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December 15, 2025

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FERC ALJ Certifies Calpine RMR Settlements

By Jason Fordney

CAISO, Pacific Gas and Electric, and Calpine have settled their differences over the terms of the reliability-must-run agreements keeping three Calpine gas-fired plants operating instead of retiring.

FERC is likely to issue a decision on the agreements by April 30, Administrative Law Judge H. Peter Young said Tuesday after certifying the uncontested settlements that would reduce the annual revenue the plants receive. The controversial out-of-market RMR payments are opposed by the California Public Utilities Commission and were reluctantly approved by the CAISO Board of Governors in November. (See Board Decisions Highlight CAISO Market Problems.)

The new settlements filed March 21 cover two different FERC dockets, one Calpine’s Metcalf plant (ER18-240), and another for the company’s Feather River and Yuba City plants in Northern California (ER18-230).

RMRs calpine caiso metcalf
Calpine’s Metcalf Energy Center | Calpine

“In general, the offer of settlement would substantially reduce Metcalf’s RMR service rates and would change the MEC facility’s operating status,” Young said of the Metcalf settlement. (See FERC Orders Hearing, Settlement Talks for Calpine RMRs.)

The Metcalf settlement would reduce the plant’s annual fixed revenue requirement to $43 million from about $72 million through 2020 if it retains its RMR status, and make the plant operator responsible for routine repairs and capital expenses. It would set recovery for planned 2018 capital items to $8 million, to be recovered in 12 installments of $675,000 beginning on Jan. 1, 2018.

If the RMR agreement is extended, capital recovery would remain at about $8 million per year. The settlement would also grant the plant $8 million in 2019 and 2020 if the revised agreement is not renewed and the unit shuts down.

The settlements would also take all three plants from Condition 2 (eligible for full cost-of-service payments) to Condition 1 (eligible for only a portion of their revenue requirement) status, and impose a must-offer requirement, which the ISO’s Department of Market Monitoring has recommended for all RMR units. CAISO is working to revise its RMR program to establish a must-offer requirement for resources. (See CAISO, Stakeholders Debate RMR Revisions.)

RMRs metcalf caiso calpine
Calpine’s Yuba City Energy Center. | © RTO Insider

The Feather River and Yuba City settlements would reduce each plants’ 2018 revenue to about $3.5 million from the previous $4.4 million, with a 2% hike for 2019 and 2020 if the RMRs are renewed. They would also impose a must-offer requirement on the plants.

After CAISO approved the RMRs last November, the CPUC issued an order directing PG&E to use energy storage to meet the needs currently served by the plants. (See CPUC Targets CAISO’s Calpine RMRs.) The storage resources must be online before 2019.

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FERC OKs MISO’s Doubled Offer Cap, Orders Alterations

By Amanda Durish Cook

CARMEL, Ind. — FERC on Wednesday approved MISO’s plan to permanently double its hard offer cap but told the RTO to clarify some details about the proposal in a compliance filing within 60 days (ER17-1570-001).

The proposal marked MISO’s second attempt to comply with FERC Order 831, which required RTOs and ISOs to raise their hard caps for verified cost-based incremental energy offers to $2,000/MWh. The commission issued the order in response to the 2014 polar vortex, which sent natural gas prices soaring and left some generators unable to cover fuel costs.

MISO offer cap FERC
MISO control room | MISO

FERC late last year rejected MISO’s first attempt at complying with the rule, saying the RTO wrongly proposed a provision that prohibited resources from submitting cost-based offers above the required $2,000/MWh hard cap. (See MISO’s Plan for Wintertime Offer Caps Stalled by FERC.)

The commission had also ruled that MISO:

  • failed to describe what factors it would consider when verifying cost-based offers or distributing uplift;
  • was silent on its treatment of external supply offers in excess of the cap;
  • neglected to specify a verification process for demand response; and
  • failed to limit the cap on all adders above cost to $100.

On Wednesday, FERC determined that MISO’s second filing had cleared up the offer validation process, which gives the Independent Market Monitor discretion to validate market participants’ data. The RTO additionally complied with a requirement that external energy transactions not exceed the hard cap but also not be subject to validation.

However, FERC said MISO still must pledge to apply the new hard cap to adjusted energy offers from fast-start resources.

