging in Kentucky, he said, because much of the area’s generation is from burning coal. The EPA cap for coal-burning plants is 1,100 pounds of carbon dioxide per MWh. State officials say that the state’s best-performing plant emits 1,750 pounds per MWh.
Exelon’s proposed acquisition of Pepco Holdings Inc. took another step forward last week when the Chicago-based energy giant filed its formal application with the Public Service Commission. The $6.8 billion merger would add PEPCO, Atlantic City Electric and Delmarva Power & Light to Exelon’s stable of utility companies it already owns: BGE, Commonwealth Edison and PECO. Exelon CEO Christopher Crane said the Maryland review could take up to 15 months. The acquisition also requires approvals by several other states and the Federal Energy Regulatory Commission.
The Public Service Commission awarded $89.5 million in energy-assistance grants to 13 organizations, including $30.2 million to DTE Energy and Consumers Energy. The two utilities will use the grant money to help low-income households with energy costs. The grants are funded by a commission-approved charge on utility bills and $40 million in Low Income Home Energy Assistance Program funds from the state Department of Human Services. Most of the grant money is provided during the winter heating months.
Scientists at Michigan State University have created a solar panel that is clear, opening the way for new uses, from self-charging smart phones to windows that capture solar energy while allowing light to penetrate. The new panel is called “transparent luminescent solar concentrator” and differs from earlier opaque solar panels. Small organic molecules, developed by Richard Lunt of MSU’s College of Engineering, absorb specific nonvisible wavelengths of sunlight, which are then converted to electrical energy.
“It opens a lot of area to deploy solar energy in a non-intrusive way,” Lunt said. “It can be used on tall buildings with lots of windows or any kind of mobile device that demands high aesthetic quality like a phone or e-reader. Ultimately we want to make solar harvesting surfaces that you do not even know are there.”
PPL’s ambitious plan to build a $4 billion to $6 billion transmission line to carry energy produced by new plants in Pennsylvania’s shale gas region is already attracting opposition. PPL bills the line, which would run from Pennsylvania to New York and New Jersey, and from Pennsylvania south to Maryland, as important to the company’s financial health and the regional power grid’s health. The proliferation of cheap shale gas has triggered a boom in new power plant construction, but the current transmission system isn’t robust enough to handle much more power.
The New Jersey Chapter of the Sierra Club says it will marshal forces to stop the line. “We have better places to invest our energy money” in or near New Jersey, state Sierra Club Director Jeff Tittel said. He said if money was spent on offshore wind, solar and energy-efficiency projects, “you wouldn’t need the power line.”
Gov. Pat McCrory is facing criticism for failing to disclose that he owned Duke Energy stock during the start of the state’s coal ash spill controversy this past spring. McCrory, a former Duke employee, sold his stock in the days after more than 39,000 tons of toxic coal ash spilled into the Dan River. Although he has since filed updated ethics disclosures, the initial ethics forms didn’t note his Duke stock holdings or the sale.
McCrory’s attorney has said the failure to note the stock ownership and stock sale on the forms was an oversight. McCrory’s communications director, Josh Ellis, said the governor sold the stock in response to criticism from the media and environmental groups after the coal ash spill. “The stock was sold in response to repeated public requests via the media and to stop the constant, unfounded challenges of the governor’s character,” Ellis said.
The state Department of Environment and Natural Resources is pressuring Duke Energy to come up with a plan for removing coal ash from four plants. The request comes after Gov. Pat McCrory issued an executive order for Duke to file plans after the state legislature failed to approve an ash-disposal bill. The efforts come in the wake of a spill of 39,000 tons of coal ash from one of Duke’s ash ponds on the Dan River. The state ordered Duke to submit plans by mid-November for cleaning up ash retention areas at the company’s Asheville, Riverbend, Dan River and Sutton plants. Some environmental groups say the state’s action doesn’t go far enough, noting that Duke has ash sites at 10 other plants in the state.
