Page 1635 – RTO Insider

June 20, 2016

Cathey’s Inner Geek Helps SPP Incorporate New Technologies

By Tom Kleckner

LITTLE ROCK, Ark. — It doesn’t take much for SPP’s Casey Cathey to let his inner geek flag fly.

Casey Cathey, SPP (copyright RTO Insider) — Casey Cathey, SPP © *RTO Insider*

“Have you heard about Solar Reserve’s salt tower?” he asks, jumping to his feet and grabbing a marker. Cathey steps to the whiteboard and begins to sketch a representation of the 110-MW Crescent Dunes Solar Energy Plant in Nevada. It is capable, its developers say, of providing enough firm solar energy to power 75,000 homes.

Cathey explains how the 10,000 tracking mirrors encircle the 640-foot molten salt tower, following the sun’s movements to concentrate sunlight onto a large receiver at the top of the tower. Molten salt flows through the receiver and down piping inside the tower, eventually being stored in a thermal tank. The salt is then passed through a steam-generation system that provides electricity as needed.

“I’m sorry, but I really geek out about things like this,” a visibly excited Cathey says.

It comes with the job. As manager of operations analysis and support, Cathey led the group that produced a 2015 wind-integration study that revealed SPP could successfully handle wind-integration levels as high as 60%. That same group is now working on a follow-up analysis, the newly renamed Variable Generation Integrated Study.

Cathey also represents SPP on the ISO/RTO Council’s Emerging Technologies Task Force, which has further exposed him to the new technologies and challenges facing the electric industry.

“What we’ve learned is everyone has problems,” he says. CAISO “has too much solar; we have a lot of wind; [and] Toronto has reduced their nuclear plants to offset the wind.”

Front-Row Seat

Cathey almost can’t believe his luck at having a front-row seat to the latest in technological innovation.

“It’s pretty amazing, especially with the people I get to meet and talk to. Ph.D.s, Popular Science, Elon Musk,” he says. “I used to put that stuff on a pedestal, but then you get to meet them and see where we’re at and where we’re going, and you start to realize where the human race is in terms of technology.

“There are a lot of brilliant people out there, but at the same time, there’s a lot of things we can do better,” he added. “There’s a lot of stuff we can improve on.”

For now, Cathey and SPP are working to educate themselves on wind and solar energy, behind-the-meter resources, and batteries, flywheels and other energy storage technologies. The more staff knows, Cathey says, the better they can forecast.

What’s Out There?

“We’re focused on our current business functions as a balancing authority and market reliability. It’s starting to be a little worrisome that we don’t know what’s out there, and we don’t have rules in place to report it.”

Cathey says SPP currently has a requirement that any behind-the-meter resource capable of producing 10 MW or more has to register in the Integrated Marketplace, so it can be modeled correctly. He says loopholes in the requirement allow for derating resources or splitting them up, saying the ratings of some resources do not always tell the whole story.

“The worst risk is if there are many smaller facilities we don’t know about, we could potentially coordinate outages incorrectly and we would not know the real impacts on the Bulk Electric System,” he says. “At these small magnitudes, they’re not going to bring down the system, but if we don’t know about certain generation and we’re not coordinating it, we could have a problem with efficiency and reliability.

“We understand the capabilities and types of generation out there, but … we’re pretty much in the same boat as a lot of other ISOs and RTOs. We don’t know what we don’t know, and [other RTOs] don’t know. The loads themselves don’t know.”

To get better information, SPP has surveyed its members about their behind-the-meter resources.

The RTO hasn’t yet settled on a name for the resources. MISO calls them DERs (distributed energy resources) while ERCOT refers to them as DG (distributed generation). And SPP?

“We don’t have a term yet, but I’m sure it’ll be a different acronym when we come up with it,” Cathey says with a laugh. “Right now, we just want to know about it, so that our models are accurate.”

The RTO will eventually require more stringent reporting on distributed generation, Cathey says — and despite some stakeholder fears, the requirement will not force them to register the resources in the market or to inhibit their contributions to state renewable portfolio standards.

