VALLEY FORGE, Pa. — Stakeholders at last week’s Planning Committee meeting endorsed PJM’s recommended load model for the 2018 reserve requirement study, which uses data from 2003 through 2012.
The study was adjusted to reflect the fact that load within the RTO’s footprint peaks during a different week than the area outside the footprint included in the model.
PJM selects a model for the study because the coincident peak distributions from the load forecast can’t be used directly in the PRISM modeling software, the RTO’s Patricio Rocha-Garrido said.
American Municipal Power’s Ryan Dolan asked why staff chose not to use the best-performing model from 2004 to 2012.
“We prefer more data to less data,” Rocha-Garrido replied, adding that the extra year “is a close second.”
“What’s the point of doing the test if we’re not going to accept the result?” Dolan asked.
“The test informs the decision,” Rocha-Garrido said.
CETL Changes
The complex interdependency of PJM’s procedures was on display when a presentation on proposed revisions to Attachment C of Manual 14B — billed as improving transparency and clarity — evolved into a discussion on potential impacts to capacity emergency transfer limits (CETLs) and concerns about how that might affect zonal capacity requirements.
The RTO’s Jonathan Kern presented the proposal, which would also “correct any conflicts between how the procedures are described and how PJM actually implements them” and include “a few minor procedural changes.” Many of the revisions focus on procedures for the load deliverability test or calculating CETLs.
Several stakeholders asked PJM to delineate how each revision might potentially affect CETL calculations. Kern said staff could provide all the distribution factors but that it was “premature” to perform full CETL analyses because the RTO hasn’t yet decided to include any of the external facilities. Staff believe considering them is “prudent” to ensure they’re not “turning a blind eye” to the potential impact of external systems if PJM analyses don’t account for them.
Market Efficiency
It appears the toil at a July 5 meeting of the Market Efficiency Process Enhancement Task Force has paid off. PJM’s Brian Chmielewski reviewed results of a last-minute poll that was requested to be completed in the few days between the task force’s meeting and the PC. (See PJM Market Efficiency Project Rules Could Slip Deadline.)
At issue was a set of six proposals to address how PJM evaluates and selects discretionary transmission projects. The poll showed majority support for Package G, which would exclude from the base case those units with facility study agreements (FSAs) and suspended interconnection service agreements and their associated network upgrades at the time of case build, unless they are needed for reliability.
Energy benefits of projects that are proposed to be in service later than the Regional Transmission Expansion Planning year would be adjusted to account for any savings forgone because of the later in-service date. Annual mandatory sensitivity studies would include FSA units only if they were excluded from the base case analysis. Sensitivities would be used for evaluation of a proposals’ robustness and sizing, but not for benefit-to-cost ratio tests. Parameters would be decided prior to the beginning of the project proposal window. In all simulated years, generation and transmission topology would be set at the RTEP-year level.
LS Power’s Sharon Segner asked that the proposed Tariff language be ready to review at the task force’s next meeting on July 20 so it can be discussed prior to the July meeting of the Markets and Reliability Committee.
Greg Poulos, executive director of the Consumer Advocates of the PJM States, asked for more clarity on FSA issues because they are “certainly of concern” to some advocates.
Segner and Public Service Electric and Gas’ Alex Stern, who had requested the fast turnaround on the poll, praised Chmielewski and other staff on the task force for compiling it so quickly.
Cascading Trees
PJM’s Aaron Berner reviewed staff’s efforts to incorporate resilience objectives into transmission planning. As part of that initiative, staff have developed a visualization tool called “Cascading Trees” that considers the potential impact to the grid of “more extreme” events and analyzes probabilities of what issues such events could cause.
“That will play an important piece in how we develop plans,” Berner said. He clarified that the current analyses assume the trigger event has occurred and said it’s unclear whether staff will consider calculating the probability of the triggering event happening in the first place.
Stakeholders seized on the analysis with questions about PJM’s plans for addressing resilience. Berner turned many of those questions away, emphasizing that the analysis remains in its infancy.
“That’s more in depth than I planned on going into today,” Berner said.
In response to a question from Dolan, Berner confirmed that staff are working with TOs, many of which already have resilience factors included in their internal planning assumptions.
“We do not intend to move forward in isolation. We are having conversations with the transmission owners on how this might work,” Berner said.
PJM’s Steve Herling reminded stakeholders that staff are simply acting on their marching orders.
“The direction we’re taking to pursue resilience is coming from the board,” he said.
