Page 1353 – RTO Insider

July 16, 2018

PJM Market Implementation Committee Briefs: July 11, 2018

VALLEY FORGE, Pa. — PJM’s Ray Fernandez told attendees at last week’s Market Implementation Committee meeting that his staff are still completing calculations for part of FERC’s ruling on retroactively reallocating costs for certain transmission projects in the RTO’s territory (EL05-121).

Staff have requested to extend the compliance filing deadline until July 30, Fernandez said. In May, FERC issued an order approving a settlement on the RTO’s procedure for allocating the costs of major transmission projects. The settlement created a cost allocation formula for projects approved prior to Feb. 1, 2013, when PJM abandoned a “postage stamp” method that billed all utilities in proportion to their load, regardless of where the projects were located. (See “Response to FERC’s Cost Allocation Order,” PJM Market Implementation Committee Briefs: June 6, 2018.)

pjm market implementation committee — PJM’s Market Implementation Committee met on July 11, 2018 | © *RTO Insider*

Staff are revising the allocations on 14 technical worksheets to reflect the approved split of 50% on the original annual load-ratio share basis and 50% on the solution-based distribution factor (DFAX) method. Market participants will need to review all the worksheets to understand the full implications of the revisions, Fernandez said. He hopes to have them completed within two weeks.

The order also includes a “black box” settlement for projects from 2007 through 2015 that will be rebilled over the next 10 years. Fernandez said those reallocation amounts were published as part of the settlement.

Seasonal Aggregation

Stakeholders unanimously endorsed proposed revisions for aggregating seasonal resources. PJM’s Andrea Yeaton presented the proposal, which is designed to better account for the resources’ accumulated capability. (See “Seasonal Aggregation,” PJM Market Implementation Committee Briefs: June 6, 2018.)

Independent Market Monitor Joe Bowring questioned staff’s planned procedure for day-ahead notification because PJM continues to use demand response as an emergency resource.

“Typically, you don’t have a day’s notice; you have an emergency,” he said.

PJM’s Pete Langbein said grid operators will continue to dispatch DR as necessary during emergencies but will use this approach “if we have the luxury” of receiving notification the day before. He said operators will continue the practice of dispatching resources with registration-level granularity, which is usually limited to a single customer.

Credit Requirements

Stakeholders resoundingly endorsed PJM’s recommended revisions to the financial transmission rights credit policy, rejecting both a pre-existing alternative and a proposal offered by DC Energy’s Bruce Bleiweis during discussion. Stakeholders also indicated that they strongly preferred the endorsed revisions to the status quo in a sector-weighted vote, with 193 (or 0.92) voting in favor of the changes, with 16 opposed and 11 abstentions. The votes had an endorsement threshold of 0.5.

PJM wants to implement a per-megawatt-hour minimum credit requirement to address potentially large FTR positions that have little or no credit requirements. (See “DC Energy FTR Credit Policy Complaint to FERC,” PJM Market Implementation Committee Briefs: June 6, 2018.)

The endorsed proposal, which PJM recommended, would implement a 10-cent/MWh minimum monthly credit requirement applicable to both FTR bids submitted in auctions and cleared positions held in FTR portfolios. It received 208 votes (0.95) in favor, with 12 opposed and 21 abstentions.

The alternative proposal, which would implement a 5-cent/MWh requirement, received 77 votes (0.35) in favor, with 141 opposed and 15 abstentions.

DC Energy’s proposal received 51 votes (0.44) in favor, with 66 opposed and 119 abstentions. The proposal would have required the credit calculation to account for profits or losses in the market. For example, if PJM calculated a $10 credit requirement and the market participant gained $2 in profit from market positions, the participant would submit $8 in collateral to the RTO. If the participant lost $2, collateral necessary would increase to $12.

Bleiweis said he was supportive of the endorsed proposal but hoped for additional revisions. That his proposal progressed to a vote was itself dramatic, as it appeared to have died without being seconded. However, it was announced during voting on the endorsed proposal that Panda Power Funds’ Bob O’Connell had seconded the proposal from the phone, and it was allowed to receive a vote.

PJM’s Bridgid Cummings also reviewed the results of a Credit Subcommittee poll on additional proposals the subcommittee hadn’t endorsed, which found 2% support for a 1- to 5-cent minimum monthly credit requirement on a declining tiered scale based on megawatt-hour volume; 25% support for a $50 million cap on the total minimum monthly credit requirement; 20% support for a $100,000 deductible applicable to the current undiversified adder; and 28% support for status quo.

Balancing Ratio

For anyone confused by the complexities of balancing ratio calculations and performance assessment intervals (PAIs), staff and stakeholders have agreed to develop a presentation for next month’s meeting to compare the proposals on the issue. Currently, there are four.

PJM’s Pat Bruno provided a first review of two proposals developed by staff to revise the method for calculating annual balancing ratios. (See “Balancing Ratio Recalculation,” PJM Market Implementation Committee Briefs: June 6, 2018.)

Bruno said the first proposal was “straightforward” because it would calculate the balancing ratio using the average balancing ratios from the three delivery years that immediately precede the base residual auction or, for years that don’t have at least 30 hours of PAIs, supplementing the actual number of PAIs with estimated balancing ratios calculated during the intervals of the highest RTO peak loads that do not overlap a PAI. PAIs are five minutes apiece.

The second proposal would estimate the number of PAIs expected in the delivery year using the past three years of data, but floored at five hours for calculating the default market seller offer cap (MSOC) and 15 hours for calculating the nonperformance charge rate in Capacity Performance. The proposals would include revisions to the formulas for the nonperformance charge and the MSOC.

Exelon’s Jason Barker noted the proposed MSOC formula wouldn’t always arrive at net cost of new entry multiplied by the balancing ratio if different assumptions for the expected number of penalty hours is employed.

He argued that FERC specifically approved a formula that uses a single assumption about the expected penalty hours and pegs the default offer cap to net CONE. Bruno contended that the commission approved the methodology to arrive at the formula rather than the result itself.

In response to a question by Barker, Bruno said staff “didn’t really have a formulaic approach” for choosing the 15-hour floor for the nonperformance charge, and that they “looked at the data” and came up with “what we thought was a reasonable estimate.”

David Mabry, representing the PJM Industrial Customer Coalition, called it “a balanced proposal.”

Additional proposals from Exelon and Calpine differed with PJM on the PAI calculations for the MSOC and nonperformance charge rate formulas. Calpine’s would floor both at 10 hours and calculate a number based on the past 10 years of data. Exelon’s would use a probabilistic model to look forward. Both would keep constant the number of PAIs used in the two formulas.

