WILMINGTON, Del. — PJM members were asked last week to consider allowing generators to revise their offers hourly to reflect changes in gas prices.
ISO-NE graphical description of self-dispatch unit using pricing flexibility.
PJM is the only RTO in the U.S. that does not allow generators to vary their cost- or market-based offers hourly, GT Power Group’s David Pratzon, representing Calpine, said in a proposed problem statement presented to the Markets and Reliability Committee on Thursday.
That means gas-fired generators must submit a single price for the day-ahead and real-time energy markets even though gas prices can change in midday. More flexible pricing would allow generators to reduce the risk premiums they include in their offers because they would have greater assurance that their prices reflected fuel costs, Pratzon said.
The most recent RTO to allow hourly price changes is the gas-dependent ISO-NE, which adopted the new rules in December.
In addition to benefiting gas-fired generators, Pratzon said, the flexibility also would be useful to energy storage resources and industrial customers whose opportunity costs for cutting loads can vary based on the hour of the day. “I can see a variety of different classes of resources that this would be useful to,” he said. “We don’t know all the ways this optionality could be used.”
PJM currently requires generators to select a single cost schedule for each unit’s day-ahead offer.
In February, PJM introduced an improvement to eMKT allowing gas-fired generators to make limited intraday changes in price schedules.
The change allows generators that did not receive day-ahead commitments and were not picked up in the reliability assessment and commitment (RAC) run to update their fuel prices three hours in advance of the operating hour. Units with day-ahead commitments and those selected in the RAC run can switch prices after the end of their last committed hour. Units committed in real time remain unable to change their cost schedules until released.
Previously, there was no way for generators to change their prices once PJM locked them at 6 p.m. the day before.
Stakeholders at the MRC meeting expressed support for the additional flexibility sought by Calpine.
“We think this is a critically needed improvement to the energy market,” Dominion’s Lisa Moerner said. “It has been working incredibly well” in ISO-NE, she added.
The proposal “will do a lot to harmonize gas-electric coordination that we’ve been trying to achieve,” said Marji Phillips of Direct Energy.
Dan Griffiths, executive director of the Consumer Advocates of PJM States, said his members “don’t have a principled objection” to the potential change but are concerned about generators claiming unreasonably high gas prices.
Independent Market Monitor Joe Bowring echoed Griffiths’ concern. “Let’s not forget what the reason was for the rule requiring only one offer per day by generating units,” Bowring said. “It was to prevent the exercise of market power.
“It’s important this doesn’t become a tool for the exercise of market power, which it easily could be used to do. There are good ways to implement this and bad ways to implement it.” Nevertheless, Bowring said, “it’s clearly a worthy discussion” to have, calling it “potentially efficiency enhancing.”
The MRC will vote on the problem statement next month. Pratzon suggested a new senior task force consider the issue.
Pratzon said it took ISO-NE about 18 months to implement its changes from the beginning of discussions. By learning from the RTO’s experience, he said, PJM might be able to make the change before next winter.
However, even if stakeholders agree quickly on new rules, Pratzon acknowledged, required software changes could delay implementation.
A 17-month Minnesota rate case covering 2014 and 2015 gives Xcel Energy the rate hike it was looking for, but it will also provide a small refund to electric customers who were paying a 4.6% interim rate hike from last year. The Public Utility Commission approved the hike, but due to the complexity of the case, and the fact that it covers two years, a final ruling on just how much the hike will be won’t be decided for several more weeks.
It will be the fifth successive rate hike for Xcel’s Minnesota customers. The company said it may seek another hike next year, as well, because the PUC rejected its proposal that would have rolled all the hikes into one. Xcel sought a 10.4% hike, which would have translated into $291 million. The final hike is expected to be close to a 9.72% return on equity, or about $191 million. The PUC also denied the utility’s request for money to cover cost overruns at its Monticello nuclear plant.
Exelon’s Oyster Creek Station Goes Back Online After 6 Days
Oyster Creek (Source: Exelon)
Exelon Nuclear’s Oyster Creek Generating Station resumed full power on Saturday after being offline since the previous Sunday. The plant automatically shut down after problems were discovered in a system that controls the plant’s steam pressure. Technicians worked through the week and corrected the problem Friday.
The company didn’t give any further details on the problem. The 636-MW station is the oldest in the company’s fleet, and is scheduled for decommissioning in 2019. The plant received a “white” performance indicator from the Nuclear Regulatory Commission because of four unplanned shutdowns, or “scrams,” in 2013 and 2014. It received a “yellow,” or more serious, finding last month after problems were found with two of five reactor pressure valves.
American Electric Power says it has hired Morgan Stanley to explore alternatives for its competitive barge transportation subsidiary, AEP River Operations, which operates river barges serving its unregulated power plants.
GE to Auction 315 MW of TSRs in Linden VFT in April
GE Energy Financial Services in April will auction 315 MW of bi-directional electricity transfer capacity across its Linden Variable Frequency Transformer smart grid project.
