Page 1148 – RTO Insider

January 28, 2020

ISO-NE Planning Advisory Committee Briefs: Jan. 23, 2020

ISO-NE is incorporating stakeholder comments and questions from December’s Planning Advisory Committee meeting as it works to complete its 2019 Economic Study in stages this year, the PAC heard last week.

The New England States Committee on Electricity (NESCOE), Anbaric Development Partners and RENEW Northeast submitted requests at the April 2019 PAC meeting for additional studies, which Patrick Boughan, ISO-NE senior engineer for system planning, said the RTO hopes to complete and publish in June and July.

“At previous PAC meetings, stakeholders requested us to evaluate other offshore wind interconnection points, but we’re only going to evaluate the interconnection points we previously presented,” Boughan said. “I think that we’ve provided a variety of interconnection points here at different points throughout the system, in Boston, off of the cape and off of Connecticut.”

“At what point does the addition of offshore wind start to cause large onshore transmission upgrade costs?” asked Theodore Paradise, Anbaric’s senior vice president for transmission strategy.

He said the region has spent about $14 billion on transmission upgrades (ISO-NE has cited $10.6 billion since 2002), creating a robust transmission system. “So, for example, west of Millstone [Nuclear Power Station in Connecticut], which is not being used in the study, has a lot of great injection points that can take 1,200 MW or more into uncongested parts of the system.

“There’s a lot of transmission there that we’ve invested in that we could see some real benefits [from] if we chose a couple of interconnection points, even just along the Connecticut shore,” Paradise said.

ISO-NE Director of Market Development Carissa Sedlacek told Paradise that the RTO has “taken on a lot of work” in agreeing to do three economic studies.

“I think we should focus on getting the NESCOE study done and move onto the Anbaric and RENEW [studies],” Sedlacek said. “Based on the scope of work that we decided in August, we’re going to be in a good position in another two months that we’re going to be ready to request additional economic studies, so that maybe part of the 2020 Economic Study could look at those interconnection points.”

In response to another stakeholder query, Boughan said the behind-the-meter PV category in the economic studies includes resources that do not participate in the wholesale markets but are reflected in the capacity, energy, loads and transmission (CELT) load forecast. The utility-scale PV category includes resources that have cleared in the Forward Capacity Market, are settlement-only generators or otherwise participate in the wholesale markets, he said.

CO2 Emissions down, Environmental Sensitivity up

Last year saw CO2 emissions from coal and oil generation drop more than 50% compared with the previous two years, while those from gas-fired generation fell 10%, Patricio Silva, the RTO’s lead analyst, told the PAC.

The RTO’s Environmental Advisory Group assists the PAC and the Reliability and Power Supply Planning committees in evaluating the impact of environmental rules on the regional power system.

Thursday’s update included regional system trends; regional generation and emission trends; the estimated impact of carbon pricing on regional energy costs; performance statistics from the Regional Greenhouse Gas Initiative; a timeline for the region’s Transportation Climate Initiative; and a snapshot of Massachusetts’ Global Warming Solutions Act and its CO2 cap on power plants, Silva said.

While retirements within New England obviously impact the system, closures in the greater Northeast and beyond also have indirect effects that may affect the RGGI compliance costs of generators in the region, he said.

“Likewise, changes in unit availability and interconnections over time could also indirectly affect the environmental performance of the system as we’re seeing more impacts from carbon compliance costs and as other costs decline … such as nitrogen oxide allowance and sulphur dioxide allowance costs that decline in both price and significance,” Silva said.

With the May 2019 retirement of the 680-MW Pilgrim nuclear plant in Massachusetts, the 2014 retirement of the 620-MW Vermont Yankee plant and an equivalent amount of coal-fired generation retired in that period, “the system is now sensitive, more than ever from an environmental performance standpoint, to changes in the weather and economic conditions,” he said.

