Page 1067 – RTO Insider

March 10, 2019January 30, 2024

Overheard at NECA Renewable Energy Conference 2019

AUBURNDALE, Mass. — Commercial demand is supplanting state policy as the driving force behind deployment of renewables, whose costs are declining in every category, participants at the Northeast Energy and Commerce Association (NECA) Renewable Energy Conference heard last week.

“You will see, maybe not so much yet in New England, but you will see across North America, customers are buying renewable energy,” Brattle Group principal Judy Chang said Thursday.

States drove renewable energy adoption in the very beginning, “but now we’re really seeing customers, particularly large commercial and industrial customers, directly signing up contracts for renewable generation — and some of those come with storage,” Chang said.

“Change” is the watchword, according to Stephen J. Rourke, ISO-NE vice president for system planning, who said he’s seen more change in the past year than in his whole 40 years in the industry.

“One way to get a sense of what’s headed our way next, when you think about the resources that are going to come forward, is to look at the [interconnection] queue,” Rourke said. “If you followed our queue from roughly 2005 to 2017, we had 12,000 to 14,000 MW in our queue, three-quarters of it natural gas. The rest of it was wind and a little bit of something else.

“If you look right now, we have over 20,000 MW of generation in our queue, and 85% of it is either wind, solar, batteries, hydro, biomass or fuel cells,” he said. “The 15% that’s left over is natural gas, so what resource developers are saying to us … is these are the resources that are coming forward … and this has changed dramatically since just 2017.”

Big Projects for Big Goals

Richard Stuebi, president of Future Energy Advisors, said that renewables accounted for 10% of New England’s generation in 2018, so that if the region and New York want to achieve their ambitious environmental goals, “we need to start doing it now.”

Moderating a panel discussion, John Dalton, president of consultancy Power Advisory, asked whether the 100% carbon-free or renewable power goals in Massachusetts and New York were attainable at all.

“Large-scale renewables like solar and wind are a primary reason the state is able to achieve these lofty goals,” said Doreen Harris, director of large-scale renewables for the New York State Energy Research and Development Authority. “The last two years alone have brought about incredible cost reductions and competition from these resources. In 2017 and 2018, New York awarded agreements for long-term contracts for 46 different large-scale projects, and at prices over 20% less than those received just two years ago.”

Gov. Andrew Cuomo in January vaulted New York ahead of other states by pledging to secure 70% of electricity from renewables by 2030 and to achieve carbon-free electricity by 2040, while nearly quadrupling its offshore wind energy goal to 9 GW by 2035. (See New York Boosts Zero-carbon, Renewable Goals.)

New York is in the midst of reviewing 18 proposals from four developers responding to its first offshore wind solicitation issued last November seeking 800 MW or more of offshore wind. The state expects to award contracts in April, Harris said. (See Four Bidders Vie for NY Offshore Wind Project.)

Harris noted the “very interesting areas of regional overlap” among the lease areas capable of serving multiple markets from New Jersey north to New York, Connecticut, Rhode Island and Massachusetts.

“Big 100% renewable or carbon-neutral goals are attainable; it’s just a matter of how much you’re willing to spend to get there,” Chang said.

Emily Green, staff attorney with the Conservation Law Foundation, said Maine Gov. Janet Mills’ new renewable energy goals of 80% by 2030 and 100% by 2050 are attainable.

“Clearly it’s a very aggressive goal, calculated to fulfill Gov. Mills’ campaign pledge to establish Maine as a leader on clean energy,” Green said. “If you look at the technical potential in the state of Maine, our solar developers would really like to tell us that the state is 33% sunnier than Germany, the global leader in solar development. In terms of offshore wind, we rank seventh in terms of technical potential, so I think the resources are there.”

Transmission Issues

David Wilby, president of Maine-based consulting firm Wilby Public Affairs, said that if asked to rank the challenges to developing large-scale renewables, “I’d rank the top three as transmission, transmission, transmission.”

Dalton asked about the potential for regional cooperation in developing offshore wind transmission.

Transmission is “an existential issue” for onshore wind, Wilby said, but getting regional cooperation for offshore wind transmission, though not easy, “probably could be done in a limited way.”

“In some cases, we just have to do better together as stakeholders as part of ISO New England and New York ISO,” said Melissa Kemp, director of policy for the region for Cypress Creek Renewables.

“Right now, something like over 50% of distribution-level solar projects and storage projects in Massachusetts are on hold,” Kemp said. “There’s absolutely no clarity about how those will be studied; there’s been no process set up ahead of time for ISO-NE transmission coordination with the distribution-level companies. That’s just not OK … that’s a crisis.”

Offshore wind comes with its own set of transmission challenges, and New York “is seeking a bundled product in the sense that we’re looking for generation and transmission, and we’re paying for it in one associated contract,” Harris said.

“The proposals that we received, in several cases the leaseholder actually partnered with a transmission company for delivery into New York,” Harris said. “It might have been conceivable to think about radials when you’re talking about 2,400 MW of offshore wind, but when you’re thinking about 9,000, obviously that’s a very different ballgame from the perspective of scale and points of interconnection.” (See Vineyard, Anbaric Team on 1,200-MW Offshore-Tx Proposal.)

Storage and Hybrid

Distributed storage will continue to be a significant part of the region’s installation base, said Jason Burwen, vice president of policy for the Energy Storage Association.