It will sell 90 MW of transmission scheduling rights that will become available on June 1, 2016, and 225 MW of TSRs available as of June 1, 2018.
The TSRs can be used to sell energy and capacity sourced in PJM into NYISO and vice versa.
In an agreement with the staff of the Public Utilities Commission of Ohio, American Electric Power has agreed to cut the cost of refusing its smart meters from $31/month to $24. The commission still needs to sign off on the agreement after public hearings. If the agreement is finalized, it will mean customers will be paying $288/year to keep an old-style analog meter, as opposed to AEP’s initial plan, which would have cost $382/year. One party that didn’t sign on to the agreement was the Office of Ohio Consumer’s Counsel, which feels the charge should be just $10.49/month. So far, the company has installed 132,000 meters. It plans to expand its GridSmart system to 894,000 homes and businesses. It said the price of refusal covers the cost for the time and travel it takes for employees to read the old-style meters.
PECO Seeks $190 Million Rate Hike for Improvements
PECO has filed a request with the Public Utility Commission to raise rates about 4.4%, or $190 million, to pay for system upgrades. If approved, it would mean an increase of about $6.55/month for the average residential user. PECO says its system needs about $300 million in work each year, which includes equipment replacement and upgrades. It said it is spending an additional $275 million over the next five years to make the system less vulnerable to storm damage.
Dominion to Build $1 Billion, 1,600-MW Plant in Virginia
Dominion Virginia Power has announced the planned construction of a 1,600-MW natural gas-fired, combined-cycle generating plant in Greensville County, Va. It said the plant will cost about $1 billion and should go into operation in 2019. It has already filed for zoning permit applications, and more regulatory applications will be filed by July. Greensville County is in southern Virginia.
Work Starts on ComEd’s Grand Prairie Gateway Tx Line
Commonwealth Edison contractors began clearing trees along the route of the Grand Prairie Gateway transmission line this month. “We’re clearing the route in areas where we will be installing structures this summer and fall,” ComEd spokesman David O’Dowd said. The project was approved over vocal opposition in October by the Illinois Commerce Commission.
The line will run 60 miles through Ogle, DeKalb, Kane and DuPage counties. While construction has started, several groups have petitions to intervene and hope the ICC will force ComEd to change the line’s route. But ComEd doesn’t see that happening.
“We anticipate that certain parties will challenge various aspects of the ICC order in the appellate court, but the ICC decision is well-reasoned and consistent with Illinois law,” O’Dowd said. “We’re proceeding to implement the ICC order as required.”
Complaint: Direct Energy’s Procedures Kept Unhappy Customers from Switching
A ruling by the Canadian Competition Tribunal gives the country’s Competition Bureau the green light to pursue a case against Direct Energy Marketing for water heater return policies and procedures that were aimed at preventing consumers from switching to competitors.
The action against Direct Energy alleges that many Ontario-based customers had little choice but to continue their rental agreements even if they wanted to purchase a water heater or switch to another rental provider.
The bureau is seeking a $15 million penalty and an order prohibiting Direct Energy from engaging in anti-competitive conduct in the future.
The Federal Energy Regulatory Commission last week approved MISO’s proposal to exempt some owners of retiring coal plants from capacity deficiency penalties, rejecting complaints that the Tariff change would undermine reliability and result in market power abuses.
MISO’s Tariff change applies to generation operating during the Planning Resource Auction offer window that will retire or suspend operations between the March 31 end of the window and the end of the 2015-2016 planning year on May 31, 2016.
The change will allow generators the option of not making offers into the PRA without facing liability for physical withholding. It will apply only to the 2015-2016 planning year and only to generators for which MISO has determined a system support reliability agreement is not necessary. (See MISO Seeks to Ease Coal Retirement Conundrum.)
Last year, several generators complained to FERC that there was no clear mechanism within the MISO Tariff that would permit them to buy replacement capacity through the auction to cover the six-and-a-half-week period between the planned retirement of the coal units and the end of MISO’s planning year.
In its March 24 ruling, the commission called MISO’s proposal “a reasonable solution for resources that cannot offer a full-year capacity product” in the upcoming auction and that it had demonstrated that it will not harm reliability (ER15-918).
The commission rejected Indianapolis Power and Light’s argument that the changes could effectively move up the retirement date of units scheduled to retire during the 2015-2016 planning year.
“Market participants with units affected by the proposed Tariff language have already submitted proposed retirement or suspension dates in their respective Attachment Y notifications,” the commission said. “There is no evidence in the record that these market participants will accelerate their respective retirement dates, nor do we see an incentive to do so if they are still participating in the daily energy and ancillary service markets.”
The order also dismissed requests by the Wisconsin Public Service Commission and the Illinois Commerce Commission that the change be rejected because it could cause capacity prices to increase or provide an incentive to exercise market power.