Energy Market Caps

PJM’s Susan Kenney reviewed staff’s two-phase plan for addressing issues with Order 831. The proposal offers a short-term fix to address conflicts in PJM’s governing documents, along with a more comprehensive long-term solution. The long-term solution will be less cumbersome than the short-term fix but will require more time to develop. The updated proposal comes after PJM’s short-term proposal failed to receive stakeholder endorsement at the May meeting of the Markets and Reliability Committee. (See “Offer Cap Revisions Stalled Again,” PJM Markets and Reliability Committee Briefs: May 24, 2018.)

PJM is hoping to have the long-term solution ready by Nov. 1, so it should be available several weeks ahead of that so stakeholders can familiarize themselves with the changes prior to implementation, Kenney said.

She outlined some “risks” of the short-term proposal, which would cap all offers at $1,000/MWh by default and allow higher offers to submit a request for verification. The Monitor’s Catherine Tyler said those concerns are the basis for the Monitor’s preference for the “switch to cost” method, which would provide generators the option to exclude price schedules from dispatch. Otherwise, generators can request the ability to submit price-based offers in line with verified cost-based offers, but they are then on the hook to ensure price-based offers at each segment remain compliant with verified cost-based offer caps.

The long-term solution will automate the process.

VRR Curve Update

PJM’s Jeff Bastian reviewed the RTO’s proposed revisions for its quadrennial review of the variable resource requirement (VRR) curve in its Reliability Pricing Model capacity market construct, including a table comparing how the different revisions would impact the gross CONE calculation.

Based on an analysis it commissioned from the Brattle Group, PJM is recommending switching its reference resource from the Frame F to the Frame H of a General Electric turbine and updating the unit heat rate, Bastian said. The frame switch would reduce the net CONE from $405/MW-day of unforced capacity to $308. Some generators have argued against the recommendation. (See Factors in New PJM VRR Curve Still in Question.)

In the table, PJM estimated the gross CONE for 2019 by escalating the 2018 figure by nearly 3%. Bastian said PJM believes it’s important to get the 10% cost adder into the dispatch cost of the reference resource. Overall, PJM’s recommendations would reduce the energy and ancillary service offset by 22% from $72/MW-day of unforced capacity to $56 and reduce the net CONE from $333 to $251.

PJM is targeting Oct. 12 to file for FERC approval, and seeking endorsement votes by the Markets and Reliability Committee on Aug. 23 and the Members Committee during an Aug. 31 teleconference.

VOM Update

As time runs out to square away where generators can recover variable operations and maintenance (VOM) costs, stakeholders remain separated on the issue. PJM is attempting to resolve those differences prior to concluding its quadrennial review of the VRR curve since the costs could be recoverable in either the capacity or the energy market.

There are four proposals set for a vote at the July meeting of the MRC, and while the voting order on the proposals is set, a recent submission from Orange and Rockland Utilities/Rockland Electric Co. has threatened to upset the likely voting. A proposal from American Electric Power that allows use of default U.S. Energy Information Administration calculations will be up first, followed by PJM’s proposal, a proposal from the Monitor and finally RECO’s offering.

AEP’s Brock Ondayko walked through the default proposal, which includes a friendly amendment introduced at the June meeting of the MRC that would prohibit units that failed to clear in the year’s capacity auction from including fixed costs in their energy offers. (See “Variable Operations & Maintenance Packages,” PJM MRC/MC Briefs: June 21, 2018.)

PJM’s Melissa Pilong reviewed the RTO’s package, which remains unchanged from past discussions. It’s the only proposal that would allow units to include fixed costs in their energy offers if they failed to clear in the year’s capacity auction.

Tyler presented the Monitor’s proposal, which would limit costs allowed in energy offers to short-run marginal costs.

“The governing documents are just not clear on these costs and only the IMM package would clean up the definitions,” she said.

Stakeholders have been reluctant to support the Monitor’s proposal because of concern about the definition.

“Part of our disagreement comes down to the definition of short-run marginal costs,” Pratzon said.

RECO’s Brian Wilkie said his proposal was meant to strike a compromise between the generator-friendly and load-friendly proposals to ensure that stakeholders wouldn’t be stuck with the status quo if coalitions stood their ground and those proposals failed to win endorsement. RECO’s proposal would allow generators to recover VOM costs up to limits that would be posted into Manual 15. Almost all unit types would be capped at $3.50/MWh for the costs. Sub- and super-critical coal and biomass would be capped at $4/MWh; nuclear at $3/MWh; and wind, solar and hydro at $0/MWh.

“We agree with the IMM’s definition of VOM is the simplest way to put it,” Wilkie said.

He said PJM staff told him there could be “exponential” cost increases for load if either the PJM or AEP proposal is implemented and later combined with the fast-start or convex hull revisions being considered in PJM’s Energy Price Formation Senior Task Force. (See PJM Board Seeks Reserve Pricing Changes for Winter.)

Generation representatives criticized Wilkie’s use of the term “exponential,” arguing that characterization was validated by estimates. Gary Greiner of Public Service Electric and Gas said it’s unfair to group in various issues when considering isolated proposals.

“I guess that depends on what you throw into the toy box,” he said. “The proper way to do it is to look at this issue [individually] and see what impacts it would have on price.”

“Exponential implies a big change,” Barker said. “To date, I don’t know what that value is.”

The Monitor supported the proposal, along with Mabry and Greg Poulos, executive director of the Consumer Advocates of the PJM States (CAPS).

“It’s not our proposal,” Tyler said of RECO’s caps, but “we believe it is better than the status quo.”

PJM attorney Chenchao Lu expressed concern about whether it would be permissible to ask FERC to approve rules that would potentially cap cost recovery below actual operating costs. Wilkie had said earlier that he was not an attorney and therefore wasn’t sure whether FERC would accept the proposal.

Wilkie said he was willing to revise the proposal to incorporate feedback from generators. Greiner had noted the changes could create a “cycling nightmare for our ops people,” and Wilkie said he would consider how to address the concerns. Pratzon said more discussion might be necessary.

Wilkie agreed to let PJM know on Thursday — before the agenda is published for the July meeting of the MRC — whether they have received much engagement on their proposal. PJM will decide, depending on that update, whether to put the issue for a vote on the agenda.

Must-offer Revisions

Bruno presented a proposal on revising the rules for what units must offer into capacity auctions. The proposal addresses many of the concerns Exelon expressed when it proposed investigating the issue. (See “Exelon-backed Analyses Approved,” PJM Market Implementation Committee Briefs: March 7, 2018.)