– Michael Kuser

January 28, 2020

SPP Names Nickell COO, Adds Board Member

SANTA FE, N.M. — S P P Chairman Larry Altenbaumer told stakeholders Tuesday that the Board of Directors has elected Lanny Nickell as its chief operating officer.

Altenbaumer said the board approved Nickell’s appointment on Jan. 26.

SPP Nickell — COO Lanny Nickell explains transmission issue to SPP stakeholders. | © *RTO Insider*

Nickell, one of several internal candidates for the CEO position filled by Barbara Sugg, replaces Carl Monroe, who announced his retirement last year after 22 years with SPP. (See SPP COO Monroe to Retire in Early 2 0 20.)

“I couldn’t be more excited about the opportunities I’ve been blessed to have, both by working in and on the SPP organization the last 22 years and to work with Barbara in our new roles as we move this fantastic organization forward,” Nickell told RTO Insider.

“I know with Barbara’s leadership our staff and stakeholders are going to do great things. I’m excited to be working more closely with our stakeholders to bring new and creative ideas to life,” he said.

“I have a tremendous amount of respect for Lanny and appreciate the expertise and strategic viewpoint he brings to the team,” CEO-elect Sugg said in a statem e n t. “His commitment to SPP and our culture will serve him well in this critical role as we look forward.”

Altenbaumer noted boards rarely get to fill both the CEO and COO positions at the same time. “It is even rarer for a board to have the luxury of the opportunity to select an individual of Lanny’s caliber to become its new COO,” he said.

Nickell, promoted last year to senior vice president of engineering, joined SPP in 1997 and has more than 27 years of experience in the electric utility industry. He directed the development of SPP’s Regional Transmission Expansion Plans; delivered the RTO’s generator interconnection, transmission and financial congestion hedging services; administered regional resource adequacy policies; and ensured reliability and market operations engineering support.

Nickell came to SPP from Public Service Company of Oklahoma and Central and South West Services, now American Electric Power. He has a bachelor’s degree in electrical engineering from the University of Tulsa and is a graduate of Harvard Business School’s Advanced Management Program.

SPP members also elected Bronwen Bastone, who has a background in financial services and human resources, to the Board of Directors.

In announcing Bastone’s approval, Altenbaumer promised “she will more than live up to the hype we have spread about her.”

Bastone has nearly 20 years of HR and human capital strategy experience, spending more than half of that time in financial services. Her deep HR background was one of the selling points to the search committee.

She replaces Phyllis Bernard, who left the board last year after 16 years as a director.

Bastone is a partner at investment bank Exos F inancial. She previously held roles at Brookfield Asset Management, Cushman and Wakefield and Knight Capital Group. Bastone has an MBA from the University of Technology Sydney.

“The challenges facing SPP and the RTO industry as a whole will continue to become more complex, and the need for a more agile, digital and strategic workforce becomes critical to its success,” Bastone said in a state m ent. “My focus will be working with the SPP board and management to ensure that we continue to attract, engage and strengthen the skills of the workforce to tackle each of the challenges facing SPP in a more innovative and proactive manner.”

January 26, 2020

FERC Grants Recovery on PATH Project Costs

By Christen Smith

FERC said last week its revised interpretation of accounting rules supports a rehearing request from developers of the abandoned Potomac-Appalachian Transmission Highline (PATH) transmission project, who are seeking recovery of $6.2 million spent on advertising, education and outreach (ER09-1256-03).

The ruling overturns, in part, FERC’s 2017 decision denying American Electric Power and FirstEnergy subsidiary Allegheny Energy recovery of costs the commission had categorized as lobbying and advertising expenses. (See FERC Orders Tx Refunds, Investigates Pipeline Rates in PJM.)

The $2.1 billion, 765-kV “coal by wire” PATH project was approved by PJM in 2007 to run from AEP’s John Amos coal generator in St. Albans, W.Va., to New Market in Frederick County, Md.

