Search
December 17, 2025

Posted on

Resource Adequacy to Get More Focus at MISO as Coal Plants Fade

By Chris O’Malley

misoCARMEL, Ind. — MISO on Thursday launched the first in a series of stakeholder workshops planned over the next 18 months dedicated to improving resource adequacy as the RTO deals with the retirement of coal-fired generation and the growth of natural gas and renewables.

There’s some urgency: MISO forecasts that its Planning Reserve Margin Requirement, which is peak demand plus the planning reserve margin, could drop below its target as early as 2016.

The RTO last month released a draft white paper, “Issues Statement on Facilitating Resource Adequacy in the MISO Region,” to serve as a framework for reversing its declining margins.

“Basically, we’re going to have smaller reserve margins and we’re going to have different resources in play,” Joseph Gardner, MISO’s vice president of forward markets and operations services, told stakeholders. “We’re trying to have a common understanding [of] what the issues are.”

The white paper notes that MISO’s current processes do not:

  • Ensure transparency across all seasons and all time horizons;
  • Address issues related to resource performance, such as fuel assurance and winterization;
  • Treat a resource consistently as it moves from interconnection to retirement; or
  • Provide applicable incentives for all load-serving entities to ensure adequate resources.

Technically, of course, MISO is not the guarantor of resource adequacy. LSEs and states that regulate them are responsible for assuring adequate resources in their jurisdictions.

MISO is building its efforts to support LSEs and the states around four “strategic goals.”

Better Picture Needed

One goal is “Regional Assessment and Transparency,” based on the survey of LSEs that MISO conducted last year with the Organization of MISO States (OMS). Some stakeholders said OMS needs to improve the survey.

Jeff Beattie, a senior engineer at Consumers Energy, said there’s skepticism about the reliability of the data collected, noting that the OMS survey is not subject to peer review. “How can we get further buy-in?” he asked.

“The nature of the OMS survey has been such that confidentiality is strongly protected and only zonal-level shortfalls have been provided to stakeholders. That greatly limits the value of the survey results,” Consumers said in pre-filed comments ahead of Thursday’s workshop.

Consumers suggests that MISO follow the example of NYISO’s “Gold Book,” which provides details for new generators and proposed and actual unit suspensions and retirements.

“If MISO moved in this direction on transparency, it would be much easier for all parties to accurately evaluate resource adequacy in the MISO footprint,” Consumers said.

MISO traditionally has forecast demand based on individual forecasts performed by LSEs, transmission operators and others. However, it recently hired a consulting firm to conduct independent load forecasts through 2017.

“As reserve margins decline, it is now more critical than ever to have confidence that demand forecasting is consistent and accurate,” the paper says.

Looking Outward

Another of the four goals is “Industry Influence, Monitoring and Coordination,” which deals with issues partly or entirely outside of MISO’s direct control, such as fuel reliability, electric and natural gas coordination and support from neighboring systems.

For example, MISO noted that it has been surveying asset owners as to their confidence about fuel deliveries and inventories. The survey is voluntary, however.

As for support from neighboring systems, Entergy has already weighed in by saying that assuming neighboring systems will provide support toward MISO resource adequacy isn’t sufficient.

“If this is an assumption MISO is relying on for [resource adequacy], a study with neighboring systems to determine the appropriate level of support to assume and contractual agreements may be needed to be put in place,” Sarah McCurdy, an analyst with Entergy, said in pre-filed comments.

Other Topics for Debate

Another goal, titled “Evolving the Resource Adequacy Requirements,” deals with MISO’s resource adequacy construct and issues such as retail choice and seasonal and locational considerations.

Traditionally, the focus has been on meeting the summer peak. But one of the questions raised by MISO staff is whether non-summer risk will increase as capacity is squeezed in the years ahead.

“How much of our footprint is winter-peaking?” wondered Amy Jo Miller, commercial market affairs executive at Ameren.

For example, MISO’s paper contemplates that as reserve margins decline, it may have to dispatch seldom-used capacity. This could include increased use of load-modifying resources — such as factories that can reduce energy use by adjusting production schedules and commercial buildings that can reduce air conditioning.

MISO said it has not called on those resources since 2006.