Bowring criticized the proposal, specifically noting his concern that this could allow hoarding of capacity injection rights and block new entry when a unit is uneconomic. He said units should offer their costs in the auction and if they do not clear, the market message is that the units are not needed and not wanted by the market at that price.

— Rory D. Sweeney

July 16, 2018

PJM Operating Committee Briefs: July 10, 2018

VALLEY FORGE, Pa. — Grid operators faced several high load forecasts and hot weather alerts last month but never had to take emergency procedures, PJM’s Chris Pilong told attendees at last week’s Operating Committee meeting.

Pilong reviewed five hot-weather alerts for the month, along with several that were called for early July, in his system operations report. On July 2, for example, the load forecast called for a roughly 152-GW peak, but several factors mitigated the actual demand to about 140 GW, he said, including showers in the RTO’s western region and the fact that date fell on a Monday going into a holiday.

“We were on track for 152 [GW]. Had we gotten there, we would have been OK, but that western rain did bring the loads down,” he said.

PJM’s Stephanie Monzon detailed the operations report for June, which included three spin events. David Mabry, who represents the PJM Industrial Customers Coalition, requested more detail on a June 4 event, caused by a trip loss of 1,210 MW from Unit 1 of the Braidwood nuclear plant. He said it seemed “unusual” the event was resolved in six minutes when the estimate for Tier 1 response was more than 1,000 MW higher than what actually responded. Monzon agreed to investigate and report back.

Real-time 30-minute Reserves

Stakeholders endorsed PJM’s proposal to create a real-time 30-minute reserve product along with a methodology for how to calculate a procurement objective for each year. PJM’s Vince Stefanowicz reviewed the proposal, which has remained consistent throughout the stakeholder process. (See “30-Minute Reserves Target Set,” PJM Operating Committee Briefs: May 1, 2018.)

Mabry urged staff to send the proposal to the Energy Price Formation Senior Task Force, which is focused on revisions to PJM’s energy market. He said working through it there would help him become more “comfortable” with the methodology and the justifications for the target procurement, which would be 3,784 MW for 2018.

While the proposal was endorsed with no objections, there were 48 abstentions that included Mabry’s coalition.

Black Start Fuel Assurance

PJM’s Glen Boyle outlined revisions to the issue charge for setting black start fuel requirements, which include pushing the anticipated start date for the stakeholder group back a month to September.

Staff also added “critical non-fuel consumables” to the list of requirements to develop and minimum tank suction level to compensation-related issues to hash out.

Load Shed Details

Pilong presented a detailed review of the May 29 load shed event in northwest Indiana. The event was short and the impact localized, but it was the first such event that might trigger the financial penalties implemented as part of Capacity Performance.

The incident analysis found that the Twin Branch-Jackson Road 138-kV line and the Jackson Road 345/138-kV transformer 3 tripped after the line contacted a tree around 12:30 p.m. Five other lines in the area were already offline for maintenance.

A contingency analysis found that if the South Bend-Twin Branch line or transformers at Twin Branch also went out, the Edison-Kankakee line might trip offline and potentially cause a cascading failure. To address this, PJM recalled two of the lines on planned outages and ordered the local utility, American Electric Power, to shed approximately 21 MW of load to relieve the Edison-Kankakee line.

About 15 minutes later, the transformer was restored to service, allowing PJM to end the load shed. The recalled lines didn’t come back online for at least another 90 minutes. The tripped line was back online slightly less than 12 hours after it tripped.

GT Power Group’s Dave Pratzon asked about a sixth line in the area that was also on a planned outage. Pilong said recalling it wouldn’t have relieved the situation because it’s on the western side of the Edison-Kankakee line and the issue was on power flowing from west to east, so it couldn’t have pushed power into the area.

“There were a lot of outages this day. That [one] didn’t have any impact,” Pilong said.

He said one of the lines had been on a planned outage since April 18, while the two lines that were recalled had started outages that day. Because the situation was resolved so quickly, operators never got the point of dispatching DR but might have if the situation had persisted, he said.

Regulation Update

PJM’s Eric Endress reviewed performance of the RTO’s regulation signal, which changed in January 2017. FERC has since rejected the compensation portion of PJM’s plan to revise its regulation market, but the signal has remained the same. (See FERC Postpones Tech Conference on PJM Regulation Market.)

Endress showed that the marginal benefits factor, which PJM has argued to use and FERC has repeatedly denied, has stayed fairly consistent since May 2017, ranging between 1.01 and 1.33 each month.

Combustion turbines have consistently been top performers in both the slower, sustained-output RegA signal and the faster, dynamic RegD signal. Hydro was also a top RegA performer, followed by demand response and steam. Storage was a top RegD performer, followed by DR and hydro.

RegD units were pegged for more than 30 minutes no more than four times in a given month, reaching that rate only in March 2017. The RegD signal is meant to peg unit response for short durations. RegA resources, which don’t have response limitations, were generally pegged more often and for longer periods.

Resilience

PJM’s Dean Manno announced that the RTO plans to substantially expand its procedures for addressing cyberattacks. The details came as part of a presentation on operational changes planned to increase system resilience, which include a procedure to freeze system changes and requiring transmission owners to inform PJM when they disable the auto-reclose feature on any transmission facilities.

The procedures will address responses to cyberattacks against PJM or its members, as well as the telecommunications network between them.

— Rory D. Sweeney

July 16, 2018

FERC OKs Dominion’s Proposed Purchase of SCANA

By Peter Key

FERC last week authorized Dominion Energy’s proposed acquisition of SCANA and its South Carolina Electric & Gas subsidiary, saying the transaction was consistent with the public interest (EC18-60).

ferc dominion scana — Dominion CEO Tom Farrell II

“We are pleased by the FERC’s considered and timely action,” Dominion Energy CEO Thomas Farrell II said in a statement. “We will continue working toward achieving the other required regulatory approvals and completing our transaction by the end of this year.”

The deal has been approved by the Georgia Public Service Commission and federal antitrust regulators. It still requires approval by SCANA shareholders, the North Carolina and South Carolina public service commissions, and the Nuclear Regulatory Commission.

Dominion offered to buy SCANA on Jan. 3 for $7.9 billion in stock and the assumption of $6.7 billion in SCANA debt. (See Dominion to Buy Distressed SCANA for $8B.) SCANA became an acquisition target after its failed attempt to add two reactors to the V.C. Summer nuclear plant. The company and its partner on the project, Santee Cooper, which is owned by the state of South Carolina, spent $9 billion on the expansion before pulling the plug on it last summer.