By 2011, however, PJM said the need for the line had moved several years beyond 2015 because of reduced load growth following the Great Recession. After ordering transmission owners to suspend work on the line pending a more complete analysis of all upgrades in its regional transmission plan, the PJM Board of Managers terminated it in 2012. PATH developers pursued cost recovery on the abandoned project totaling $121.5 million.

In 2012, two opponents from West Virginia filed a pro se intervention challenging the companies’ request for recovery of the lobbying and advertising campaigns that were intended to win political support for the project. FERC supported most of an initial decision by Administrative Law Judge Philip C. Baten, who found “that all of PATH’s expenditures were directed at obtaining a public convenience and necessity determination.”

FERC’s 2017 order directed AEP and FirstEnergy to refund ratepayers more than $7 million for the canceled project. The commission also found that PATH’s base return on equity should be reduced from 10.4% to 8.11% and disallowed recovery of $1.1 million in expenses booked into a wrong account.

But the commission said Thursday that, upon further reconsideration, efforts to obtain a certificate of public convenience and necessity “do not fall within the ambit of referenda, legislation, ordinances, the grant of franchise and the like because PATH’s efforts were in service of an RTO-approved project.”

“We find that general promotional efforts on behalf of an already approved project to obtain a finding of a public convenience and necessity are not the type of political activity included in the first clause of the regulation,” FERC said, referring to the rules governing which accounts developers can use for certain types of expenses.

In granting the rehearing, the PATH developers must recalculate the project’s total revenue requirement and account for refunds paid during the interim, FERC said.

The commission denied rehearing on PATH’s reduced ROE but ordered the developers to submit supplemental briefs and additional written evidence regarding how FERC’s proposed revised ROE methodology would apply to the proceeding. The methodology — replacing the discounted cash flow model with one that gives equal weight to the DCF and three other techniques — was developed after the D.C. Circuit Court of Appeals determined the commission’s existing formula was unjust and unreasonable. (See FERC Changing ROE Rules; Higher Rates Likely.)

January 26, 2020

MISO West Tx Construction Steady in 2020

By Amanda Durish Cook

Transmission buildout costs in MISO West under the 2020 expansion plan will look much the same as last year’s, RTO officials said last week.

The officials offered that prediction at MISO’s first West Subregional Planning Meeting of the year on Thursday. The meeting is part of a series held by subregions as MISO begins assembling its 2020 Transmission Expansion Plan (MTEP 20).

Some stakeholders have expressed concern over transmission development in MISO West — encompassing Minnesota, Iowa, parts of the Dakotas and western Wisconsin. They complain that proposed renewable generation in the RTO’s interconnection queue is inhibited in recent years by a lack of new capacity combined with prohibitively expensive network upgrades.

MISO has convened a special task team to address the increasing cost of network upgrades in its interconnection queue. Possible solutions involve linking the RTO’s annual transmission planning process with network upgrade planning. The synchronization could have MISO approving more transmission projects. (See MISO Seeks Ideas for Streamlined Tx Planning.) However, those changes will begin with MTEP 21, not MTEP 20.

MISO West transmission — MTEP 19 investment in MISO West versus projected MTEP 20 investment | *MISO*

MISO so far estimates similar spending on transmission buildout in West under MTEP 20 when compared to 2019, with both at nearly $790 million.

“We’ll likely have fewer proposed projects this year, but the investment remains the same,” MISO Manager of Expansion Planning Zheng Zhou told stakeholders.

Of that investment, transmission upgrades to accommodate interconnecting generators is predicted to increase year-over-year, from $103 million in MTEP 19 to a projected $133 million in MTEP 20.

MISO has yet to perform independent planning assessments on the MTEP 20 projects proposed by transmission owners. The assessments could identify project alternatives.