The commission acknowledged that its previous ruling mistakenly understood “proxy offers” to include fast-start resources’ adjusted offers, but it said it now recognizes the term applies to resources deployed during emergency operating procedures.

“The commission did not intend to change the definition of ‘proxy offers,’” FERC said.

MISO had proposed to apply the $2,000/MWh hard cap to most proxy offers used during emergency conditions for price-setting purposes, but it said emergency demand response proxy offers would not be included. The RTO has long allowed emergency DR resources to exceed the hard price cap up to the value of lost load, which is currently $3,500/MWh.

FERC said it viewed MISO’s value of lost load as an “administratively determined pricing mechanism beyond the scope of the offer cap reforms in Order No. 831.”

The commission also accepted the RTO’s plan to have its Monitor verify offers from DR resources above the $1,000/MWh soft offer cap before market clearing in order to allow them to set the LMP. FERC also approved edited Tariff language that allows resources to submit cost-based incremental energy offers above $2,000/MWh and recover verified costs through make-whole payments, although such offers are barred from setting LMPs.

But the commission is requiring MISO to provide more detail on the Monitor’s verification process for resources that submit incremental energy offers above $1,000/MWh that cannot be verified prior to the market clearing. FERC said MISO must also describe when the Monitor will verify the prices and revise reference levels, and when a market participant can dispute revenue sufficiency guarantee make-whole payments.

“Additionally, we direct MISO to propose Tariff language describing how the amount of the make-whole payment will be determined,” FERC added.

FERC also ordered MISO to update its Tariff to include references to its Operating Cost Survey, which is used to determine reference levels by collecting more than 200 “pieces of data for a single plant,” according to the RTO.

FERC additionally said MISO must clarify the use of its adder for “outage risk,” a term the RTO used in its amended offer cap filing but is not found in Tariff provisions that define reference levels, which instead employs the term “legitimate risk.”

FERC also said MISO appeared to violate a rule that limits to $100/MWh the sum of any adders for cost-based incremental energy offers above $1,000/MWh by allowing two types of adders within its offer cap: the legitimate risk adder and a fuel cost uncertainty adder. The commission gave the RTO 60 days to explain the differences, if any, between the two terms and describe how it will stay within the $100/MWh adder limit.

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Massachusetts Bids Adieu to Northern Pass

By Michael Kuser

Massachusetts on Wednesday revoked its selection of Northern Pass as the sole winner of a massive clean energy solicitation, saying it will instead enter contract negotiations with the rival New England Clean Energy Connect (NECEC) project.

The decision capped a tumultuous two months since the state chose Northern Pass in its MA 83D solicitation for 9.45 TWh per year of hydro and Class I renewables (wind, solar or energy storage). The joint project between Eversource Energy and Hydro-Quebec won the contract Jan. 25, only to see the New Hampshire Site Evaluation Committee (SEC) unanimously reject the 1,090-MW transmission line a week later. (See New Hampshire Rejects Permit for Northern Pass.)

Eversource said it understood why Massachusetts needed to move on with its clean energy plans but that “despite recent delays, we continue to believe that Northern Pass is the best project for the region and New Hampshire, and we intend to pursue all options for making it a reality.”

The company had appealed the New Hampshire decision, but the SEC voted March 12 to wait until its permit denial is published later this month before considering the appeal, effectively killing the 192-mile HVDC line’s chance to meet Massachusetts’ March 27 contract deadline. Any contract awarded under the request for proposals must be submitted to the state’s Department of Public Utilities by April 25.

The Massachusetts committee charged with reviewing proposals selected the NECEC as an alternative to Northern Pass. (See Mass. Picks Avangrid Project as Northern Pass Backup.) The committee consists of representatives from the state’s Department of Energy Resources and distribution utilities Eversource, National Grid and Unitil.

Northern Pass Clean Energy NECEC
| Eversource, Central Maine Power

Central Maine Power, an Avangrid subsidiary, partnered with Hydro-Quebec on NECEC, a 145-mile transmission line that would deliver up to 1,200 MW of Canadian hydropower to the New England grid. The partners estimate the project will cost $950 million.

No Free Pass for NECEC

Massachusetts Sierra Club Director Emily Norton on Wednesday lauded the rejection of Northern Pass as “good news,” saying the project “would have increased electricity costs in the state, destroyed pristine wilderness in New Hampshire and continued the destruction of traditional hunting and fishing grounds of First Nations in Quebec, all while failing to reduce climate pollution in the region.”