The decision created a firestorm in South Carolina, where SCE&G and Santee Cooper ratepayers have been shouldering the project’s cost. The state late last month enacted a law directing the Public Service Commission to cut SCE&G’s rates by an amount that would cover nearly all the portion of the rates that go to covering the failed nuclear project’s cost. SCE&G responded with a lawsuit challenging the law’s constitutionality in federal court.

SCE&G has been sued by its customers over the project, which is being investigated by the FBI, the South Carolina State Law Enforcement Division and the Securities and Exchange Commission, none of which has filed any charges.

SCANA said Friday it has added two independent directors to its board and appointed them to a Special Litigation Committee charged with investigating claims alleged against some of its current and former directors in shareholder lawsuits against it in federal and South Carolina courts.

July 16, 2018

FERC: MISO Merchant HVDC Procedures Incomplete

By Amanda Durish Cook

MISO’s proposal to allow merchant HVDC lines to connect to its system is incomplete, FERC informed the RTO last week in a deficiency letter.

In its filing with the commission, MISO said it based the proposed merchant agreement on its existing generator interconnection agreement and procedures, but FERC on July 12 asked it to explain why it was appropriate to do so — among other questions (ER18-1410). The commission gave MISO 30 days to file a response.

miso merchant hvdc — HVDC lines in MISO footprint | *MISO*

The RTO’s proposal involves treating merchant HVDC as transmission rather than generation, and requires merchant developers to acquire MISO injection rights or a precertification that the system will be able to reliably manage the capacity and energy from proposed lines at the point of connection. (See MISO Plan Provides Tx Treatment for HVDC Lines.)

FERC asked MISO why the timeline and termination provisions for the proposed agreement differ from those in the GIA, given the RTO’s claim that the former is based on the latter.

The proposed HVDC agreement stipulates that if injection rights are not converted to external network resource interconnection service within three years of a line’s commercial operation date, MISO will terminate interconnection service. With the RTO’s GIA — which doesn’t include the concept of injection rights — an interconnection customer can extend its commercial operating date for up to three years without risking queue withdrawal. MISO had said the termination provision matched that of its GIA because in both cases, the “underlying agreement may be terminated if commercial operation is not achieved within three years of the commercial operation date.”

FERC also asked MISO to clarify whether it plans to simultaneously update its merchant HVDC connection agreement when it proposes to make changes to its GIA.

The HVDC agreement also includes a provision stating that transmission owners will be able to review any modifications to a connection facility that affects them, but FERC asked MISO how it would move forward with a HVDC connection request if a party to the connection agreement does not accept a modification.

The commission also asked MISO to describe the processes behind examining injection rights and its proposed merchant HVDC connection service study.

July 16, 2018

SPP Briefs: Week of July 9, 2018

SPP’s Market Monitoring Unit said last week that energy prices averaged about $23/MWh in the spring, despite higher loads.

The MMU’s quarterly State of the Market report also highlighted the recent merger between Westar Energy and Great Plains Energy, the parent company of Kansas City Power and Light, although its completion happened outside the report’s March-May range. (See Westar-Great Plains Merger Wins Final Approval.)

The Monitor said the combined company would have accounted for 19.2% of total system load over the period, making it the largest energy user in SPP’s market footprint. Additional information will likely be included in the summer report, MMU Executive Director Keith Collins said.

The report indicates that spring hourly average load was up 8% from 2017 — and 14% for May alone — as a result of abnormally high temperatures. Average day-ahead prices increased 13% to $23/MWh over last spring, while average real-time prices gained 10% to $22/MWh.

spp mmu regional cost allocation — | *SPP MMU*

Spring’s average monthly gas price at the Panhandle Eastern hub was $2.14/MMBtu, down from $2.70/MMBtu in 2017. Gas prices in spring 2016 were $1.68/MMBtu.

Coal-fired resources continued to account for a smaller share of the RTO’s energy production at 37%. Wind resources accounted for almost 29% of generation, with nameplate wind capacity increasing to 17.7 GW by June, up from 12.8 GW at the end of May 2016.

The Monitor said occurrences of negative price intervals decreased from the winter period and last spring. This spring, prices were negative in just over 5% of real-time intervals, and just under 2% of day-ahead hours.

According to the report, overall congestion in the footprint has declined, with real-time intervals with a breached or binding flowgate dropping from 40% last spring to 20% this spring.

The Monitor recently conducted a study of day-ahead market congestion and auction revenue rights bidding behavior following complaints by market participants that were unable to obtain hedges in the ARR process. The study led to three main conclusions, the MMU said: Successful ARR nominations have decreased; the market’s overall need for hedges has increased; and nomination behavior has remained relatively consistent.

The growth in day-ahead congestion correlates with the overall increase in wind production, the Monitor said. It said the 28 GW of additional wind capacity planned in the generation interconnection queue will likely increase the need for hedging.

The MMU recommends “further review and consideration of the auction revenue right process by the RTO and stakeholders” going forward. It will host a webinar July 25 to discuss the spring report.

SPP Preps AECI Seams Project for 2nd Crack at FERC

David Kelley, SPP’s director of seams and market design, told the Seams Steering Committee on Friday that the RTO has performed additional analysis in order to gain FERC approval of a seams project with Missouri-based Associated Electric Cooperative Inc.

Kelley said staff intends to present “new evidence” on regional cost allocation to FERC in July or August. He said SPP will be presenting the avoided costs of regional projects — a metric the commission has already approved — and the reduced regional costs of day-ahead market uplift.

“We’re thinking we’re in really good shape,” said Kelley, who last met with FERC on July 12. “It’s been a little challenging to figure out a way to do regional cost allocation for a single project.”

SPP is trying to reverse FERC’s October rejection of cost allocation for the Morgan project, one of two potential seams projects with AECI. It consists of a new 345/161-kV transformer at AECI’s Morgan Substation near Springfield and the rebuild of a 161-kV line.

The other project, a 345-kV, 50-MVAR reactor at City Utilities of Springfield’s existing Brookline substation, has been included in SPP’s Integrated Transmission Planning Near-Term assessment that will be presented to the Markets and Operations Policy Committee and Board of Directors/Members Committee this month.

The Brookline project’s costs will be allocated under SPP’s normal processes, but Kelley said AECI wants to pick up its share. The two projects have a combined estimated engineering and construction cost of more than $18 million.

The SSC agreed to take a crack at developing a Tariff mechanism to allocate costs for seams projects. With no such mechanism in place, SPP has to take seams projects to FERC on a case-by-case basis.

SPP, MISO Discuss Jan. 17 ‘Big Chill’

The Regional Transfers Operating Committee (RTOC), a six-person committee that includes two representatives from SPP and MISO, met twice in June to discuss what Kelley called “The Big Chill,” the Jan. 17 event when unusually frigid weather forced MISO to initiate a maximum generation alert for its South region.