Meanwhile, the RTO continues to try to clear MISO West projects from its nearly 82-GW interconnection queue. It is working on negotiating and finalizing generation interconnection agreements for the two remaining generation projects representing 245 MW that entered the interconnection queue in the February 2017 cycle. That cycle once contained more than 5 GW of proposed wind and solar projects, and it was the sharp drop-off of generation projects that caused the stakeholder community to take notice of the transmission-constrained western region.

MISO also said it’s preparing generation interconnection agreements for 13 West projects at about 2.3 GW that entered the queue in August 2016. It identified about $269 million in necessary network upgrades for those projects.

Finally, the RTO reports that affected-system studies are ongoing for the crop of 27 West projects — comprising 4.1 GW — that entered the queue in August 2017.

MISO will hold two more West planning meetings before MTEP 20 approval, one in either May or June and another in August.

January 26, 2020

FERC Denies Rehearing on NYISO LCRs

By Michael Kuser

FERC on Thursday denied rehearing of its October 2018 order accepting NYISO’s revisions to the methodology it uses to determine locational minimum installed capacity requirements (LCRs), rejecting every one of the more than two dozen arguments made by the Long Island Power Authority (LIPA) and its subsidiary, Power Supply Long Island (ER18-1743-002).

NYISO’s installed capacity (ICAP) market rules require all load-serving entities to purchase a specified amount of capacity to count toward the statewide minimum installed reserve margin (IRM), based on each LSE’s coincident peak load. LSEs with customers in certain transmission-constrained areas, defined as “localities,” must fulfill a portion of their respective purchase obligations from capacity resources electrically located within those areas.

NYISO has designated three such localities: G-J, which is composed of load zones G, H, I and J in the Lower Hudson Valley; New York City (Zone J), which is nested within G-J; and Long Island (Zone K).

With the creation of the G-J locality, NYISO supplemented its former method, which recognized that the loss-of-load-expectation (LOLE) reliability standard used in setting the IRM may be achieved by carrying many different combinations of ICAP in various locations. The ISO now takes steps to calculate the LCR for the G-J locality.

In Thursday’s order, the commission found that the ISO’s alternative LCR methodology satisfies the 0.1-days/year LOLE reliability standard, which LIPA asserted was insufficiently demonstrated or certified.

“NYISO presented sufficient record evidence in this proceeding to support its claim that the alternative LCR methodology will meet the 0.1-days/year LOLE reliability standard,” the commission said. “Moreover, LIPA has not provided evidence that would persuade us otherwise.”

The commission also rejected LIPA’s request for additional technical details in the Tariff.

“We find unpersuasive arguments that the commission failed to address … NYISO’s alleged failure to model and analyze ‘known’ likely future system conditions; and the sensitivity of the alternative LCR methodology to actions, such as election of unforced deliverability rights, taken in Zone J that adversely affect Zone K,” the commission said. “LIPA’s arguments reduce to a disagreement with NYISO regarding the number and type of sensitivity analyses” that need to be performed.

January 26, 2020

NYISO DER Participation Model Gets FERC OK

By Michael Kuser

FERC on Thursday approved NYISO’s proposal to allow aggregations of distributed energy resources to participate in its markets.

The commission said the proposed model enhances competition “while also providing DERs with appropriate flexibility to meet various needs both within and outside the NYISO-administered wholesale markets” (ER19-2276).

“Among other considerations, NYISO’s filing facilitates the participation of DERs and other aggregations of resources in its wholesale markets by enabling heterogenous groups of technologies to aggregate and be compensated for services that they are collectively capable of providing,” FERC said.

A group of stakeholders — Advanced Energy Management Alliance, Advanced Energy Economy, Consumer Power Advocates, Energy Spectrum, Natural Resources Defense Council and the New York Battery and Energy Storage Technology Consortium — jointly contested the Tariff revisions regarding dual participation, metering and telemetry, installed capacity market requirements, and buyer-side mitigation.