SPP does have an acronym for stored energy resources: SERs. Staff has drafted a revision request that would add energy storage capability to the Integrated Marketplace’s rules, enabling the resource to be registered as a generator type for regulation only. Staff has tweaked the revision request to take advantage of PJM‘s and MISO’s experience with the technology.

Cathey says SPP’s current rules are not “conducive to allow us to embrace that technology.”

“You can actually help out the system by plugging [the batteries] in … they’re providing regulation-down service,” says Cathey, who expects the first SER to show up by year-end. “That extends the life of conventional resources, because we’re not [ramping] them up and down. We’re sending the battery up and down.”

SPP’s current wind-integration study was renamed to include technologies like these, but its primary focus remains wind. The RTO has already seen wind integration reach 48.32%, a record for all North American ISOs and RTOs. It currently has 12,397 MW of installed and available wind capacity, with another 33,819 MW in development.

Cathey says the current study, which will use updated models and assumptions to analyze frequency response and transient response, is an extension of the 2015 study. It will take a “much more thorough” look at voltage, he said. The first study ignored thermal constraints and used an hourly ramp, but the second study will honor thermal ratings and use a five-minute ramp, “so it’s much more realistic.”

“Frequency and ramp, that’s one aspect we’re really interested in,” he says. “Is there a real problem when we have 50%, 60% wind penetration, while honoring thermal constraints? Are we Chicken Little, or is this an actual problem?”

SPP is working with Powertech Labs to develop a module that honors thermal constraints and is placed on top of its voltage-security assessment tool. Cathey says the RTO is past the R&D phase with the technology, which will eventually be rolled out to other ISO/RTOs.

“The model basically … lets us know we need to concentrate further on [a] scenario and build in more planning and operational processes,” he says.

Data, Data and More Data.

Cathey is also helping out with SPP’s Synchrophasor Strike Team’s work, which is intended to ensure the RTO isn’t pushing phasor measurement units (PMU) without stakeholder buy-in.

PMUs are devices that measure the voltage, frequency and angle of the grid’s electrical waves, using a common time source for synchronization. The devices can take samples hundreds of times a second, while the standard SCADA systems can have scan rates of 10 to 30 seconds.

“If we’re making measurements at that scale, we can determine whether there are issues with the models,” Cathey says. “But the problem with PMU incorporation is the data is so much. An operator needs to understand if it’s just a blip on the system for a nano-second. You’re talking petabytes [1 million gigabytes] of data. You’re well beyond terabytes.”

Staff is currently working on how best to filter the data and make it more manageable for operators. In the meantime, SPP has posted a revision request that would require all new generators to have a PMU. The request has been vetted within the strike force, which will determine whether the cost-benefit analysis justifies requiring existing generation to be retrofitted with PMUs.

Oklahoma Gas & Electric, which has installed more than 200 PMUs as part of a Department of Energy grant, has become a proponent of the technology, Cathey said.

“They’re the [subject-matter experts] for the industry, not just our area,” he says. “According to OG&E, the cost is not that much. Where the cost comes into play is if your substation or your switchyard is not capable of accepting the PMU.

“These are things we don’t traditionally think about. We think about power, getting it from Point A to Point B and whether the line can sustain it. … Now, we’re thinking about very engineering-centric problems.”

Which is exactly the way Cathey likes it.

June 20, 2016

FERC Accepts ISO-NE Auction Results

By William Opalka

FERC accepted the results of ISO-NE’s 10th Forward Capacity Auction last week, again rejecting allegations of market manipulation and concluding that the prices were just and reasonable (ER16-1041).

Brayton Point power plant, ISO-NE forward capacity auction, ferc — Brayton Point *Wikipedia*

The auction, covering the 2019/20 commitment period, saw prices drop to $7.03/kW-month from last year’s $9.55/kW-month. It was the first decline in four years. (See Prices Down 26% in ISO-NE Capacity Auction.)