“We note that auction prices would likely increase even in the absence of MISO’s proposal, as the market participants owning these partial-year resources would have to obtain other resources for the remainder of the year — and factor the costs of the replacement resource into their offers,” the commission said. “Inasmuch as the Illinois Commission has not demonstrated how resources not offered into the auction under MISO’s proposal would result in significantly higher revenues than would occur if they offered their capacity including higher cost replacement capacity, we find no basis for its claim that the MISO proposal incentivizes generators to exercise market power.”
Resources that do not offer into the 2015-2016 PRA, but continue to participate in MISO’s energy and ancillary services markets during the portion of the year that they remain in service, will remain subject to MISO mitigation rules, the commission added.
In a related order, the commission rejected Wisconsin Power and Light’s request for a waiver of MISO’s must-offer requirement over its retirement of its 200-MW Nelson Dewey coal-fired units in southwestern Wisconsin (ER15-872). The units must retire by Dec. 31 under the terms of a 2013 consent decree with the Environmental Protection Agency and the Sierra Club.
The commission said its approval of the MISO Tariff changes “provide Wisconsin Power relief from the misalignment between [its] … retirement deadline and the timeline of the 2015-2016 planning year.”
A 277-page report on an explosion at the Department of Energy’s Waste Isolation Pilot Plant last year concludes that the incident was caused by … cat litter.
That’s right: Workers at Los Alamos National Laboratory have long used cat litter to absorb liquid nuclear waste. But not all cat litter is alike, as pet owners around the world have long known. Instead of using inorganic clay litter, workers apparently used Swheat Scoop organic litter inside troubled drum 68660.
And while Swheat Scoop may appeal to those seeking a green solution to cat cleanup, it does not work well in certain industrial settings. “Experiments showed that various combinations of nitrate salt, Swheat Scoop, nitric acid and oxalate self-heat at temperatures below 100 C. Computer modeling of thermal runaway was consistent with the observed 70-day birth-to-breach of drum 68660,” according to the report.
The incident caused the drum to burst open, spreading radioactive plutonium, americium and uranium throughout the facility. The plant closed after the incident, but the department hopes to open it next year.
DOE Pledges $450 Million for Modular Reactor Design
The Department of Energy has said it will provide $450 million for design studies for small modular reactors. It said the money will go toward engineering, design certification and licensing for up to two SMR designs over the next five years. SMR designs call for reactors about a third of the size of the current 1,000-MW designs now in use. Experts say the smaller size translates into lower construction costs and increased safety and siting potential. The latest funding announcement is aimed at pushing forward designs by 2022 that have the commercial potential.
The Nuclear Regulatory Commission is questioning some of Entergy’s proposed uses of the Vermont Yankee decommissioning funds. Entergy has said it wants to use some of the $660 million in the fund to pay for its property taxes, some insurance and security costs, as well as its membership in the Nuclear Energy Institute.
“We have identified several line-item expenditures that, at least at first glance, do not appear to be permissible under NRC regulations in this area,” NRC spokesman Neil Sheehan said. NRC is asking Entergy for more information before making a ruling on the spending. Any disbursements from the fund in the early stages of decommissioning mean it will take longer for it to reach $1.2 billion, the estimated total cost of dismantling and cleaning up the reactor site.
Virginia Senator Questions FERC on Pipeline Hearing Rules
Warner
Virginia Sen. Mark Warner has written a letter to the Federal Energy Regulatory Commission after opponents to a proposed pipeline through the rural central part of the state said they felt short-changed by the public input process.
Warner asked FERC Chairman Cheryl LaFleur to make clearer the process for signing up to comment during public meetings. The request came after opponents to the proposed Atlantic Coast Pipeline showed up at a scoping meeting in Nelson County earlier this month. They had been told to show up a little before the 7 p.m. meeting to sign up to comment, and found that Dominion Resources, one of the pipeline’s owners, had already signed up dozens of supporters to speak.
Friends of Nelson member Ernie Reed said the public comment process needs to slow down and allow all members who want to talk a chance to be heard. “To just give it the time required and the time that’s necessary is all we’re asking, but it’s the type of an ask that Sen. Warner has now made, and we’re hoping FERC responds in a positive way and gives us and the rest of the public the opportunities that we deserve,” he said.
FERC Tells Planners of Ohio Pipeline to Find Less Populated Route
The Federal Energy Regulatory Commission told the company planning to build a 103-mile natural gas pipeline through northeastern Ohio to find a less populated area for the project’s path. Texas-based Nexus Gas Transmission said it will consider the request, which came a day after the city of Green proposed the pipeline be moved away from heavily populated areas.
The proposed pipeline is being built to move gas from Ohio’s Utica Shale fields. FERC noted in its letter to Nexus that the project is generating “a large volume of public comments.” The city, in its filing with FERC requesting that the pipeline route be adjusted, said the route was “hastily drawn and ill-conceived with no respect to the human and environmental concerns.”