During a three-day hearing in February, New Hampshire’s SEC voted 7-0 to reject Northern Pass after expressing concerns that it would harm property values, tourism and land use.

Testifying on behalf of the city of Concord, N.H., during the hearing, wetlands scientist Rick Van de Poll said that the project’s temporary and permanent impacts to wetlands in the city would be significantly greater than the developers assumed in their October 2015 wetlands permit application.

Van de Poll said permanent impacts would include reduced habitat fish and aquatic life habitat; loss of habitat for rare and endangered species; and reduced scenic quality, flood storage and groundwater recharge.

But NECEC is not getting a free pass from environmentalists and other industry stakeholders. New Hampshire Sierra Club Director Catherine Corkery joined Norton in saying, “It is too soon to celebrate, however.” NECEC “carries many of the same problems as Northern Pass.”

“MA has gone from the fatally flawed Northern Pass to the nascent NECEC, which doesn’t have any permits,” New England Power Generators Association President Dan Dolan tweeted. “If the original goal was to meet 2020 climate targets, that’s now out the window. All while leading to potentially the largest electric rate increase in state history.”

Three top generators in Maine are already contesting the NECEC. Calpine, Dynegy and Bucksport Generation, which together own one-third of the state’s installed electric generating capacity, have asked the Public Utilities Commission to allow them to intervene late as full parties in the proceeding to review the project. (See Generators Challenge HVDC Line at Maine PUC.)

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ALJ Rules New England Tx Owners’ ROEs not Unjust

By Michael Kuser

A FERC administrative law judge ruled Tuesday that municipal utilities and commission staff failed to prove that the New England Transmission Owners’ (NETOs) base return on equity of 10.57% (11.74% with incentives) is unjust and unreasonable, rebuffing requests to reduce it.

The March 27 initial decision by ALJ Steven A. Glazer found that the discounted cash flow (DCF) analyses by the complainants — the Eastern Massachusetts Consumers-Owned Systems (EMCOS) — and FERC staff were “fatally defective” because they failed to include Algonquin Power & Utilities in their proxy groups, “despite this company’s ample qualifications to be included” (EL16-64-002).

FERC Base ROE Emera Maine

| Avangrid

The EMCOS, whose case was supported by state regulators and industrial consumers, asked FERC in a April 2016 complaint to reduce the NETOs’ base ROE to 8.93% or lower (11.24% with incentives). It was the fourth challenge since September 2011 to the ROE for the NETOs, which include Emera Maine, Northeast Utilities, Central Maine Power, National Grid and NextEra Energy. (See FERC Denies New England Tx Owners ROE Rehearing.)

The 2011 challenge resulted in FERC lowering the base ROE to 10.57% from 11.14% in 2014. But the ruling was vacated by the D.C. Circuit Court of Appeals last April, which found that the commission failed to prove the higher rate was unjust and unreasonable, as required before setting a new rate (Emera Maine et al. v. FERC). (See Court Rejects FERC ROE Order for New England.)

The commission has not responded to the court’s remand.

Setting the Proxy Group

Glazer sided with the NETOs in ruling that the EMCOS’ and staff’s DCF analyses should have included Algonquin because the company pays dividends and operates within the contiguous U.S., and its credit ratings are within the “comparable risk band” for the NETOs. Glazer said FERC staff improperly rejected the company because it is headquartered in Canada and also broke with commission precedent in ignoring the credit ratings of the NETOs’ parent companies.

The EMCOS’ economist rejected Algonquin because it was not included in the Value Line Investment Survey and did not have a five-year Institutional Brokers Estimate System (IBES) earnings growth rate published in Yahoo Finance, the source of earnings growth forecasts used by the commission. IBES later added the company to its ratings; inclusion in the Value Line survey is not required by FERC, the judge said.

Including Algonquin’s IBES-based ROE of 16.14% would significantly alter staff’s and EMCOS’ DCF analyses, making the current 10.57% base ROE within the zone of reasonableness, Glazer said.

“Their zones of reasonableness would shift upward from approximately 6 to 11% to approximately 7 to 16%, and the midpoint of their zones would shift from approximately 8.4% to approximately 11.8%,” Glazer wrote.