The Utility Workers Union of America has claimed the Brayton Point generating plant in Massachusetts has been withheld from the last three auctions to drive up capacity prices. The plant, purchased by Dynegy in 2015 from Energy Capital Partners, is scheduled to close next year. (See FERC Again Rebuffs Brayton Point Union.)

“We emphasize, as the commission has stated in previous orders, that the commission’s Office of Enforcement reviewed Brayton Point’s bidding behavior in FCA 8 to determine whether further investigation of Brayton Point was warranted and ‘found credible justifications for the owners’ retirement decision and elected not to widen its investigation to include Brayton Point,’” FERC said. “We are not persuaded by Utility Workers Union’s allegations that market manipulation affected FCA 10, as the record is devoid of any evidence to that effect, and we similarly reject Utility Workers Union’s request for a stay pending discovery and further adjudication of that allegation.”

The commission also said that a “rigorous” review by ISO-NE’s Internal Market Monitor determined FCA 10 was competitive.

FERC Backs ISO-NE in Tariff Dispute

In a separate order, the commission rejected a complaint that alleged ISO-NE violated its Tariff when it refused to qualify an increase in a Massachusetts generating plant’s output for FCA 10 (EL16-48).

Northeast Energy Associates, owner of the Bellingham generating station, agreed with ISO-NE that an additional 10 MW of capacity was a “significant increase” but disagreed on whether it should be treated as new or existing capacity. New capacity is required to submit a composite offer linking incremental summer qualified capacity to existing winter qualified capacity.

NEA said the 10 MW should have been added to the existing summer qualified capacity without a composite offer and asked the commission to order ISO-NE to include the increase as if it had cleared FCA 10 — a move that would result in capacity payments to NEA of almost $844,000.

FERC sided with ISO-NE, saying that NEA, which is owned by subsidiaries of NextEra Energy and GDF SUEZ Energy Resources, misread the Tariff.

“We agree with ISO-NE that … the Tariff is clear that a significant increase must abide by all the provisions applicable to a new generating capacity resource,” FERC wrote.

This is the second time FERC has addressed a capacity increase for Bellingham. Previously, FERC granted a waiver to allow the plant to participate when the company submitted a late interconnection deposit. ISO-NE wanted to disqualify the resource, but the commission said a good-faith effort was made to submit a timely payment after NEA discovered its oversight. (See FERC Overrides ISO-NE, Grants Waiver for Late Capacity Payment.)

June 20, 2016

FERC Proposes Protections on CEII

By Michael Brooks

WASHINGTON — FERC last week issued a Notice of Proposed Rulemaking to implement legislation enacted last year to protect the grid from terrorist attacks (RM16-15).

The Fixing America’s Surface Transportation (FAST) Act, signed by President Obama in December, was mainly a highway funding bill, but it also amended the Federal Power Act to require FERC to update its critical energy infrastructure information (CEII) regulations. (See Transportation Bill Includes Grid Security Measures.)

The NOPR details how the commission plans to update its procedures for designating CEII, sharing CEII with other government agencies and sanctioning employees for unauthorized disclosures.

“Obviously, maintaining the confidentiality of critical infrastructure information is absolutely essential to our work in this area, particularly on reliability,” Commissioner Cheryl LaFleur said. “The FAST Act contains important new authority for the commission that allows us to both protect critical information and confidentially share it with government and private parties.”

LaFleur in particular praised Congress’ exemption of CEII from Freedom of Information Act disclosure.

The sanctions for unauthorized release of CEII stemmed from former Chairman Jon Wellinghoff publicly discussing a confidential FERC analysis on the grid vulnerability to physical attacks. The NOPR says that any FERC employee who knowingly discloses CEII would be subject to termination and/or criminal prosecution. Commissioners who do so would be referred to the Energy Department’s Inspector General.

FERC Chairman Norman Bay would not detail what criminal statutes an employee would be prosecuted under, only saying that CEII is not the same as classified material.

Comments on the NOPR are due 45 days after its publication in the Federal Register.