Departure of Harry Reid Could Spell Rebirth of Yucca Repository
The announcement by Sen. Harry Reid (D-Nev.), long an opponent of the Yucca Mountain nuclear waste repository, that he would not seek reelection in 2016 could signal a rebirth for the project. According to Bloomberg, Senate Democrats who had been loath to vote against Reid on the project may be more likely to with him gone. The project, which has so far cost U.S. taxpayers $15 billion, went dormant after the Obama administration said it wasn’t a “workable option” and cut funding.
IG Investigating NRC Actions in PG&E Quake Standards
The Nuclear Regulatory Commission’s Office of the Inspector General is reviewing the agency’s actions in allowing Pacific Gas & Electric to make changes to its earthquake safety standards without a public hearing. PG&E made the changes in response to a discovery of more nearby fault lines than originally thought.
Fault lines were discovered after construction of the plant began in 1968, but more were found in 2011, and in 2013 PG&E changed the plant’s final safety report to use a less conservative method of making seismic-damage calculations.
Investigators are looking into that change of procedure, as well as charges by a former NRC inspector at the plant. That inspector, Michael Peck, said the plant was no longer operating within the parameters of its license. Peck has said his concerns were ignored by both NRC and PG&E. “The ground motion is way beyond what was analyzed in the original license,” he said in an interview Wednesday. “They basically bypassed that whole process. We’re not enforcing it, and I don’t know why. We gave them a pass.”
PG&E said the plant is observing all NRC regulations and is safe.
First Ocean Wind Energy Research Facility to be Built off Va. Shore
A 12-MW offshore wind energy test facility will be built off the coast of Virginia Beach, the first research lease to be executed in federal waters. The Bureau of Ocean Energy Management announced that two 6-MW wind turbines will be installed and operated by Dominion Virginia Power. Information gathered by the test facility will be used to help researchers and developers of future wind energy facilities offshore, according to BOEM.
The towers will be built about 24 miles off Virginia Beach. Power is to be delivered to the grid through subsea cables.
Environmentalists applauded the news. “Full-scale development of offshore wind can create thousands of clean energy jobs and address climate change while displacing Dominion’s plans for new gas power plants and an unwise investment in a new nuclear reactor at North Anna,” said Glen Besa, director of the Virginia Chapter of the Sierra Club.
The Illinois Municipal Electricity Agency will not be able to use capacity resources outside of the Commonwealth Edison locational delivery area to fulfill its internal capacity requirement for the 2018/19 delivery year, the Federal Energy Regulatory Commission has decided.
In its ruling, FERC distinguished IMEA’s waiver request from a similar one it granted last year (ER14-1681). In that decision, FERC deemed IMEA did not have adequate notice to prepare for its ComEd LDA being modeled for the first time with a separate variable resource requirement curve.
“PJM and IMEA note that the treatment of IMEA’s external resources is being addressed through the PJM stakeholder process, which will allow for concerns related to reliability and harm to third parties to be vetted and, as appropriate, inform any proposed changes to the Reliability Assurance Agreement or other PJM governing documents,” FERC said.
“We recognize that denial of IMEA’s waiver for the 2018/2019 delivery year will require IMEA to adjust its capacity portfolio for the planning year, but we encourage IMEA and PJM to continue to work on a longer term solution.”
A labor council representing New York utility workers is worried that the state’s path-breaking initiatives in the smart grid, distributed energy resources and energy storage are taking attention away from overdue needs for transmission upgrades in the state.
A so-called Memorandum of Concerns, while endorsing the new “utility paradigm” of New York’s Reforming the Energy Vision, said that the program needs extensive transmission upgrades to succeed. (See New York PSC Bars Utility Ownership of Distributed Energy Resources.)
“While these initiatives have provided benefit to New York ratepayers and thrust New York state to the forefront of the electric industry, the transmission infrastructure these elements are connected to have been greatly neglected,” said Theodore Skerpon, chairman of the 15,000-member New York State International Brotherhood of Electrical Workers Utility Labor Council, in a March 20 filing with the PSC (12-T-0502).
“The primary foundation of REV is the ability to efficiently move electricity across the state to determine an accurate cost-benefit analysis for proposed local generators,” the memo adds.
The memo points out that 80% of the state’s high-voltage transmission lines are at least 35 years old and that 4,700 circuit miles will require replacement within the next 30 years. Upstate New York generation is needed to supply demand but is constrained by transmission bottlenecks.
New York Gov. Andrew Cuomo unveiled the New York Energy Highway to address those issues in 2012, building upon his administration’s own assessment and studies by NYISO and the Federal Energy Regulatory Commission. The initiative is envisioned as a public-private partnership to spur at least $2 billion in private investment to expand or upgrade transmission corridors from upstate generating plants to load centers in and around New York City.
