WILMINGTON, Del. — The PJM Markets and Reliability Committee on Thursday tabled voting until next month on a proposal to tighten rules on lost opportunity costs for combustion turbines.
PJM and Independent Market Monitor Joe Bowring supported the change, saying that current rules provide incentives for units to offer and clear in the day-ahead market but not in the real-time market.
Under the proposal, units with start-up and notification times of no more than two hours and minimum run-times of two hours would be paid lost opportunity costs if they are not dispatched. Resources with real-time startup and notification times or minimum run-times of more than two hours will not receive lost opportunity payments unless PJM bars them from running in real time to avoid transmission overloads.
PJM would use the generator’s energy schedule to calculate opportunity costs except for self-scheduled units, for which the higher of the available cost- or price-based curves would apply.
“The two-hour start notification and two-hour minimum run are designed to be aligned with what the dispatch operators can see,” said Stu Bresler, PJM vice president of market operations.
Bowring called the proposal “clearly an improvement.”
But Ed Tatum of Old Dominion Electric Cooperative raised an objection to limiting LOC compensation to units with minimum run times of two hours or less, saying it was too restrictive.
Susan Bruce of the PJM Industrial Customers Coalition said dropping the restriction would be “cherry picking” on a compromise that stakeholders agreed to at the Energy Market Uplift Senior Task Force, where the proposal won 84% support last month.
With two objections and one abstention, the MRC decided to send the issue back to the task force for additional discussions at its meeting tomorrow. The MRC will vote on the current proposal at its April meeting, considering any friendly amendments or alternate motions developed at the task force meeting.
Separately, members approved a proposal that was unanimously approved by the task force, instructing the Planning Committee to treat uplift as an input to analyses under the Regional Transmission Expansion Plan.
Opponents of a pipeline that would move shale gas from northeastern Pennsylvania to New York and New England markets made good on a promise Friday to go to court to force a rehearing of federal regulators’ approval of the project.
The Federal Energy Regulatory Commission issued a rehearing order on Jan. 27, but the Stop the Pipeline group says that is merely a procedural move as the regulator avoids its petition “to grant, deny or otherwise act on the merits of STP’s Jan. 2, 2015, request.” The group wants FERC to hold a rehearing by May 1, it said in its plea for a writ of mandamus from the U.S. District Court of Appeals for the Second Circuit in New York (15-926). (See Constitution Pipeline: Headed to Completion or to Court?)
The proposed 124-mile Constitution Pipeline won a certificate of public convenience and necessity from FERC on Dec. 2. The commission issued its Final Environmental Impact Statement on Oct. 24.
The actions were taken before the project received other regulatory approvals, including water quality permits under the Clean Water Act’s section 401, which opponents say is a violation of the law.
The project is currently under review by the New York Department of Environmental Conservation, which closed its public comment period on Feb. 27.
Without action on the rehearing, STP says it is in “administrative limbo” while it also is denied the opportunity to challenge FERC’s order in court. STP said Constitution started more than 120 eminent domain proceedings in mid-December, and by Feb. 21 a district court had given Constitution the right to condemn the properties and enter potential pipeline sites without the owners’ permission.
“The commission has caused, and continues to cause, significant injury to STP’s members … before it has even been determined that the pipeline project will ultimately be authorized to proceed,” the petition states.
Constitution is on an aggressive schedule, with construction scheduled to start this year and the pipeline in operation by late 2016. It would connect the Pennsylvania gas fields with an interstate pipeline that runs from the Southwest to New England.
“FERC has already thoroughly evaluated the project and approved this vital infrastructure, agreeing that the plan we have developed minimizes environmental impacts. We are looking forward to obtaining final clearances so we can begin construction this summer,” Constitution spokesman Christopher Stockton said.
Multiple stakeholders have asked the Federal Energy Regulatory Commission for a rehearing of its Feb. 19 ruling involving MISO’s system support resources agreements at a trio of aging power plants in Michigan’s Upper Peninsula.