Concept for DER coordination entity aggregation (DCEA) in energy, operating reserves and regulation markets | *NYISO DER Roadmap*

But the commission disagreed with their concern that NYISO’s requirement that market participants must “bid in a manner that ensures they will be dispatched by the ISO for the market intervals consistent with the manner in which the resource operates to meet such obligation(s)” creates a barrier to entry.

“We find that this proposed requirement appropriately balances any additional burden placed on market participants in determining their bids against the need for NYISO’s system operators and dispatch software to account accurately for the operation of dual participating facilities,” the commission said.

It also noted that the ISO did not propose any substantive changes to its market power mitigation provisions and, therefore, it found protests of the group, the New York State Energy Research and Development Authority and the state Public Service Commission to be beyond the scope of the proceeding. The protesters had contended that application of NYISO’s existing buyer-side market power mitigation rules to DER aggregations could result in over-mitigation of the resources.

FERC also on Thursday dismissed NRG Curtailment Solutions’ complaint over NYISO’s metering requirements, saying it had been rendered moot by its approval of the ISO’s DER aggregation model (EL18-188). The commission had granted NRG’s complaint in part in 2018 and establishing a paper hearing to determine an appropriate remedy.

January 26, 2020

NextEra Sees Competitive ‘Near Firm’ Renewables

By Tom Kleckner

NextEra Energy CEO Jim Robo said Friday that battery-backed “near firm” wind and solar power will be increasingly competitive by 2025.

Speaking during NextEra’s quarterly and year-end earnings call with financial analysts, Robo predicted that new near firm wind will be a $20 to $30/MWh product and near firm solar a $30 to $40/MWh product in five years.

“At these prices, new near firm renewables will be cheaper than the operating cost of most existing coal, nuclear and less efficient oil- and gas-fired generation units,” he said. “We will be at the vanguard of building a sustainable energy era that is both clean and affordable, and we are driving very hard to continue to be at the forefront of the disruption that is occurring within the energy sector.”

Robo said his company is poised to take advantage of the “enormous disruption” taking place within the nation’s generating fleet.

“Our confidence in renewables being the low-cost generation alternative in the middle of this decade remains stronger than ever,” Robo said. “We expect the disruptive nature of renewables to be terrific for customers, terrific for the environment and terrific for shareholders by helping to drive tremendous growth for this company over the next decade.”

The Florida-based company fell short of analysts’ expectations by reporting fourth-quarter earnings of $975 million ($1.99/share). Although that more than doubled 2018’s fourth-quarter earnings of $422 million ($0.88/share), NextEra’s adjusted earnings of $706 million ($1.44/share) came in below Zacks Investment Research’s consensus estimate of $1.54/share.

The company reported year-end earnings of $3.8 billion ($7.76/share), down from $6.6 billion ($13.88/share), in 2018. NextEra also reaffirmed a 6 to 8% growth rate in adjusted earnings per share through 2021.

Robo said NextEra’s performance “was strong both financially and operationally, and we had outstanding execution on our initiatives to continue to drive future growth across the company.” Wall Street sided with Robo, driving the stock price up $6.38 shortly after market open to close at $263.70.

Renewable energy will play a major role in NextEra’s ongoing performance. The company said NextEra Energy Resources, its wholesale electricity supplier, added more than 5.8 GW to its contracted renewables backlog and commissioned another 2.7 GW of wind and solar projects. More than half of the solar additions included a battery storage component, Robo said.

January 26, 2020

MISO, PJM Weighing New Interregional Study

By Amanda Durish Cook

Fresh off the approval of their first interregional transmission project, MISO and PJM are now contemplating a new study this year and asking stakeholders what direction it might take.

Staff from both RTOs laid out the possible options in a conference call of the MISO-PJM Interregional Planning Stakeholder Advisory Committee (IPSAC) on Friday.

PJM’s Alex Worcester said the study could take the shape of a targeted market efficiency project (TMEP) study, a special targeted ad hoc study or a two-year coordinated system plan, the last of which could culminate in the RTOs’ second-ever large interregional market efficiency project (IMEP).