“You’re going to see a significant fraction of deployment coming onto distribution systems … and the duration of these assets getting longer,” Burwen said.

The story, he said, is the decline in costs, precipitous and somewhat unprecedented in the history of energy technologies at bulk scale, with 8 to 10% declines in installed costs from year to year.

All the storage in the country amounted to 1,200 MWh in 2017, while today a single facility planned to go online in California next year will have the same 1,200-MWh capacity, Burwen said.

“That gives you a sense of how the order of magnitude of the amount of storage coming onto the system is changing, as well as the size of these projects,” he said.

Aside from its known benefits of providing flexibility and balance on the grid, “you’re going to see storage used for congestion avoidance and curtailment avoidance, and that becomes particularly important at much higher levels of renewables, whether that’s in more localized systems for congestion, or on a more systemwide basis for the curtailment issue,” he said.

“Adding storage to our assets across the country is the lowest-hanging fruit,” Kemp said. “In the Northeast … the first and easiest entry point has been the distributed market … relatively straightforward, predictable revenue streams for adding storage to various sizes of distributed assets.”

But there is still work to do on the wholesale market side, Kemp said, citing the ISO/RTO filings in December on Order 841 implementation to allow for greater market participation by storage resources. (See RTOs/ISOs File FERC Order 841 Compliance Plans.)

“There are a lot of problems there,” Kemp said. “I think Order 841 from FERC symbolically looks great, but … we’re not there yet. In New York, there’s discussion about dispatch, whether that has to be controlled by the ISO because of software constraints. … ISO-NE is in some ways simpler because they have the Pay-for-Performance.”

The Pay-for-Performance program took effect last June to replace the RTO’s Winter Reliability Program, increasing financial incentives for resource owners to make investments to ensure reliability and responsiveness during periods of scarcity.

— Michael Kuser

March 10, 2019

PJM MIC Briefs: March 6, 2019

VALLEY FORGE, Pa. — The PJM Market Implementation Committee on Wednesday heard a first read on a proposed change to the calculations for financial transmission rights forfeitures.

Brian Chmielewski, manager of market simulation, said PJM and the Independent Market Monitor agreed the current forfeiture rules should be adjusted because they do not distinguish between on-peak and off-peak FTRs.

Joe Bowring, Independent Market Monitor | © *RTO Insider*

Chmielewski said the issue was discovered in January but that the RTO determined its code is aligned with the Operating Agreement and Manual 6 and that no rebilling was necessary.

FTR forfeitures are intended to discourage traders from cross-market manipulation — for example, placing increment offers or decrement bids to cause congestion on paths where they hold FTR positions.

Holders subject to forfeiture are credited for the hourly cost of the FTR. Under current rules, a $1,500 off-peak FTR for June 2018 would be credited an hourly cost of $2.08, equivalent to $1,500 divided by 720 hours (30 days x 24 hours). Under the proposed change, the FTR cost would be divided by only 384 off-peak hours, increasing the credit to $3.91.

PJM plans a vote on the changes at the April MIC, with first read at the April meeting of the Markets and Reliability Committee and an effective date in the third or fourth quarter.

Current and proposed FTR forfeiture formula | *PJM*

Incremental Auction Revenue Rights Funding

Chmielewski also presented the first read on a problem statement and issue charge to address a risk to FTR market revenue funding. The initiative concerns the awarding of incremental auction revenue rights (IARRs) — ARRs created by the addition of required transmission enhancements, merchant transmission or customer-funded upgrades.

IARRs are granted to the customer only if the transmission improvement provides additional capacity that makes the request feasible. PJM guarantees that awarded IARRs are at least 80% of studied IARR megawatts.

Chmielewski said underfunding of interregional IARRs could occur because MISO’s rules cannot guarantee future firm flow entitlements (FFEs) to PJM for upgrades built for IARR requests. Any portion of the FFEs for an affected coordinated flowgate that is less than 80% of the IARR megawatt total will result in inadequate FTR revenues, the RTO has found.

The MIC will vote on the initiative at the April meeting. PJM wants stakeholder work completed by Aug. 1 to allow implementation of the new rules for the 2020/21 planning period.

Gas Contingencies Update

PJM will take its rejected gas contingencies proposal back to the MRC on March 21 for stakeholder input on what a new plan might look like, PJM’s Thomas DeVita told the MIC.

On Feb. 19, FERC Rejects PJM’s Gas Pipeline Contingency Proposal.)

PJM’s filing would have allowed generators to request cost recovery across nine categories, such as overrun charges and exceeding maximum daily quantity.

The proposal would have allowed crediting of non-penalty switching costs prior to commission approval, subject to refund, while penalty costs would be credited only after commission approval.

FERC described PJM’s definition of “penalty” — costs that are designated as such in the pipeline or local distribution gas company tariff — as “unreasonably narrow and unsupported.” The commission said situations that trigger penalties by some pipelines are called switching costs by others.

The commission also said PJM must add events that trigger fuel-switching directives in its Tariff because they “significantly affect rates, terms and conditions.”

PJM staff said Wednesday it was “somewhat telling” that FERC rejected the order without prejudice, leaving the door open for the RTO to tweak the proposal for resubmission.