PSC Spokesman James Denn said REV and the Energy Highway are proceeding in tandem, as the PSC in December said it will determine the need for relief of persistent transmission congestion along the Mohawk and Hudson Valley transmission corridors. A technical conference will be convened in mid-2015 to identify the scope of the problem. (See New York PSC Orders Study, Conference on Transmission Congestion.) New York has identified the need for about 1,000 MW of additional capacity but has not named specific projects (13-M-0457).
“Staff’s need report is expected to be issued on or before June 10, 2015, followed closely by the all-parties technical conference to ensure that all parties can raise questions about its recommendations. The proceeding remains very active, with parties, including staff, submitting well over 100 critically important documents since December,” he said.
A meeting last Tuesday among the New England congressional delegation, ISO-NE and Federal Energy Regulatory Commission Chairman Cheryl LaFleur ended the way that it started: with LaFleur and the RTO defending rising capacity prices and the delegation unhappy.
The delegation requested the meeting after its failed attempts to get FERC to reopen the results of last year’s Forward Capacity Auction. Total costs tripled to $3 billion in FCA 8, covering the 2017-2018 period.
The results became effective when a short-handed FERC deadlocked at 2-2 over whether they were “just and reasonable.” LaFleur, who voted to approve the results, stood by her decision in a letter to the delegation last month. (See LaFleur Rejects Further Review of 2014 ISO-NE Capacity Auction.)
Last week’s meeting at the Capitol was organized by Massachusetts Democratic Reps. Joseph P. Kennedy III and Richard Neal, and included LaFleur, ISO-NE CEO Gordon van Welie, 14 other congressmen and three senators. Staff members of several other congressmen and senators also attended.
According to Kennedy’s office, LaFleur stated that the capacity market is working as intended, with rising prices drawing new generating resources into the region. Reopening a settled case would also set a bad precedent, she added.
Van Welie warned that prices could go even higher.
LaFleur also reportedly said she was satisfied with a staff investigation of the planned closure of the 1,510-MW Brayton Point generating station in Massachusetts, which concluded the closure was not an exercise of market power that would benefit the plant owner’s other assets, as critics have charged. Energy Capital Partners said Brayton Point would close in 2017 and prospective owner Dynegy has stayed with that plan.
“New England residents pay some of the highest electricity prices in the country and these capacity rates continue to climb. There is no way we can look at this system and say it’s working,” Kennedy said. “The markets are rewarding highly consolidated energy incumbents on the backs of consumers … FERC’s inaction around the results of FCA 8 have left ratepayers in legal purgatory with no means to contest skyrocketing rates. This is a regulatory shortcoming that must be remedied. … [Tuesday’s] meeting was the start of a conversation I expect will continue in the weeks and months ahead.”
ISO-NE spokeswoman Lacey Girard reiterated that until plant retirements were announced in 2013, New England had a capacity surplus. About 10% of the fleet is expected to leave the market in coming years.
“These are basic economic fundamentals — when there is excess supply, prices fall, and when there is a shortage of supply, prices rise. The higher prices coming out of last year’s auction helped spur investment in new resources in the most recent capacity auction, including more than 1,000 MW of new generating capacity, which will help address the region’s resource shortage and meet peak demand in 2018,” she said. (See Exelon, LS Power Join CPV in Adding New England Capacity).
“I appreciate Congressmen Kennedy’s and Neal’s work to gather together so many members of the New England delegation to talk about the interesting and complex energy issues facing the region. I welcomed the opportunity to hear the view of the congressmen and senators and feel it was a very productive meeting,” LaFleur said in a statement.
MISO’s Independent Market Monitor says transmission loading relief requests attributed to a Tennessee Valley Authority constraint are causing price volatility within the RTO.
David Patton, CEO of Potomac Economics, told the Markets Committee of the Board of Directors he was concerned MISO is taking costly actions to manage a constraint that is not binding and that TVA may be relying excessively on external relief.
“We have a relatively unfavorable set of provisions that obligate us to model the constraint in our market, as if this is our constraint, and then obligates us to provide what appears to be an oversized amount of relief on the constraint,” Patton said during a presentation to the committee March 25.
Patton cited a TLR event on Feb. 20 in which TVA called for curtailing non-firm commitments toward managing the Volunteer-Phipps Bend constraint. He explained that when a TLR is called, MISO activates the constraint in its market, causing its generators to move and provide the flow relief requested.
The price effects on MISO’s market “can be dramatic,” Patton said, citing the price volatility that occurred in Michigan between 1 a.m. and 1 p.m. on Feb. 20.
Real-time prices at the Michigan Hub that were fluctuating around $50/MWh without the constraint began “bouncing up and down” to as high as $450/MWh with the effect of the constraint. “When prices do this we’re ramping generators up and down,” Patton said.
That one day’s price volatility raised the average price in February by more than 5%, Patton told the committee.