MISO exceeded its 3,000-MW regional dispatch limit on transfers between its North and South regions over the SPP transmission system for an hour and was forced to make emergency purchases from Southern Co.

Kelley said the RTOC reviewed the use of NERC’s transmission loading relief process during the event and processes for acquiring and delivering emergency energy. He said improved communications will be the key to preventing a recurrence and improving operations and reliability.

“Situations like Jan. 17 don’t just show up without advance warning,” he said. “We and MISO had multiple warnings days before. We feel, and MISO feels, we can do a better job of communicating in advance.”

The RTOC is an operating committee created by a 2016 settlement agreement between SPP, MISO, Southern and the Tennessee Valley Authority. (See SPP, MISO Reach Deal to End Transmission Dispute.) It will meet again in late July.

M2M Generates $397,428 in Payments to SPP in May

Market-to-market (M2M) payments between SPP and MISO dropped to $397,428 in May, the lowest amount since last August. However, it was also the 10th straight month, and the 18th of the last 20, in which the payments have been in SPP’s favor.

The RTO has incurred $53.7 million in M2M payments from MISO since the two began the process in March 2015.

Current and temporary flowgates were binding for 254 hours in May, SPP staff told the SSC.

— Tom Kleckner

July 16, 2018

MISO Weighing Feedback to Storage Proposal

By Amanda Durish Cook

MISO last week outlined the range of stakeholder feedback it has received since revealing its straw proposal for energy storage resources (ESRs) in June.

The RTO’s proposal for complying with FERC Order 841 called for ESRs participating under four modes of commitment: charging, discharging, continuous operations and outage/offline. When in online mode, storage would be treated as must-run resources. (See MISO Offers Straw Storage Proposal to Meet Order 841.)

At a July 12 Market Subcommittee meeting, MISO said that stakeholders have stressed the importance of coordination with distribution system providers and expressed concern that requiring hourly offers might limit storage’s flexibility. Others reminded the RTO that storage resources are not generation and said they should not be bound to a must-offer requirement. Some said storage should be treated like load-modifying resources while others said storage should be restricted to the ancillary services market, despite FERC’s requirement that it be allowed to provide capacity and energy.

Stakeholders asked how hybrid storage-and-renewable formats will fit under the proposal and requested optimized pumping and withdrawal options for pumped storage facilities. MISO dismissed the latter as beyond the scope of Order 841 but said it will meet with market participants to discuss ways to fully incorporate pumped storage into the market.

miso energy storage straw proposal — Vannoy | © *RTO Insider*

MISO Director of Market Design Kevin Vannoy said the RTO would return in August with more detail around the proposal and examples of how storage will function under the model. It will focus examples on non-market services, storage modeling, metering, commitment and dispatch rules, Vannoy said. Market clearing prices or LMPs will set emergency pricing for injecting and withdrawing during maximum generation events.

“There might be restoration payments when energy storage resources provide black start restoration from an event,” he added.

MISO also said it will rely on its existing ramp performance measures — excessive and deficient energy flagging and deployment failure penalties — to evaluate storage performance.

Vannoy said he’s gotten at least two requests for private meetings with MISO staff to discuss the straw proposal. While MISO isn’t opposed to setting up one-on-one meetings, he said, staff are busy working on Order 841 compliance and have limited time. He also said it may be best to raise storage issues and suggestions in public meetings.

“We’re not necessarily looking to facilitate private discussions,” Vannoy said, urging stakeholders to bring their storage questions and recommendations to the Resource Adequacy, Market and Reliability subcommittees.

Vannoy said while MISO usually doesn’t solicit extensive stakeholder feedback on FERC compliance directives, Order 841 compliance is a “special case” that warrants more intensive stakeholder involvement, and MISO plans to collect more feedback through summer.

“I don’t think this is a pure vanilla compliance filing. It’s not where FERC says, ‘Do A, B and C,’ and we file A, B and C,” Vannoy said.

MISO will solicit feedback through fall while presenting more refined versions of the plan. It plans to have a draft compliance plan by mid-October. Its Tariff filing is due in December.

Storage Model on Old Platform

MISO plans to implement its new storage participation model before it replaces its current market platform with a more sophisticated modular system. Responding to the straw proposal, stakeholders asked that the RTO not make a storage participation model dependent on the new platform’s capabilities. Instead, they asked that MISO design the market platform with storage needs in mind.

Kevin Larson, MISO market and modeling director, said the RTO will continue to assess principal vendor General Electric’s performance on project deliverables and will evaluate alternate vendors through the end of 2019. MISO last month said GE was overly optimistic in its original timeline for the replacement, which may lead to delays and a small budget overrun. (See MISO Platform Replacement Risks Delay, Budget Overrun.)

“We’re in an evaluation phase with General Electric,” Larson said.

MISO reported in June that, as part of its multiyear market platform replacement, it had improved its day-ahead solve time by more than six minutes, about a 10% improvement. Larson said the additional headroom will allow for “select market enhancements while the new market system is being developed.”

Storage Capacity Accreditation

At the July 11 RASC meeting, MISO presented its proposal on how it will accredit storage capacity, another requirement of Order 841.

Senior Adviser of Capacity Market Administration Rick Kim said MISO is proposing to require that storage resources continuously discharge energy equivalent to their zonal resource credits committed in the Planning Resource Auction.

The continuous discharge would be subject to a minimum run time, either 24 hours or four hours for limited-use resources. Storage resources would also have to submit the generator verification test capacity (GVTC) data required of other planning resources. MISO would ask for a storage resource’s GVTC by Oct. 31, 2019, for the 2020/21 planning year capacity auction. The RTO said it would also want storage resources to provide documents to support the megawatt-hours of capacity they claim. MISO will apply default outage rates to determine unforced capacity calculations for storage resources that have less than a year of operational data.

Storage assets should also secure either firm transmission service or network resource interconnection service before offering as a capacity resource. If the storage resource is interconnected at the distribution level, the resource will be subject to coordination with the distribution provider, transmission owner and MISO.

Kim asked stakeholders for specific ideas on the calculations and tests for capacity accreditation.

July 16, 2018

MISO, SPP Loosen Interregional Project Requirements

By Amanda Durish Cook

MISO and SPP announced Friday they plan to relax barriers that have prevented them from agreeing to develop interregional projects.

The two RTOs will remove their $5 million cost threshold and joint modeling requirement for the projects, staff revealed during a July 13 conference call of the Interregional Planning Stakeholder Advisory Committee.