Moving the Goal Post

The judge was particularly critical of the EMCOS’ analysis, saying it contained “numerous errors and changed significantly throughout this proceeding,” including on the last day of the hearing in the case. “Both the EMCOS and staff made several unwarranted changes to the commission’s typical DCF analysis,” he said. “In short, the goal post was moved repeatedly by the EMCOS and staff to wherever the football was in order to score points.”

Glazer said he did not need to determine a new ROE because of the inability of staff and the EMCOs to provide reliable analyses that proved the existing rates were not just and reasonable. “The failure of the EMCOS and the staff to meet their burden of proof means that the case is over, because they have produced no DCF analysis that is usable in this case for any purpose.”

He also said that their failure also “renders moot the EMCOS’ further argument that the base and maximum ROEs should be adjusted downward in order to mitigate alleged harm to consumers” caused by the NETOs’ maintenance of equity–heavy capital structures.

Exceptions to the decision are due in 30 days, with objections to the exceptions due 20 days later. If no party objects, the ALJ’s decision would take legal effect without further action by the commission.

That’s unlikely, ClearView Energy Partners said in an analysis of the ruling, which predicted challenges to the inclusion of Algonquin.

Response to Remand

The analysts said FERC could respond to the D.C. Circuit’s remand of the 2014 ruling by opening a Notice of Inquiry or by issuing a revised decision.

“If the remand proceedings ahead for the Emera Maine decision result in the FERC upholding the June 2014 revision of the ROE to 10.57%, then we expect the commission might also affirm the ALJ’s finding here that the most recent complaint fails,” the analysts wrote.

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NYISO Management Committee Briefs: March 28,2018

RENSSELAER, N.Y. — NYISO’s Management Committee on Wednesday approved Tariff revisions intended to provide external resources with Rest of State (ROS) deliverability rights to improve their ability to participate in the ISO’s capacity market.

The March 28 vote recommended that the ISO’s Board of Directors authorize staff to file the revisions with FERC under Federal Power Act Section 205.

Ethan Avallone, NYISO senior market design specialist, said Hydro-Quebec US (HQUS) proposed the ISO develop a method for awarding capacity resource interconnection service (CRIS) to entities that create increased transfer capability through transmission upgrades over external interfaces. (See “External Deliverability Rights,” NYISO Business Issues Committee Briefs: March 15, 2018.)

NYISO management committee deliverability rights
| NYSEG

FERC last year granted HQUS eligibility to receive CRIS in proportion to the incremental transfer capability created by its Cedars Rapids Transmission intertie project (ER17-505). National Grid also stands to benefit from the change after it completes upgrades on its 115-kV Dennison-Alcoa line in Zone D in Q4 2019.

2017 CARIS Report Moves to Board

The committee also approved the 2017 Congestion Assessment and Resource Integration Study (CARIS) Phase 1 draft report on the potential costs and benefits of relieving congestion on the transmission system through generic transmission, generation, demand response and energy-efficiency solutions. (See “2017 Congestion Assessment and Resource Integration Study,” NYISO Business Issues Committee Briefs: March 15, 2018.)

Tim Duffy, economic planning manager, said NYISO has identified three main areas of the state where transmission congestion is: Edic-Marcy, Central East and New Scotland-Pleasant Valley.

To provide additional value to stakeholders, Duffy said the ISO developed a system resource shift case, which assumed retirement of the Indian Point nuclear plant by 2020/2021 and all coal units in the state by 2020, and a resource mix consistent with attaining Clean Energy Standard targets by 2026.

— Michael Kuser

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PG&E to Seek Storage, EE to Replace Dynegy Plant

By Jason Fordney

Pacific Gas & Electric is requesting proposals for the development of up to 45 MW of “clean energy” resources including at least 10 MW of energy storage, as the centerpiece of its plans to replace the aging Dynegy Oakland jet fuel-fired power plant.

The utility said it will open a two-month request for offers process in spring, inviting “innovative and competitive solutions for the portfolio.” It hopes to bring the new mix of resources online in mid-2022; the procurement total will depend on the exact resource mix, the company said.

PG&E Oakland Power Plant Dynegy Energy Efficiency
A historical photo of the Oakland Power Plant, which went into operation in 1888. The current jet-fueled generators, owned by Dynegy, went into service 40 years ago. | PG&E

The 165-MW Dynegy plant currently operates under a CAISO reliability-must-run contract to meet local reliability needs.

