Page 1177 – RTO Insider

April 11, 2018

RTOs, Regulators Set Course for DER Market Participation

By Michael Kuser and Jason Fordney

Grid operators and regulators on Tuesday hashed out the complexities of integrating distributed energy resources (DER) during the first session of a two-day FERC technical conference on boosting the role of energy storage in wholesale electricity markets.

FERC ordered the conference in February after issuing Order 841, which requires each RTO/ISO to develop a “participation model” allowing storage resources to provide any energy, capacity and ancillary services of which they are capable and be eligible to set clearing prices as both buyers and sellers. (See FERC Rules to Boost Storage Role in Markets.)

A morning panel brought together RTO/ISO representatives who discussed the operational intricacies of integrating DER into wholesale markets, focusing on approaches to aggregating the market participation of the small-scale resources to make them manageable for grid operators.

“DER aggregation requires a level of cooperation you don’t see to this point, not even in demand response, because of the impact DER can have on the system,” said John Goodin, CAISO manager of infrastructure and regulatory policy. “It’s important if you’re going to establish DER aggregation, that you impose both size and boundary constraints; that’s something that the ISO has done.”

DER CAISO Market Monitor phase angle regulators — University of Delaware Vehicle to Grid (V2G) cars parked at the Science, Technology, and Advanced Research (STAR) Campus. 15 V2G vehicles act as a mini power plant, drawing energy during off-peak times and delivering it back to the grid when it’s most needed. In partnership with NRG Energy Inc., the University has created the world’s first revenue-generating vehicle-to-grid project using technology developed by Professor Willett Kempton of UD’s College of Earth, Ocean, and Environment. | *University of Delaware*

CAISO set a 20-MW size limit on aggregations participating in its market, although individual resources can range from 0.5 to 1 MW. Any resource exceeding 20 MW becomes a participating generator subject to a different set of requirements, Goodin noted.

Nodal vs. Zonal

Pointing to the dual nature of DER as both transmission and distribution resources, Jeff Bladen, MISO executive director for market services, said it’s important to distinguish between the challenges of taking load off the system and putting supply onto the system.

“As we think about aggregation groups, it needs to be more than how do we do security-constrained aggregations for the transmission system, but how are we going to manage potential restraints at the distribution level,” Bladen said.

“Let’s remember we are a nodal system,” cautioned Joe Bowring, president of Monitoring Analytics, PJM’s Independent Market Monitor. He encouraged industry stakeholders to think about developing a sustainable model for significant expansion of DER.

“It’s critical to think about how [aggregation] works in a nodal system,” Bowring said. “It’s not possible to predict congestion; it’s not possible to predefine constraints that exist or don’t exist in a zone.” Any configuration larger than a node is “way too big for aggregation,” he said.

DER Distributed Energy Resources FERC Technical Conference — | *NYISO*

Michael DeSocio, NYISO senior manager for market design, said while New York does allow zonal aggregations, none is participating in the market today.

“So as much as we hear it’s important, we don’t see much of that actually occurring in New York,” DeSocio said. “As we thought about making sure the values were there for DER and making sure the price signals incentivize DER to locate in the right places, it occurred to us that nodal made the most sense.”

Henry Yoshimura, ISO-NE director of demand resource strategy, noted resources coming into the New England system are primarily solar and energy efficiency and the RTO’s settlement-only construct allows any resource up to 5 MW to participate in the wholesale market. “Because there’s no size limitation, there’s no real need for aggregation,” he said.

Goodin said CAISO sees significant benefits to aggregation.

“We don’t have a single node,” Goodin said. “You can have an aggregation across the [sub-load aggregation point], across multiple nodes, and why is it advantageous? One, it allows for the providers to actually go out and solicit and pull together, aggregate, meaningful-sized customers, meaningful from the ISO’s perspective … the key thing is that aggregations allow for the right sized resource.”

Andrew Levitt, PJM senior market strategist, said, “We think there are benefits to aggregation in ensuring open market access to resources of all sizes, including resources smaller than our 100-kW minimum highest threshold.”

National Solutions?

Commissioner Cheryl LaFleur asked why there should be different processes among the different regions.

“Shouldn’t we try to solve the coordination process once and then sort of spread that, as opposed to developing six ways to do it?” LaFleur asked. “Maybe we should standardize more. Can we skip a step and figure it out?”

“I don’t know that the rules are the issue,” DeSocio said. “I think really what the main difference that we’ve observed in New York is what is the posture of each of the different distribution utilities, what is their ability to actually see into their own grids.”

Goodin added, “If we are going to enable DER to really flourish, you have to address some of the things that are outside the walls of the ISO and the authority of an ISO through FERC.”

He enumerated three priorities: access to capacity markets and capacity payments; reducing interconnection barriers and cost; and creating more clarity around allowing DER to tap multiple value streams and simultaneously provide grid services to the both ISO and distribution domains.

“In my opinion, those are the much more weighty issues — resource questions, interconnection, multiuse — than sort of the day-to-day functionality of managing these DER and settling these DER resources in the wholesale market,” he said.

Yoshimura said the primary issue is a lack of “consensus in the industry as to how distributed energy resources ought to be operated, if at all. And the struggle that any ISO would have is, whereas we model transmission constraints, I don’t think any of us model distribution constraints.”

MISO’s Bladen said, “We like to think of ourselves as a service provider, to the states in many respects, that our job is to take the fleet that regulators are designing and implementing through their integrated resource plans and to optimize that, to get the most value you possibly can out of that fleet across a broad region.”

“We don’t know yet what best practices are going to look like, don’t know what the dominant DER technologies will be, and that what you have in front of you are a number of companies interested in identifying best practices,” Bladen said.

Bowring said: “We should have the same rules. The fact there’s all this complexity doesn’t mean we shouldn’t have the same set of rules. They will evolve, but we to need start in the same place where everyone is facing the same issues.”

Head Banging

During the afternoon panel, regulators from California, Ohio, Pennsylvania and D.C., as well as others, carried on the discussion of DER aggregation, including issues around reliability and markets. The conversation illustrated the newness of the technology and the many challenges of coordinating state regulations, markets, and the requirements for utilities.