“Because declared emergency conditions will likely become more prevalent as reserve margins decline, MISO may call on LMRs more extensively going forward,” MISO says.

The final goal is “Process Alignment,” which involves identifying and eliminating barriers or inconsistencies within MISO procedures.

One such issue raised by stakeholders is that the current annual construct doesn’t address mid-year retirements and suspensions of generating plants.

Next Meeting

The next workshop meeting is tentatively scheduled for May 15.

Posted on

Low-Income Groups Seek Clarification on Utility Ownership in Reforming the Energy Vision

By William Opalka

A coalition of organizations representing low- and moderate-income households in New York has asked for a clarification and rehearing of last month’s Reforming the Energy Vision order to allow greater participation in the program by less affluent residents (14-M-0101).

The New York Public Service Commission set up a framework for the REV process that limits utility ownership of distributed energy resources with a limited number of exceptions, one of the cornerstones of the state’s path-breaking initiatives in the smart grid, distributed energy resources (DER) and energy storage. (See New York PSC Bars Utility Ownership of Distributed Energy Resources).

“While seeking to pay attention to low- and moderate-income residents, the commission continues to view low- and moderate-income households as merely consumers of energy while providing the opportunity for more affluent residents to be more active participants and owners,” according to a Tuesday filing by the Energy Democracy Working Group, a coalition of six organizations from throughout the state.

The REV generally excludes utility ownership of DER assets, but it allows exceptions for the development of DER intended to benefit the less affluent. The REV order noted that consumer advocates expressed concerns during the proceeding that those residents, including renters, would be excluded from REV benefits.

Energy Democracy agreed with the PSC’s assessment that utility investment may be needed but said the order is unclear regarding what types of investments that may mean, and how partnerships with community groups would be organized.

“We seek clarification as to whether ‘investment’ … means ‘ownership’ or whether it means providing access to financing or other support to allow low-income and moderate-income people to own distributed energy resources themselves,” it wrote.

The group also says that the assumption that DER markets will not develop without utility ownership is “premature” and that the “REV proceeding is meant to change the status quo and reduce barriers” for DER.

While the order does not define low or moderate income, Energy Democracy said it assumes standard measures that define “area median income” are used. “We hope the commission does not mean to write off the approximately 50% of New Yorkers who are low- or moderate-income as unreachable by the new REV markets,” the petition states.

“Low- and moderate-income New Yorkers represent a substantial portion of the state’s population and a large portion of the electricity market. This raises the possibility that … the exception … will represent a significant portion of the market,” it adds.

Posted on

NYISO Asks if ICAP Order Includes the Lower Hudson Valley

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.

Posted on

FERC Cuts ITC Transco Adder in Half

By Rich Heidorn Jr.

itcA 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.

“This order also sends the wrong message at a time when new regulations, such as the [Environmental Protection Agency’s] Clean Power Plan, will likely drive the need for more transmission investment.” (See related story, MISO, SPP Stakeholders Developing Trading Plan to Comply with EPA Carbon Rule.)

“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.”

Posted on

FERC: PJM Demand Response Stop-gap Measure ‘Premature’

By Michael Brooks

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.)

US-Demand-Response-Forecast,-With-and-Without-FERC-Order-745---2014---2023-(Source-GTM-Research)-for-webPJM’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.”

demand response
FERC Commissioner Tony Clark (© RTO Insider)

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.

Posted on

FERC: PJM Capacity Performance Filing ‘Deficient’

By Suzanne Herel

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.
Posted on

Union: Transmission a Critical Part of New York REV

By William Opalka

new york
Skerpon

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.

Posted on

Congressional Meeting Fails to Sway LaFleur on Capacity Results

By William Opalka

new england
Kennedy III

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.)

FCA 9, held in February, saw costs rise another $1 billion, to $4 billion for 2018-2019. (See ISO-NE Files Capacity Auction Results; Comments due April 13.)

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.

Posted on

External Constraint Vexing MISO, Market Monitor Says

By Chris O’Malley

miso
Patton

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.

misoOn 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.

Posted on

FERC Interfering with Reliability Order, NYPSC Says

By William Opalka

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.