March 6 Day-ahead Results Rerun

PJM told members it had to rerun the results of its day-ahead market for March 6 but that the changes were minor.

The bidding period was extended by a half-hour because of “challenges” getting up-to-congestion bids into Market Gateway, PJM’s Tim Horger said. Staff had to make some manual transfers of data, which resulted in about 10% of UTCs not being transferred properly.

“The impact was minor. I understand that’s relative to participants as to what minor would be,” Horger said. He said unit commitments for physical generation did not change, although the dispatched megawatts may have. The revised results were posted Wednesday afternoon.

Load Management Testing Requirements

Members approved by acclamation a problem statement and issue charge on load management testing requirements.

PJM said the RTO’s current testing rules are based on limited demand response (LDR) requirements made obsolete by Capacity Performance.

LDR applied only to summers, non-holidays and weekends, while CP requires the resource on demand year-round. Likewise, CP events can now last up to 15 hours — versus just six under LDR — and lack LDR’s cap of 10 reductions a year.

The Demand Response Subcommittee is expected to take 12 months to investigate the issue and recommend potential changes. Any rule changes would require revisions to the Reliability Assurance Agreement and several manuals, PJM’s Jack O’Neill said. (See PJM DR Subcommittee to Review Capacity Test Requirements.)

OASIS

PJM’s Chris Advena provided a first read on the update of the Open Access Same-Time Information System (OASIS) tool, which he said has been unchanged since 1990.

Advena said the changes are administrative and cosmetic, including product name changes, additional fields and the automation of annulment request evaluations, a process currently done via email. The MIC will be asked next month to endorse related changes to the regional transmission and energy scheduling practices.

The new tool also will reflect changes to the business practices of the Neptune, Hudson and Linden VFT merchant transmission facilities.

Early Look at Redesigned Homepage

PJM has posted a beta version of its redesigned home page available for visitors to test and provide feedback before its scheduled rollout at the end of March. RTO officials also gave stakeholders a sneak peek at the redesign during meetings last week.

The new design is intended to highlight “more dynamic and up-to-date content,” including announcements and real-time grid conditions, PJM said. The new homepage also includes a new section for filings and orders, streamlines meeting and training information, and includes a reorganized and expanded footer with links and contact information.

Questions and comments can be sent to webfeedback@pjm.com.

– Christen Smith and Rich Heidorn Jr.

March 10, 2019

PJM PC/TEAC Briefs: March 7, 2019

VALLEY FORGE, Pa. — PJM last week scheduled two meetings in the coming weeks to discuss rules for removing projects from the Regional Transmission Expansion Plan.

Aaron Berner, PJM’s manager of transmission planning, told the Planning Committee on Thursday that the RTO crafted a problem statement for a holistic review of the process in response to stakeholder concerns over rules for removing supplemental projects.

The initiative could result in changes to Manual 14B. Staff, he said, are otherwise “unconcerned” with existing manual language.

He said meetings scheduled for March 22 and March 29 will focus on educating stakeholders about PJM’s past project cancellations — a process that is currently handled on a case-by-case basis resulting from a reduction in load forecasts or because developers are unable to get state siting approval.

“We should look to solidify rules that are consistent among the three project types: baselines, network upgrades and supplementals,” Berner said. “They are all modeled the same.”

The issue arose after Sharon Segner, vice president of LS Power, proposed an amendment to Manual 14B: PJM Region Transmission Planning Process specifying that a transmission owner’s supplemental project “will generally be removed from the RTEP” following a final order by a state siting agency rejecting the project. Supplemental projects are proposed by TOs and are not required for compliance with PJM’s reliability, operational performance or economic criteria. (See PJM Rebuffs Stakeholders on Supplemental Projects.)

At Segner’s request, the Markets and Reliability Committee last month agreed to delay a vote on revised transmission planning rules for 60 days to accommodate further discussion on the language. (See “Transmission Replacement Vote Deferred Until April MRC,” PJM MRC/MC Briefs: Feb. 21, 2019.)

Sharon Segner, LS Power | © *RTO Insider*

“Certainly, we don’t object to having a broader discussion” at the March 22 meeting, she said Thursday. “We request the specific issues we listed for discussion in the delay motion to be part of the agenda for the March 22 meeting.”

Ed Tatum, vice president of transmission for American Municipal Power, said he was confused by the problem statement. He said there are many improvements AMP would recommend to the modeling process for adding or removing facilities, but that doesn’t seem to be what PJM wants to tackle.

“This is really more of PJM’s position on the MRC’s direction than a problem statement,” he said. “Stakeholders raised concerns that PJM should simply acknowledge that it has the same discretion to supplemental projects as it does to all other projects,” he continued. “It’s important to have a good understanding of the types of projects PJM has already removed from the plan.”

PC Chairman Ken Seiler said staff will “tighten up” the language of the problem statement based on stakeholders’ comments and present a revised draft at the March 22 meeting.

PJM Readies Package on Market Efficiency Rule Changes

PJM presented the first read on proposed rule changes developed by the Market Efficiency Process Enhancement Task Force.

Brian Chmielewski, PJM’s manager of market simulation, said the package that staff will present for a vote at the PC’s April 11 meeting changes how often the RTO will re-evaluate projects and shifts the long-term submission window and timing of the mid-cycle updates.