FERC commissioners noted the difficulties for states developing separate policies and approaches that will need to be integrated into wholesale and retail markets. The panel covered how federal and state regulators — and others — can better coordinate on the issue.

“This is a case where all the technology might be ahead of the regulators,” LaFleur said.

FERC Chairman Kevin McIntrye put it simply, telling the state regulators, “We want to avoid messing anything up.” He asked about the negative impacts of individual and aggregated DER on states and said the discussion should help build a robust evidentiary record.

California Public Utilities Commission (CPUC) President Michael Picker recommended a “DER roadmap” similar to one developed by his agency, which looks at grid architecture, DER planning, and developing appropriate rates and tariffs. California is a leading state in DER integration, including efforts by the CPUC and CAISO.

“There are a lot of challenges here,” Picker said, adding that the CPUC’s effort has uncovered issues around safety for workers and emergency responders who have to deal with DER equipment. The effort has also identified operational issues around DER integration, including congestion in the distribution system, and is mapping the distribution system similar to how RTOs map transmission systems.

“We have a grid system that was never designed for a lot of two-way flow,” Picker said. The CPUC effort is “acknowledging that these are trends that are going to happen,” he said. He noted that other states will be able to learn from and “leapfrog” California’s efforts.

“I would recommend you let us bang our heads against those brick walls,” he told FERC, pointing to CAISO’s Energy Storage and Distributed Energy Resources program, now in its third phase. (See CAISO Storage, DER Plans Progressing.)

Different States, Different Rules

The regulators noted their states have different policies with different cost impacts that will need to be integrated into markets. They also hold differing views on allowing DER to participate in wholesale and retail markets.

Public Utilities Commission of Ohio Chairman Asim Haque discussed an issue raised by several regulators: that DER should not be compensated twice — in retail and wholesale markets — for providing the same services.

But Haque added that DER owners and operators should be left to decide how they choose to be compensated for behind-the-meter DER, such as staying on a net metering tariff or participating in the wholesale market through aggregation if that is more profitable.

“Their goal is to maximize the value of that resource,” he said. “That is acceptable to us as well.”

Ben D’Antonio, counsel for the New England States Committee on Electricity, said distribution utilities in New England are going to drive many of the outcomes as DER resources are added, but “the operational impacts are not known at this time.”

“We are actively working on it, but some of ours states have some pretty ambitious goals and others do not,” D’Antonio said. He said it’s unclear how quickly DER will grow in New England, but he thinks the integration effort will need to be consistent with the integration and interconnection requirements of the distribution utilities, who have a “critical gatekeeping role.” Utility decisions will be driven by the tariffs, requirements, and incentives that federal and state regulators put in place, he said.

”We support the idea of DER being able to take part in both wholesale and retail markets,” said Tammy Mitchell, deputy director of the New York State Department of Public Service. But she thinks much work remains to develop the rules and protocols, including the double-payment issue, which could increase ratepayer costs.

D.C. Public Service Commissioner Willie Phillips said he thinks the city can benefit from DER, but “it’s really a resource-by-resource analysis.” The city has seen no negative impact from its load control programs, for example, he said.

“Here in the district, people are dying to get at this,” but the compensation issue must be solved first, Phillips said.

April 10, 2018

PJM Capacity Proposals to Duel at FERC

By Rory D. Sweeney

PJM’s Independent Market Monitor scored a victory Monday after the RTO announced it filed with FERC to consider both its two-stage capacity repricing proposal and the Monitor’s plan to expand the minimum offer price rule (MOPR) (ER18-1314).

As part of the filing, PJM requested that the commission choose one proposal — even if that requires more information for full approval — and to identify what aspects of it need to be revised, rather than send the issue to “trial-type proceedings.” The RTO instead suggested establishing settlement judge procedures, if necessary.

Minimum Offer Price Rule MOPR PJM FERC — Schneider | © *RTO Insider*

“PJM anticipates that if the commission makes the outstanding issues more manageable by accepting one of the two tariff alternatives, a good faith consensual effort could be the most productive means of resolving those outstanding issues,” the RTO said.

The RTO requested an effective date of Jan. 4, 2019, to be in place for the 2019 Base Residual Auction for delivery year 2022/2023. To that end, the RTO asked for an order be issued prior to July so that any necessary follow-up could be completed in time for January.

“Based on PJM’s showings in this filing, the commission has substantial evidence on which it could fully accept either of the two alternatives in an order issued by June 29, 2018,” the RTO said.

The filing is what former FERC Chairman Norman Bay called a “jump ball” on Twitter, as it asks the commission to settle a disagreement that divided the grid operator, its Monitor and stakeholders throughout 2017. PJM campaigned from the beginning for its plan to accept bids from subsidized resources in its capacity auctions, but then isolate them during a second stage and reset the price without them. The Monitor’s MOPR-Ex proposal would extend the MOPR to all units indefinitely, but in alternative versions included carve-outs for states’ renewable portfolios and public power self-supply. (See PJM Board Punts Capacity Market Proposals to FERC.)

Stakeholders, who saw the Monitor proposal as having the least impact on the current construct, backed it all the way to the Markets and Reliability Committee, but all its different versions stalled after PJM CEO Andy Ott announced he would be recommending the RTO’s plan to the Board of Managers no matter the outcome of the committee vote. Still, subsequent pressure from stakeholders forced staff to offer both proposals to the board, which in the end punted the decision to FERC.

PJM FERC MOPR — Andy Ott, PJM (left) and Bowring | © *RTO Insider*

The Monitor had vowed to file his proposal if it wasn’t recommended to the board, even though it would have meant meeting the tougher standards under Section 206 of the Federal Power Act of demonstrating not only that the proposed changes are just and reasonable, but that the existing rules are unjust and unreasonable. That’s a higher hurdle than proposals that receive board approval, which only have to show the proposal is just and reasonable under the standards of Section 205.

“The question raised by PJM’s filing in this case is not whether states have the right to [encourage development of preferred generation resources within their borders] but instead how the wholesale market should respond to such actions so that the goal of ensuring just and reasonable rates is not frustrated by an individual state’s actions,” PJM said in the filing.

