NYISO asked the Federal Energy Regulatory Commission this week if a recent order meant to mitigate market power in the installed capacity market in New York City would apply to its new capacity zone in the Lower Hudson Valley (EL07-39-006). NYISO wants an expedited ruling by Monday because market participants are preparing for the May monthly auction. Enrollment closes on Wednesday.
The order accepted NYISO’s compliance filing with the exception of its proposal to grant a blanket exemption from offer floor calculations for all payments and other benefits to special case resources (SCR) under state programs. An SCR is a demand-side resource that participates as a supplier in NYISO’s capacity market. (See FERC Upholds Most of New York City Market Power Order.)
NYISO said it is clear the order requires revisions to state programs for SCRs in New York City and will be included in determinations under buyer-side capacity market power mitigation rules. “It is not clear whether that revision is also to apply to new SCRs in the Load Zones G, H and I (i.e., those within the G-J Locality) or in any mitigated capacity zones that may be created in the future,” NYISO wrote.
The New York Transmission Owners on Thursday opposed the NYISO petition, saying it was counter to the plain language meaning contained in the FERC order. “The clarification request is, in substance, an untimely motion asking the commission to expand the scope of a March 19, 2015, ruling in this proceeding far beyond that expressly established by the commission and addressed by the parties during the more than seven years that this proceeding has been pending,” it wrote.
A split Federal Energy Regulatory Commission on Tuesday granted ITC Midwest’s request for an incentive adder but cut the bonus in half, prompting a dissent from Commissioners Philip Moeller and Tony Clark.
ITC had requested an adder of 100 basis points, consistent with what the commission has granted “independent, stand-alone” transmission companies (transcos) since such incentives were authorized by Congress in 2005 to increase transmission spending.
In response to that directive, the commission issued Order 679, concluding that the transco business model responds more rapidly and precisely to market signals and was thus deserving of an incentive.
“We continue to find that the transco business model provides the benefits that the commission recognized in Order No. 679. However, we note that the commission did not specify the size of the transco adder in Order No. 679,” the commission wrote (ER15-945).
Under current conditions, the commission said, 100 basis points is excessive. “We conclude that 50 basis points is an appropriate size for the transco adder, taking into account the interests of consumers and applicants, as well as current market conditions. Granting this 50-basis-point adder strikes the right balance by appropriately encouraging independent transmission consistent with Order No. 679, while acknowledging protesters’ concerns regarding the rate impacts of such adders.”
The commission said the adder would be applied to a base return on equity within the “zone of reasonableness” determined by an updated discounted cash flow analysis being conducted in docket EL14-12. (See ROE Talks Between MISO Industrials and TOs Collapse.) ITC said it would defer collection of the adder, which became effective April 1, pending the outcome of that proceeding.
Dissent
Moeller and Clark blasted the majority’s ruling, the first time that the commission has reduced a requested transco adder.
“The majority has not provided any guidance as to what showing is necessary to support a 100-basis-point adder moving forward,” they wrote.
“We also find it puzzling that the commission would reduce transmission incentives for a transco business model when it is just beginning to see the effects of competitive solicitation under Order No. 1000,” the commissioners continued. “These mixed messages from the commission on the value of innovative business models and transmission investment decrease regulatory certainty at a time when it is most needed.”
The Federal Energy Regulatory Commission on Tuesday rejected PJM’s contingency plan to include demand response in its capacity auctions in the event an appellate court ruling limiting FERC’s jurisdiction over DR is allowed to stand (ER15-852).
FERC called the filing premature, saying it would disrupt the commission’s options in dealing with the aftermath of the Electric Power Supply Association (EPSA) v. Federal Energy Regulatory Commission case.
FERC has asked the Supreme Court to reconsider the 2-1 ruling, which found that Order 745 violated state ratemaking authority by forcing RTOs to pay market-clearing prices to DR resources. While the ruling only directly addressed FERC’s jurisdiction over DR in energy markets, PJM wanted to be prepared in case it were applied to FERC-regulated capacity markets. (See PJM to File Post-EPSA Demand Response Contingency Plan with FERC.)
PJM’s proposal would have altered its demand curve to reflect actual load by accepting DR bids from any “wholesale entity” in May’s Base Residual Auction, reducing the amount of capacity procured and the price at which it clears.
As a result of FERC’s rejection, PJM said in a statement Wednesday, the BRA for delivery year 2018/19 “will move forward under the existing rules for the participation of demand response.” However, the auction, scheduled for May 11-15, may be delayed as a result of a separate FERC ruling Tuesday that required the RTO to provide additional information on its Capacity Performance proposal. (See related story, FERC: PJM Capacity Performance Filing ‘Deficient’.)
FERC ruled that PJM’s DR idea was good but before its time. “While we recognize that PJM’s goal is to reduce uncertainty surrounding demand response participation in its upcoming BRA, in the present circumstances, it is unavoidable that some uncertainty is inherent in the current stance of the EPSA case,” FERC said.
“Moreover, we are concerned that PJM’s proposal introduces uncertainties that may exceed those it seeks to avoid, particularly with respect to potential unanticipated spillover effects on state programs and private sector arrangements.”