NERC Databases

FERC also amended its regulations to require NERC to provide the commission and staff access to three of its databases (RM15-25).

The rule gives FERC access to NERC’s transmission availability data system, generating availability data system and protection system misoperations databases. (See FERC to Look over NERC’s Shoulders on Reliability.) It will not take effect, however, until the commission issues a final order implementing the FAST Act provisions.

June 20, 2016

New York Transmission Developers Ask FERC to Order a Do-over

By William Opalka

Three competitive transmission developers asked FERC last week to order NYISO to issue a new request for proposals for transmission upgrades to alleviate congestion and bring renewable energy downstate (EL16-84).

The RFP was issued in February in response to a New York Public Service Commission order that declared a public policy need for two projects in the Mohawk and Hudson valleys to deliver energy to load centers in and around New York City. (See NYPSC Directs NYISO to Seek Tx Bids.)

The developers — Boundless Energy NE, CityGreen Transmission and Miller Bros. — say NYISO violated its Tariff and FERC directives under Order 1000 when it solicited projects without conducting its own review and instead deferred to state regulators.

“We are filing a petition with FERC because the NYISO violated its FERC tariff by inappropriately deferring to the New York Public Service Commission rather than follow its FERC-approved transmission planning function,” Boundless President Rod Lenfest said in a statement.

nypsc

“Based on FERC’s own guidelines, the NYPSC has a limited role in the energy transmission planning process. While that planning process allows the NYPSC to identify to the NYISO the transmission needs for the state, here the NYPSC went even further and pushed for a particular project solution to meet those needs. Rather than consider these projects along with other alternatives that could reduce costs for consumers, the NYISO decided to consider only proposals for the particular projects identified by the NYPSC.”

The developers asked FERC “to confirm that the NYISO, not the NYPSC, is the entity that is required to study and identify the specific project solutions.”

The plaintiffs said the ISO should follow its normal study process — including its base assumptions and generator dispatch modeling — to consider competing solutions without excluding specific technologies or relying on the PSC’s assumptions and modeling.

Developers’ proposals, which were submitted in late April, are currently being evaluated by NYISO staff.

Boundless CEO E. John Tompkins said in an affidavit that the company is seeking a stay of the solicitation process in the appellate division of the state Supreme Court.

The company participated in an evaluation of potential projects last year by NYPSC staff in its AC Transmission initiative. But staff recommended that the developer be disqualified because its proposals were deemed to be not cost-effective. (See NYPSC Staff Recommends $1.2B in Transmission Projects.) Boundless also sought a rehearing of the NYPSC order that declared the public policy need, but that petition was denied in February.

Earlier this month, NYISO named 10 project finalists in a concurrent public policy proceeding designed to alleviate congestion in the Buffalo area. (See NYISO Identifies 10 Public Policy Tx Projects.)

June 20, 2016

FERC Eliminates Wind’s Reactive Power Exemption

By Michael Brooks

WASHINGTON — New wind generators will be required to provide reactive power following a FERC order last week eliminating their exemption from having to provide the service (RM16-1).

wind inverter reactive power ferc — Inverters, necessary for wind turbines to provide reactive power, have become much less expensive since FERC exempted the resource from having to provide the service.

Reactive power, essential for controlling the voltage of the grid, can be measured at three points: the generator itself, the generator substation or the point of interconnection. Synchronous generators’ reactive power is measured at the interconnection point.

The commission’s order revises the commission’s pro forma generator interconnection agreements — both small and large — to require nonsynchronous generators’ reactor power to be measured at the high side of generator substations. In its Notice of Proposed Rulemaking in November, FERC had proposed the interconnection point, but it was persuaded by commenters who said doing so would require additional investment in equipment.

FERC issued the wind exemption in Order 661 in 2005 because it was concerned that the cost of the technology needed to provide reactive power would inhibit the development of the resource. Improvements in that technology since then have made it far less expensive, and FERC said that continuing the exemption could result in insufficient reactive power as wind power grows and traditional synchronous generation retires.