The Public Utilities Commission is working on a new rule to require electric utilities to include a distinct line item on customer bills that discloses the costs of renewable and energy-efficiency programs. The requirement was part of Senate Bill 310, which froze renewable energy standards for two years. The issue has pitted lawmakers against utility companies. A workshop is to be held this week to discusss how the rule will be implemented.
Moundsville Power received another approval for its planned 549-MW gas-fired plant. A split Marshall County Commission approved a payment-in-lieu-of-taxes agreement for the plant. Under the agreement, the commission would own the $615 million plant and lease it back to Moundsville Power, which would operate it. Moundsville would pay an estimated $1 million each year to the county in lieu of taxes. The company said it would begin construction next year.
Private equity firm Panda Power Funds has started construction on a second power plant designed to take advantage of Pennsylvania’s Marcellus Shale gas boom. The 829-MW Patriot generating station will be in Montgomery, Pa., which lies just inside Lycoming County’s Marcellus Shale territory. The combined-cycle plant is expected to go online by the middle of 2016. Panda Power’s first Marcellus project, the Liberty plant, is under construction in Bradford County, Pa. The company is building three others in the ERCOT region in Texas and is in the final planning stages of plants in Maryland and in Virginia.
Hoosier Energy has agreed to buy 25 MW of the output of Rail Splitter Wind Farm in Illinois for 15 years, the company announced. The wind facility, about 25 miles west of Bloomington, Ill., has a total capacity of 100 MW. It is one of 31 wind farms in the U.S. operated by EDP Renewables of Texas. Hoosier Energy President and CEO Steve Smith said the deal will add to the renewables portfolio serving Hoosier’s 18 electric coops in southern Indiana and southeast Illinois. Hoosier also obtains energy from hydro and methane collection systems.
Critics Call FirstEnergy’s Plan ‘Bailout,’ Want More Info
FirstEnergy insists that its plan to have Ohio ratepayers subsidize generation costs for its merchant plants will be a good deal for consumers, but critics of the plan see it as a bailout and say the company is slow to provide all the details of the plan. Under the “Powering Ohio’s Progress” plan that it submitted to the Public Utilities Commission of Ohio, the state’s regulated utilities would enter into long-term power-purchase agreements with the plants, including the W.H. Sammis coal plant and the Davis-Besse nuclear plant. The regulated utilities would then resell that power on the market.
FE admits that the first few years would probably result in a net loss to the utilities, but it insists that consumers would benefit in later years. Consumer advocates and other critics say it amounts to a bailout for the company and are complaining that they are having trouble obtaining access to the information FE filed with PUCO. They have vowed to contest the agreement before the commission.
“FirstEnergy admits that there are going to be costs, but that somehow everything will change, and in the out years there will be benefits,” said Dwayne Pickett, State Electric Caucus Chair for the Retail Energy Supply Association (RESA). “This is a bad idea.”
Exelon Lobbies Illinois Lawmakers for Nuclear Generation Credits
Exelon, operator of the largest nuclear fleet in the U.S., told the Illinois Commerce Commission that it should get credit for the carbon emission-free electricity its reactors generate. Talking at an ICC policy meeting last week, the company said that in light of the recent Environmental Protection Agency’s emissions rule, nuclear generation should be recognized for its emissions-free generation.
“We’re the largest clean-energy producer in the country. We’ve ridden that horse for a long time,” an Exelon executive said. “If nuclear is not preserved in this country, there is no way we can meet those carbon rules.” Exelon said earlier this year that at least three of its nuclear generating stations are at risk of being shut down if they don’t receive some sort of credit.
Five Integrys Energy Group executives will receive about $34.1 million in cash and stock after the company is sold to Wisconsin Energy next year, according to Securities and Exchange Commission records. Integrys CEO Charles Schrock will get $13.1 million. President Lawrence Borgard will get $9.6 million. None of the five is expected to have roles with Wisconsin Energy after the closing.
Kentucky Utilities and Louisville Gas & Electric cancelled plans to build a $700 million natural gas-fired plant in western Kentucky, citing decisions by nine municipal customers to terminate their power contracts. The proposed Muhlenberg County plant would have replaced the output of the soon-to-be shuttered Green River Station coal plant, and some Green River employees would have been shifted to the new plant.