CAISO identified PG&E’s proposal, the Oakland Clean Energy Initiative, as a preferred solution in CAISO’s 2017/18 transmission plan approved by the ISO’s Board of Governors last week. (See CAISO Moves Ahead With Market Changes.)

The plan includes:

  • transmission line rerates and system upgrades to remove limiting elements;
  • at least 10 MW of 4-hour utility-owned in-front-of-the-meter storage in the Oakland C and Oakland L 115-kV substation pocket;
  • competitive procurement of 10 to 24 MW of “preferred resources” — energy efficiency, demand response, renewable generation and storage — in the substation pocket, at least 19.2 MW of which is “load modifying in nature;”
  • continuing to rely on transferring Alameda Municipal Power load from Cartwright (North) to Jenny (south) during peak load conditions and after an N-1 contingency, in preparation for an N-1-1.

The project marks the first time that clean energy resources would be deployed as an alternative to fossil fuels for transmission reliability in the PG&E area. It will be working with local community choice aggregator East Bay Community Energy to determine the clean energy and reliability solution.

“PG&E and the system operator worked collaboratively over the last several transmission planning cycles to study how distributed clean energy resources could become part of the solution,” the company said in a news release. The utility said it will seek cost recovery for the battery storage facility from FERC and for distributed energy resources from the California Public Utilities Commission. It expects to file with the PUC by the end of the year.

Since 2010, CAISO has increasingly focused on non-transmission alternatives in its planning. The ISO cannot specifically approve non-transmission alternatives part of its annual plan, but it can identify them as preferred solutions, as it did with the PG&E proposal.

CAISO’s transmission plan said the closing of the 40-year-old generator would cause thermal overloads on the Oakland 115-kV system without new local generation. The estimated cost of the PG&E proposal is about $102 million (2022 dollars), while other alternatives, including transmission lines and generation, ranged from $367 million to $574 million.

PG&E Oakland Power Plant Dynegy Energy Efficiency
Forecast load in PG&E Transmission Access Charge Area 2011-2017 | CAISO

The Dynegy plant’s RMR agreement with CAISO was renewed in September 2017, based on local reliability analysis. The ISO said that based on real-time operations data for 2015 and 2016 there is a need for at least 98 MW for a one-in-three heatwave scenario that would cause heavy loads. It also cited instances where all three 55-MW Oakland units were running for local reliability. A 2018 forecast showed a need of 56 MW because of a discrepancy in substation load forecast distribution that the ISO said it would work with PG&E to correct.

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Study Predicts Growth in MISO Demand Management

By Amanda Durish Cook

An energy consulting firm thinks MISO has the potential for several gigawatts of demand-side energy savings by 2038, stakeholders learned Thursday.

The 20-year estimates of MISO’s future demand response, energy efficiency and distributed generation were produced by Applied Energy Group (AEG), with near final results presented to stakeholders at a special March 22 conference call. The commissioned study will inform the RTO’s 2019 Transmission Expansion Plan, with researchers using the conditions from four MTEP future predictions to project likely demand-side management.

By 2038, total demand-side management could reduce MISO peak summer demand by 22.5 GW, or about 15%, with 11.3 GW of the energy savings from energy efficiency, 7.2 GW from DR and 4 GW from distributed generation. Next year, AEG predicts MISO will save about 8.2 GW on summer peak demand from demand-side management.

MISO energy efficiency Demand-side Management
Summer peak demand savings | Applied Energy Group

In two decades, energy efficiency will be responsible for a 69,899-GWh annual energy savings in MISO; distributed generation will account for a 19,566-GWh annual savings; and DR programs will yield a 539-GWh annual savings. The 89,971-GWh savings total by 2038 is a more than seven-fold increase from AEG’s expected 12,764-GWh savings in 2019.

AEG predicts that Michigan, Minnesota, Iowa and Wisconsin have the most potential for energy savings through the next 20 years.

MISO energy efficiency Demand-side Management
Annual energy savings | Applied Energy Group

Some stakeholders commented that there was virtually no way to verify AEG’s forecasted values with what transpires because behind-the-meter activity is expected to remain largely undocumented.

AEG Managing Director Michael Daukoru said his firm examined both regional and state-specific customer adoption trends along with various state incentives, costs of programs, utility-provided forecasts and capacity growth rates in the study.