Order 661 did not exempt other types of nonsynchronous generation, such solar, but FERC has been treating them similarly to wind on a case-by-case basis. The commission has sometimes required that balancing authorities demonstrate that the lack of reactive power from a non-wind, nonsynchronous generator would threaten reliability before requiring it to provide the service.

The new requirements apply to all new nonsynchronous generators, regardless of type, that have not executed a facilities study agreement as of 90 days after publication in the Federal Register. They would not apply to existing generators, including those making upgrades that require new interconnection requests. FERC said these provisions would allow generators to complete the interconnection process without delay or extra costs.

FERC approved the new requirements at Thursday’s meeting, which was open to the public again after the commission closed it last month. (See Pipeline Protesters Force FERC to Close Monthly Meeting.) Staff’s presentation of the order was interrupted by two protesters, who urged the commission to halt approval of natural gas pipelines.

“There’s a certain irony here because the protesters interrupted a presentation by staff on commission work that can enable a higher degree of penetration by wind resources while maintaining reliability,” Chairman Norman Bay said in response. “This final rule will ensure comparable and nondiscriminatory treatment of both traditional resources and new resources, such as wind and solar, in the provision of reactive power, while recognizing that some technological differences remain.”

“Today’s rule recognizes that wind and other nonsynchronous generators, which are an increasingly important part of the fleet, now have the technical ability to provide reactive power at reasonable cost, and so they’ll now be required to do so,” Commissioner Cheryl LaFleur said. “I think today’s rule highlights that wind and solar are no longer just niche technologies.”

June 20, 2016

FERC OKs Change to MISO SSR Process

FERC last week accepted portions of MISO’s system support resource (SSR) Tariff changes but rejected the RTO’s proposal regarding the retention and transfer of interconnection rights (ER12-2302-004).
The changes allow new generation not available at the time of reliability studies and SSR designation to become an alternative to an SSR assignment.

However, FERC told MISO its proposal on interconnection rights had gaps.

Presque Isle Power Plant (Source We Energies) - FERC MISO SSR process interconnection rights — Presque Isle Power Plant *Source: We Energies*

MISO permits owners and operators of retiring SSR facilities to retain or transfer interconnection service. FERC said that in three filings, the RTO hasn’t yet proposed an impartial method for implementing the rule.

“MISO must propose additional procedures that ensure that the retention and transfer of interconnection service is offered on a fair, transparent and nondiscriminatory basis,” FERC said. “MISO is required to propose additional procedures, which should, among other things, allow a clear and consistent way in which generators seeking a transfer of interconnection service from a retiring generator may identify opportunities and address how such a generator would be chosen for such service.”

FERC also said MISO’s February filing to remove language regarding retention of interconnection service from its SSR procedures and insert them into Attachment X “merely moves this provision from one Tariff section to another without providing the requisite additional procedures.”

— Amanda Durish Cook

June 20, 2016

FERC Clarifies Electronic Quarterly Report Rules

FERC last week clarified its Electric Quarterly Report (EQR) reporting requirements, emphasizing that transmission providers must report transmission-related data (RM01-8, et al.).

The order also updates the EQR Data Dictionary, effective with the report for the fourth quarter of 2016, clarifying reporting requirements and fields related to “Increment Name” and “Commencement Date of Contract Terms.” It also makes changes regarding the “Time Zone” field options and deletes fields for reporting e-Tag data.

Future minor or non-material changes to EQR reporting requirements and the Data Dictionary will be posted directly to the commission’s website, and EQR users will be alerted via email of the changes.

– Rich Heidorn Jr.

June 20, 2016

PJM News Briefs from FERC Open Meeting

FERC last week denied a request by PJM’s Independent Market Monitor to clarify or rehear a March order in which the commission found fault with the RTO’s use of the cost-based energy offer cap as the sole measure of short-run marginal cost in calculating capacity market caps (EL14-94, ER16-1291).

At the same time, it accepted PJM’s compliance filing in response to the March ruling. (See FERC Rejects PJM’s Method for Capacity Offer Caps.)