“We’ve analyzed the situation carefully and believe that it is in the best interest of all of our customers to withdraw our current application for the natural gas combined-cycle unit in western Kentucky,” said Paul W. Thompson, chief operating officer for KU and LG&E. “Removing more than 300 MW of demand changes our load forecasts and thus delays the need for new generation.” The power companies said they are still looking at plans for a solar energy facility in the region.
Ameren Missouri said it would need to build 1,200 MW of natural-gas fired generation at a cost of $2 billion to comply with the Environmental Protection Agency’s proposed carbon emissions rule. Customers would see 10-15% rate increases. “We don’t really need that generation, but in order to comply with this, we need to install something to get that rate down because [the EPA’s proposal] is a rate-based formula,” said Mike Menne, Ameren vice president of environmental affairs.
Instead, the company is promoting its own plan that would combine new plant construction with renewable energy and energy-efficiency programs. The plan would take longer, missing the EPA’s proposed deadline, but cost much less. “We’ll still get to the final place, and we think it will be a lot less expensive for our customers,” Menne said.
Dominion’s Plant Closing Plan Leaves Tons of Toxic Coal Ash
Dominion Virginia’s plan to decommission a coal-fired plant on the Elizabeth River in Virginia would leave nearly 1 million tons of coal ash at an on-site waste dump, records show. The Virginia Department of Environmental Quality is reviewing the plan. The company announced in 2011 that it would shut down the Chesapeake Energy Center by the end of 2016, but it recently moved that date up to the end of this year. The 973,400 tons of coal ash will be buried under a cap of synthetic liner and soil.
Allentown officials fear the city would lose 600 jobs with the proposed spinoff of PPL’s generation business into the new Talen Energy. PPL officials have said they have not decided where the new company’s headquarters will be located but said Allentown is still in the running. PPL’s filing with the Federal Energy Regulatory Commission seeking approval of the spinoff said it would make “commercially reasonable efforts to maintain competitive retail energy supply business activity” in the city for at least three years. City authorities have said losing the jobs and the tax revenue would be a hard hit in already hard times.
FirstEnergy’s decision to exit the retail energy business means that up to 70 of its employees in the Akron, Ohio, headquarters could be out of work as early as tomorrow. FirstEnergy Solutions officials told a gathering of about 230 employees last week that although 30% of positions would be eliminated at the Akron facility, some of those employees would be offered jobs at other FE facilities. Company officials said the job cuts would be among sales and marketing groups, as well as support staff.
NRG Energy said last week it will acquire Goal Zero, a Utah company that makes “personal power” solar units that allow people to plug in no matter where they are. Elizabeth Killinger, president of NRG Retail, said Goal Zero’s business of producing portable solar generators and panels fits in with NRG’s vision to provide small-scale distributed generation. She said Goal Zero’s solar products free consumers of the need to find a wall outlet to recharge their electronic devices. “When I’m on the go, it’s an easy way to get power and not have to sit on the floor next to the (airport) bathroom,” she said. “People deserve their dignity.” Terms of the deal were not disclosed.
Dynegy’s purchase of Energy Capital Partners’ New England power plants will immediately make it a major participant in a market where it has been a bit player.
Dynegy’s only presence in ISO-NE is the gas-fired 540-MW Casco Bay Energy Facility in Maine. The company is acquiring four combined-cycle gas generators in Massachusetts and Connecticut totaling 1,902 MW, in addition to the Brayton Point station in Massachusetts, a 1,510-MW coal-fired power plant that is slated for closure in May 2017.
Dynegy said it will retire Brayton Point on schedule. But for the two years that it will operate the plant, Dynegy will rival Exelon at the top of the generation market-share rankings in New England.
Calpine announced yesterday that it is purchasing Exelon’s 809-MW Fore River generating station in Massachusetts. The deal, expected to close in the fourth quarter, would make Calpine the eighth-largest generator in New England, up from 13th.
Including all of the ECP plants, Dynegy will have about 200 MW more than Exelon once the Fore River sale is complete.