Chmielewski said the task force agreed PJM will not re-evaluate any projects once a certificate of public convenience and necessity (CPCN) has been issued or — in the case of states without such a process — once construction has begun. Under current rules, PJM reviews the costs and benefits of economic-based transmission projects annually to ensure they remain economical.

Ed Tatum, American Municipal Power | © *RTO Insider*

Both the costs and benefits of market efficiency projects costing more than $20 million will be re-evaluated annually if they lack CPCNs or are not subject to such requirements. Projects under $20 million will not be re-evaluated if the updated costs do not cause the benefit-cost ratio to fall below 1.25 based on the original benefits.

Segner said LS Power supported the language, noting her comfort level came with PJM’s qualifiers for how the process changes under different state regulatory requirements.

“Essentially, if you are in a state that needs a CPCN, the state grants it or they don’t, and the re-evaluation stops at that point,” she said. “If your permits are more municipality-driven … the test for states that don’t have a CPCN process is physical construction because the focus of stopping the re-evaluation is tied to the construction at the physical site.”

PJM attorney Pauline Foley agreed and said the distinction between the two divergent processes “puts us in a lot better place than we are today regarding when re-evaluation can cease.”

The task force also proposed shifting the long-term window back two months to January-April from November-February to align it with MISO’s processes. If approved, both RTOs would post economic drivers in January.

The mid-cycle model refresh would be made in late April to allow project proposers extra time to analyze their projects under the revised case prior to a final submission.

The changes were the result of the task force’s “Phase 2” discussions.

Staff will seek PC and MRC approval of the changes in April, with Members Committee endorsement of Operating Agreement revisions scheduled for May. PJM wants the new rules effective Aug. 1 for the 2020/21 long-term window.

Chmielewski said the task force is considering a third phase of discussions after failing to reach consensus on two other proposals:

Evaluating regional targeted market efficiency projects to address historical congestion using the same criteria as used in interregional TMEPs; and
Changing the 1.25 benefit-cost threshold to measure energy benefits separately from capacity benefits.

Revisions from Order 845

PJM says it has met, or is close to meeting, changes required by FERC’s Feb. 21 ruling clarifying Order 845.

In Order 845-A, the commission ruled on 12 requests for rehearing or clarification of the 2018 rulemaking intended to improve the transparency and timeliness of the generator interconnection process. (See ‘Boring Good’ Rulemaking Seeks to Clean up Order 845.)

PJM’s Susan McGill briefed the PC on four Tariff or manual changes it has finalized and said an additional six changes will be presented to the PC in April. The RTO faces a May 22 deadline for its compliance filing.

Among the changes will be new definitions and clarifications and a new Tariff section for nonbinding dispute resolution procedures including interconnection customers.

Offshore Interconnection Rights Meetings Begin in April

PJM will commence a series of stakeholder meetings on offshore wind development and merchant transmission beginning April 16.

Suzanne Glatz, PJM’s director of infrastructure planning, said the first meeting will consist of education about the RTO’s current process, followed by three months of exploration into alternative options before returning to the PC in August for endorsement of proposed changes.

Last month, the committee approved a problem statement to consider granting merchant transmission developers capacity interconnection rights (CIRs) for offshore wind. (See “PC Moves Forward on Offshore Interconnection Rights,” PC/TEAC Briefs: Feb. 7, 2019.)

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, stakeholders will consider allowing merchant transmission developers to request CIRs, or equivalents, for non-controllable AC transmission offshore.

$15M Project to Solve High-voltage Alarms in Dayton Zone

Berner told the Transmission Expansion Advisory Committee on Thursday that PJM and Dayton Power & Light planners have identified a $15 million solution to address excessive high-voltage alarms in the utility’s zone. The utility has logged approximately 19,000 alarms over the last two years.

The alarm-to-minimum-load-hour ratio nearly doubled between 2017 and 2018, Berner said, with 327 alarms over the two years at 345-kV buses.

PJM said the problem is attributable in part to plant retirements, which have left the zone with only peaking plants.

The RTO said that after exhausting all typical operating procedures, Dayton is frequently forced to switch out equipment to avoid long-term damage from high-voltage exposure — a practice it finds unsustainable and ineffective.

The solution will be the installation of three 100-MVAR reactors with a projected in-service date of Dec. 31, 2021. They will be located at the 138-kV Miami, Sugarcreek and Hutchings substations.

Alarms by 138-kV substation, January 2017 to December 2018, for Dayton Power & Light | *PJM*

End-of-life Project for London-Dulles Junction

Dominion Energy plans to rebuild a 4.4-mile-long section of the 230-kV #2008 line between Loudon and Dulles Junction in Virginia to eliminate corroding towers.

PJM said removing a section of the line would cause 241 MW of load to be on radial and 311 MW of load to be dropped by a failed breaker contingency at the Reston substation.

Line #2008 will share the towers of line #2173, double-circuit structures that currently have an empty arm.

Dominion also plans to retire the 8.44-mile-long line #156 from Loudoun to the Bull Run substation and cut and loop a 230-kV line into the substation to prevent thermal violations. Three 230-kV breakers would be added to accommodate the upgrade.

The plan also removes two 230-kV transformers and a 115-kV capbank at the Loudoun substation; removes a 115-kV capbank at the Bull Run substation; and removes a 230-kV line switch from line #295 at the Bull Run substation.