Removal of the $5 million cost standard will not affect other criteria, such as the 5% or higher benefit threshold for each RTO and the requirement that projects be in service within 10 years of approval, the RTOs said.

miso interregional projects reserve requirements — Lopez | © *RTO Insider*

Instead of creating a joint model, MISO and SPP will now leverage their existing regional planning models to evaluate interregional projects. Eliminating the joint model requirement will shorten a lengthy study process and allow the RTOs to examine more potential projects, they said. MISO and PJM removed a similar requirement almost two years ago in response to a FERC complaint filed by Northern Indiana Public Service Co. (See FERC Orders Changes to MISO-PJM Interregional Planning.)

MISO Planning Adviser Davey Lopez said removing the joint model will eliminate inconsistencies between the joint model and the RTOs’ respective regional models.

“We’re both doing very robust regional reviews,” SPP Interregional Coordinator Adam Bell added.

Concerns over Cost Allocation

Bell said stakeholders were split over removal of the joint model; while some wanted the triple hurdle eliminated, others were concerned about equitable cost allocation absent a joint model. Had MISO and SPP approved an interregional project, the joint model would have determined each RTO’s share of the cost.

The RTOs said they will calculate adjusted production costs and avoided costs for all interregional projects using their regional calculations of benefits. They have pledged to provide interregional cost allocation examples to address stakeholders’ concerns about inequities and explore the possibility of adding a market-to-market benefit metric.

The Wind Coalition’s Steve Gaw stressed the need for the RTOs to develop an objective cost allocation plan rather than promising negotiations.

“For me, this isn’t sweeping things under the rug. This is sweeping things into a different room,” Gaw said. “If you’ve got two RTOs determining what their benefits are. … I think you have to have something that avoids you arguing over how the benefits are calculated in each of your regions.”

Other stakeholders also asked for a more specifics on cost allocation, and Lopez promised more discussion on the issue during the August IPSAC meeting.

“This is a difficult conversation to have without examples in front of us,” Bell acknowledged. He assured stakeholders the RTOs only arrived at the decision to remove the joint model after substantial discussion about how it would affect project cost allocation.

The two RTOs agreed in February not to pursue a 2018 coordinated system plan, which could have resulted in an interregional project, instead promising to examine their joint planning process and seek ways to improve interregional coordination.

The two have completed two coordinated system plan studies to date, but neither has resulted in a viable interregional project. During their 2016/17 study, the RTOs identified three possible projects, but all were disqualified by the $5 million cost requirement, Lopez said.

“I think the studies have shown us that there are some barriers,” Lopez said.

Bell said MISO and SPP will likely return to the IPSAC next month to seek approval to revise their joint operating agreement, which will be filed by the end of the year.

Bell said the RTOs hope to produce another coordinated system plan study in 2019, although filing timelines could interfere with the goal.

No Dent in MISO 345-kV Threshold

The JOA revisions will not include a provision to lower MISO’s requirement that market efficiency interregional projects be at least 345 kV.

“SPP continues to encourage MISO to pursue lowering its current 345-kV voltage threshold for SPP-MISO interregional projects,” SPP said. However, MISO said it continues to view the voltage threshold as a strictly regional issue, not up for discussion in the IPSAC because there is no voltage threshold criteria in the JOA. Lopez said MISO’s Regional Expansion Criteria and Benefits Working Group will continue to explore the effects of lowering the threshold.

MISO last month said it will revise its regional — not interregional — cost-sharing practices for market efficiency interregional projects with SPP in order to match its process for PJM seams projects, lowering the voltage threshold to 100 kV over some stakeholders’ objections. (See MISO to Lower SPP Interregional Project Thresholds.) MISO lowered its 345-kV threshold for MISO-PJM projects to 100 kV in 2016 under FERC’s orders.

The MISO-SPP plan also excludes a requirement that prospective interregional projects that were evaluated but didn’t pass a cost-benefit ratio be reviewed and voted on by both boards of directors. MISO said requiring such a move was unnecessary: Interregional projects that pass all criteria would still need to be approved by the boards.

July 15, 2018

NYPSC: Offshore Wind ‘Ready for Prime Time’

By Michael Kuser

ALBANY, N.Y. — The New York Public Service Commission on Thursday voted unanimously to authorize state agencies to procure 800 MW of offshore wind energy by next year, the first phase of a plan to develop 2,400 MW by 2030.

offshore wind nypsc — Rhodes | © *RTO Insider*

Offshore wind is “viable, valuable and ready for prime time,” PSC Chair John B. Rhodes said.

Under the commission’s July 12 order (18-E-0071), the New York State Energy Research and Development Authority will issue a solicitation for 800 MW of offshore wind in the fourth quarter, in consultation with the New York Power Authority and the Long Island Power Authority.

NYSERDA will announce the award in the second quarter of 2019 and, if needed, issue a second solicitation next year to meet the 800-MW goal. The agency will hold a technical conference on the solicitation process from July 23 1-3 p.m. at the Department of Public Service’s office at 90 Church Street in New York City; it will also be available via webinar.

High-Stakes Race

Gov. Andrew Cuomo’s office said that offshore wind will not only help achieve the state’s Clean Energy Standard goal of obtaining 50% of electricity from renewables by 2030 but also will support nearly 5,000 new jobs, nearly 2,000 of them long-term career opportunities in operations and maintenance.

“We’re in a race right now with our fellow states along the Eastern seaboard to get these staging and fabrication facilities for this new industry built in our state, and of course they want it in their states,” Commissioner Gregg C. Sayre said. “I think it would be appropriate for us to get moving quickly and win this one for New York.” (See Competition, Cooperation and Costs the Talk at OSW Conference.)

The U.S. Department of Energy in June awarded a $18.5 million grant to NYSERDA to lead a nationwide research and development consortium for the offshore wind industry, with the state to match the federal funds.

In May, Massachusetts awarded a contract for 800 MW of offshore wind and Rhode Island agreed to procure 400 MW. (See Gov. Signs NJ Nuke Subsidy, Renewables Bills.)

Massachusetts officials hope to develop supply chains for the nascent industry in the Port of New Bedford but will have to avoid interfering with fishing operations there, the No. 1 fishing port in the U.S. (See Overheard at ISO-NE Consumer Liaison Group Meeting.)

According to the environmental impact statement issued by NYSERDA in June, the New York offshore wind projects will affect only 3% of the state’s fishing grounds.

Bidding Details

David G. Drexler, DPS managing attorney, told the commission that NYSERDA will solicit two separate bids from each participating bidder. One would be for a fixed-price offshore wind renewable energy certificate (OREC), while the other would be based on a variable OREC tied to an index.