In its request, Monitoring Analytics generally supported FERC’s order but called flawed the use of market-based offers as the measure of short-run marginal costs when they are higher than cost-based offers.

“The Market Monitor contends that the extent to which a market-based offer exceeds a cost-based offer constitutes a markup, and markup is not part of a competitive offer,” the commission said.

“We continue to find that, with limited exceptions, PJM should use, for the purpose of calculating a unit-specific capacity market offer cap, a resource’s non-zero market-based offer to reflect its marginal costs,” FERC ruled. “Simply because a market-based offer exceeds a cost-based offer does not necessarily establish that the market-based offer fails to reflect a resource’s marginal costs.”

The March ruling stemmed from a 2014 FirstEnergy petition that said PJM’s Market Monitor was violating the Tariff by calculating marginal costs using the lower of the market-based offer and cost-based offer.

FERC Denies Rehearing on Order Requiring DR in Capacity Auctions

FERC denied Talen Energy’s request for rehearing of a July 22 order that required PJM to include demand response in its transition auctions for Capacity Performance (ER15-623, EL15-80).

FERC, PJM — Smart Meter *Source: CPS Energy*

That ruling caused the RTO to delay the transition auctions. (See FERC Orders PJM to Include DR, EE in Transition Auctions.)

The commission also accepted a compliance filing by PJM in response to the July 22 order.

Talen had sought to apply a ruling by the D.C. Circuit Court of Appeals that voided FERC’s jurisdiction over DR in energy markets. However, the Supreme Court later reversed that ruling. (See Supreme Court Upholds FERC Jurisdiction over DR.)

“Accordingly, we dismiss Talen’s rehearing request as moot,” FERC said.

FERC also dismissed an objection by the Advanced Energy Management Alliance Coalition regarding the method PJM proposed to measure and verify DR participation in the transition auctions, saying it was an unrelated issue.

Commissioner Tony Clark concurred in a separate statement.

“I write separately to note my policy and procedural disagreements with the underlying order as fully explained in my separate statement of July 22, 2015,” he said.

Clark dissented from that order, saying it was improper procedurally because the commission had previously approved “unambiguous” Tariff language barring DR and energy efficiency from the auctions.

— Suzanne Herel

June 20, 2016

CAISO to Study Impact of Gas Shortages on Reliability

By Robert Mullin

CAISO transmission planning staff last week proposed studies on the implications of gas shortages on grid reliability.

The planners outlined the studies in a June 13 stakeholder call, saying they will consider the risks to Northern California as well as the more vulnerable southern part of the state.

The disparity between the regions stems from design differences in their pipeline systems and the synergy between Southern California’s storage facilities and its pipeline network.

“Gas storage in the [Los Angeles] Basin is critical [to pipeline operations],” said ISO senior advisor David Le, referring to the gas system’s dependence on the Aliso Canyon storage facility.

Le pointed out that the Aliso Canyon — closed earlier this year because of a gas leak — is vital not only for its massive 86 Bcf storage capacity, but also for its ability to quickly supply large volumes of gas to support pipeline pressure.

Aliso Canyon usually accounts for more than 65% of the inventory held in Southern California’s four major storage sites. The facility also boasts a daily withdrawal capacity of 1.86 Bcf, which helps keep 17 gas-fired generators in the basin supplied with gas under strained conditions.

That withdrawal capability is usually tapped during summer months to help generators meet peak demand. CAISO says that, because of the “magnitude and speed” of the generators’ consumption, pipeline capacity is often insufficient to supply their needs without the ability to backfill from storage such as Aliso Canyon.

CAISO plans to model multiple scenarios stemming from the closure of Aliso Canyon to assess the potential long-term impact of the gas system’s balancing act on Southern California’s grid reliability. Planning staff will develop scenarios in which gas pipeline operators and gas generators lose access to other storage facilities in the region in addition to Aliso.