However, some stakeholders remained unsatisfied with either option. Jennifer Chen, an attorney with the Natural Resources Defense Council’s Sustainable FERC Project, said PJM’s proposal “would funnel more money from consumers to power plants for no additional benefit” while the Monitor’s proposal “would discriminate against offshore wind and force consumers’ utilities to over-procure generation.”

“Either of PJM’s two competing pricing proposals will drive up the utility bills of 65 million electricity customers in 13 Mid-Atlantic and Midwestern states,” she wrote. “The proposals also ignore the real issue — that PJM’s capacity market commitment to supply electricity in the future forces utilities to purchase a specific amount today, but without the opportunity to choose the kind of energy customers want to power their homes and businesses tomorrow.”

April 10, 2018

CAISO RC Plan Undercuts Peak Rates

By Jason Fordney

CAISO last week issued its proposal to offer reliability coordinator (RC) services in the West, including a plan to charge rates that appear to dramatically undercut rival Peak Reliability.

But when asked about the figures Monday, Peak told RTO Insider that “a true and accurate side-by-side comparison is not possible.”

The ISO on Friday provided more details on the planned Tariff changes and rates it will charge after its planned departure from current RC service provider Peak Reliability in September 2019. It plans to become certified as its own RC provider. (See CAISO to Depart Peak Reliability, Become RC.)

CAISO PJM RTO Insider Western RTO — CAISO says it plans to be up and running with RC services by spring of 2019 | © *RTO Insider*

CAISO will develop an RC funding requirement — which includes the operating budget and reserve, as well as an annual revenue adjustment — to determine what it will charge per megawatt-hour. The ISO estimates its annual funding requirement will range from $5 million for only the ISO area to $12 million for all potential balancing areas in the region. Dividing those amounts by projected volumes yields a rate of 2 to 3 cents/MWh. CAISO said the monthly service charge will be derived by multiplying the RC rate by the megawatt-hour volumes submitted, citing an example of $51,000 monthly and $614,000 annually based on a monthly customer with a volume of about 2 million MWh.

By comparison, Peak said it charged customers nearly $44.6 million for its RC function in both 2016 and 2017 and will maintain the same level of funding for 2018.

“Yes, we can do it that much cheaper,” CAISO spokesman Steven Greenlee confirmed.

But Peak spokeswoman Rachel Sherrard said a comparison is not possible, “as the depth and breadth of the services Peak RC provides for its current rate of around 5 cents per retail customer per MWh is significantly more than we believe will be offered by CAISO.” She said that price includes the core RC function and several enhanced tools and technologies such as the WECC Interchange Tool, the Enhanced Curtailment Calculator and the Peak Synchrophasor Project.

“These additional value-adding tools, requested by our funding parties over the past nine years, have been consistently modified and refined to meet the reliability challenges posed by the changing landscape,” Sherrard said. “Our understanding is that CAISO is going to offer the basic NERC-compliant RC services, which doesn’t directly correlate to what we provide.

“In addition to switching costs associated with a transfer from Peak to any other RC, there is risk in transitioning from an entity with a strong operational track record, exceptional talent with an immense knowledge of the Western Interconnection and skills to an entity that is not yet an established RC,” Sherrard said.

Next Steps

CAISO has scheduled an April 12 meeting at its headquarters to discuss its RC rate design straw proposal, which it will develop into a final plan submitted to the ISO Board of Governors and then FERC.

CAISO reliability coordinator peak reliability — CAISO’s planned milestones for development of RC services | *CAISO*

“All transmission operators within the CAISO balancing authority (BA) area will become reliability coordinator service customers of the CAISO at that time,” the ISO said. The RC services will also be offered to balancing authority areas outside of CAISO area and to transmission operators in those BAAs.

The RC is the highest level of reliability authority under the NERC model and has the widest view of the bulk electric system, with authority to prevent or mitigate reliability problems in both next-day analysis and in real-time.

The ISO said it also will be working with transmission operators in CAISO and others that have provided a letter of intent for RC services and signed non-disclosure agreements to develop operating procedures, technical requirements and other facets of the RC proposal.

CAISO’s model is based on seven ratemaking principles used to determine its other rates, including grid management charges and Energy Imbalance Market (EIM) administrative fees: cost causation, use of services, transparency, predictability, ability to forecast, flexibility and simplicity.

The ISO will require RC customers to initially commit to 18 months of services and will not penalize for withdrawals provided that six months of notice is given. The ISO estimates it will need 28 full-time employees that will work solely on the RC function.

CAISO in January initially announced its intent to depart Peak and offer its own RC services.

The ISO cited as the reasons for the move Peak’s decision to partner with PJM to provide market services and Mountain West Transmission Group’s likely departure from Peak after it joins SPP. (See Peak/PJM Enter Western Market ‘Commitment Phase’.)

CAISO is also developing a plan to extend its day-ahead market across the EIM, setting up competition for developing the market that could possibly develop into a new Western RTO. (See Multiple Entities, Markets Now Beckon in West.)

April 10, 2018

PJM Market Implementation Committee Briefs: April 4, 2018

VALLEY FORGE, Pa. — PJM’s Eric Hsia told attendees at last week’s Market Implementation Committee meeting that the RTO plans to salvage the non-compensation portions of its proposal to revise its regulation market that FERC rejected last month. (See FERC Rejects PJM Regulation Plan, Calls Tech Conference.)

PJM had filed for approval of revisions that included four interdependent components. The commission denied the proposal outright because it would have paid units a formula rate that didn’t specifically compensate for the actual amount of regulation work they provided, but its order didn’t address the other three components. Hsia said PJM plans to ask FERC to reconsider those components separately as the RTO determines how to address the commission’s issues with its compensation plan. He confirmed that PJM wouldn’t change the language describing the three components in its reconsideration request.

Stakeholders considered market-related issues last week at PJM’s Market Implementation Committee meeting. | © *RTO Insider*

Direct Energy’s Marji Philips asked if PJM plans to consolidate its regulation signals into a single signal as FERC pointed out in its order is the process that all other grid operators follow. Hsia said the RTO is considering that option.

VOM Proposal

Stakeholders endorsed proposed revisions for how operations and maintenance costs are recovered that would allow “major” maintenance to be included in variable operations and maintenance (VOM) calculations. Both PJM’s and a default proposal received overwhelming support. The RTO’s proposal received 169 votes in favor, or 75%, and 57 opposed. The default package received 178 votes in favor, or 81%, and 43 votes opposed.