To contain costs, NYSERDA will reject bids higher than a confidential “upset price,” like the method used in Renewable Energy Standard Tier 1 procurements, Drexler said.

“NYSERDA … would at all times have the authority to reject any and all bids, taking into account not only the benchmark upset price but also recent auctions and market conditions,” Drexler said.

NYSERDA will rank bids based on the following weights price (70%); economic benefits (20%); and project viability (10%). The agency will have discretion in fixing the specific terms of the contract, which will run for 20 to 25 years.

Transmission Component

The Phase 1 order for the initial 800 MW makes the generation developer responsible for its own radial transmission to shore, calling it “the most easily implementable and feasible option for jump-starting offshore wind development in New York.”

NYSERDA recommended that backbone transmission and independent ownership be reserved for consideration in Phase 2, to procure the remainder of the 2,400 MW total. It noted that the Bureau of Ocean Energy Management has sold only one wind energy lease directly off New York — Equinor’s site, which is capable of hosting approximately 1,000 MW. The agency said a shared radial system would create unnecessary risks of stranded assets and provide limited cost advantages.

Equinor and Vineyard Wind supported the direct generator lead approach in the early stages of development, arguing in joint comments that “requiring a separate transmission provider would increase project uncertainty and the risk of delay.”

The Green Building Council, the Sustainability Institute and transmission developer Anbaric argued that the first phase should include soliciting bids to develop an “Open Access Offshore Transmission” system, with Anbaric saying it would provide more information about the best options and potentially reduce the costs of the procurement.

Anbaric said that requiring direct generator leads would lead to a piecemeal approach and would not optimize the interconnection, potentially increasing costs for later stages of development. The Green Building Council and the Sustainability Institute concurred with Anbaric’s argument, saying that the generator lead approach would result in a highly inefficient array of separate transmission cables.

Central Hudson Gas & Electric, Consolidated Edison, New York State Electric and Gas, National Grid, Orange and Rockland Utilities, and Rochester Gas & Electric, filing as “Joint Utilities,” also argued that the state should immediately consider developing a transmission backbone and optimizing onshore interconnection locations. They said utility ownership of the transmission portion could produce substantial ratepayer savings. NYPA and New York City also urged that “a coordinated approach to transmission should be initiated immediately,” with NYPA adding it was prepared to assist in the effort.

“Anbaric remains eager to deliver offshore wind to the New York onshore grid quickly and economically,” Anbaric CEO Edward Krapels said in a statement Friday. “We will intensify our development of our New York OceanGrid and look forward to working with generation companies to link the first 800 MW of offshore wind to the New York state grid.”

Cryptocurrency Tariff Change

The PSC also approved new electricity rates for an upstate utility, Massena Electric Department, that will allow high-density load customers, such as cryptocurrency companies, to qualify for service under an individual service agreement.

“As part of our continuing effort to balance the needs of existing customers with the need to attract new companies, we must ensure that business customers pay a fair price for the electricity that they consume,” Rhodes said. “However, given the abundance of low-cost electricity in upstate New York, there is an opportunity to serve the needs of existing customers and to encourage economic development in the region.”

The commission’s order (18-E-0211) said that the individual service agreement tariff includes provisions to protect customers from increased supply costs resulting from the new service.

The program will apply to customers who have a maximum demand of at least 300 kW.

The new rates become effective July 17.

Low-income CDG Initiatives

The commission also adopted three measures to enhance the ability of low-income residents to participate in community distributed generation (CDG) programs: a bill discount pledge program; an income verification service; and a loss reserve fund (15-E-0082).

CDG projects are generating facilities located behind a nonresidential host meter coupled with a group of off-takers who receive bill credits based on the generation of that facility. New York defines low income as at or below 60% of the state median income.

Public funds will be held in reserve to cover losses that CDG project owners or their lenders may incur if low-income subscribers default on or terminate their subscriptions at a higher rate than other customers. DPS staff reported that “a relatively modest amount could provide surety for hundreds or even thousands of subscriptions” but did not define the amount.

Con Ed Smart Solutions Program

The commission approved, with modification, Con Ed’s request for a Smart Solutions Program, which included an enhanced gas energy efficiency program, a new gas demand response program, a new “Gas Innovation” program to encourage renewable alternatives to natural gas heating technologies, and a new market solicitation for non-pipeline solutions.

The order (17-G-0606) established criteria for continued development of the gas innovation program and denied the company’s request “to recover costs associated with parallel pipeline development efforts, thereby maintaining customer protections associated with unsuccessful pipeline development projects.”

The commission said Con Ed’s proposed gas DR program and non-pipeline proposal both “require further information from the company, input from stakeholders, and review from staff, and therefore, these components of the petition will not be considered in this order.”

July 15, 2018

NYISO Business Issues Committee Briefs: July 11, 2018

RENSSELAER, N.Y. — The NYISO Business Issues Committee voted Wednesday in favor of changing how the ISO reports on historic congestion, agreeing with management that the current process is resource-intensive and the resulting data underutilitized.

The BIC’s vote recommends that the Management Committee endorse the new process, which will require Tariff changes, to the Board of Directors.

Some of the congestion metrics required by the Tariff can be extracted from production security-constrained unit commitment (SCUC) runs but other data require rerunning SCUC to calculate the difference between the actual constrained grid and an unconstrained system.

“In our review of the site traffic, we realized there was not much use of the historic congestion data, so it’s of limited value in finding where congestion is on the system,” said Timothy Duffy, manager of economic planning. “We don’t believe there are any stakeholders using that data meaningfully.”

The proposed changes would eliminate the requirement to compare historic data to an unconstrained system.

The ISO will continue providing the historic metrics generated by SCUC: the value of demand congestion by constrained element or contingency; load and generator payments; and total load and generation scheduled.

It will add a new set of metrics: actual congestion rents by constraint, based on modeled flows and shadow prices.

Consolidated Edison’s Jane Quin representative abstained, saying it was premature to change the current reporting before the ISO has moved ahead with an economic transmission project to address congestion. Quin also said NYISO had not shown that the current Tariff requirement was unduly burdensome.

“Data we are pulling is not used in any settlement proceeding at all … and the data we are presently required to produce [that we would no longer produce] would not be of any value in planning an economic transmission project,” Duffy responded.

By the fourth quarter, the ISO will provide a report of historic congestion information relating to 2018 data utilizing the new metrics, broken into quarterly figures to mesh with quarterly reports beginning with 2019 data.

The data will continue to include actual demand ($) congestion by constrained element/contingency; load and generator payments ($); and total load and generation scheduled (MWh).

The reporting of historic congestion will incorporate actual congestion rents by constraint based on modeled flows and shadow prices.

