Page 1198 – RTO Insider

September 16, 2019

PJM PC/TEAC Briefs: Sept. 12, 2019

VALLEY FORGE, Pa. — The PJM Planning Committee rejected a problem statement and issue charge on Thursday that sought to bring end-of-life supplemental projects under the purview of the RTO’s regional planning process.

American Municipal Power and Old Dominion Electric Cooperative said that although incumbent transmission owners play a major role in planning for the replacement of aging infrastructure, the process “should be broader, more inclusive and more transparent.”

TOs have said they don’t object to shining a light on their own analyses, but they believe new rules governing increased planning coordination belong in manuals, not the Tariff or Operating Agreement. The TOs also note that many replacement projects benefit from the expertise of local planners — a knowledge source that PJM can’t readily access. (See PJM Members Debate Dueling Tx Replacement Plans.)

After an extensive negotiating process, AMP and ODEC modified the issue charge to drop specific references to the OA, but it wasn’t enough to sway majority support. Only 39% of stakeholders approved the document in a sector-weighted vote.

Consumer Advocates: CIP-014 Projects Need More Transparency

The D.C. Office of the People’s Counsel wants to create language for PJM’s manuals, Tariff and OA that addresses future management of critical transmission assets on NERC’s CIP-014 list.

The issue came to a head last month when incumbent TOs asked for feedback on a Tariff attachment that details the process for vetting transmission system enhancements designed solely to remove critical assets from the CIP-014 list, of which fewer than 20 exist within the PJM footprint. NERC reliability standards deem these assets “highly critical … that, if rendered inoperable or damaged due to physical attack, could result in significant grid concerns: widespread instability, uncontrolled separation or cascading.”

At the Markets and Reliability Committee meeting in August, Consumer Advocates of the PJM States (CAPS) asked why the attachment wasn’t up for stakeholder discussion. The ensuing conversation revealed concerns among states and load interests that the TOs couldn’t provide enough transparency into development of the attachment, leaving yet another subset of supplemental projects “behind a veil.” (See PJM TO Tariff Filing Stirs up Transparency Concerns.)

“We appreciate the sensitive nature of these projects, but the advocates are wondering why the development of the process wasn’t brought through the stakeholder process,” said Greg Poulos, CAPS executive director.

Pulin Shah of Exelon at a PJM Planning Committee — Pulin Shah, Exelon | © *RTO Insider*

In the problem statement and issue charge presented Wednesday, the D.C. OPC said the development of a process that protects confidential information about these assets and still fulfills the requirements of stakeholder participation outlined in PJM’s governing documents should involve all sectors. “This is a very sensitive subject,” said Pulin Shah, director of transmission strategy and contracts for Exelon. “We are concerned about reverse engineering and determining which assets these are. A lot of the deliverables that are outlined here go into areas that I know I’d be very uncomfortable talking about.”

Shah later clarified that TOs have adhered to a standard process outlined in the Consolidated Transmission Owners Agreement, which requests feedback from all stakeholders at least 30 days in advance of a Federal Power Act Section 205 filing at FERC. The TOs have already raised the issue with FERC and state commissions, he said.

PJM offered no opinion on whether the filing violates Tariff and OA rules, though Vice President of Planning Ken Seiler said staff are generally supportive.

“The elephant is in the room, so it’s not like we are ignoring it,” he said. “PJM conceptually supports the idea of electrically making critical facilities noncritical. We think that’s the best thing for this system.”

PJM Recommends Sunsetting Offshore Wind Special Sessions

After six special sessions that delved into PJM’s process for developing offshore wind projects, stakeholders have opted against recommending changes — for now.

John Reynolds at the PJM Planning Committee — John Reynolds, PJM | © *RTO Insider*

John Reynolds, of PJM’s resource adequacy department, said 51% of stakeholders preferred the status quo over pursuing changes. Some of those changes included granting merchant TOs temporary capacity interconnection rights (CIRs) or modifying the generation request process and the studies that process involves.

Current rules allow merchant transmission developers to obtain transmission injection and withdrawal rights for DC facilities or controllable AC facilities connected to a control area outside the RTO. Under the problem statement approved in February, stakeholders considered allowing merchant transmission developers to request CIRs, or equivalents, for non-controllable AC transmission offshore. (See “PC Moves Forward on Offshore Interconnection Rights,” PJM PC/TEAC Briefs: Feb. 7, 2019.)

Reynolds said stakeholders felt the proposed changes gave offshore wind projects special treatment and could interfere with other queue projects. Instead of pursuing further changes, stakeholders said other topics deserved higher priority for the PC and suggested broadening future discussion of offshore wind development. He recommended sunsetting the special sessions for six months.

AEP Supplemental Projects

American Electric Power presented two supplemental projects for consideration at Thursday’s Transmission Expansion Advisory Committee meeting.

The first involves the second transformer at the Dumont 765-kV substation in eastern Indiana. AEP said the 25-year-old unit suffered a catastrophic failure in 2018.