A follow-up vote found that 71% of voters preferred one of the packages over the status quo. The revisions will impact how units calculate their cost-based offers and have implications for other market and operational issues, such as frequency response. (See PJM SHs Debate Frequency Response Rules.)

The Independent Market Monitor’s Catherine Tyler provided context for the Monitor’s proposal, which would have replaced “incremental” with “short-run marginal” in the Operating Agreement and assumed that all maintenance and labor costs are included in a unit’s capacity offer. It fell well short of the votes needed, receiving 11% favorability, or 24 votes out of 224.

“The cost-based offer should be set at a competitive level, and that is short-run marginal cost,” Tyler said.

She said that while every unit provides a cost-based offer, which is only applied if the unit fails its market power test, it isn’t used frequently because price-based offers are often lower than cost-based ones, which she said is a particular concern when cost-based offers are overstated. A unit has incentive to pad cost-based offers because it provides more room to adjust price-based offers when the unit fails its market power test.

PJM’s Gary Helm said the quadrennial analysis of how unit-type net cost of new entry (CONE) is determined will evaluate both including and excluding major maintenance from the VOM calculation. PJM hired the Brattle Group to do the review, which will be presented later this month and is slated for filing for approval at FERC on Aug. 1.

The last review in 2014 became mired in infighting at FERC over details in the engineering portion of how costs could be determined.

FES Bankruptcy

PJM staff did not offer any specific comment on FirstEnergy Solutions’ bankruptcy announcement and plans to shutter its three nuclear facilities, but they agreed to field stakeholder questions on the issue.

Stu Bresler, senior vice president of markets and operations, confirmed that the plants’ “must-offer requirement is retained” absent an exemption. Because the period for seeking such an exemption has closed, it would require a FERC waiver granting it.

CFO Suzanne Daugherty said, “PJM is still ready for June 1,” referring to the target date for Ohio Valley Electric Corp.’s integration into the RTO. But she said staff would accommodate a delay if requested. She said that all PJM members are in compliance with credit requirements but clarified that any without investment-grade ratings wouldn’t be eligible for unsecured credit.

It remains unclear how the deactivations will impact prices.

“I can’t imagine the analysis resulting in any other [locational deliverability area] model than what’s already been modeled,” Bresler said. But Monitor Joe Bowring said he can’t tell if an additional LDA would clear the Base Residual Auction above the RTO-wide capacity price unless it’s modeled in the auction.

SOM Revisions

Bowring announced that several calculations have been revised in the IMM’s annual State of the Market Report that paint a less rosy picture for nuclear facilities than originally thought. (See IMM Report Says PJM Prices Sufficient.)

The Monitor revised its calculations on forward-looking profitability for nuclear plants, reducing the numbers by tens of millions of dollars. It now predicts a revenue shortfall of $11 million this year for the Perry generating station, which is one of the facilities FES plans to close, instead of the previous $500,000 profit. Perry also overtook Three Mile Island, which Exelon has threatened to close, for the grimmest long-term outlook, expected to hemorrhage $79.5 million in 2020 alone.

Exelon’s Dresden facility in Illinois overtook the company’s Limerick facility near Philadelphia as the plant with the best outlook, with about $58.8 million in profit expected for 2020.

Nodal Mapping

Stakeholders are working on several initiatives involving financial transmission rights.

Proposed revisions to address the nodal remapping issue are expected at the May MIC meeting to target a Sept. 1 effective date that coincides with the 2018 LMP bus modeling likely for mid-September, PJM’s Brian Chmielewski said.

The revisions are in response to concerns highlighted by Direct Energy about replacing nodes where FTRs begin or end and are terminated based on changes in load, generation or system topology. When that happens, an “electrically equivalent” node must be identified to replace the terminated one, but stakeholders who have experienced that issue have been unsatisfied. The proposal would create a “dummy” pricing node at the same location as the terminated one where only “sell” bids would be allowed. After all connected FTRs are sold or expire, the node would be terminated. The same process would work for incremental auction revenue rights.

Long-Term FTR

PJM also plans to bring a proposal to the May MIC meeting for addressing long-term FTRs, with a target effective date by June 1 in time for the 2020/23 auction, Chmielewski said. PJM’s plan would eliminate the current “year all” offering, leaving only the one-year options that are one, two or three years in the future.

PJM said interest was low in the “year all” option that included all three years and eliminating it would improve FTR software performance. The proposal would also limit ARR modeling. Instead of including all planning period ARRs as fixed injections and withdrawals, it would only include those that cleared based on the annual model with all transmission outages removed. Chmielewski said the plan better represents the residual capability on the system and preserves capability for ARR holders in the subsequent annual allocation.

— Rory D. Sweeney

April 10, 2018

PJM PC/TEAC Briefs: April 5, 2018

VALLEY FORGE, Pa. — PJM stakeholders are questioning the process for how a transmission development proposal will proceed following a debate at last week’s Planning Committee meeting.

The issue arose during a discussion of the effort to incorporate cost containment into transmission project proposals. A series of events at January’s Markets and Reliability Committee meeting culminated in the issue going back to the PC for additional consideration. A PJM proposal was voted down, and the RTO’s Suzanne Daugherty, who chairs the MRC, then determined that an alternate proposal from LS Power, which didn’t receive a vote, would be the main proposal the committee considers when the issue returns.

PJM Market Efficiency Projects Cost Containment — Stakeholders considered transmission and planning-related issues last week at meetings of PJM’s Planning and Transmission Expansion Advisory committees. | © *RTO Insider*

But a gas-fired generation representative who asked not to be named questioned whether Daugherty had the authority to make that determination. Stakeholders who supported his assessment pointed out that the MRC directed the PC to give the issue additional consideration. The PC could vote on any proposals that come out of that reconsideration to determine the order in which they’re presented at the MRC, they argued.

Other stakeholders, including Calpine’s David “Scarp” Scarpignato, were hesitant to accept that interpretation of the rules, arguing that they had acted at the MRC under the expectation that the appropriate outcome had occurred.