MISO staff have said the trickiest part of load forecasting is capturing and projecting the footprint’s unknown amount of demand-side management. (See MISO Looks to Align Load Forecasting, Tx Planning.)

The study found that energy efficiency provides the most significant magnitude of demand and energy savings resources.

“Energy efficiency in our view will continue to play a critical role in demand-side management,” Daukoru said. “EE is quite significant in terms of savings.”

Daukoru predicted that residential behavioral programs that encourage improvements in energy efficiency and home weatherization programs will continue to gain popularity within MISO. New federal lighting standards in 2020 and efficiency upgrades to existing buildings and equipment will also play a role in energy efficiency, the study found.

Distributed resources, driven by rooftop solar, will impact peak loads. MISO will continue to see rapid adoption of distributed generation with the rapidly declining cost of residential rooftop solar, Daukoru said. Distributed wind, on the other hand, is expected to remain prohibitively expensive for most residents.

Combined heat and power is already at high saturation point in parts of MISO, including Texas, Louisiana and Michigan. Expensive installation costs limit more adoption, Daukoru said.

The study found that MISO has room for “significant” DR opportunities, despite “several mature” programs in certain states. AEG expects residents in the footprint to participate in expanded direct load control programs within two decades, installing connected thermostats and smart water heaters that can be automated to turn off in response to reliability threats or energy price spikes.

AEG said utility-led dynamic pricing programs will be emerging only “from isolated pilots.”

“There is enormous potential for dynamic pricing, but it requires political will,” said AEG Senior Vice President Ingrid Rohmund.

Customized Energy Solutions’ David Sapper asked if AEG considered how the federal push to value resilience might affect the adoption of demand-side management in MISO.

“I have not given that much thought,” Daukoru said. “That was not accounted for in our analysis.”

Daukoru added that demand-side resources could be valuable to resilience given their ability to deliver energy savings and render loads more flexible.

AEG’s study will be finalized in June and included in the MTEP studies. MISO and AEG will continue to refine study assumptions for behind-the-meter participation and the potential impact of electric vehicle adoption over the next few weeks.

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PJM MRC/MC Briefs: March 22, 2018

Markets and Reliability Committee

Additional Reserves Needed?

Moments after stakeholders approved the charter for the Energy Price Formation Senior Task Force (EPFSTF) without comment at last week’s Markets and Reliability Committee, PJM moved to revise the issue charge on which it’s based to also address concerns about insufficient secondary reserves.

“The topic of potential new reserve products has been raised in our discussion around energy price formation,” PJM’s Dave Anders explained. “We realized that it would really be beneficial for the Operating Committee to provide some input to those considerations around reserve products.”

The EPFSTF decided that the first step is for the OC to define the “reliability-related aspects” that need to be addressed so they can be incorporated into the market-structure changes the task force is contemplating. To include that, they recommended adding a “key work activity” to the task force’s issue charge and assigning it to the OC.

The initial proposal tasked the OC with identifying the factors a 30-minute real-time product should have and how it would interact with synchronized reserves. However, stakeholders — led by the Independent Market Monitor Joe Bowring — eventually replaced that with a more generalized task to analyze secondary reserves and any “interdependencies” it would have with primary reserves.

Calpine’s David “Scarp” Scarpignato asked that the discussion include any reserve requirement changes that would interact with the reliability assessment and commitment (RAC) process and the day-ahead and real-time markets. Anders said the language had been added to the EPFSTF’s charter.

PJM REV MISO Annual Stakeholders' Meeting Second Circuit Court of Appeals
Souder | © RTO Insider

PJM’s Dave Souder said the reserve considerations are an extension of the gas-electric coordination and pipeline-contingency initiative that he has been leading since late last year. He said he plans to “set aside an hour” at each monthly OC meeting to create a recommendation on the appropriate inputs and what revisions might need to happen in real time. (See “Resilience Update,” PJM Operating Committee Briefs: March 6, 2018.)

“I think it’s within our purview at the OC to see if we have reliability need, and we can recommend that the product be developed, but how that’s developed would be through the [EPFSTF],” Souder said. “There may be times where the gas contingency is larger than our largest 30-minute requirement. Under those conditions, we may need to ensure we have sufficient 30-minute reserves.”