RTEP Processes
Berner and PPL’s Frank “Chip” Richardson presented plans for reorganizing the processes for reviewing transmission projects. Berner covered plans for the sub-regional RTEP and Transmission Expansion Advisory Committee. Richardson explained TOs’ plan for supplemental projects.
The process designs are similar and stick to the requirements outlined in FERC’s ruling that TOs weren’t properly complying with their obligations under Order 890 to involve stakeholders early enough to solicit their needs and provide required information before making decisions to proceed with “supplemental” projects — transmission expansions or enhancements not required for compliance with PJM reliability, operational performance or economic criteria. TOs describe them as projects planned by each company individually to address items not addressed by PJM, such as customer service, replacement of failing, poor performing or antiquated equipment and enhancements to the security of their transmission system. (See Group Contests ‘Supplementals’ Ruling as PJM, TOs Advance.)
Stakeholders pressed TOs for more detail on how they plan to engage in the meetings, but Richardson emphasized the TOs’ focus on implementing the changes.
“Certainly, as we implement this, people will be able to voice opinions about what they think … but we’re not focused on changes right now. We’re focused on getting it implemented,” he said. “When we’re ready to have you take a look at it, we’ll let you know. … We’ll think about [feedback] after we get through a few cycles.”
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.)
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.
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.
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.
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.
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).
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.
FERC cleared the way for South Carolina Electric & Gas to become part of Dominion. | SCE&G
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.
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.
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.
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
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.
| SPP MMU
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.
| SPP
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.
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 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.
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.
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.
FERC on Friday tentatively accepted a cost-of-service agreement between Exelon and ISO-NE for Mystic Generating Station Units 8 and 9, ordering an expedited hearing process on unresolved issues (ER18-1639).
The order drew sharp rebukes from Commissioners Robert Powelson and Richard Glick, both of whom called it “yet another rush to judgment.”
The agreement would allow the gas-fired units in Massachusetts an annual fixed revenue requirement of almost $219 million for capacity commitment period 2022/23 and nearly $187 million for 2023/24. But the commission found the information Exelon provided to support those figures insufficient, setting for hearing the company’s proposed capital expenditures, fuel costs, and operations and maintenance expenses.
Notably, FERC did not hold the hearing in abeyance and appoint a settlement judge, as it often does when it suspends an accepted filing. Instead, it ordered an expedited hearing schedule, citing Exelon’s Jan. 4, 2019, deadline for deciding whether to retire the units and the beginning of Forward Capacity Auction 13 on Feb. 4. The agreement goes into effect June 1, 2022, subject to the outcome of the hearing.
The commission ordered the presiding judge to certify the record by Oct. 12, with initial briefs due Nov. 2 and reply briefs Nov. 16.
ISO-NE’s Tariff does not allow for reliability-must-run agreements, and only allows cost-of-service agreements to respond to local transmission security issues. FERC on July 2 denied the RTO’s request for a Tariff waiver to allow for the Mystic agreement. Exelon said in March that it would retire the 2,274-MW plant when its capacity obligations expire on May 31, 2022 (ER18-1509). (See FERC Denies ISO-NE Mystic Waiver, Orders Tariff Changes.)
Mystic Generating Station, on the Mystic River in Everett, Massachusetts. A wind turbine owned by the local water authority to power a pumping station is on the right.
The commission instead ordered the RTO to revise its rules to allow cost-of-service agreements for facilities needed to address fuel security issues, or show cause as to why it shouldn’t have to (EL18-182). ISO-NE’s response is due Aug. 31.
Powelson and Glick also dissented in that order, and both cited it in their dissents last week.
“The commission is not even waiting for stakeholders’ responses to the show cause order it issued last week before plunging ahead with its plans to bail out Mystic and Distrigas,” Glick said. Exelon included in the agreement the costs of purchasing fuel from and operating the nearby Distrigas LNG import terminal, which it is buying from ENGIE North America.
“By setting the agreement for modified settlement and hearing procedures, the majority is expressing a preference for a short-term cost-of-service mechanism to address fuel security,” Powelson said. “That message may have been implied in the waiver order, but after today’s order there is no question as to the majority’s direction. …
“Over the next few months, interested participants will focus time and energy on the agreement in an attempt to reach consensus on a host of challenging issues. Because the commission has failed to narrow the issues to be addressed in this proceeding, today’s order has opened a proverbial can of worms. Thus, instead of working collaboratively to respond to the commission’s Section 206 inquiry or consider more cost-effective alternatives, stakeholders will be working on the Mystic agreement.”