Stakeholders have been considering the issue through special sessions of the PC and working under the belief that LS has control of what the primary proposal will say. Under the MRC’s rules, the committee doesn’t consider alternate proposals if the primary proposal is endorsed. (See PJM Stakeholders Explore Cost Containment Complexities.)

PJM staff agreed to consider the process questions and make a determination, but they also questioned the usefulness of focusing on that rather than trying to find stakeholder consensus.

“This is largely academic,” PJM’s Steve Herling said.

“We can as a group figure out what’s giving everybody the most heartburn and try to work on those” issues, PJM’s Sue Glatz said.

Market Efficiency Charter

Stakeholders endorsed the charter for the Market Efficiency Process Enhancement Task Force (MEPETF), which has been stood up to consider ways to improve the process for developing market efficiency projects. It will analyze seven processes:

How the benefit-to-cost ratio is calculated;
How facility service agreements (FSAs) are modeled;
The process for proposal windows;
How interregional market efficiency projects (IMEPs) are selected;
How projects are re-evaluated;
The process for regional targeted market efficiency projects (TMEPs); and
The process for updating assumptions about the system in the middle of the proposal cycle.

The group has met three times, with the next meeting planned for April 20.

Reactive Transfer

The RTO plans to revise two of its reactive transfer interface definitions effective June 1, PJM’s Yuri Smolanitsky said. Staff will add the 5059 Breinigsville-Alburtis No. 1 500-kV line to the eastern interface. The new line is expected to be in service by next spring.

Three 345-kV lines — Hanna-Chamberlin, Star-N. Medina and Monroe-Lallendorf — are being added to the Cleveland interface to extend it further south and east. Staff expects “minimal” operational impacts, Smolanitsky said.

“One of the reasons we’re trying to expand the definition [is] so we have more options” to address operational contingencies, PJM’s Aaron Berner explained.

Facility Rating Concerns

Ryan Dolan of American Municipal Power highlighted concerns his organization and the PJM Industrial Customer Coalition have with how transmission owners calculate facility ratings. Dolan said the methodologies used by TOs to file facility ratings in compliance with NERC reliability standard FAC-008-3 aren’t made available to stakeholders, so it’s impossible to independently verify them.

The same issue is at the heart of a ruling made in January by a FERC administrative law judge that PJM’s system impact study (SIS) process is unjust and unreasonable because of a lack of transparency. In that case, merchant transmission developer TranSource brought a complaint that it wasn’t able to accurately assess cost estimates prior to paying significant filing fees for line upgrades it proposed because PJM uses confidential information in the estimates. The RTO vowed to challenge the ruling, and parties in the case have submitted comments. (See FERC Judge Faults PJM, TOs on Transmission Upgrade Process.)

AMP says it wants to discuss better tracking of changes to facility ratings and development of a publicly available ratings database to help stakeholders determine factors that are limiting facilities’ performance.

Order 1000 Filing Catches Up

Staff plan to file for FERC approval later this month process revisions related to Order 1000 that stakeholders endorsed in February 2016, PJM assistant general counsel Pauline Foley said. The revisions will require renewal every three years of transmission developers’ prequalified status to be named the designated entity for a project. They also clarify that the deadline for designated entities to submit their agreement and credit paperwork is 60 days after PJM provides it to them.

The filing was postponed while FERC was without a quorum and ran into unforeseen staff delays subsequent to the quorum returning, Foley said. PJM will be contacting the prequalified entities to update their prequalification status.

Nuclear Deactivations

Staff have begun the analysis of whether the four nuclear plant closures announced by First Energy Solutions in March will create reliability concerns. Calpine’s Scarp said the main question is whether PJM will be offering the units reliability-must-run contracts.

“Really, that’s the only information out of this we’re trying to get,” he said.

Staff said that determination would be based on an analysis that hadn’t been completed yet. FES has requested to deactivate Davis-Besse in the ATSI transmission zone in Ohio by June 1, 2020. Perry, which is also in ATSI, and Unit 1 of the Beaver Valley facility in Duquesne Power and Light’s zone would be deactivated by June 1, 2021, and the second unit by Nov. 1, 2021.

PJM denied are any reliability issues when FES announced the closures on March 29. (See FES Seeks Bankruptcy, DOE Emergency Order.)

— Rory D. Sweeney

April 10, 2018

PJM Operating Committee Briefs: April 3, 2018

VALLEY FORGE, Pa. — With the exception of three nor’easters, system operations in March were relatively uneventful, PJM’s Chris Pilong told attendees at last week’s Operating Committee meeting.

Pilong reviewed the monthly operations report, noting there were no spinning reserve events during the month. The load forecasting error was 1.53% overall. The error during off-peak hours was 1.48%, 0.1% above the same metric in March 2017, but the on-peak error was 1.58%, down 0.16% from a year ago.

There were 45 excursions for a total of 99 minutes outside PJM’s frequency target range, down from 106 excursions for 257 minutes in March 2017. Unplanned outages, planned emergencies and the total outage average by percentage were all lower than the same period a year ago. The forced outage average by percentage, along with the forced and total outage averages by megawatts, were up slightly.

Stakeholders considered operational issues last week at PJM’s Operating Committee meeting. | © *RTO Insider*

“We’re starting to ratchet up the planned outages,” Pilong said. In previous years, April and May have been the second- and third-highest months for outages, behind only October.

PJM estimates production-cost savings of more than $11 million in 2018, almost all of which occurred in March.

Gen Transfer Vote Postponed

PJM postponed a planned vote on approving stricter requirements for notifying the RTO about generation ownership transfers, but the RTO’s Rebecca Stadelmeyer said ongoing discussions with owners remain productive. The two sides hope to have a mutually acceptable proposal prepared for a vote at May’s OC.

Both sides recently engaged in a four-hour discussion, and a final call is scheduled for this month, Stadelmeyer said. Generation owners in February objected to rules proposed by PJM that they felt were too onerous, but at last week’s meeting, they appeared to agree that the consensus was likely. (See “Generation Transfer,” PJM MRC/MC Briefs: March 22, 2018.)