Uneconomic Flows
Besides causing price volatility, the TLRs affect the dispatch of MISO’s resources, Patton said, pointing to flows between MISO South and MISO Midwest regions.
Without the TLR constraint, transfers from MISO South to MISO Midwest were economic because of relatively high natural gas prices in the Midwest.
But the February constraint caused flows to frequently change direction and flow uneconomically from Midwest to South, Patton said.
On Feb. 20, MISO was virtually the only entity re-dispatching to reduce the flow on the constraint, “yet we’re incurring tremendous costs in our dispatch to provide relief, so there’s a couple of problems there.”
“One is that the amount of relief we’re being asked for is overly aggressive,” Patton continued, and the other is that MISO’s flows aren’t considered firm even though it is dispatching its own generation to serve its load.
“We also have concerns about other entities around us that are being overly aggressive in their use of the TLR process and we’re not sure there’s any oversight of what entities are doing.”
Board Chairman Judy Walsh asked Patton what MISO can do about the problem and how much it is costing the RTO.
Patton said he believes there are provisions that would allow MISO to categorize its day-ahead dispatch as firm. That would allow the RTO not to have to provide relief unless entities around MISO, including TVA, are curtailing services or redispatching their own systems. “At this point we’re carrying all the water on a day like this.”
As for cost, “it’s costing us tens of millions [of dollars] in congestion. It’s hard to quantify what it costs us” insofar as ramping generation up and down.
On the upside, Patton said the biggest concerns MISO has had historically with TLRs involved SPP, but the market-to-market process the RTOs now use to cooperatively manage each other’s constraints has virtually eliminated those TLRs.
Working on Congestion Management
Todd Ramey, who manages MISO’s real-time operations, told the committee that the TVA constraints are “interregional transfer constraints that bind infrequently but predictably.”
Typically this occurs when there are high loads to the north and east of the interconnection and lower and more moderate loads to the south and west.
The weather was particularly cold in the north on the day cited by Patton.
Ramey said he has no doubts that reliability concerns of the TVA reliability coordinator in the flow gate “were legitimate” during the period in February, but he said he concurred with Patton’s concerns.
Since the Feb. 20 constraint, MISO has been working with TVA to improve joint administration, Ramey said. “Efforts are underway. We’ve had conference calls with TVA” and plan additional meetings to go over data for joint congestion management, Ramey added.
Winter Performance Improved
At the meeting, Patton also summarized market conditions for February and noted a stark contrast from a year earlier, when the RTO struggled with extreme cold during the polar vortex.
This February, energy prices were down almost 40% — and natural gas prices down 57% compared to the year before.
“Market conditions were quite a bit more stable this year,” Patton said, noting fewer fuel supply issues, more available generating units and milder weather.
Ramey said while this past winter has been referred to as relatively mild, there were some parts of the MISO region that experienced cold temperatures reminiscent of the winter of 2013-14. Ramey cited a much-improved performance of peaking units and continued coordination with gas pipeline operators in the most recent winter.
New York regulators say the Federal Energy Regulatory Commission’s recent order on reliability-must-run agreements “interferes” with state authority as they try to address generation shortages in the state (EL15-37).
The New York Public Service Commission last week asked for a rehearing of FERC’s Feb. 19 order, which said the state must adopt uniform rules to prevent the need for protracted proceedings to ensure generators received compensation for continuing to operate. FERC said the lack of uniform rules created uncertainty that could compromise system reliability. (See FERC Orders NYISO to Standardize RMR Terms in Tariff.)
“The commission must reconsider the RMR order because it ignores the fact that the NYPSC has already exercised its authority to ensure the availability of generation facilities needed for reliability, and interferes with the NYPSC’s ongoing exercise of this authority in approving reliability support services agreements,” the PSC wrote.
The PSC has relied on RSSAs to delay the retirements of generating facilities needed for reliability, such as the Dunkirk plant outside Buffalo and the Cayuga plant in Lansing, near Ithaca.
The PSC said FERC “failed to provide evidence that the NYPSC-approved RSSAs were inadequate to the task of addressing the reliability concerns cited in the RMR order.”
The PSC also objected to a FERC proposal to require what it termed an excessive full cost-of-service rate. “Full COS rates are neither required, nor just and reasonable, where the provider of a public service intends to abandon that service,” the PSC wrote. “Indeed, it has long been a well-accepted regulatory principle that a public service provider may not abandon service and must continue service even at less-than-COS rates until the abandonment is authorized.”
FERC ordered NYISO to create a process for determining which generation resources seeking to deactivate are needed for reliability; how they should be compensated, including accelerated cost recovery for generators that require upgrades; and how RMR costs should be allocated.
American Electric Power and FirstEnergy plan to shut down more than 9,200 MW of coal-fired generation and invest hundreds of millions to keep other plants operating under the Environmental Protection Agency’s Mercury and Air Toxics Standards (MATS).