The project is expected to be in service by the end of 2023.

Separately, Dominion canceled a $2.7 million project to add three 500-kV breakers at the Mt. Storm substation after the manufacturer indicated existing breakers are capable of 44 kA.

LS Power’s Segner said PJM should evaluate whether the Loudon-Dulles Junction project would address any regional needs and should be subject to the Order 1000 competitive process.

She cited the August 2018 D.C. Circuit Court of Appeals ruling ordering FERC and PJM to reconsider how they allocate the costs of high-voltage transmission projects developed to satisfy individual utilities’ planning criteria. The court ruled in a case prompted by Old Dominion Electric Cooperative, Dominion Energy Services and Virginia Electric and Power Co., which had challenged FERC’s approval of a PJM Tariff revision that resulted in the RTO assigning all the costs for two transmission projects proposed by the companies to the Dominion zone (17-1040, 17-1041). (See DC Circuit Rejects PJM Tx Cost Allocation Rule.)

The commission has not acted on the remand order.

“Because the matter is remanded to FERC, we need to wait and hear what FERC is going to say on this issue,” PJM’s Foley responded. “So, we’re on hold. … When the commission finally addresses this issue, we will implement what it decides.”

Dominion, ATSI Supplemental Projects Presented

Dominion gave the TEAC a pres e ntation on several supplemental project needs:

A new Paragon Park substation to support existing data center load and a new data center campus in Loudoun County with a total load in excess of 100 MW;
A third, 84-MVA distribution transformer at the Poland Road substation in Loudoun County to address customer load growth and contingency loading for the loss of one of the existing two transformers; and
The replacement of the aging Chesterfield Tx#9 and Peninsula Tx#4 224-MVA, 230/115-kV transformers.

Dominion also presented proposals to:

Install a 1200-A, 40-kAIC circuit switcher and associated equipment to feed the fourth transformer at the BECO substation in Loudoun County ($750,000); and
Interconnect the new Buttermilk substation with line #2152 (Cumulus-Beaumeade) and line #2170 (Roundtable-Pacific), and install line switches, circuit switchers and bus work for the new transformers ($11 million).

American Transmission Systems Inc. presented a plan to rebuild 1.5 miles of the Perry-Ashtabula-Erie West 345-kV tap line as a double circuit at a cost of $23.7 million. The current three terminal lines are prone to misoperations with lengthy fault locating analyses and restorations. The company said the existing transmission relay communication equipment is approaching its end of life and is difficult to maintain and repair.

– Christen Smith and Rich Heidorn Jr.

March 10, 2019

MISO Expects ‘Modest’ Spring Risk

CARMEL, Ind. — MISO foresees a “modest probability” it will declare a systemwide maximum generation event this spring.

The RTO last week said such a scenario would culminate from both high loads and forced outages, and it stressed that the need for emergency procedures will be “impacted by the availability of resources,” such as wind generation, capacity imports, stranded capacity and load-modifying resources.

MISO predicts a 101-GW peak this spring and says it has 150 GW of resources, including load-modifying resources, available to cover demand and outages. Last spring, total outages in the RTO in April neared 50 GW, the highest level in the last five years.

The National Oceanic and Atmospheric Administration forecasts average temperatures in MISO Midwest and higher than normal temperatures in MISO South during the season.

Speaking at a March 7 Market Subcommittee meeting, Manager of Probabilistic Resource Studies Ryan Westphal said the forecast indicates a good chance of a “normal spring for the north part of the footprint.”

MISO has projected it has a probable 103.3 GW worth of generation capacity in March, 95.2 GW in April and 105.1 GW in May.

Westphal said the RTO expects May to have the highest chance of systemwide maximum generation event procedures.

MISO’s all-time record spring peak occurred last year on May 29 when unseasonably hot weather prompted a 107-GW peak load. (See “Volatile Spring,” MISO Players Probe Causes of Increasing Emergencies.)

Meanwhile, in preparation for summer, MISO will hold readiness drills for members to review emergency operation procedures on April 18, April 25, May 2, May 9, May 16 and May 23. It will also hold its annual summer readiness workshop on April 23.

— Amanda Durish Cook

March 10, 2019

MISO, Stakeholders Debate Merits of Seasonal Auction

By Amanda Durish Cook

CARMEL, Ind. — MISO last week revived the idea of implementing a seasonal capacity auction as part of its multipronged resource availability and need (RAN) initiative but promised to gather more data on resource flexibility before defining long-term solutions.

Seasonal Auction Revival

MISO planning adviser Davey Lopez said he’s observed a shift from stakeholders criticizing a two-season capacity auction to becoming open to analysis of possible benefits, including better capacity availability and price signals. Lopez also said stakeholders indicate the most support for a four-season construct. However, stakeholders still support holding a single auction rather than performing auctions in different seasons, he added.

But whether that single auction would be conducted simply with seasonal inputs, encompass four separate seasons or be four auctions performed simultaneously remains to be seen, Lopez said. MISO said it will work on seasonal design elements through the end of the year.

“I think by the end of the year we’ll have at least some results on here’s what a seasonal auction would look like and here’s what the results will be,” Lopez said at a March 6 Resource Adequacy Subcommittee meeting.