Storage

PJM’s Scott Baker highlighted progress being made by the Distributed Energy Resources Subcommittee on determining how combined storage and generation resources should measure and account for the differences between wholesale and retail power sales. The subcommittee has developed potential definitions for wholesale-retail delineations during complicated transactions, such as when a storage resource is charging from both the grid and a co-located resource and discharging to the grid while the generation resource is also injecting directly to the grid.

Baker also outlined the non-wholesale information PJM believes it needs from DERs and the communication and data-validation channels that will likely be necessary to properly oversee storage resources.

Black Start Fuel Assurance

As part of the current black start procurement, PJM is looking to add rules that ensure plants have fuel when needed. The RTO’s David Schweizer introduced a plan for “restoration fuel assurance,” which it hopes to implement in the third quarter of this year and apply to any black start resource procured after 2018.

The changes would include a transition plan for existing units, including those picked up in the current procurement. The plan will also address fuel-assurance issues — including dual-fuel capability, onsite fuel storage and units having connections to multiple gas lines — and compensation mechanisms.

Schweizer said he received preliminary proposals from 90 different sites in its current procurement, which PJM undertakes every five years. Staff have sent notifications for detailed proposals to about 25 of the 90. PJM is planning to award contracts to any successful proposals by the end of May. There are currently about 150 black start units RTO-wide.

Schweizer said the new rules are in response to the fleet becoming significantly more gas-heavy. He noted that the current rules require that black start units be back online within three hours, and that gas travels in pipelines at 20 mph on average. Gas pipeline operators have assured the RTO that the lines are packed sufficiently to supply black start units if necessary, but “increased reliance on natural gas means increased need for black start ability,” he said.

CIR Revisions

PJM’s Jerry Bell presented additional analysis on summer performance of wind and solar units and how that relates to providing capacity injection rights (CIRs). The work is part of PJM’s ongoing effort to revise Manual 21, which covers procedures for determining changes to generators’ capability. (See “Limiting Meetings Causing Stakeholder Strain,” PJM PC/TEAC Briefs: March 8, 2018.)

Bell said staff analysis found that the average peak hour, which is used for determining capability, is a good approximation of the median for solar units but not for wind. The study found that average wind performance during the peak hour of demand is likely to reflect the actual amount of production only 36% of the time. The median was about half as much, and wind production was zero in two of every seven peak summer hours, Bell said.

For the May OC meeting, PJM plans to provide more analysis on whether the current June-August testing period is appropriate, and if simultaneous testing would be more indicative of the true capability of plants that have common load spread across multiple units.

Stakeholders remained skeptical of the potential changes, noting concerns that ranged from how unit testing will be conducted, to whether there’s an appeals process for PJM’s determinations, to how the rights planned for units in the interconnection queue would be handled if they are not brought online before the rules change.

PMUs to Monitor IROLs

PJM is considering using its growing synchrophasor network to monitor interconnection reliability operating limits (IROLs). The RTO’s Shaun Murphy explained that phasor measurement units (PMUs) could offer redundant monitoring of the IROL interfaces. Past issues with PJM’s emergency management system have required manual monitoring of IROLs. Implementing the plan would require installing 14 PMUs and modifying four.

The proposal is the most recent initiative in PJM’s effort to exploit the opportunities created by its synchrophasor network. (See “Synchrophasors Backup,” PJM Operating Committee Briefs: Sept. 12, 2017.)

University Park RAS Done

Commonwealth Edison’s Alan Engelmann announced plans to end the company’s remedial action scheme at its University Park North Energy Center. The RAS will be disabled by July 1 and physically removed by the end of the year.

The plan trips generators for certain delayed-clearing multi-phase and single-phase faults to prevent instability, Engelmann said. Incremental reinforcements, such as circuit breaker replacements and protection system redundancy, have made the plan unnecessary.

— Rory D. Sweeney

April 10, 2018

Perry Hints DOE Won’t Grant FES ‘Emergency’ Request

By Rich Heidorn Jr.

NEW YORK — Energy Secretary Rick Perry insisted again Monday that coal and nuclear generation is essential to electric resilience but indicated he was not likely to declare an emergency to keep FirstEnergy Solutions’ struggling power plants operating.

FirstEnergy DOE Rick Perry FES — Perry | © *RTO Insider*

FES asked the Department of Energy last month to issue an emergency order directing PJM to compensate coal-fired and nuclear power plants that have 25 days of onsite fuel with “full recovery” of their costs and a “fair return on equity.”

The company asked Perry to act under Section 202c of the Federal Power Act, which allows DOE to declare emergencies “during the continuance of any war in which the United States is engaged, or whenever [FERC] determines that an emergency exists by reason of a sudden increase in the demand for electric energy, or a shortage of electric energy.”

FES said the closing of its nuclear and coal generation would undermine the reliability of PJM’s grid, a contention the RTO dismissed, saying “there is no immediate emergency.” (See FES Seeks Bankruptcy, DOE Emergency Order.)

Perry spoke Monday at Bloomberg New Energy Finance’s (BNEF) Future of Energy Summit, where Ethan Zindler, head of Americas for BNEF, asked him to define “emergency.”

“When you flip on the lights and nothing happens,” Perry responded.

Would FES’ request qualify as an emergency that deserved intervention? Zindler asked.

“That is an issue in front of DOE that is being looked at as we speak,” Perry said. “My job is to find solutions to challenges that face us. The 202c may not be the way that we decide what is the most appropriate, most efficient way to address this. It’s not the only way.”

Perry did not elaborate on what path DOE might take, but he reiterated his longstanding position that an “all of the above” fuel strategy, including the retention of coal and nuclear, was essential to reliability. He also repeated his response to those who have complained that the emergency order — and the Notice of Proposed Rulemaking he sought from FERC last year to boost such generators — would undermine markets.

“Nobody was using the term ‘free market’ when we were talking about renewables and the subsidies that came from the government,” he said. “The reality is government affects the market every day.”

In an earlier session at the BNEF Summit, former FERC Commissioner Nora Brownell said granting FES’ request would be a “tragedy” for capitalism, markets and ratepayers. Noting the FPA’s reference to war or shortages, she predicted any emergency declaration would be overturned by the courts.