At the Sullivan 765/345-kV substation in the southwestern corner of the state, AEP is seeking to replace a disconnected failed breaker after discovering the breaker’s current transformers were developing combustible gases.

— Christen Smith

September 16, 2019

FERC Considering Tx Line Rating Rules

By Michael Brooks

WASHINGTON — FERC staff last week held a technical conference to receive input from RTO officials and stakeholders on dynamic and ambient-adjusted line ratings, including whether and how the commission should require transmission owners to implement them (AD19-15).

Much of the two-day conference held at FERC headquarters focused on the current limited use of the practices on the grid, the different kinds of devices and how RTOs accommodate them. But staff — and Commissioner Richard Glick, who attended parts of the conference each day — received plenty of advice, with some urging a requirement for TOs to use ambient-adjusted ratings (AARs), and others stressing caution against a one-size-fits-all approach. Others urged the commission to force TOs to disclose how they calculate their ratings.

All seemed to agree, however, about the potential benefits of dynamic line rating (DLR) technology.

“If this country is going to meet its numerous clean energy targets established by numerous states and corporations, we’re going to need a more vibrant transmission system,” Glick said in opening the conference Sept. 10. “And part of that is we’re going to need more transmission capacity. But it also means using our existing system more efficiently. … Certainly, this commission needs to consider whether there are alternative mechanisms for establishing line ratings … that can squeeze more out of the transmission system without impairing reliability.”

A transmission line’s rating determines how much electricity can flow through it. TOs provide their line ratings to their RTOs/ISOs. Most are static — rarely changing throughout the line’s lifetime — and very conservative, often based on worst-case scenarios: high temperatures, cloudless days and minimal wind.

Some TOs use seasonal ratings, allowing for more power flow in the winter months — though a TO’s definition of “winter” can vary, with some increasing the rating beginning in October and maintaining it all the way into April. As one panelist noted, April temperatures are quite different from those in January.

AARs, which change every so often (the frequency can vary from as high as every 15 minutes to daily) based on temperature forecasts, are widely used in PJM and ERCOT, and see limited use in MISO and SPP. Rarer still are dynamic line rating (DLR) devices, some of which can take into account not only temperature, but humidity, wind speed, sunlight and precipitation; others simply measure the sag of a line and adjust its rating accordingly.

Dillon Kolkmann (second from right), of FERC’s Office of Energy Policy and Innovation, led the technical conference. With him are fellow staffers (left to right) Eric Ciccoretti, Jignasa Gadani and Thomas Dautel. | © *RTO Insider*

Many TO representatives who spoke at the conference were positive about the technology, pointing to specific experiences their companies have had in using certain devices. But they cautioned against a hard rule from FERC for widespread implementation.

“At a high level, the concept of AARs sounds appealing and relatively simple: adjust line ratings based upon current or near-term environmental conditions (ambient temperature and sometimes wind velocity) to increase the efficiency of energy flow on the bulk electric system,” Dennis Kramer, senior director of transmission policy for Ameren, said on behalf of MISO’s TOs. “The broad implementation of AARs, however, is not simple and could be very complex with impacts on multiple existing processes and procedures, as well as requiring creation of entirely new policies, requirements, obligations and capabilities.”

“Individual transmission owners should be given an opportunity to determine whether implementing AAR on a particular transmission line would be beneficial to the transmission system in either alleviating congestion or enhancing the reliability of the transmission system,” said Rikin Shah, principal engineer for PacifiCorp. “Requiring the transmission owners to implement AARs on every single transmission line may result in unnecessary capital investment without the return that was expected and put additional burden on consumer rates.”

Carlos Casablanca, director of advanced transmission studies and technology for American Electric Power — which he said has been using AARs for more than 10 years in several RTOs — encouraged FERC to require TOs to use the technology on most of their lines, as they “can increase the value of a robust transmission system to the benefit of our customers and bring flexibility to the transmission operations environment.”

On the Sept. 11, the second day of the two-day technical conference, FERC staff and Commissioner Richard Glick hear from panelists on the ability of RTOs and ISOs to accommodate DLRs in their markets. | © *RTO Insider*

But even he said that not all lines would benefit from their use. “We have some assets that are over 100 years old in some regions. … We don’t think it may be safe or prudent to apply [AARs] to those facilities.”

Joe Bowring, PJM’s Independent Market Monitor, said not requiring TOs to use AARs “is akin to saying, ‘You have your ratings wrong most of the time.’ … PJM real-time prices are calculated every five minutes. The system operates in real time. There’s no reason for line ratings to be the same [every] season, at all hours of the day.”

Transparency Concerns

But regardless of the TO and their position on AARs or DLRs, line rating practices vary dramatically. As multiple speakers pointed out, for example, there is no uniform methodology for calculating static line ratings — and no requirement for TOs to explain how they calculate them.

Advocates for FERC stepping in seized upon those differences in making their case.