But representatives from Xcel Energy, DTE Energy and Madison Gas and Electric said they still favored MISO’s erstwhile monthly auction design. The RTO switched from monthly voluntary auctions to an annual voluntary capacity auction in 2013.

MidAmerican Energy’s Greg Schaefer said the monthly auction was a lot of work that yielded unclear price signals.

“Rather than leaping from once per year to 12 times per year, let’s try something intermediate,” Schaefer urged.

But some stakeholders say price signals are no better in MISO’s current capacity situation.

“With the current annual construct, we don’t have a price signal … we have a price that is essentially zero,” Coalition of Midwest Power Producers’ Mark Volpe said.

Many stakeholders said MISO must come prepared with study results that show a seasonal capacity auction will solve potential capacity shortfalls.

“From our perspective, the case has yet to be made, and the analysis has yet to be exhausted,” WPPI Energy’s Steve Leovy said. He also argued that MISO shouldn’t proceed with a seasonal auction unless the RTO’s loss-of-load expectation (LOLE) study shows risks outside the summer season.

MISO Independent Market Monitor Michael Chiasson said the current annual capacity market design prohibits some resources unavailable in the summer from entering the market at all.

“So those are essentially lost resources from a capacity value perspective. This sort of flexibility should increase the number of capacity resources. … That will make our market a lot deeper … and more economically efficient,” Chiasson said.

“Assuming that the LOLE can be edited, [we still] need to be careful about summer and winter compared to the spring and fall,” Minnesota Public Utilities Commission staff member Hwikwon Ham said, emphasizing that MISO should still recognize that summer and winter risks will continue to be more pronounced than those in spring and fall.

“I need to remind people we’re in a planning reserve sharing group. And if we go to seasonal accreditation, what’s the point of being in the MISO?” Consumers Energy’s Jeff Beattie said. “The bottom line is we need to show value in this; otherwise we’re going to … be in a ‘Groundhog Day’ situation,” Beattie said in reference to MISO’s proposed, three-year forward capacity auction design that was rejected by FERC in early 2017.

Beattie noted that Consumers is relying on MISO’s reserve sharing characteristics while its Ludington pumped storage facility is on an extended outage for major upgrades. He said when the facility returns, Consumers will repay the reserve-sharing debt with nearly 2 GW in storage capacity.

Consumers has said MISO moving to a two- or four-season construct would be “a step back” in the RTO’s value to stakeholders unless it also devises a method for monthly true-ups, similar to NYISO’s practice.

“A seasonal construct with a minimum of two seasons with forward monthly true-ups has been proven to be FERC-acceptable for many years,” Consumers said in comments to MISO.

Mississippi Public Service Commission consultant Bill Booth asked how a seasonal auction construct would impact MISO’s annual must-offer requirements for resources.

“It may be a little premature to talk about must-offer requirements … but I think, yeah, we’d have to address the must-offer requirement in some form or fashion,” Lopez said.

MISO Director of Resource Adequacy Coordination Laura Rauch said the RTO may find it needs a higher percentage must-offer requirement but a lower overall megawatt requirement for fall, when outages spike and weather becomes volatile.

“There will be impacts across the board that we’ll have to analyze,” Rauch said.

Lopez said outages in particular will be a consequential variable for a seasonal auction. He also said MISO will have to examine seasonal auction inputs, including the loss-of-load target, planning reserve margins, local reliability requirements and capacity import and export limits. Resources, including wind and solar generation, would also need accreditations that vary by season.

Lopez said MISO will likely devise hypothetical seasonal inputs and study them against annual auction values based on a summer peak.

Data on the Way

MISO this week committed to more internal study on its system to gather more data to support future long-term RAN solutions, including the possible seasonal capacity auction.

At a March 7 Market Subcommittee meeting, MISO market design adviser Dustin Grethen said the RTO will conduct an analysis to provide “visibility into availability and flexibility.”

“So a lot of buzzwords there,” Grethen said, smiling. “We’re really going to be digging deep into availability and flexibility. What are the system needs and characteristics that MISO has? … We need to make sure we have good empirical evidence for the things we’re proposing.”

MISO said it will assess multiple years of hourly, real-time location-specific values for load, reserves and net-scheduled interchange. It will use those data sets to look into changing needs for energy, ramp and reserves in MISO regions and in load pockets throughout the year. Grethen said MISO will also examine its past forecasts and the “final disposition” of all megawatts that were potentially available to meet system needs. The goal is to quantify MISO’s uncertainty and resource flexibility, he said.

Grethen also said stakeholders have made “many calls” for MISO to develop a multiday market forecast as part of the RAN project. He said MISO will have to complete its data-gathering and future discussion before such an addition is made. Discussions on a multiday forecast are currently on hold until early 2020, according to the RTO’s Market Roadmap list of possible market changes.

Xcel Energy’s Kari Hassler asked MISO to not assume in its new analyses that coal and nuclear resources continue in their must-run capacities, as incentives to continue operating such generation are vanishing.

“Please don’t assume that all of your must-run resources will continue to run that way,” she told Grethen, who took notes.

“Waiting for data is not the answer. Volatility is a given; uncertainty is a given. We have to work under that assumption instead of waiting for data. To me, that’s a very dangerous proposition,” the Minnesota PUC’s Ham said.