The February ruling affirmed FERC’s previous finding that MISO could no longer allocate broadly within the American Transmission Co. pricing zone the SSR costs of keeping open three aging plants — most notably the Presque Isle generating station near Marquette. (See FERC Upends MISO’s SSR Cost Allocation Practice.)
The March 23 filings seek rehearing on several parts of the commission’s February order that required MISO to file a new study method to identify entities that benefit directly from the three plants and allocate costs of the agreements directly to them.
Double Recovery
One of the requests was filed jointly by Tilden Mining and Empire Mining Partnership, which last October filed a protest alleging Presque Isle owner We Energies was recovering SSR costs through the utility’s retail rates as well as through MISO’s SSR surcharges. Last November, FERC acknowledged the double recovery issue was raised by several stakeholders. It accepted a replacement SSR but said it would be subject to refund.
But the mines complain FERC declined to address concerns about double recovery of fixed capital costs through We Energies’ retail rates.
“FERC failed to engage in reasoned decision making and abdicated its statutory responsibility to assure that MISO’s federally regulated SSR rates are just and reasonable in the context of shared state and federal regulatory responsibility,” the mines said (ER14-1242).
“Whether or not the commission likes it, the fact is that the state-authorized recovery of [Presque Isle] costs through [We Energies’] 2014 Wisconsin retail rates included full recovery of the Wisconsin share” of the utility’s Presque Isle costs.
The Sault Ste. Marie Tribe of Chippewa Indians made the same argument in a separate filing (ER14-2952-002).
The City of Mackinac Island also requested rehearing, also citing the mines’ reasoning. The city also alleges that MISO should not have authorized an SSR agreement for Presque Isle because the plant’s owner had not made a “definitive” retirement decision (EL14-103).
Michigan PSC
The Michigan Public Service Commission filed a 20-page request saying FERC should reverse its retroactive allocation of SSR costs for Presque Isle, White Pine and Escanaba plants (ER14-2952). FERC established April 3, 2014, as the retroactive date.
FERC’s Feb. 19 order was a win for the Wisconsin Public Service Commission, which last year alleged MISO improperly allocated SSR costs on a pro rata basis to all load-serving entities in the ATC footprint.
The Wisconsin PSC argued that 92% of the projected $52.2 million in annual fixed costs under the original Presque Isle SSR would be allocated to load serving entities in Wisconsin even though they would receive only 42% of the benefits from the plant’s continued operation.
The city of Escanaba, Mich., asked the commission to clarify that its rejection of MISO’s cost allocation proposal does not bar “a methodology using all or part of either an optimal load shed methodology or some use of [local balancing authority area] boundaries under certain circumstances, if MISO’s compliance process fails to produce a suitable substitute” (EL14-34).
Challenge to Rate Design
But the order has also drawn additional opponents, including Integrys Energy Services. In its rehearing request, it alleges the commission erred by applying a new rate design methodology to the ATC zone different than that applied in MISO previously and by applying that new rate design retroactively (ER14-1242).
“On rehearing, if the commission is going to require a new methodology for allocating SSR costs throughout MISO, it should apply these changes prospectively and only after the methodology has been shown to be just and reasonable,” Integrys said.
The recent filings are just the latest in the ongoing Presque Isle saga. In mid-March officials announced that a deal to sell Presque Isle to Upper Peninsula Power would be scrapped. We Energies will retain the plant now that Tilden and Empire will come back as customers of Presque Isle. The mines decided two years ago to purchase power from other providers under Michigan’s partially deregulated electricity market.
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.
NRG Awaiting State Approval to Switch Dunkirk to Gas
NRG Energy is awaiting approval from the New York Department of Environmental Conservation of its updated air quality permit to allow the switch of its Dunkirk, N.Y., generating station from coal to gas. A 30-day period for public comment ended on March 20. Dunkirk was built in the 1950s and has always been a coal-burning plant. The conversion is expected to be completed by the end of the year. (See Dunkirk Plant Chronology.)
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.
WILMINGTON, Del. — The PJM Markets and Reliability Committee on Thursday tabled voting until next month on a proposal to tighten rules on lost opportunity costs for combustion turbines.