Supplemental Resource Evaluation Improvements

NYISO has made progress in clarifying the minimum deliverability requirements for capacity from PJM, Rana Mukerji, ISO senior vice president for market structures, told the BIC.

ISO officials made presentations on the current Supplemental Resource Evaluation process and potential changes at joint meetings of the Installed Capacity Working Group and Market Issues Working Group in April and May. The ISO will present the market design proposal for process improvements at a joint ICAPWG/MIWG meeting July 26.

In his Broader Regional Markets Report, Mukerji also discussed NYISO’s efforts since 2016 to find an alternative approach for calculating locality exchange factors, which measure the capability of import-constrained regions relative to neighboring control areas.

NYISO has concluded the stability and transparency of the current approach is preferable to a probabilistic approach. The ISO has told stakeholders that further work on this effort is unlikely to yield an implementable methodology and continued investigation of a probabilistic approach is not warranted.

Mukerji also discussed Public Service Electric and Gas’ May 3 complaint against Consolidated Edison concerning two transmission lines, B3402 Hudson-to-Farragut (B line) and C3403 Marion-to-Farragut (C line). PSE&G alleged that underwater portions of the lines may have been permanently damaged and should be removed; however, the complaint acknowledged that a prior leak in the B line has been repaired.

NYISO filed a protest with FERC on June 6 indicating that removal of the lines would undermine resilience in both New Jersey and New York. The lines support grid resilience by providing opportunities for operational flexibility and emergency service in both the New York Control Area and PJM. The ISO’s protest noted that PSE&G’s complaint did not demonstrate that another leak from either of the lines was imminent and requested that the complaint be denied.

Public Website Redesign Update

NYISO Business Issues Committee Transmission Congestion — Draft Web Page | *NYISO*

Dave O’Brien, NYISO project manager, provided an update on the project to redesign the ISO’s public website.

The main objectives of the redesign are to improve the site navigation and search engine capability and implement a document library. The project will recategorize the most frequently accessed documents to make them easier to find.

O’Brien indicated that existing webpage and document links on www.nyiso.com would be changing because of the project, but he emphasized there would be no changes to existing mis.nyiso.com (OASIS) links. The project is targeting a launch by year-end.

BIC Elects Aaron Breidenbaugh Vice Chair

The BIC elected Aaron Breidenbaugh of energy management consulting firm Luthin Associates as its vice chair.

In addition to helping clients in procuring electricity and natural gas, Luthin also represents an unincorporated group of nonprofit institutional customers known as Consumer Power Advocates before the ISO, Public Service Commission and FERC.

“I’m happy to be able now to pay back into the NYISO governance structure,” Breidenbaugh said.

Energy Prices up 32% YoY

NYISO prices averaged $32.53/MWh in June, up from $28.78 in May and higher than $31.76 in the same month a year ago, Mukerji said.

Year-to-date monthly energy prices averaged $47.70/MWh through June, a 32% increase from $36.01 a year earlier. June’s average sendout was 445 GWh/day, higher than 397 GWh/day in May but down from 454 GWh/day a year earlier.

Transco Z6 hub natural gas prices averaged $2.45/MMBtu, down 4% from May but up 4.5% year-over-year.

Distillate prices dropped slightly compared to the previous month but were up 56.3% year-over-year. Jet Kerosene Gulf Coast and Ultra Low Sulfur No. 2 Diesel NY Harbor averaged $15.47/MMBtu and $15.32/MMBtu, respectively.

Total uplift costs and uplift per megawatt-hour rose from May, with the ISO’s local reliability share at 18 cents/MWh in June, lower than 22 cents the previous month, while the statewide share climbed from -17 cents/MWh to 12 cents.

Thunderstorm Alerts in New York City, which cause more conservative operations with reduced transmission transfer limits, cost 39 cents/MWh, up nearly fivefold from 8 cents in May.

— Michael Kuser

July 15, 2018

MISO Resource Adequacy Subcommittee Briefs: July 11, 2018

Responding to a stakeholder query, MISO staff have determined that it’s appropriate and possible for capacity import limits between local resource zones to bind in the RTO’s annual Planning Resource Auction.

MISO says that while, historically, the local clearing requirement has always bound before the CIL, it is “mathematically possible and reasonable” for CILs to be more restrictive than LCRs.

In this year’s capacity auction, MISO Local Resource Zone 3 in Iowa and Zone 6 in Indiana and Kentucky came closest to binding on their CIL, with Zone 3 coming within 938 MW and Zone 6 within 1,290 MW. MISO said the two zones could have bound if either the LCR or amount of exports varied.

capacity import limit resource adequacy — Sutton | © *RTO Insider*

During a July 11 Resource Adequacy Subcommittee meeting, MISO engineer Matt Sutton said it remains “highly unlikely that the capacity import limit” will bind in future capacity auctions, although that could be subject to multiple variables, such as transmission transfer capability.

“Though we’ve not seen a capacity import limit bind, it is a necessary parameter in the auction,” Sutton said.

Some stakeholders said they could not understand how CILs could bind before LCRs. WPPI Energy’s Steve Leovy said MISO staff have previously told him that CILs should not be enforced. Sutton said he thought MISO staff responsible for resource adequacy would disagree with that viewpoint.

Other stakeholders pointed out that market participants can replace capacity from other resources at midyear and that MISO must still ensure that import limits are not violated.

RTO staff committed to more discussion on the topic at future RASC meetings.

Stakeholders Quiet on Uncertain OMS-MISO Survey Results

Stakeholders offered muted reaction to this year’s annual resource adequacy survey by MISO and the Organization of MISO States, which predicts adequate reserves through 2019 but is less certain about thereafter.

“It’s important to keep in mind that this is a point-in-time forecast,” Ryan Westphal, MISO resource studies manager, told stakeholders.

Over the next five years, MISO’s footprint could see anything from a 7.5-GW surplus to a 4.5-GW shortfall. The results were less optimistic than last year’s survey, which showed MISO would have anywhere from 0.7 to 7.3 GW of excess resources in 2018-2022.

Westphal said the forecast is even more uncertain as MISO continues its conversion from coal generation to a mixture of gas, wind, solar and load-modifying resources.

Stakeholders asked why Zone 4 in Illinois experienced such a large dip in forecasted reserves year over year. Westphal attributed the decline to a combination of retirements, potential retirements and changes in generator performance.

Coalition of Midwest Power Producers’ Mark Volpe asked if MISO adjusts survey responses to reflect interzonal transactions that may go unreported. Westphal said MISO staff reach out to load-serving entities for clarification on some survey responses.

— Amanda Durish Cook