Ham also said as long as distributed energy resources aren’t visible to MISO, its data collection will continue to be incomplete. He said MISO should aggregate DERs and let them into the market in order to alleviate some uncertainty.

Grethen said MISO hasn’t been sitting on its hands waiting for data and pointed to its three “stopgap” Tariff filings aimed at freeing up 5 to 10 GW of capacity this spring. MISO has two near-term filings awaiting FERC action as part of the short-term piece of the three-phase RAN project, one to subject demand response to annual capability testing and one to impose new generator accreditation penalties for planned outages taken with fewer than 120 days notice and during “low-margin, high-risk periods.” (See MISO LMR Capacity Rules Get FERC Approval.)

History on Repeat?

As part of RAN, MISO is also mulling modeling both nonoptimized planned outages and resource lead times in its annual LOLE study, and an investigation into how resources are accredited before the 2020/21 Planning Resource Auction. MISO’s current LOLE doesn’t account for either variable. Lopez also said MISO will continue to evaluate its capacity accreditation for the PRA over the next several months.

However, MidAmerican’s Schaefer said he didn’t see why MISO was considering modeling sub-optimized scheduled outages in the LOLE when it has a Tariff filing out for FERC approval aimed at improved scheduling.

“It doesn’t make sense that we’re telling FERC we can do better. … We just can’t blindly tell FERC that history will repeat itself when we’re telling FERC that history won’t repeat itself,” Schaefer said.

March 10, 2019

Showdown Set on PJM Must-offer Exceptions

By Christen Smith

VALLEY FORGE, Pa. — Members of the PJM Market Implementation Committee on Wednesday set up a showdown over whether the RTO can force capacity resources into energy-only status for failing to meet Capacity Performance requirements.

About 61% of MIC voters endorsed an Exelon proposal that would allow capacity resources to voluntarily switch to energy-only status but would not allow PJM to force such a switch. Eighty-five percent also said they preferred the Exelon rules over those proposed by PJM and approved by the MIC in November. The votes made the Exelon proposal eligible to be considered by the Markets and Reliability Committee next month.

Both proposals, which would require changes to Manual 18 and the Tariff, will receive first reads at the March 21 MRC meeting. However, the November proposal will be voted on first at the April 25 MRC meeting because it was previously approved by the MIC, winning 79% support. The Exelon proposal will only get a vote if the November proposal fails to clear the necessary two-thirds sector-weighted threshold.

MIC members Wednesday also preferred Exelon’s proposal over a joint plan from PJM and the Independent Market Monitor that received only 35% support, below the 50% threshold for consideration by the MRC. About 49% preferred the PJM-IMM plan to the November proposal.

Remand

The original MIC-endorsed plan was remanded back to the committee in December after the MRC agreed further discussions were needed. It would require existing capacity resources not offered in three consecutive auctions to change to energy-only status. Capacity interconnection rights (CIRs) of such resources would be terminated one year from the switch to energy-only, unless the rights holder submits a new generation interconnection request within that year using those same CIRs.

The PJM-IMM proposal would have added to the November proposal a requirement that any resource receiving a must-offer exception file a plan showing how it will become able to satisfy CP requirements in order to retain capacity status. The requirement would be effective with the 2023/24 delivery year. Resources would be granted exceptions for no more than two auctions. (See PJM MIC to Vote on Alternative Must-offer Exception Rules.)

“Both [the original proposal and PJM-IMM addition] have a requirement for units with CP must-offer exceptions to go energy-only after a certain amount of time,” PJM’s Pat Bruno said. “The main difference between the two is the way that they would be required to go energy-only and how soon that would take effect.”

Sharon Midgley, Exelon | © *RTO Insider*

Exelon said it did not support a mandatory switch to energy-only because stakeholders were not in consensus on the issue, which raised equity issues over resources’ potential loss of CIRs. Intermittent resources are exempt from must-offer rules.

“We were able to support the compromise approach previously endorsed by the MIC,” Sharon Midgley, senior manager of wholesale market development for Exelon, said Wednesday. “Exelon does not support the PJM-IMM alternative proposal. We have concerns with the mandatory process and concerns with the CIR inequities between traditional generation resources and renewables.”

‘Unlevel Playing Field’

Other generation owners agreed with Exelon’s objections.

David “Scarp” Scarpignato, Calpine | © *RTO Insider*

“If you have renewable resources that aren’t offering into auctions … they should probably forfeit CIRs for all the same reasons,” said David “Scarp” Scarpignato of Calpine. “Allowing energy-only wind resources to have CIRs and to say generators of other types aren’t allowed to is a completely unlevel playing field. It’s more than problematic. It’s contrary to the Operating Agreement.”

Consultant Roy Shanker agreed that PJM should subject renewables to the same requirements as traditional resources.

“If we can hold the CIR without being CP based on an exemption, then they get to do that,” he said. “To Scarp’s point, then they, just like everybody else, should be expected to forfeit CIRs under the same conditions. We passed the hurdle a long time ago that those definitions of capacity resources within CP being different going forward. They go hand in hand. To me, there’s no reason to partition between anyone.”

John Brodbeck, EDP Renewables | © *RTO Insider*

John Brodbeck of EDP Renewables argued companies like his pay for interconnection upgrades and receive CIRs in return. “When you pay for something, you want to own it,” he said.