Worcester asked stakeholders to submit ideas on the options by Feb. 26.

“What we’re looking for here is specific study suggestions,” Worcester said. He asked that stakeholders identify specific constraints or flowgates that could use analysis. “Saying there’s lot of congestion to be studied doesn’t really provide us a lot of direction.”

In December, the RTOs finished a data exchange on regional issues, newly approved projects near the seam and the latest historical market-to-market congestion information. They reviewed each other’s information over January.

The RTOs will hold another IPSAC meeting March 27 to explore the need for a new study. By mid-May, the Joint Regional Planning Committee — composed of planning staff from both RTOs — will render the final verdict.

MISO PJM Interregional Study — Michigan City-Trail Creek-Bosserman project map | *MISO*

During the call, a few stakeholders said they would be interested in the RTOs working on another TMEP. The two decided against conducting a third TMEP study process in 2019 after determining that only one year of additional historical data would be available coming on the heels of the 2018 study.

A TMEP must cost less than $20 million, completely cover its installed capital cost within four years of service and be in service by the third summer peak from its approval. The process has a shorter outlook than the RTOs’ IMEP process, which evaluates projects over a 15-year timeline.

Similarly, MISO and SPP will evaluate the need for a 2020 interregional study at their IPSAC meeting March 10.

Meanwhile, MISO is waiting on MISO, PJM Poised for 1st Major Interregional Project.)

The project needs MISO to implement cost allocation rules before it can proceed. MISO last week filed a plan with FERC to allocate interregional economic project costs to benefiting transmission pricing zones.

January 26, 2020

PJM Members Resist TO Critical Infrastructure Filing

By Christen Smith

PJM members endorsed a resolution Thursday that objects to a Tariff attachment pending before FERC that would create a new confidential process to mitigate critical infrastructure on NERC’s CIP-014-2 list.

The unusual step came less than a week after a group of transmission owners submitted the proposal to the commission following several tense conversations dating back to August that left other sectors wary of its vague details.

LS Power, author of the resolution, argues that incumbent TOs don’t get exclusive rights to handling critical infrastructure on the list. Because the projects could carry significant regional implications, the company believes PJM should plan their mitigation — a point other stakeholders echoed during the Members Committee meeting on Thursday. (See PJM TO Filing Stirs Up Transparency Concerns.)

PJM Critical Infrastructure Filing — The Members Committee on Jan. 23 debates a resolution from LS Power opposing a Tariff filing that would mitigate critical infrastructure projects.

“We feel strongly that PJM should have stepped up and taken this issue under its wing as a reliability issue,” said Carl Johnson of the PJM Public Power Coalition. “It would have saved us a lot of trouble.”

The resolution alleges that the filing also conflicts with the Operating Agreement because mitigating these critical assets — which count as a subset of supplemental projects — must involve an open and transparent discussion with stakeholders. But doing so, the TOs contend, poses the dilemma that the highly secretive location of these facilities could be revealed. (See “Critical Infrastructure Resolution,” PJM MRC/MC Briefs: Dec. 5, 2019.)

The TOs also point out that NERC’s confidentiality standards — and their rights under PJM’s Attachment M-4 process — support their intention to file the mitigation plan at FERC without consent from other sectors.

In an effort to quell rising concerns, TOs collected questions from other stakeholders and hosted a webinar in November to answer some of them publicly. The two-hour meeting, however, left many issues unresolved. Seemingly frustrated by the unfolding process, the Planning Committee endorsed an issue charge in December to consider whether PJM must develop governing document language to deal with the mitigation of existing and future critical infrastructure on the list. (See “Critical Infrastructure Mitigation,” PJM PC/TEAC Briefs: Dec. 12, 2019.)

Top-secret Cost

PJM has refused to take sides in the debate, despite protests from stakeholders that mitigating the facilities presents risks to reliability that the RTO should handle. It’s a decision staff now question, Vice President of Planning Ken Seiler said. (See PJM Remains Neutral in CIP-014 Debate.)