Excluding the coal plant, the ECP acquisition will put Dynegy in fifth place, behind Exelon, Dominion Resources, GDF Suez Energy and NextEra Energy. About 10% of Dynegy’s portfolio will be located in New England.
ISO-NE said it is planning for the loss of Brayton Point with a study to identify transmission upgrades needed to move power into southeastern Massachusetts and Rhode Island.
“Private investors can also come forward with proposals for generation or demand-side resources that could address the reliability concerns,” ISO-NE spokeswoman Marcia Blomberg said. “If the needed transmission upgrades or resource proposals aren’t in service by the time that Brayton Point retires, the ISO and transmission owners will have special transmission operating plans in place to deal with unexpected transmission or generation outages.”
Members deadlocked last week on changes to capacity market parameters, with none of five proposals winning a supermajority.
As a result, the Board of Managers will decide for itself whether to seek Federal Energy Regulatory Commission approval for PJM staff’s proposed changes, including a shift in the shape and position of the capacity demand curve.
The board must file changes with FERC by Oct. 1. Changes approved by the commission would be implemented for the 2015 Base Residual Auction (BRA).
Not Even Close
Stakeholders nearly reached consensus in PJM’s last Triennial Review of the market parameters in 2011. This time around, it wasn’t close.
In meetings of the Capacity Senior Task Force, members did reach agreement on several issues, including the use of a combustion turbine as the reference technology for calculating the cost of new entry (CONE). They also agreed to use data from the U.S. Bureau of Labor Statistics to raise CONE for inflation, replacing the proprietary Handy-Whitman index.
But agreement was nowhere to be found on changes to the variable resource requirement (VRR) curve.
Proposals by PJM staff, Public Service Enterprise Group (Package B) and Dayton Power and Light (Package I) all received less than 50% support in sector-weighted votes of the Markets and Reliability Committee, with only the Transmission Owners and Generation Owner sectors showing heavy support.
Virtually all members of the Electric Distributors and End User Customer sectors opposed the proposed changes and supported the status quo, which received a 56% vote overall.
A proposal to use the PJM plan but keep the current energy and ancillary services offset also failed.
Unconvinced
Load representatives said they were not convinced by arguments from PJM staff and the Independent Market Monitor that changes to the VRR curve were needed to prevent the RTO from falling short of its one-day-in-10-years loss-of-load expectation.
“We came dangerously close to the edge in January,” when the RTO nearly ran short of generation, FirstEnergy’s Jim Benchek said.
Exelon’s Jason Barker said the changes are needed to stabilize the capacity market and prevent retirements of “at-risk” coal and nuclear capacity.
But load representatives said PJM had failed to make its case for the changes, which Walter Hall of the Maryland Public Service Commission said could increase customers’ capacity costs by up to 50%. Hall said the PSEG and DPL proposals would likely increase capacity costs by more than the PJM proposal, which would have increased capacity revenues in the last three BRAs by $1 billion to $1.7 billion, according to a PJM simulation.
Carl Johnson, representing the PJM Public Power Coalition, said changing the curve was inappropriate now, at a time when PJM is also proposing a “redefinition” of what capacity is. (See related story, Reaction Muted as PJM Pitches New Capacity Product.)
PJM is asking “us to buy more of something we don’t have an understanding of,” Johnson said. “It’s not that we oppose any shift in the VRR curve for all time.”
PJM Executive Vice President for Markets Andy Ott said the proposed curve change “doesn’t mean we will procure more [capacity]. It means increased stability of the investment signal.”
Convex Curve
The PJM proposal would shift to a convex-shaped curve from the current concave shape. It would also shift the curve recommended by The Brattle Group, PJM’s consultant, to the right by 1%.
Additionally, it would reduce CONE values from the status quo, eliminate CONE area 5 and move Dominion into area 3.