In January, FERC rejected Perry’s NOPR, which would have directed RTOs and ISOs to compensate the full operating costs of generators with 90 days of onsite fuel. The commission instead opened a new docket to receive input on the resilience issue. (See RTO Resilience Filings Seek Time, More Gas Coordination.)

April 9, 2018

CAISO Developing New CRR Proposal

By Jason Fordney

FOLSOM, Calif. — CAISO is advancing into the second phase of reforms to its congestion revenue rights auction, focusing on implementing a structure that provides only a partial congestion hedge rather than a full one.

The ISO is moving through auction reforms in stages after its Department of Market Monitoring called for disbanding the program; it found the transactions have led to losses in the hundreds of millions for ratepayers. (See CAISO Monitor Proposes to End Revenue Rights Auction.) Financial entities and traders have objected to the changes, leading to a complex debate over the current structure and whether it is fair for ratepayers. Similar discussions are going on in other organized markets over financial transmission rights.

The ISO has already completed “Track 1A” of its CRR auction changes, unanimously approved by the Board of Governors last month. (See CAISO Moves Ahead With Market Changes.) At the meeting, board members agreed with the Monitor’s contention that the CRR market as currently devised it is not a real auction because it does not involve willing buyers and sellers.

Auction participants can currently purchase CRRs at generator locations, load locations, trading hubs, pricing nodes, and import and export scheduling points, but the changes proposed in Track 1A limit CRR sources and sinks to only the combinations needed to hedge congestion costs associated with delivering supply. The revisions also established a deadline for reporting transmission outages prior to the auctions to more accurately estimate transmission capacity available for CRR purchases.

Partially funded CRRs

CAISO is now developing changes under “Track 1B,” targeted for June approval by the board and implementation in time for settlement of the 2019 CRR auction. Under consideration for this track is a switch from fully funded CRRs — in which the auctioned rights provide a complete hedge and always receive a full difference in marginal congestion components — to a partial funding arrangement.

CAISO CRR congestion revenue rights — Servedio | © *RTO Insider*

Other ISOs and RTOs only partially fund FTRs, relying on a system in which auctioned rights share in payment shortfalls and do not provide a complete hedge, CAISO Market Design Policy Developer Perry Servedio said Thursday in a presentation to the ISO’s Market Surveillance Committee (MSC).

CAISO also plans to develop a “Track 2” set of rule changes consisting of more comprehensive changes to be implemented in time for the 2020 CRR auction.

The ISO is considering two approaches to partially funding CRRs. One is an ex ante approach in which the ISO derates CRRs prior to the day-ahead market. This would allow market participants to adjust their forward energy positions prior to the day-ahead market to hedge final supply delivery.

Another ex post approach would charge CRR holders for shortfalls after the day-ahead market, which could eliminate incentives by market participants to “game” modeling differences between the CRR market and day-ahead market, CAISO said.

Other approaches are also under consideration, including lowering the percentage of system capacity released in the CRR process, eliminating use of the whole transmission system in the auction or implementing reserve prices.

CAISO Considers MSC Viewpoints

CRR congestion revenue rights caiso — Harvey | © *RTO Insider*

At Thursday’s meeting, Scott Harvey of FTI Consulting briefed Servedio and other CAISO staff with a presentation on what he said could be other factors contributing to CRR auction revenue inadequacy, including the fact that CRRs are allocated and auctioned based on auction shift factors but are settled based on day-ahead shift factors.

MSC members James Bushnell, of the University of California Davis, and Ben Hobbs, of Johns Hopkins University, also raised issues with one CRR proposal developed by Southern California Edison and the Monitor that would eliminate using the available transmission system in the CRR auction, saying the move would have technical, institutional and legal implications.

“Even if there is large-scale willing participation by sellers, forming desired new CRRs out of offered counterflow CRRs may be difficult or unlikely,” they said.

After the Track 1B process is complete, CAISO says it will embark on Track 2 in time for the 2020 auction with “potential comprehensive changes.” The ongoing overhaul indicates the current CRR process is due to change significantly in coming years.

April 9, 2018

Interior Plans Would Boost Mass., NY Offshore Wind

By Michael Kuser

Offshore wind got a boost on two fronts Friday when U.S. Interior Secretary Ryan Zinke announced two new proposed offshore wind leases for Massachusetts, while the Interior Department’s Bureau of Ocean Energy Management issued a call for commercial interest in four wind energy areas in the New York Bight.

“The Trump administration supports an all-of-the-above energy policy and using every tool available to achieve American energy dominance,” Zinke said.

BOEM on Apr. 11 will publish in the Federal Register a proposed sale notice for the Massachusetts leases and a call for information and nominations on the New York areas.

BOEM Ryan Zinke Offshore Wind — Offshore Wind Platform | *Deepwater Wind*

Massachusetts later this month will select one of three bids received in December for up to 800 MW of offshore wind energy projects, with contracts to be submitted at the end of July. The bidders include Bay State Wind, a joint venture between Orsted and Eversource Energy; Deepwater Wind; and Vineyard Wind, a joint venture of Avangrid Renewables and Copenhagen Infrastructure Partners.

All three developers have purchased renewable energy leases off Martha’s Vineyard from BOEM. (See Mass. Receives Three OSW Proposals, Including Storage, Tx.)

OSW, Yes; Offshore Drilling, No

The proposed lease areas offshore from Massachusetts total 460 square nautical miles.

Interior Counselor for Energy Policy Vincent DeVito said in a statement that the federal government had worked “with a broad community of engaged stakeholders, including fishing communities,” to identify “areas that can support a large-scale commercial wind project, while minimizing the impacts to fishing habitats, marine species and other uses” of the outer continental shelf.

The proposed “call areas” being considered in the New York Bight — a region of the Atlantic Ocean between Long Island and the New Jersey coast — are named Fairways North, Fairways South, Hudson North and Hudson South, and comprise 2,047 square nautical miles.

BOEM Acting Director Walter Cruickshank said in a statement that the bureau and stakeholders will look at the potential impacts of offshore wind in New York.

“For example, commercial and recreational fishing are important cultural and economic activities that must be considered,” Cruickshank said.

New York in January released its master plan for 2,400 MW of offshore wind development, which includes an initial phase of solicitations this year and next for at least 800 MW. (See NY Offshore Wind Plan Faces Tx Challenge.)