“The same facilities should have the same ratings under the same operating conditions regardless of the transmission owner,” Bowring said. “Transmission owner discretion should be minimized or eliminated in line ratings.”

Speaking about MISO, Michael Chaisson of Potomac Economics, the RTO’s Monitor, echoed Bowring’s sentiments. He presented a histogram showing how many TOs used certain ratings in the winter for their 115-kV lines. “You can see it’s all over the map … but this isn’t even the worst of it,” he said. “This histogram actually proceeds several more pages off to the right with outliers. … You can’t effectively monitor without knowing the basis for the ratings.”

Michelle Pivach Bourg of Entergy Services pushed back, pointing to NERC Reliability Standard FAC-008-3’s requirement that TOs make their methodologies for calculating ratings available to their RTOs and reliability coordinators upon request.

But RTOs don’t review the line ratings that TOs submit for accuracy, the Monitors said. Both Bowring and Chaisson said their respective RTOs monitor for abnormal ratings and only then request information from the TOs.

Bowring said to Bourg, “I never said that the information was not available to the RTOs. I said they don’t actually do the review. There’s a difference.”

“I think the key phrase is ‘upon request,’” Chaisson said. “What we’re seeing in practice at MISO is that they don’t have a comprehensive folder with all these methodologies stored, and they don’t have a comprehensive database with the limiting elements. … All they have are the ratings the TOs gave them and the ability to ask about particular ones, which they do from time to time.”

Bowring also recommended that the commission require TOs to “at least engage in” pilot programs for DLR technology, not necessarily to permanently install the devices, “but to get the data.”

“There’s been a lot of talk about ‘smart grids,’” he said. “This seems to me one of the basic elements of what a smart grid would be. You can’t be smart without information.”

The first panel of the conference on Sept. 10 served as an introduction to line rating methodologies and technologies. | *FERC*

Adam Rousselle Sr., president of Alternative Transmission Inc., agreed. “What we’re seeing is the advent of great new information, and we’re asking questions about how to integrate it with a system designed not to have it. … I think we have to have the data, and after we have it, we’ll have better opportunities to steer.”

Rousselle advocated for “a broad, systemwide and immediate evaluation of every bulk electric transmission circuit’s facility rating. … If you put a blood-pressure cuff on every circuit … there would be no doubt at what the rating was.”

Mike Kormos, senior vice president of transmission and compliance for Exelon, balked at these suggestions. “I’d be happy for that rate base,” he joked. “I think it’s a real waste of money.

“Please recognize that the vast amount of line ratings on the system have no impact. Those lines are not overloaded; those lines do not go into congestion,” said Kormos, a former PJM executive. “For those lines that are in routine congestion or extreme congestion, even for a short period of time, I can assure you that the first question asked is, ‘Are the ratings right?’ … When I was at PJM, I asked, and now that I’m with Exelon, I will provide.”

September 16, 2019

MISO Eases New Rules on Extended Outages

By Amanda Durish Cook

CARMEL, Ind. — MISO has softened a proposal to crack down on long-term outages from capacity resources, granting some wiggle room for outages taken June through August and removing a replace-or-pay requirement.

The RTO last month introduced a provisional solution that would limit extended planned outages to fewer than 90 days to qualify for participation in the Planning Resource Auction. Additionally, resources expected to be unavailable for the first 90 days of the planning year would not qualify. (See MISO to Limit Capacity Resource Extended Outages.)

Tim Bachus of MISO discussing extended outages — Tim Bachus, MISO | © *RTO Insider*

Now, MISO has relaxed the proposal so that resources unavailable for 90 of the first 120 days of the planning year will be disqualified from participation. Tim Bachus, MISO capacity market administration analyst, told the Resource Adequacy Subcommittee on Wednesday that the new proposal recognizes that September is becoming more summer-like in terms of hot weather-related demand.

Bachus said the rules will apply to both full and partial outages. Had the rules been in place during the last PRA, about 254 MW would have been impacted, he added. Currently, the RTO doesn’t impose any penalties for capacity resources that take extended outages.

“We don’t have any mechanisms in place to address this, and that’s what we’re hoping to do today,” Bachus said.

MISO has also scrapped its original provision to make cleared resources on 90-day-plus planned outages replace their capacity or be penalized at its approximate $240/MW-day cost of new entry.

Bachus said that while stakeholders were generally supportive of the 90-day planned outage limit, they criticized the CONE payment penalty as too extreme.

“We realize that not all resources will be in a position to replace,” he said.

Bachus stressed that the new rule is meant to be provisional. “This proposal is really only meant to cover a year or two, and then we’ll have a more robust construct in place,” he said.

September 16, 2019

PJM MIC Briefs: Sept. 11, 2019

VALLEY FORGE, Pa. — After a one-month delay, the PJM Market Implementation Committee on Wednesday endorsed two packages to update the RTO’s opportunity cost calculator.