The study is intended to take a long view, looking at the implications of such gas curtailments to inform transmission planning for 2021 and 2026 as California advances on its 50% renewables mandate.

A parallel study would examine the likelihood for gas curtailments in Northern California, a region with a “much different” gas system, according to Binaya Shrestha, CAISO regional transmission engineer lead.

To provide context for his assertion, Shrestha pointed to the February 2011 gas outages that cut supplies to a number of San Diego-area generators. “Southern California is [subject to] historical outages, but in Northern California, there hasn’t been any curtailment of that level for gas-fired plants,” he said.

That success can be attributed in part to both the line capacity and topology of the gas system.

caiso, gas shortages, reliability — The proximity of gas storage facilities to Northern California’s backbone pipeline provides flexibility for the region’s gas system.

The region’s backbone pipeline — Line 401/402 — has a firm capacity of more than 2 Bcfd. Additional supply arrives via the Mojave gas system originating in the southern part of the state, which serves about 2,200 MW of generation in the ISO’s Pacific Gas and Electric zone.

Furthermore, nearly all of Northern California’s eight major gas storage facilities are distributed along the length of Line 401/402. That arrangement provides operational flexibility because gas can be injected into the system from multiple sites.

Those facilities also equip the region’s gas suppliers with a combined 238 Bcf in inventory capacity — double that in Southern California — and more than 4.5 Bcf in withdrawal capacity.

Still, the ISO wants to better understand the dynamics of gas supply in Northern California to investigate what chain of events leading to curtailments could compromise the region’s electric reliability.

Stakeholders must submit comments about the gas-electric studies by June 27. Findings will be incorporated into the ISO’s draft transmission plan early next year.

June 20, 2016April 2, 2025

FERC Issues 1st RTO Price Formation Reforms

By Michael Brooks

WASHINGTON — RTOs will be required to align their settlement and dispatch intervals and implement shortage pricing during any shortage period under new price formation rules approved last week by FERC (RM15-24).

FERC Order 825 requires RTOs to settle real-time energy, operating reserves and intertie transactions in the same time interval it dispatches, prices and schedules them, respectively. Although all RTOs currently dispatch resources in five-minute intervals, ISO-NE, MISO and PJM settle those transactions based on the average price for all dispatch intervals during the hour.

This misalignment distorts price signals, as compensation is based on average hourly prices rather than specific periods, including those of greatest need. “These distorted price signals can mute a resource’s financial reward for being able to quickly respond to system needs and create a disincentive for resources to respond to price signals,” Stanley Wolf, of FERC’s Office of Energy Policy and Innovation, said at the commission’s open meeting Thursday.

Additionally, in some RTOs, an energy or reserve shortage is required to last a minimum amount of time before shortage pricing is triggered. “Due to such delays, short-term prices fail to reflect potential reliability costs, as well as fail to reflect the value of both internal and external market resources responding to a dispatch signal,” Wolf said.

Commissioner Colette Honorable called the order — the first final rule in the commission’s efforts to reform price formation in the organized electricity markets — a “milestone.” The commission began evaluating price formation in 2014 and issued a Notice of Proposed Rulemaking in September. (See NOPR Requires RTOs Switch to 5-Minute Settlements.)

“These requirements will help ensure that rates for energy and operating reserves are just and reasonable and will align prices with resource dispatch instructions and operating needs, provide appropriate incentives for resource performance and maintain reliability,” FERC said.

The final order clarifies that the rules would apply to all supply resources, including demand response.

The new requirements take effect 75 days after publication in the Federal Register. Each RTO will be required to make a compliance filing 120 days after that detailing the tariff changes needed to implement the new rules. The order stipulates that FERC will allow an additional year after the compliance filing deadline for the settlement interval changes to go into effect, while it will allow another 120 days for the shortage pricing changes.

“I know that it will take some time and effort for the RTOs to comply with the portion of the rule on settlement intervals; it won’t necessarily be easy,” Commissioner Cheryl LaFleur said. “However, I think it’s critically important that markets send clear, accurate, timely and undiluted price signals.”