“I agree, we could have done things differently,” he said, noting that a rough estimate of the cost to remove these assets from the list would total much less than $1 billion.

When stakeholders pressed for a more accurate cost estimate — key information many said may make them more comfortable with the Tariff filing — Seiler declined.

“We’ve looked at what the potential solutions would be and most of them are fairly simple,” he said. “Line rerouting, substation reconfiguration, very minor things that would keep the cost at a reduced rate for everybody … we are nowhere near into the billions of dollars on this.”

Sharon Segner, vice president of LS Power, said that although Seiler’s feedback was “encouraging,” there’s nothing in the Tariff proposal that caps costs.

“What would encourage my company even more would be for PJM to be in charge of these top-secret projects,” she said. “If PJM were to be in charge, then this language would go in the OA and not the Tariff. If it’s in the Tariff, at the end of the day, the TOs are in charge. There’s nothing in this language that provides cost containment. There’s a finite number of projects, but there is no restriction on cost.”

PJM Board of Managers member Susan Riley — who last month encouraged TOs and PJM to tally a cost for projects on the list — pushed back against sentiments that the RTO should have greater authority over the process.

“We’ve agreed to have an oversight role,” she said. “TOs have ultimate authority. I know the costs have been moving around, but they are moving down. We are reasonably confident that it won’t be more than $1 billion and won’t be more than 20 projects. We are committed in a very public way. Whether or not there wasn’t enough discussion, that’s up to you. I think there was.”

The MC endorsed the resolution in a sector-weighted vote of 3.83 to 1.17. Segner said LS Power intends to submit the resolution as part of its protest against the TO proposal. Comments on the filing are due within 21 days, Segner said, hence the timing of the vote.

January 26, 2020

FERC Stalls PJM Fast-start Compliance Filing

By Christen Smith

FERC said Thursday it will hold PJM’s fast-start pricing compliance filing in abeyance until July 31 in order to give the RTO enough time to resolve pricing and dispatch misalignment issues currently under review by stakeholders (ER19-2722).

In April, the commission ordered PJM and NYISO to revise their tariffs to allow fast-start resources to set clearing prices, saying their current rules are not just and reasonable. (See FERC Orders Fast-start Rules for NYISO, PJM.) PJM submitted a compliance filing in July that the Independent Market Monitor, state commissions and consumer advocates argued didn’t provide clear evidence that it would implement fast-start pricing correctly.

Specifically, the groups said that PJM uses different market intervals to calculate prices and dispatch instructions, suggesting that resources’ compensation doesn’t correspond to their dispatch instructions.

PJM Fast-start Filing — PJM control room | *PJM*

As part of its April order, FERC directed PJM to alter its real-time energy market clearing process to consider fast-start resources “in a way that is consistent with minimizing production costs.” The process requires PJM to first execute a cost-minimizing dispatch run, followed “by a pricing run where integer relaxation for fast-start resources allows them to set price.” The use of integer relaxation is intended to pinpoint a unit’s commitment costs in the pricing run and allow for their recovery through a market process rather than administrative methods.

“However, PJM may not be able to implement these separate dispatch and pricing runs in a way that is just and reasonable without first resolving the pricing and dispatch misalignment problem,” FERC said Thursday. “If fast-start resources dispatched in a given market interval could be compensated with a price from a different market interval, prices may not accurately reflect the marginal cost of serving load.

“Moreover, implementing fast-start pricing as directed … could exacerbate the pricing and dispatch misalignment issue because the lost opportunity cost payments … may be calculated based on inaccurate prices and, therefore, may not correctly compensate opportunity costs.”

FERC said implementing fast-start pricing now could also render lost opportunity cost payments ineffective “because they may not provide correct incentives to follow dispatch.”

PJM’s stakeholder process to fix the issue remains ongoing, with plans to conclude the effort by May.