The latest plan from Dominion Energy and Panda Power Funds would make what the sponsors called “modest improvements” to the calculator and include Manual 15 revisions so that it more closely resembles the Independent Market Monitor’s calculator that most stakeholders prefer using. Just under 84% of members voted in favor of the new package.

Jim Davis, Dominion Energy | © *RTO Insider*

When polled on PJM’s package — which maintains the status quo but also makes minor clarifications in Manual 15 — 51% of stakeholders also approved. Both plans will advance to the Markets and Reliability Committee for consideration, with the Dominion/Panda proposal considered first.

Critically, Panda and Dominion withdrew three other proposals that were discussed at the August MIC meeting, including one that eliminated PJM’s calculator altogether. (See “Opportunity Cost Calculator Vote Delayed,” PJM MIC Briefs: Aug. 7, 2019.)

“We thought that this would be a good compromise,” Dominion’s Jim Davis said. “We worked with PJM to see what they would be willing to change in a timely fashion.”

Monitoring Analytics, however, disagreed that the latest changes made PJM’s calculator any more similar to its own and said that Manual 15 changes were unnecessary.

“We think these are modest changes, we agree with that, but this brings us a little closer to the IMM calculator and lets us just focus on further documentation of the IMM calculator,” Davis said.

Monitor: Review ARR/FTRs to Improve the Allocation of Congestion Rights

The Monitor told the MIC that the existing constructs for auction revenue rights and financial transmission rights leaves some load zones unable to sufficiently offset their congestion costs.

“There is a significant misalignment between congestion as it has been allocated and congestion as it has occurred,” said Howard Haas, chief economist for Monitoring Analytics. “Even if you were to claim all the rights made available to you, you cannot offset all off the congestion assigned to you.”

Zonal ARR and FTR total congestion offset (in millions) for ARR holders for the 2018/2019 planning period | *Monitoring Analytics*

Existing rules generated a 91.8% rate of congestion offset recovery across all of PJM last year, but the rate varies wildly from zone to zone, Haas said. For example, Dayton Power & Light only offset 27.2% of its congestion costs, while Baltimore Gas and Electric offset 367.3% of its costs, despite producing significantly different amounts of congestion, according to the Monitor’s table.

Howard Haas, Monitoring Analytics | © *RTO Insider*

Both PJM and stakeholders said they were generally supportive of exploring the issue, but some worried the problem statement and issue charge as presented were “too narrow.”

“I believe the GreenHat [Energy] report said we should take a comprehensive look at the FTR/ARR design,” said Exelon’s Sharon Midgley, noting that the Financial Risk Mitigation Senior Task Force is instead focusing on other credit and risk policies post-default. “This issue charge is leading towards a solution that is perhaps a little too narrow.”

Haas said that the key work activities listed in the issue charge provide appropriate room for that discussion. The deliverables would require stakeholders to identify the causes of congestion misalignment and decide whether changes to the market design could fix the problem.

“I would like to keep this more broad,” Midgley insisted. “All stakeholders might not necessarily share the same exact view on your description of the problem to be solved here.”

Other stakeholders agreed. Vitol’s Joe Wadsworth said he would like to see the rolling monthly auction option that PJM has presented at prior task force meetings added into the scope of the Monitor’s proposed review. The issue charge will be up for approval at the October MIC meeting.

Regulation Historic Performance Score

PJM presented revised Manual 11 language that would address a gap in missing historical performance scores used for regulation market clearing.

The MIC endorsed the manual changes in August, but at the MRC on Aug. 22, stakeholders took issue with the proposed value PJM would use when a system failure or other issue prevents the transfer of timely data.

The latest revisions will note that “if no historic performance scores are available from the last three days, then the latest available regulation qualification or regulation requalification test score for each resource by signal type is used.” A previous version indicated PJM would use a default value of 1 instead.

September 16, 2019

NEPOOL Participants Comm. Briefs: Sept. 13, 2019

ISO-NE COO Vamsi Chadalavada’s operations report to the New England Power Pool Participants Committee on Friday showed the region’s energy market value dropped to $321 million in August, down $93 million from July 2019 and down $240 million from August 2018.

August natural gas prices were 11% lower than the previous month’s average values, with average RT Hub LMPs ($23.58/MWh) down 19% from July. The average day-ahead Hub LMP was $25.69/MWh for the month, and average August 2019 natural gas prices and RT Hub LMPs were down 36% and 40%, respectively, from August 2018 averages.

The average day-ahead cleared physical energy during the peak hours as percent of forecasted load was 101.3% during August, up from 99.9% during July. Day-ahead cleared physical energy is the sum of generation and net imports cleared in the day-ahead energy market.

ISO-NE results shared at the NEPOOL Participants Committee — | *ISO-NE*

Chadalavada drew attention to slides showing that forecasting trends are shifting fast. He said the RTO is continuing efforts to improve load forecast models and tools to produce better day-ahead and long-term load forecasts.