The PSEG and DPL proposals would use most of the PJM proposal. The PSEG proposal would shift the recommended curve by 2%, increase CONE values for PJM’s five areas by 39% to 58% and increase the after-tax weighted cost of capital to 13.5% from PJM’s proposed 8%. The DPL proposal would move the curve by 2.5%, essentially eliminating the “holdback” that the Market Monitor has cited as one of the causes of “price suppression” in the capacity market. (See related story, Monitor: Resist Subsidies, Don’t Retreat from Markets.)
Ott said staff was likely to recommend its proposals regarding the shape and location of the VRR curve for consideration by the board. “I don’t have any reason for hesitating on those recommendations,” he said.
However, he said staff would reconsider its proposal to replace the current backward-looking energy and ancillary services offset with a forward-looking measure. While some stakeholders praised the concept, they said it needed more vetting before being included in a FERC filing.
There were seemingly as many questions as answers Friday as PJM met with stakeholders to discuss its plan for a new “Capacity Performance” product to improve reliability on peak demand days.
PJM officials said they were willing to change — or had not decided on — numerous elements of the proposal.
“Staff was being very clear that they are open to and looking for feedback,” said Nancy Bagot, vice president for regulatory policy for the Electric Power Supply Association, after the four-hour meeting. “I think it’s too early for us to have formed any opinions — even to ask good questions. I do get the feeling that a lot could change.”
PJM proposed a series of changes to the capacity market on Wednesday, the centerpiece of which is the addition of the Capacity Performance product. It would supplement existing Annual Capacity (renamed Base Capacity), Extended Summer and Limited Demand Response offerings. (See PJM: New Capacity Product Needed for Reliability.)
The new product would include generation, demand response and energy efficiency providers that can guarantee their availability during Hot and Cold Weather Alerts and Maximum Emergency Generation Alerts. The resources would need to demonstrate they can produce their committed installed capacity for 16 hours for each of three consecutive days.
Enhanced Liaison Committee
PJM said they will invoke a never-used “Enhanced Liaison Committee” process so that the new rules can be filed with the Federal Energy Regulatory Commission in time for the winter of 2015/16. The process was developed in 2011 to allow members to provide input on issues for which consensus is unlikely and the Board of Managers acts independently. (See PJM to Hike Penalties, Incentives to Improve Winter Reliability.)
While the board will have the last say on what is submitted to FERC — and protests are almost certain, regardless of the final package — PJM would like to eliminate as many points of conflict as possible beforehand.
Executive Vice President for Markets Andy Ott said that officials were willing to adjust the metrics used to determine requirements and penalties and how the new rules would apply to vertically integrated utilities.
Although no one voiced overt opposition to the proposal Friday, one stakeholder representing consumers raised concerns over market power.
Potential Changes
One item that may be changed is the use of installed capacity (ICAP) rather than unforced capacity (UCAP) in determining requirements and penalties.
ICAP represents the plant’s maximum output during summer; UCAP is the ICAP value minus its recent forced outage rate (EFORd).
FirstEnergy’s Jim Benchek said the rule could be unfair to pump storage that has high ICAP values but lower offer amounts.
Ott said PJM officials would consider a change, agreeing with one questioner that the choice between the two measures was a “jump ball.”
“In the [proposal] they put an ‘I’ instead of a ‘U,’” Ott said.
Distribution of Penalty Revenues
Ott said staff may also reconsider how the penalty rules would apply to vertically integrated utilities and load-serving entities with Fixed Revenue Requirements.
PJM plans to distribute penalty revenues to load, unlike New England, which distributes them among “overperforming” resources.
Dave Pratzon of GT Power Group said distributing penalties to load could give load-serving entities with generation less incentive to improve performance than independent generators, who have no way to recover any of their penalties.
“It seems like you’re taking money out of one pocket and into another,” said Pratzon, whose company represents generators.
Ott agreed. “We have to deal with those who are indifferent to costs coming out of the capacity market,” he said.
Outside Management Control
Officials said they also plan to clarify the RTO’s definition of force majeure. The proposal allows no exclusions for force majeure “at this point,” PJM Chief Economist Paul Sotkiewicz said.
PJM has proposed changing current rules, which allow a generator to remove outages defined as “outside management control” from the forced outage rate that determines the capacity it can sell.