Congestion Overlap

PJM
Horger | © RTO Insider

Stakeholders endorsed the second phase of an initiative with MISO to address overlapping congestion. The first phase was filed with FERC in December, but PJM had to respond to a deficiency notice in January and it was not approved by the proposed March 1 implementation date. With the endorsement of the second phase, staff hope that both phases can be approved for implementation by June 1, PJM’s Tim Horger said.

The proposal addresses the potential for pseudo-tied resources to pay twice for congestion charges as their energy crosses the market borders. The first phase eliminated the charges, and the second phase allows hedging of potential congestion charges through day-ahead transactions, auction revenue rights and financial transmission rights. Owners will be refunded or charged for deviations between day-ahead submittals and real-time operations. (See MISO, PJM Pursue Pseudo-Tie Double-Charge Relief.)

Solution to congestion overlap | PJM

Generation Transfer

Concerns with PJM’s proposed deadlines for notifying the RTO of generation transfers are being ironed out, PJM’s Rebecca Stadelmeyer said. A vote on the issue was deferred at February’s MRC meeting because some generation owners felt PJM’s timeline was too onerous. (See “Generators Hesitate on Ownership Transfer Rules,” PJM Markets and Reliability Committee Briefs: Feb. 22, 2018.)

Stadelmeyer said stakeholders have sent in redlines, and a group of generation owners, coordinated by GT Power Group’s Dave Pratzon, are engaged on the issue.

“It definitely appears PJM and the generator owners are coming to a mutual understanding,” she said.

The group has another call scheduled for March 28.

Stakeholders Approve Variety of Actions

Stakeholders endorsed by acclamation several manual revisions and other operational changes:

Members Committee

Overlapping Congestion Endorsed Through Consent Agenda

The Tariff and OA revisions to address the overlapping congestion issue were added to the consent agenda, which stakeholders endorsed by acclamation without comment.

The issue was brought for a vote at both committees on the same day because stakeholders agreed to that arrangement when they deferred the vote at February’s MRC. The dual vote allows PJM to maintain its preferred timeline for filing and implementation.

Monitor Recommends Redrawing Market Lines

Monitor Bowring believes the lines that define regional price separations within the RTO in the capacity market are antiquated and that price separation should be dynamic based on the actual characteristics of the market. He discussed the recommendation while briefing members on the 2017 State of the Market report. (See IMM Report Says PJM Prices Sufficient.)

Bowring | © RTO Insider

Bowring’s thoughts on redefining locational deliverability areas (LDAs) in the capacity market came in response to a question from Ruth Ann Price of the Delaware Division of the Public Advocate. She had asked him to expound on his recommendation that LDA definitions be dynamic and market based.

“We think that it should be based on a nodal definition so that the price separation is a function of the actual transmission characteristics of the system as well as the relative offer prices of the system,” Bowring said. “LDAs are arbitrary lines … [that are] almost without exception the old-fashioned transmission zones. There’s no reason to believe that those are the right way to have prices separate.”

He said the first step to addressing the issue is modeling every LDA to see if any prices separate. He said he hasn’t done the analysis to determine how many LDAs would price separately, but that he would investigate it.

Bowring said another “work in progress” is examining the nature of the competition to provide transmission upgrades and expansions.

— Rory D. Sweeney

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FERC Approves ISO-NE Capacity Termination

FERC on Friday accepted ISO-NE’s request to terminate 11 MW of the capacity supply obligations (CSOs) for a Maine wind farm that delayed its commercial operation and reduced its planned output.

However, FERC said the RTO was wrong in executing the termination before commission approval, delaying the effective date to March 24 (ER18-704).

The RTO filed its termination request on Jan. 23, asserting that developer Blue Sky West had delayed its original 2015 commercial operation date multiple times before achieving partial operation in March 2017.

FERC ISO-NE CSOs capacity supply obligations
Bingham Wind Project | NovatusEnergy

In Forward Capacity Auction 6, the Bingham wind project in Somerset and Piscataquis counties won CSOs of 42.3 MW for summer and 87.3 for winter, beginning with the 2015/16 capacity commitment periods (CCP).

The company agreed to voluntarily relinquish about 20 MW of summer and 22 MW of winter CSOs based on its decision to reduce the number of turbines in the project and change the turbines to a design with a lower capacity. But the company disputed ISO-NE’s demand to reduce the summer CSO by 10.3 MW and winter by 0.79 MW following the RTO’s audits of the farm’s actual output.