Consent Agenda

The Participants Committee voted unanimously to approve the single item on the consent agenda, revisions to OP-14E to incorporate energy storage as a type of asset-related demand that can be selected on ISO-NE’s form NX-12E, which provides the RTO with details that are not included in bid information.

ISO-NE and NESCOE Budgets Update

Kenneth Dell Orto, chair of the Budget and Finance Subcommittee, presented an update of the RTO’s proposed 2020 operating and capital budgets, as well as the 2020 budget of the New England States Committee on Electricity.

The budgets are in the final stages of development and will be voted on at the Oct. 4 Participants Committee meeting in Boston.

A more detailed presentation was provided to the subcommittee last month.

ISO-NE’s budget presentations to the New England state agencies, with their questions and the RTO’s answers, can be found here.

— Michael Kuser

September 16, 2019

Michigan PSC Settlement Resolves PURPA Clashes

By Amanda Durish Cook

Michigan regulators last week approved a settlement between Consumers Energy and solar developers, resolving arguments over the utility’s obligation to support small generation projects under the Public Utility Regulatory Policies Act.

The Public Service Commission’s approval of the agreement means that Consumers will interconnect new solar projects and is allowed to establish a new avoided-cost rate (ACR) for qualifying facilities (U-20615).

Consumers will now purchase power from an additional 584 MW worth of solar projects to be interconnected by 2023. About 170 MW of the projects will receive the current ACR, while the remaining 414 MW will be eligible to enter contracts at a rate based on MISO LMPs plus the capacity prices established in the RTO’s annual capacity auction. Solar developers Geronimo Energy, Cypress Creek Renewables and sPower stand to receive a cut of the first 170 MW of projects at higher rates.

The move will more than triple solar capacity in Michigan, which currently has more than 153 MW of solar. The settlement puts to rest five separate cases between Consumers and more than 40 entities. The settlement was signed by several QFs, Consumers, PSC staff and the Solar Energy Industries Association.

Public Utility Regulatory Policies Act benefits solar — Solar panel construction | *Consumers Energy*

Under PURPA, utilities such as Consumers are obligated to purchase electricity from independently owned QFs at rates that reflect a utility’s own cost to build new generation. Consumers’ existing avoided costs generally range from about $95 to $110/MWh, but the company has alleged the figures are outdated and above-market.

While the settlement will put some QFs in operation, its leaves many awaiting approval and compensation from Consumers. The company’s current PURPA interconnection queue is jammed at 3.3 GW, and several QF owners complained that the first version of its integrated resource plan didn’t do enough to clear the backlog. Consumers has previously mounted an unsuccessful bid with its state regulators to waive deadlines on reviewing QF applications for approval. The utility claimed it was simply overwhelmed by the more than 1,700 QF applications in the pipeline.

A previous settlement in June modified Consumers’ IRP so that the utility will now conduct an annual competitive bidding supervised by a third party for adding new capacity (U-20165). Consumers can only own up to half of the new capacity it secures through competitive bidding; the rest must come from power purchase agreements with unaffiliated companies. Any remaining capacity needs after bidding is complete can be filled by QFs.

Consumers this fall will bid out about 1,200 MW of new solar energy for the 2019-2021 time frame. Although the bidding will focus on solar generation, the utility said QFs of all fuel types will be allowed to bid.

The June settlement also stipulates that Consumers will use a five-year horizon instead of the previous 10-year outlook to determine whether it has a capacity need. Consumers will also have to file new ACRs for regulatory approval within 30 days of each annual bidding process. Current QFs with a PURPA-based contract will continue to get new PPAs regardless of Consumers’ capacity needs. Additionally, QFs 150 kW or smaller will receive PPAs based on the full avoided cost, also regardless of Consumers’ capacity status.

Last year, Michigan regulators lifted a 10-month suspension on the state’s new avoided-cost calculation for Consumers. The utility argued it didn’t need any additional capacity over the next 10 years and had put about 700 MW of solar projects on hold. The PSC rejected the argument, saying the utility’s IRP would determine whether it needed new capacity.

PURPA in Flux

Michigan isn’t the only state in the MISO footprint where utilities have tried to alter or discontinue their obligation to pay independent developers under PURPA, arguing that rates exceed actual avoided costs for new generation.

The 9th U.S. Circuit Court of Appeals ruled in June that it could not force the Montana Public Service Commission to compel NorthWestern Energy to purchase power from solar developers at originally established and higher ACRs. (See Montana PSC Racks up 2nd Lawsuit over PURPA Rates.)

FERC this summer also avoided addressing whether the addition of storage facilities at the Beaver Creek wind farm in Montana would put the project’s QF standing in jeopardy under PURPA when the owner withdrew applications to recertify the four 80-MW projects (EL18-195). NorthWestern argued last year that the addition of storage units to 80-MW wind facilities would put them over the PURPA megawatt limit.