Gov. Andrew Cuomo released a statement Friday welcoming BOEM’s support in advancing the state’s offshore wind plan but added he remains “deeply concerned by the federal government’s proposal to allow new offshore oil and gas drilling.”

“New York has formally requested to be excluded from this offshore drilling plan, and we believe offshore wind is a better direction for our economy, for our environment and for our energy future,” Cuomo said.

April 9, 2018

FERC Approves Change to Eliminate Gaming in SPP Markets

FERC last week overruled a stakeholder’s objections in approving SPP’s proposed Tariff revisions to eliminate a gaming opportunity related to regulation deployment adjustments (ER18-757).

The commission found that SPP’s modifications to the regulation deployment adjustment charge and payment calculations to be just and reasonable, accepting them to become effective May 1.

FERC said that by allowing the use of mitigated energy offer curves or as-dispatched energy offer curves in regulation deployment adjustment calculations, the Tariff revisions “help ensure that the regulation deployment adjustment amount will compensate resources for their output associated with regulation deployment.”

The RTO’s Market Monitoring Unit had pushed for the change (MWG-RR243), saying manipulation of regulation-down offers has cost the SPP market more than $1 million in recent years.

FERC disagreed with Westar Energy’s argument that the revisions represent a “fundamental change” in the incentives for market participants’ selection between the energy or regulation markets. It also disagreed with Westar’s complaint that incorporating resources’ mitigated energy offer curves as a component of the regulation deployment adjustment’s calculation is unjust and unreasonable — noting that market participants perceiving any inequity between the markets can modify their regulation offers accordingly.

SPP FERC Regulation Deployment Adjustment — Westar Energy’s headquarters | *Seeking Alpha*

The commission said it agreed with the MMU that closing the gaming opportunity outweighed concerns that the Tariff revisions would extend the use of the mitigated energy offer curve beyond local market power mitigation.

“We find that using the mitigated energy offer curve when calculating the regulation deployment adjustment amount should limit gaming opportunities and also helps ensure that the resources deployed to supply regulation recover their costs,” FERC said.

Westar contended that the proposed revisions would automatically cause all regulation deployment adjustment payments to be based on the type of offer (mitigated or market-based) that causes credits to be minimized. It said SPP was proposing a solution that “inappropriately and unreasonably affects all resources, when SPP should instead narrowly address the few bad actors believed to be economically withholding.”

The utility proposed that SPP be required to apply some type of economic withholding evaluation instead. SPP responded that Westar had confused gaming with economic withholding, and said that its market-clearing engine co-optimizes energy demand and regulation requirements with energy and regulation offers while ensuring resources are agnostic relative to selection for energy or regulation.

Commission Denies Golden Spread’s Rehearing Request

The commission denied Golden Spread Electric Cooperative’s rehearing request for its 2017 approval of SPP’s Order 825 compliance filing (ER17-772).

FERC’s September order accepted Tariff changes made to comply with Order 825, which requires RTOs to settle real-time energy, operating reserves and intertie transactions in the same time interval it dispatches, prices and schedules them, respectively. (See FERC Approves SPP Shortage Pricing Changes.)

Golden Spread argued that SPP’s filing did not comply with Order 825 because it did not address the RTO’s practice of committing additional capacity through the reliability unit commitment (RUC) process or through manual operations that can prevent scarcity pricing events. The commission said the protests were outside the proceeding’s scope and encouraged the cooperative to address its concerns through SPP’s stakeholder process.

In its appeal, the cooperative argued that FERC’s dismissal of its concerns as beyond the scope “effectively overlooks the fact that SPP’s current, unchanged practices purposefully and fundamentally mask the presence of market scarcity and subvert the primary goals of Order No. 825.”

The commission noted that its September ruling found that Order 825 did not require Golden Spread’s suggested modifications to SPP’s RUC or manual commitment processes. “The absence of such requirements places these SPP practices beyond the scope of a compliance filing,” FERC said.

The commission has “stated on numerous occasions” that the sole relevant issue in reviewing compliance filings is whether they comply with the directions in the order requiring them, it said. It also pointed out that it will not consider arguments raised in a compliance proceeding “that are not responsive to the narrow issue of the filing utility’s compliance.”

FERC Accepts ITC Midwest’s Interconnection Agreement

FERC accepted ITC Midwest’s third restated interconnection agreement with Corn Belt Power Cooperative and Interstate Power and Light (IPL), effective April 7 (ER18-801).

The agreement adds a substation as an additional point of interconnection between IPL and Corn Belt. The interconnection was expected to be in service in the first quarter of 2018.

Corn Belt and IPL are parties to other dockets (consolidated under ER15-2028) before the commission involving Corn Belt’s entry into SPP as a transmission owner and the resulting implications for existing agreements between the utilities.

The original agreement with ITC dates to 1956 but was designated as a grandfathered agreement (GFA) under MISO’s Tariff. ITC said that because of its possible GFA status under SPP’s and MISO’s Tariffs, Corn Belt and IPL had declined to execute the agreement.

The commission dismissed concerns by Missouri River Energy Services (MRES) that the proceeding’s outcome could affect cost allocations in its transmission zone, finding the proceeding “not to be relevant” to ITC’s proposed addition of the substation.

“We therefore are not persuaded to consolidate this proceeding with [ER15-2028] or otherwise hold it in abeyance,” FERC said. It said its acceptance of the agreement does not affect the ongoing proceeding in that docket.

East River Co-op Granted Waiver to Revise Tx Rates

The commission granted East River Electric Power Cooperative’s request for a one-time waiver to revise its 2018 update and associated informational filing for its formula rate template and protocols under SPP’s Tariff (ER18-860).

The waiver allows East River to reclassify the Groton-Ordway 115-kV transmission project, which it said it had initially understood should be classified as a base plan upgrade eligible for recovery through zonal and regionwide charges. The project will now be included in the cooperative’s annual transmission revenue requirement as part of its zonal charges.

East River is a wholesale electric power supply cooperative serving 24 rural electric cooperatives and one municipally owned electric system in eastern South Dakota and western Minnesota. It became a TO member of SPP in 2015 as part of the Integrated System.

— Tom Kleckner