“We have been investing in, operating and staffing the generating units scheduled for retirement in a way that would not support their continued operation past their planned date of retirement,” AEP spokeswoman Tammy Ridout said Monday.
For those plants that AEP plans to keep, “the investments that we are making [to meet MATS] also satisfy other Clean Air Act requirements,” such as the Cross State Air Pollution Rule (CSAPR) and Regional Haze regulations, she added. “We are fully committed to those investments, and by the time a decision from the Supreme Court is expected, we will have completed or be well on our way toward completion with most of them.”
FirstEnergy has the same outlook. “The plants that we’ve announced for closure, we don’t have any plans to change those decisions,” said FirstEnergy spokeswoman Stephanie Walton. “We’re investing $370 million in upgrades to comply with MATS. Most of [the investments] will have been made by the time the Supreme Court rules.”
Indeed, about 90% of the capital expenditures needed to meet MATS compliance have already been spent, attorney Paul M. Smith, representing Calpine and other generators, told the justices last week.
AEP and FirstEnergy aren’t alone in downplaying the potential impact of the court’s ruling on the queue of coal plants headed for the gallows.
“We see little in immediate practical implications on power markets arising from a scenario where the Supreme Court overturns MATS,” UBS analysts said in a research note last week. “Rather, with the current gas price environment virtually ensuring limited run times on coal plants, particularly of the Appalachian variety which are primarily impacted by these regulations, we do not think many coal assets will elect to continue operations.”
“I think it’s pretty unlikely that anything like a majority of the plants announced for retirement could be backed off on,” agreed Anne Smith, co-chair of NERA Economic Consulting’s global environment practice.
Cost-Benefit Analysis
While the court’s ruling will be too late to provide a reprieve for most of the old, small plants targeted for retirement, it could have an impact on EPA’s efforts to reduce emissions from electric generation.
A ruling that requires EPA to take costs into account when it decides what to regulate — as opposed to when it sets the standards — could have broad implications.
Some environmental attorneys say the Supreme Court decision to hear the MATS challenge could indicate it is reconsidering its 2009 decision that held EPA had discretion on how to consider the cost of regulating large cooling water intake structures under the Clean Water Act, which doesn’t expressly authorize or forbid the use of cost-benefit analyses.
A ruling that found it was “arbitrary and capricious” for EPA not to consider costs could raise the bar for future regulations.
EPA claims MATS will cost $9.6 billion annually but produce total benefits of at least $37 billion to $90 billion per year, preventing as many as 11,000 premature deaths and 130,000 asthma attacks, while eliminating 5,700 hospitalizations and emergency room visits and 540,000 missed workdays.
However, only a fraction of the benefits — $500,000 to $6.2 million annually — are directly related to cuts in mercury emissions. The remainder are “co-benefits” that arise not directly from reducing toxic emissions, but from reductions in particulate matter and carbon emissions expected to result from the standards.
Critics say EPA has engaged in over counting, citing the same co-benefits to justify multiple EPA regulations.
Section 112 vs. 111(d)
The MATS case, which turns on an interpretation of section 112 of the Clean Air Act, also could have an impact on challenges already filed to EPA’s proposed greenhouse gas rule, which the agency is pursuing under section 111(d) of the act.
A suit by coal mining company Murray Energy argues that it is illegal for EPA to regulate generating plants under section 111(d) because power plant emissions are already regulated under section 112. If the Supreme Court rejects the mercury rule, it could remove that as a basis for a challenge on the carbon rule, some say.
PJM Impact
But MATS, 25 years in the making (see related story), will have a major impact regardless of the court’s ruling.
In PJM, 120 generating units totaling about 12,500 MW have indicated plans to retire by 2018. The plants average 48 years old, with some as old as 67. Only four of the units, totaling 425 MW (3.4% of total capacity at stake), are less than 40 years old.
At the end of last year, AEP had generating capacity of almost 37,600 MW, more than 23,700 MW of it coal-fired. It plans to retire 6,500 MW by the end of next year, including 5,400 MW in PJM.
AEP said a decision to remand or suspend the rule could impact certain aspects of the operation of environmental controls that are already installed or are currently under construction. “For example, there could be greater flexibility to operate selective catalytic reduction systems and SO2 scrubbers if they are not needed to achieve the mercury and acid gas limits under the MATS rule, but are only required to achieve compliance with the market-based CSAPR programs,” Ridout said.
FirstEnergy cited MATS in announcing in January 2012 it would retire six coal-fired plants totaling 2,689 MW in Ohio, Pennsylvania and Maryland by September of that year. The closures were projected to affect about 529 employees. Retirements of three Ohio plants — Eastlake, Ashtabula and Lakeshore — have been delayed under reliability-must-run agreements.
The retirements will leave FirstEnergy with six coal-fired plants totaling 9,228 MW in Ohio, Pennsylvania and West Virginia. Most of those being retired are 500 MW or smaller and served as peaking or intermediate generators; those being retained are 1,000 to 2,500 MW baseload plants.