In comments to the petition, the Edison Electric Institute said the case raised new issues for PURPA’s treatment of energy storage and urged FERC to hold off on deciding on the motion until it could address the issues of “modernizing” PURPA in a more comprehensive proceeding, given that on-site storage capability could increase a facility’s capacity beyond 80 MW.

FERC has been reviewing its implementation of the law since 2016, holding a technical conference in June of that year, but it has languished under numerous shakeups at the commission. However, one of its agenda items (E-1) for this month’s open meeting Thursday concerns “qualifying facility rates and requirements” and “implementation issues” under PURPA. The item is listed under both the docket FERC opened in 2016 (AD16-16) and a new rulemaking docket (RM19-15), indicating a Notice of Proposed Rulemaking is potentially imminent.

September 16, 2019

PJM OC Briefs: Sept. 10, 2019

VALLEY FORGE, Pa. — Exelon told the PJM Operating Committee last week it is near agreement with RTO staff on business rules for non-retail behind-the-meter generation (NRBTMG) that would exclude retail community solar and aggregate net energy metering programs.

Exelon told the Markets and Reliability Committee in August that it approves of the concepts and reporting requirements outlined in the changes to Manuals 13 and 14D but wanted more time to review the differences in the application of the rules — specifically whether community solar programs and aggregate net energy metering are within scope. It asked the MRC to delay its vote for 30 days. (See “Non-retail BTM Generation Vote Delayed,” PJM MRC Briefs: Aug. 22, 2019.)

PJM Operating Committee underway — PJM’s Operating Committee met on Sept. 10 in Valley Forge, Pa. | © *RTO Insider*

Since then, both parties have agreed that neither program should fall under the category of NRBTMG. Exelon will bring its revisions to the MRC meeting scheduled for Sept. 26, Sharon Midgley, the company’s director of wholesale development, told the Operating Committee on Sept. 10.

NRBTMG refers to resources used by municipal electric systems, electric cooperatives or electric distribution companies to serve load. They do not participate as supply resources in PJM markets but can be netted against their wholesale load to reduce transmission, capacity, ancillary service and administrative fee charges.

Hot August Spawned 4 Weather Alerts

Soaring temperatures last month spawned four hot weather alerts Aug. 18-21. A feedwater control valve issue also tripped units at Salem 2, creating the first spinning event of the summer.

Manuals Endorsed

Staff must update all three manuals to comply with FERC Order 841’s energy storage participation mandates.

Manual 14D adds metering requirements specific to energy storage resources, outage reporting requirements and generating unit reactive capability curve specification and reporting procedures.

In Manuals 36 and 40, PJM updated the exception to critical cranking power to include non-hydro energy storage resources and added a lower megawatt threshold for electric storage resource training requirements.

September 16, 2019

MISO Resource Adequacy Subcomm. Briefs: Sept. 12, 2019

CARMEL, Ind. — MISO will suspend updates on its resource availability and need (RAN) project through November to allow time for analysis that may drive future draft rules.

During a Resource Adequacy Subcommittee meeting Wednesday, MISO planning adviser Davey Lopez said the RTO will skip the monthly RAN presentation at next month’s meeting to analyze its loss-of-load methodology, a possible seasonal auction and new capacity accreditation for planning resources.

By the first half of 2020, MISO expects to finish a filing to alter capacity accreditation.

MISO is mulling an available capacity estimate that includes a measure of historical availability and the impact of planned and maintenance outages in addition to already-counted forced outages. The RTO is also considering distinct accreditations for intermittent, load-modifying and emergency-only resources.

MISO RASC underway — The MISO RASC met in Carmel, Ind., on Sept. 11. | © *RTO Insider*

MISO also wants its loss-of-load expectation modeling “more closely aligned to the real world,” Lopez said. The new LOLE may rely on seasonal data and might become a seasonal result itself. More detailed data, including extreme weather scenarios, historical outages, actual load-modifying resource participation, external assistance from neighboring balancing authorities and the capabilities of intermittent resources may be incorporated.

Customized Energy Solutions’ Ted Kuhn urged MISO to be innovative in adjusting or redefining seasons. He said it might be that September is found to be sufficiently risky that it warrants a spot among the summer months, or a separate loss-of-load risk might need to be defined for winter.

“Just be thoughtful when you go through these, and don’t straight jacket solutions,” Kuhn urged.

Lopez said MISO will examine monthly risk and whether it should change the calculations behind its planning reserve margin and local reliability requirements.

MISO’s fall pause doesn’t mean other smaller RAN initiatives are on hold. The RTO expects to make a filing by October to improve the modeling of LMR participation in the capacity auction and create “reasonable expectations” for capacity availability during the planning year.

New PRA Deadlines Before FERC

MISO has filed with FERC to shift the offer window times and data submission deadlines for its Planning Resource Auction (ER19-2559).

The changes would allow more time for market participants to prepare data submittals to MISO and end the RTO’s middle-of-the-night closings and openings of the offer window.