“The performance penalties ultimately adopted as part of this proposal will apply to generation resources regardless of the reason for a forced outage, and therefore it would be inconsistent to remove outside management control outages from the EFORd calculation,” PJM’s proposal said.
Penalties, ‘Unbounded’ Risk
PJM would set the hourly penalty for Performance Capacity resources to the LMP multiplied by the number of megawatts the unit failed to produce.
The penalty would apply to whichever was lower: the quantity of MWs scheduled by PJM or the unit’s ICAP. A unit with a 100-MW ICAP commitment that was dispatched by PJM to produce 75 MW but produced only 25 MW would be penalized for the 50-MW difference.
PJM said the calculation is based on an ISO-NE model already approved by FERC.
PJM would set an annual cap, limiting the penalties applied to a Capacity Performance resource to 2.5 times the resource’s capacity revenues for the year. Penalties for Base Capacity resources would be limited to 1.5 times capacity revenues.
“Whenever we put too much risk on the seller at the plant, it shows up in cost. We could create so much unbounded risk that we could all be worse off when all is said and done,” said Mark Scott, a consultant for Old Dominion Electric Cooperative. “You want some pain, but you don’t want to kill them.”
Ott said officials believe the penalty has to be severe enough that resources that fail to perform suffer financial pain — not just the loss of capacity revenues.
“It has to be able to go negative in our opinion. Otherwise the worst-case scenario is I lose my capacity payment and I can be a price taker in the capacity auction and roll the dice” on getting dispatched.
But Ott said the 2.5 penalty multiplier could be changed. “We had to put a number out there. We get it. … That number is moveable.”
PJM may also expand on a proposal allowing generating companies to avoid penalties by offsetting an outage at one unit with production by another in their portfolios. Asked whether generators could replace the shortage through bilateral trades, Ott said, “I can’t think of a reason not to allow it. … We certainly can think about it.”
Scott asked why PJM was attempting to solve all the reliability issues through the capacity market rather than also using the energy market.
Ott said many generation owners would have to make capital investments to their plants to meet the Performance Capacity requirements. “It would be a forward investment. Therefore it made sense that there be an opportunity to recover that through capacity,” he said.
Risk Premium
One issue that Sotkiewicz acknowledged would be controversial is the inclusion of a risk premium in addition to the current 10% adder allowed for “hard-to-quantify” costs.
“Given the change in the penalty structure, we think it’s appropriate to include an explicit risk premium,” he explained.
PJM says the risk premium will ensure “symmetry between risk and reward” for Capacity Performance resources. PJM proposed the premium be based on the 7% pool-wide EFORd, multiplied by the historic average of Hot and Cold Weather Alert hours, multiplied by the average real-time LMP at the generation bus.
Using the 7% EFORd ensures generators will have the incentive to make the operations, maintenance and other investments “to achieve significantly better performance than PJM has historically observed during peak periods,” PJM said.
American Electric Power’s Dana Horton asked whether his calculation of the premium — about $10/MW-day — was accurate. “Yes, that is the order of magnitude,” Sotkiewicz said.
Market Power Concerns
James Wilson, a consultant to state consumer advocates, said he was concerned that owners of large generation portfolios will have incentives to withhold the Capacity Performance Product, choosing to offer part of their portfolios only as the Base Capacity product. “That’s one topic you need to give a lot more attention to,” he said.
Current rules require capacity resources to offer into the day-ahead energy market. PJM said it’s “an open question” how that obligation should apply to the new product.
“If all capacity were required to satisfy the criteria for the Capacity Performance product, then the current must-offer requirement would make sense,” PJM’s proposal says. “However, if there are multiple products, it is not clear how the must-offer requirement should apply.”
“At a minimum, the must-offer requirement to offer into the capacity market as one type of product or another should apply. But with multiple products, market incentives and competitive forces should then take over with resources offering in the product area that will result in the most surplus (clearing price minus the cost of providing the product).”
Stakeholders will meet again on Sept. 11 to further discuss the proposal.