Distrigas, Cost Allocation
While FERC said it could not determine whether the agreement was just and reasonable, it did comment on several issues raised by protesters in the proceeding.
Several protesters questioned whether including an entire LNG facility in a cost-of-service rate violated the Federal Power Act.
Distrigas Terminal at sunset | Everett Chamber of Commerce
The commission said it would set the matter for hearing, but “in advance of the hearing, we find unpersuasive arguments that the FPA prohibits any recovery of the fuel supply charge for the Distrigas facility.”
“This finding as to jurisdiction does not mean that Mystic is entitled to recover all costs that it claims in connection with the Distrigas facility,” the commission said. “Whether individual components of a cost-of-service rate, including fuel-related costs, are recoverable turns on whether they are just and reasonable, not whether the commission has regulatory authority over all aspects of those rate components.”
Other protesters were concerned that there was no cost allocation mechanism in the agreement. FERC noted that in its show cause order, it directed ISO-NE to include such a mechanism in any Tariff revisions the RTO proposes.
The commission also said that while capital expenditures would be subject to hearing, the Mystic units should be allowed to collect actual prudently incurred costs, subject to true-up.
“We find that given the inherent difficulty in projecting costs in advance of the agreement’s effective date, and the concerns raised as to whether certain expenditures will be necessary to keep the Mystic units operational during the proposed service period, a true-up mechanism is necessary to ensure that the rates established reflect actual costs incurred,” the commission said.
The order directed the participants to present evidence regarding the appropriate design of the true-up mechanism in the agreement, noting that ISO-NE may also address the related clawback provision in EL18-182.
FERC on Friday rejected PJM’s proposal to exempt incumbent transmission owners from signing designated entity agreements (DEAs), saying it gave them an undue advantage over non-incumbents (ER18-1647).
In May, PJM proposed two changes to the competitive proposal window process mandated by Order 1000.
The commission approved PJM’s request to allow transmission developers 60 days to accept a DEA after receiving it as the winner of a project. The agreement includes a development schedule and a requirement to provide a letter of credit equal to 3% of the estimated project cost.
But the commission rejected the RTO’s proposal to exempt incumbent TOs from the requirement to execute a DEA for Regional Expansion Transmission Plan projects that the Operating Agreement requires PJM to designate to an incumbent. Such projects include TO upgrades; projects that would alter the TO’s use of its right of way; and those located solely within a TO’s zone that are not allocated outside.
PJM argued that the terms of the Consolidated Transmission Owners Agreement (CTOA) governing incumbents are comparable to the DEA. It said the security requirement — to protect ratepayers from additional costs if the original developer abandons a project and it must be reassigned — was unnecessary for incumbents because they cannot abandon projects and that requiring it would only increase costs.
| Asplundh Construction
The commission said PJM’s proposal would provide an advantage to incumbent TOs in the RTO’s evaluation of transmission proposals. FERC noted that it had rejected similar exemptions in Order 1000 filings by FERC Accepts Order 1000 Compliance Filing.)
“The less stringent requirements in the Consolidated Transmission Owners Agreement also could spare an incumbent transmission owner from a breach (and the associated remedies) that would otherwise be triggered if it executed the designated entity agreement. Although PJM argues that the proposal to exempt incumbent transmission owners from the requirement to execute a designated entity agreement in certain cases will further administrative efficiency, any such benefits do not overcome undue discrimination concerns,” the commission said.
“Under PJM’s proposal, an incumbent transmission owner proposing a transmission owner designated project in PJM’s competitive proposal window process could reflect the cost savings associated with not having a security requirement in its proposal,” FERC added.
The commission also said the CTOA’s milestone requirements are less stringent than that in the DEA, which includes “several interim milestone obligations and consequently, more potential events for breach.”
FERC said the DEA could prevent a transmission developer from assigning its rights to an affiliated limited liability company or C-corporation as financing vehicles, or from meeting legal requirements for state public utility status. “Such prohibition could inhibit the developer’s ability to seek siting approval from that state, particularly if the state requires that the developer be incorporated as a public utility under state law,” FERC said.
The commission approved PJM’s proposal to change the time period for a transmission developer to accept its designation.
Rather than having 60 days from receiving notification of its designation to accept, PJM proposed that the developer have 60 days after receiving the DEA.
“We agree that this proposal will provide PJM with more time to develop and issue the designated entity agreement, as well as for the transmission developer to respond to the initial designation with a development schedule with milestones and relevant project information,” FERC said.