MISO Manager of Capacity Market Administration Eric Thoms said the RTO expects a FERC ruling before the RASC meeting Oct. 9.

The filing would take effect beginning with the 2020/21 PRA, altering deadlines for demand response testing, submission of generator verification testing data, behind-the-meter registration, unforced capacity values and the posting of preliminary auction data. In most cases, the deadlines would be extended into the winter from late fall. (See “Timeline Change Next Year,” MISO Ponders Changes After Latest PRA.)

MISO is also proposing to open and close the offer window during normal business hours instead of the usual midnight-to-midnight run of the four-day window. The RTO requested permission to open the offer window at 8 a.m. ET and close at 6 p.m.

Thoms also said the RTO is readying the 2020/21 PRA in MISO software.

CONE Increases

MISO also filed its annual update of cost of new entry values this week, with prices up over last year’s estimates across all local resource zones (ER19-2781).

Michael Robinson addresses stakeholders at the MISO RASC — Michael Robinson, MISO | © *RTO Insider*

This year, staff and the Independent Market Monitor calculated the CONE at an average $251/MW-day for the entire footprint. Last year, the average CONE was about $238/MW-day footprint-wide.

Arkansas and East Texas’ Zone 9 has the lowest CONE value of about $237/MW-day, while Lower Michigan’s Zone 7 has the highest, with about $258/MW-day.

MISO’s CONE is used as the RTO’s maximum clearing price and maximum clearing offer in the PRA. CONE represents the estimated cost of constructing a 237-MW combustion turbine in different locations in the footprint.

Stakeholders asked why CONE numbers were up year-over-year. To that, MISO adviser Michael Robinson pointed to the philosophy behind Isaac Newton’s and Gottfried Wilhelm Leibniz’s calculus of infinitesimals.

Robinson said “several contributing factors” — including small upticks in cost of debt, operation and maintenance costs, and tax rates — contributed to the increase.

“When you add them all up, it contributes to about a 5 to 6% increase,” he said.

Wind, Solar, Storage Focus of New Deliverability Proposal

MISO will move ahead with a stricter capacity deliverability requirement for its intermittent planning resources.

“This is something we’re going forward with, so it’s not up for debate if we are or aren’t going to do this,” MISO’s Darrin Landstrom said.

Landstrom said MISO would return with a proposal and examples at the Oct. 9 RASC meeting.

According to the RTO, stakeholders were most receptive to an approach that would use an intermittent resource’s transmission service request value as the maximum output for calculating the average capacity factor, which would reduce capacity credits. (See MISO Deliverability Plan Prompts Skepticism.)

MISO expects to make a FERC filing in December. The proposal would only apply to wind, solar and electric storage resources that offer capacity beginning in the 2020/21 planning year. The RTO draws a distinction between conventional and intermittent resources for deliverability.

Still, some MISO stakeholders maintained last week that the RTO has not demonstrated its current process is causing stranded intermittent capacity during peak hours.

But Landstrom said the proposal will stave off potential problems from MISO assuming planning resources will perform to an installed capacity deliverability level when they’re only required to demonstrate deliverability up to an unforced capacity level.

“The IMM [and] FERC have recommended we close this gap, and MISO agrees with them,” Landstrom said.

— Amanda Durish Cook

September 16, 2019February 26, 2025

UPDATED: LaFleur Elected to ISO-NE Board

By Michael Kuser

Former FERC Commissioner Cheryl LaFleur was elected to a three-year term on the ISO-NE Board of Directors on Friday, just two weeks after leaving her job in D.C.

LaFleur will replace Director Raymond Hill, who is completing his third consecutive three-year term this month.

Re-elected were Directors Barney Rush and Vickie VanZandt, each of whom will begin their third consecutive term, the maximum allowed. Absent a waiver, an incumbent board member cannot serve more than three consecutive three-year terms.

Former FERC Commissioner Cheryl LaFleur appointed to ISO New England board

Although LaFleur’s second term on FERC ended June 30, she served until the end of August, as allowed by law in the absence of a successor. She announced she would not be appointed to a third term in January. (See LaFleur Announces Departure from FERC.)

Returning to New England

The announcement represents a homecoming for LaFleur. Prior to joining the commission, LaFleur worked at National Grid, ultimately serving as executive vice president and acting CEO of the U.S. subsidiary. She had served at various times as COO, president of the company’s New England distribution companies, and general counsel.

LaFleur said in a statement that she was excited to join the board. “New England is my home and where I have spent most of my career, and I welcome the opportunity to be part of an organization that serves electricity consumers across the region.”

ISO-NE Board Chair Philip Shapiro said LaFleur “not only will bring insights from her long tenure at FERC, but also from her experience at National Grid.”

“Cheryl is a welcome addition to the ISO New England board,” ISO-NE CEO Gordon van Welie said. “The sum of her career experience will be put to good use as the region’s grid continues its transition to a future with cleaner, more distributed resources.”