The RTO filed to terminate immediately that portion of the resource’s CSOs in the 2017/18 through 2020/21 capacity years, and to adjust the facility’s qualified capacity for future capacity auctions.

Blue Sky West filed an emergency motion asking the commission to order reinstatement of the disputed CSOs, arguing the grid operator must receive commission approval before the termination could become effective. On Feb. 2, 2018, the commission granted the motion, ruling that the termination could not be made effective prior to March 24, the end of the 60-day notice period.

The RTO’s Tariff allows termination of CSOs if a new facility covers its capacity shortfalls through bilateral trades or the reconfiguration auctions for two capacity commitment periods. The developer claimed the audits should not be justification for reducing the CSOs because they are not listed as “critical path” schedule requirements in the RTO’s Tariff.

The commission disagreed, saying, “Neither achieving ‘commercial operation’ nor fulfilling ‘critical path schedule milestones’ precludes ISO-NE from terminating a resource’s CSO under” the Tariff.

The RTO said that if it did not perform terminations in advance of the FCA, a resource that is not fulfilling its CSO could obtain one for another year and potentially suppress auction clearing prices and provide the region with phantom megawatts that cannot produce energy.

FERC agreed with the grid operator’s right to manage its capacity resources but departed with it regarding its termination rights. “While the [Tariff] language is ambiguous, we find that under a sensible reading of the provision and as a practical matter, [a Federal Power Act] Section 205 filing is necessary to obtain a ‘commission ruling’ on any aspect of an involuntary termination,” the commission said.

Requiring such approval of involuntary terminations “should not impede the grid operator’s administration of the Forward Capacity Auction,” FERC said.

“Given that the [FCA] takes place in February of each year, the [RTO] usually submits termination filing in October of the prior year, giving the commission enough time to rule on the termination filing before the Forward Capacity Auction is conducted,” the commission said.

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Del. Group Seeks to Block Artificial Island Project

By Rory D. Sweeney

Could PJM’s Artificial Island project get any more complicated? Apparently, yes.

A Delaware demand-side group has asked the PJM Board of Managers to again suspend the project because of announcements from Exelon and Public Service Enterprise Group that that they will cancel future capital investments at the two Salem nuclear units they co-own and shut the plants down if New Jersey doesn’t provide them $300 million annually in subsidies to keep the plants open. (See NJ Lawmakers Advance Latest Nuke Subsidy Bills.)

The project was developed to address transmission stability problems at the Hope Creek and Salem nuclear units in southern New Jersey and allow them to operate at full power without a book-size compilation of operating constraints.

pjm board of managers artificial island
The Hope Creek and Salem nuclear units on Artificial Island in southern New Jersey | BHI Energy

PJM’s first competitive solicitation under Order 1000, the Artificial Island project has long been mired in controversy. In June, the RTO announced several cost allocation alternatives that would shift much of the $280 million price tag from Delaware ratepayers to those in New Jersey and Pennsylvania. (See PJM: AI Costs Would Shift to NJ, PA Under New Allocations.)

The Board of Managers had two months earlier restarted the project and ordered the analysis of alternative allocation methods. It also re-awarded the project to LS Power, which was selected when the board approved the project in July 2015. Complaints over mounting costs, scope changes and a cost allocation that Delaware felt was unduly burdensome caused the board to suspend it in August 2016.

But the announcements from Exelon and PSEG in February cast doubt over whether the plants are long for this world. PSEG said it might also cancel spending on the Hope Creek reactor, which shares Artificial Island with the Salem units.

“These actions call into question the long-term operational viability of the Salem and Hope Creek plants,” wrote Michael K. Messer, president of the Delaware Energy Users Group, noting that Delaware consumers stand to pay “a significant share” of the project’s cost. “The cost increase is at a level that will severely impair the competitiveness of Delaware businesses. This scenario becomes far worse should the driving reason for the transmission project, Salem and Hope Creek reliability, cease to exist.”

He asked the board to consider whether the project is necessary or if its scope changes if any or all of the plants close and whether the project’s timeline should be delayed “to minimize expenditures until a long-term commitment is established for the Salem and Hope Creek plants.” LS Power’s award has an in-service date of June 1, 2020.

PJM’s Dave Anders, who oversees stakeholder relations, said it’s unclear what the board’s response will be. “At this point, I do not have a sense for when/if there will be a formal response,” he said in an email.