PJM’s reliability concerns also led East Kentucky Power Coop. to delay retirements of Dale Station Units 3 and 4 until April 2016, a year later than planned. EKPC closed Units 1 and 2 of the Clark County, Ky., plant about a year ago.
EKPC said Units 3 and 4 would be maintained in case market and regulatory conditions allowed their retrofit or conversion. The plant, with a capacity of 196 MW, began operating in 1954, with the newest unit dating from 1960.
“If the Supreme Court makes a decision that changes the rules on MATS, our board would carefully look at that decision to assess whether our plans should change,” said EKPC spokesman Kevin Osbourn.
GHG Rule: Good for Regulated Gens, not Merchants
EKPC, which has invested nearly $1.5 billion in two new coal-burning units and retrofits to older units, said it fears those investments could become stranded as a result of EPA’s Clean Power Plan, which will require Kentucky to reduce its carbon emissions by 18% from 2005 levels by 2030.
But the additional regulations won’t necessarily be a bad deal for utility investors.
“To the extent we install additional controls on our generation plants to limit CO2 emissions and receive regulatory approvals to increase our rates, return on capital investment would have a positive effect on future earnings,” AEP told investors in its 2014 annual report. “Prudently incurred capital investments made by our subsidiaries in rate-regulated jurisdictions to comply with legal requirements and benefit customers are generally included in rate base for recovery and earn a return on investment. We would expect these principles to apply to investments made to address new environmental requirements.
“However, requests for rate increases reflecting these costs can affect us adversely because our regulators could limit the amount or timing of increased costs that we would recover through higher rates. For our sales of energy into the markets, however, there is no such recovery mechanism.”
The Federal Energy Regulatory Commission on Friday approved Dynegy’s purchase of 12,500 MW of generation from Duke Energy and Energy Capital Partners, the final approval needed for both deals (EC14-141, EC14-140).
The $3.45 billion ECP deal is scheduled to close Wednesday, while the $2.8 billion Duke acquisition will close Thursday.
With the two deals, Dynegy — which emerged from bankruptcy less than three years ago — has boosted its total ownership to nearly 26,000 MW of generation.
Dynegy will own 11 Duke generating units in Ohio, Illinois and Pennsylvania totaling about 6,100 MW, as well as Duke Energy Retail Sales, its competitive retail business in Ohio. The ECP deal gives Dynegy 10 generators totaling 6,400 MW, primarily in the Midwest and New England.
Dynegy would gain about 9,000 MW in PJM, boosting it to more than 10,700 MW and eighth in generation share in the RTO.
Dynegy expected to close the deal with Duke by the end of last year, but it missed that deadline while it was addressing market power concerns from PJM’s Independent Market Monitor. Those concerns were resolved in a settlement last month, with Dynegy agreeing it would not try to buy any of the plants that will come on the market as a result of the PPL-Riverstone Holdings deal to form Talen Energy. It also committed to offer all of its units into the PJM capacity market auctions and promised it wouldn’t retire any units unless they failed to clear. (See Dynegy, PJM IMM Reach Settlement on Duke, Energy Capital Partners Deal.)
No Market Power Concerns
In approving the deals, FERC said it saw no market power concerns in either ISO-NE or PJM. It said Dynegy’s share of New England’s energy market would rise as high as 17.7% and its share of the region’s capacity market would be 9.4%.
The commission also rejected a complaint by Utility Workers of America Local 464 that the transaction would enable Dynegy to raise New England capacity prices due to its acquisition of ECP’s Brayton Point Station, which is scheduled for retirement in 2017.
The commission said Brayton Point’s closure was beyond the scope of its review of the ECP transaction and that the union did not explain how it derived the price increases it claimed would result from the a reduction in offered capacity.
“As the commission has explained, its authority to condition [asset sale] authorizations is limited to addressing specific, transaction-related harm,” FERC said. “The issues raised by UWA Local 464 are related to the retirement of the Brayton Point Station, which the commission has already reviewed, rather than the proposed transaction.”
More Deals on the Way?
The Houston-based merchant generator has indicated it is looking to expand its fleet still further. A Dynegy executive toldColumbus Business First last month that the company “would be very interested” in American Electric Power’s coal plants in Ohio. AEP, which failed in its initial bid to secure a power purchase agreement for one of its Ohio coal plants, has hired investment bank Goldman Sachs Group to investigate the sale of its coal-fired fleet. (See AEP Considering Sale of 8,000 MW in Ohio, Indiana.)
Those plants, with a combined capacity of 7,875 MW, are in Ohio, except for the 1,186-MW Lawrenceburg plant in Indiana. Some 2,100 MW of the plants Duke is selling to Dynegy are partially owned by AEP already, and Dynegy has said it would make sense to consider acquiring AEP’s share.