Mr. Rush was re-elected to the ISO New England Board

Barney Rush | ISO-NE

Rush also serves on the board of Azure Power Global, which develops solar plants in India, and is a senior representative for Fieldstone, a regional investment bank that raises capital for power plants and infrastructure in Africa and other emerging markets. He is the former group CEO for Mirant Corp. in Europe. He is also the mayor of the town of Chevy Chase, Md.

VanZandt runs VanZandt Electric Transmission Consulting, based in Washington state, and is the Western Electricity Coordinating Council’s program manager for the Western Interconnection Synchrophasor Program. She retired from the Bonneville Power Administration in 2009 after 35 years, including a position as its senior vice president of transmission services. She served as BPA’s chief engineer for a decade.

Committee Assignments

Ms. VanZandt was re-elected to the ISO New England Board — Vickie VanZandt | *ISO-NE*

The slate of board candidates is selected by the Joint Nominating Committee, endorsed by members of the New England Power Pool’s Participants Committee and confirmed by the board and the New England Conference of Public Utilities Commissioners (NECPUC). The nominating committee is composed of 14 members: six PC members representing their sectors; one member of NECPUC; and seven members of the board.

Van Welie announced that the board had also elected Director Kathleen Abernathy to replace Shapiro as chairperson. Committee assignments, as listed in the CEO report posted with the meeting materials, are as follows:

Audit and Finance Committee: Michael Curran, LaFleur and Shapiro, with Christopher Wilson as chair;
Compensation and Human Resources Committee: Abernathy, Brook Colangelo and VanZandt, with Roberto R. Denis as chair;
Joint Nominating Committee: Abernathy, Curran, LaFleur, Rush, VanZandt and Wilson, with Shapiro as chair;
Markets Committee: Curran, LaFleur and Wilson, with Rush as chair;
Nominating and Governance Committee: Abernathy, Curran and Rush, with Shapiro as chair;
System Planning and Reliability Committee: Colangelo and Denis, with VanZandt as chair; and
Special Committee on Information Technology and Cyber Security: Colangelo and Wilson will serve on the temporary committee, with Colangelo as chair.

Age Limit

Voting directors on the RTO’s board serve staggered, three-year terms. A nominee cannot stand for election or re-election if they have reached the age of 71.

However, on Aug. 15, ISO-NE and NEPOOL filed amendments to the Participants Agreement to authorize the Joint Nominating Committee to waive the age limit (ER19-2616). That filing is currently pending and, if accepted, would permit the amendments to become effective Oct. 15.

ISO-NE said each of the candidates on the 2019 slate was under the age limit but declined a request for the current board members’ ages, calling it “personal information.”

“I can tell you that candidates’ ability to meet eligibility requirements are evaluated by the members of the Joint Nominating Committee and then by members of the NEPOOL Participants Committee, and all members of the board, including the slate taking office Oct. 1, currently meet the eligibility requirements,” ISO-NE Spokeswoman Marcia Blomberg said.

September 15, 2019January 30, 2024

FERC Orders Expanded Mitigation for LGE-KU

By Rich Heidorn Jr.

FERC last week rejected Louisville Gas & Electric and Kentucky Utilities’ proposed transition for exiting from market power mitigation measures the commission had imposed to address the companies’ 1998 merger and withdrawal from MISO in 2006 (ER19-2396, ER19-2397).

The rate de-pancaking mitigation provisions were imposed to resolve horizontal market power concerns. In March, the commission agreed the provisions could be removed because loads located in the LG&E/KU market would have access to enough competitive suppliers after the mitigation is removed. It conditioned the removal on a transition mechanism to protect customers that had relied on transmission service on the MISO system.

FERC said that “although it determined that there would continue to be a sufficient number of competitive suppliers in the LG&E/KU market if the de-pancaking mitigation was terminated, termination will affect the relative economics of competing suppliers in different markets by making the cost of purchases from resources located in MISO more expensive.”

Eligible for the transition were contracts by the Kentucky Municipal Power Agency to supply KU requirements customers that went into effect on May 1; a requirements contract between the city of Benham and American Municipal Power; a requirements contract between the city of Berea and AMP that went into effect on May 1; and a contract between the city of Owensboro and Big Rivers Electric Cooperative.

The commission said the proposed transition mechanism filed by the companies in July was overly narrow and spelled out changes the companies must make regarding which customers and power purchase agreements should be covered and the definition of “covered” transmission service requests. It also ordered changes regarding which MISO schedules are eligible for reimbursement, reimbursement adjustments and the handling of exports.

In an accompanying ruling rejecting rehearing of its March order, the commission also identified three additional customers as eligible for the transition: KYMEA and member cities Paducah and Princeton (EC98-2-002, ER18-2162-001).

LG&E serves 411,000 electric customers in Louisville and 16 surrounding counties. KU serves 553,000 customers in 77 Kentucky counties and five counties in Virginia. The two companies, which are now PJM members, are owned by Allentown, Pa.-based PPL.