Commissioner Tony Clark dissented, saying that the commission was sidestepping the merits of PJM’s filing.
“Today’s order unnecessarily delays action and perpetuates system inefficiencies created by the overcompensation of demand response products in wholesale electricity markets,” Clark said. FERC should “seize the opportunity to provide guidance on a functional demand-side product to the betterment of the PJM markets.”
Clark, however, said he thought that PJM’s proposal may not have gone far enough and ignored the role its existing Price Responsive Demand product could have played. “Enabling functioning price-responsive demand is the right answer to the conundrum in which we now find ourselves, and it is where the commission should expend the bulk of its efforts,” he said.
PJM had requested the proposal go in effect April 1, in time for the BRA. The RTO argued it was being proactive, and that the changes would only be a temporary measure while FERC developed a more comprehensive solution.
PJM noted that if the Supreme Court granted its writ of certiorari, it would have withdrawn the changes from the Tariff and run the BRA under the previous rules. The court is expected to decide this month whether to take the case.
In its protest to the filing, the Advanced Energy Management Alliance argued that LSEs, curtailment service providers and DR owners would not be able to change their business strategies in time for the BRA. The Illinois Commerce Commission and the Maryland Public Service Commission also argued that in some states, laws and regulations would need to be amended in order to enact the changes.
While not taking a strong position on the merits of PJM’s proposal in its protest, Public Service Enterprise Group argued that if FERC accepted the plan, it should require PJM to keep the changes intact regardless of whether the Supreme Court took the EPSA case, as withdrawing them would create uncertainty in the results of the BRA.
PJM proposed creating two new capacity products: Whole Load Reductions and Whole Energy Efficiency Load. PJM General Counsel Vince Duane said in December, when the proposal was first presented to stakeholders, that the term “wholesale entity” was left “deliberately vague” to allow load-serving entities and electric distribution companies to submit DR bids.
PJM’s controversial Capacity Performance plan was turned back Tuesday by the Federal Energy Regulatory Commission, which deemed the filing deficient and gave the RTO 30 days to provide additional information (ER15-623).
FERC’s four-page order questioned 10 areas of the proposal, which was conceived to increase reliability expectations of capacity resources with a “no excuses” policy.
PJM said Wednesday it will respond to FERC’s questions “promptly and seek expedited review” to allow the new rules to be in effect for the Base Residual Auction scheduled for May 11-15.
“We recognize that process may require a delay to conduct an orderly auction process,” Dave Anders, director of stakeholder affairs, said in an email to members. “While PJM clearly would have welcomed approval, we appreciate the FERC’s thoughtful consideration of our proposal and the commission’s demonstrated commitment to reliability and enhanced generator performance.”
Anders said PJM has never delayed a BRA before.
The commission compared aspects of the PJM proposal with ISO-NE’s “pay-for-performance” design, which it approved last year and on which PJM’s proposal was in large part modeled.
PJM’s proposal was expected to result in both larger capacity payments for over-performing participants and higher penalties for non-performers.
FERC asked PJM to explain its derivation of an appropriate competitive clearing price when no new capacity is required in a locational deliverability area (LDA), and to provide more detail on a default offer cap and how it would apply in several situations.
It also requested any analyses the RTO had conducted on expected performance charges and bonus payments under the proposal. The commission asked if it made sense to phase in the penalties — as ISO-NE has — and for ideas of how to provide incentives for resource performance. In addition, it asked PJM how it plans to evaluate the performance of external resources not pseudo-tied to the RTO.
Moeller: Delay Creates Uncertainty
The commission’s order drew a rebuke from Commissioner Philip Moeller. The RTO’s filing “already contains sufficient information to permit the commission to issue an order on the merits of PJM’s proposal in advance of the May 2015 Base Residual Auction,” he said in a statement.
“Markets provide the best prices for both buyers and sellers when participants know the market rules. Regardless of whether the commission ultimately decides to accept or reject PJM’s Capacity Performance proposal, by failing to act, the commission is creating market uncertainty on issues that need clarity now,” he added.
Dynegy and NRG Energy shares fell sharply April 1 on the news of the ruling, with Dynegy down 2.1% and NRG falling 5.6%. Dynegy recaptured its losses April 2 while NRG only partially rebounded.
More than 60 entities filed comments and protests in response to the plan.
States and load-serving entities (LSEs) were skeptical about the need for a major overhaul, while generators split over elements they liked and others they said must be changed. (See States, LSEs Skeptical, Utilities Split Over Capacity Performance.) Many generators complained the penalties were too harsh; others, including Exelon, said the penalties were too lax.
LSEs feared the product redesign was overkill and would result in unnecessary price increases.
As proposed, the changes would have begun to take effect for the 2016/17 delivery year and be fully implemented in 2020/21.
The details are outlined in nearly 1,300 pages filed in two dockets:
EL15-29 contains proposed changes to PJM’s Operating Agreement and Tariff “to correct present deficiencies in those agreements on matters of resource performance and excuses for resource performance.”
ER15-623 proposes changes to the Reliability Pricing Model in the Tariff and Reliability Assurance Agreement.
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.