Load interests, however, said generators’ focus on who owns CIRs muddles the issue. Carl Johnson of the PJM Public Power Coalition said some legacy generators stand to lose CIRs for which they never paid.

“Some may have [paid], many have not,” he said. “As topology has changed, a lot of legacy generators did not pay for them. Loads have.”

March 8, 2019

WECC Board Continues Focus on RC Transition

By Hudson Sangree

The Western Electricity Coordinating Council continued to deal with issues related to this year’s reliability coordinator transition at its board of directors meeting in Salt Lake City on Wednesday.

Among the matters heard was an update from Peak Reliability CEO Marie Jordan on the wind-down of the company’s operations this year as CAISO, SPP and BC Hydro prepare to take over RC functions across the Western Interconnection by the end of 2019. (See Peak Reliability to Wind Down Operations.)

Keeping key staff on board at Peak and maintaining high operational standards are among the top priorities, Jordan told WECC board members.

WECC’s board and committees meet in Salt Lake City. | *WECC/Kirha Quick*

Another issue discussed was WECC’s proposed process for requesting key data and information from the incoming RCs under NERC Rules of Procedure Section 1600. The planned move reflects the new operating conditions in a multiple-RC environment rather than one exclusively overseen by Peak, WECC staff said.

“We’ve been working internally for about the past nine months to put this together in anticipation of moving to the multi-RC environment and want to make sure that WECC maintains its options for the receipt of information,” WECC General Counsel Steve Goodwill said.

“Because a Section 1600 request would only apply to U.S. entities, not to our Canadian or Mexican partners [such as BC Hydro], we need a different mechanism to collect data from them,” Goodwill said.

WECC had provided the draft Section 1600 request to incoming RCs and NERC, “totally informally but just for their review and comment before we started any formal process,” Goodwill said. WECC incorporated their comments and changes, and in February it initiated a formal Section 1600 request, he said. The final draft was submitted to NERC and FERC last month for a 21-day comment period, which will be followed by a 45-day period starting Friday for stakeholder comments.

The WECC board still must give final approval to the request. “We would like to have that in place by mid-June at the board meeting so that as the RCs go live, we can issue the data request to them,” Goodwill said. CAISO will assume the RC role for its existing territory on July 1, “so that keeps us on the right timeline.”

Peak Reliability Update

At WECC’s last board meeting in December, speakers expressed concerns about the multiple turnover dates involved in the Western RC transition, each of which could provide opportunities for errors. (See RC Transition Fraught with Pitfalls, WECC Hears.)

WECC’s board of directors meet Wednesday. From left to right: Chair Kristine Hafner, President and CEO Melanie Frye, Gary Leidich and Richard Campbell. | *WECC/Kirha Quick*

After CAISO, BC Hydro will become the RC for most of British Columbia on Sept. 2. CAISO will then take over for many areas outside its footprint on Nov. 1, while SPP will take responsibility for other parts of the West on Dec. 3.

Another area of concern was the ability of Peak to hang on to essential staff members through the long transition.

After announcing it would get out of the RC business and end operations, Vancouver, Wash.-based Peak saw a number of employees depart, Jim Shetler, general manager of the Balancing Authority of Northern California and chair of Peak’s Member Advisory Committee, told the WECC board in December. Some Peak employees in Washington and Colorado took positions with electricity entities in those areas, he said.

To stem attrition, Peak detailed the severance packages that employees will receive if they stay with the company until they’re no longer needed, he said. With that, Shetler said, “the unplanned departures, I expect, will come down quite a bit.”

Peak said in January that of its 169 staff members at the start of 2018, 23 had left by the end of the year. Peak’s RC department declined from 42 staff members to 34 throughout 2018.

Jordan’s presentation to the board seemed to partly confirm Shetler’s prediction that the attrition would abate with increased transparency and communication with employees. Staffing levels in Peak’s RC department have held steady since October, Jordan’s presentation showed, though some engineering and IT employees continued to depart through February.

March 8, 2019

FERC Blocks GridLiance Oklahoma Tx Acquisition

By Robert Mullin

FERC on Wednesday rejected GridLiance High Plains’ plans to acquire transmission assets from Oklahoma-based People’s Electric Cooperative, finding the company failed to prove the transaction would not have an adverse impact on rates (EC18-122).

The proposed deal would have seen GridLiance take over 55 miles of 138-kV lines and a substation from People’s, which provides electricity to about 15,000 members across 11 Oklahoma counties and operates a 4,500-mile distribution and transmission network.

People’s Electric Cooperative line in Oklahoma | *People’s Electric Cooperative*

Completion of the transaction was subject to FERC accepting GridLiance’s proposal to earn an annual transmission revenue requirement on the assets by moving them under the company’s commission-approved rates in SPP. The co-op is not a member of the RTO.

In making its case for the acquisition, GridLiance contended the rate impact would be small: about $2.7 million, based on a $14.9 million net book valuation of the assets. It said “non-quantifiable” benefits would offset those costs.

In rejecting GridLiance’s request, the commission acknowledged that the transaction “on its face” resembled those of similar proposals it had approved in the past. Like GridLiance, the buying party in each of those deals acknowledged the acquisition would increase rates for transmission customers, “which the commission has acknowledged ‘is not unexpected’ when the transaction involves ‘ownership changes from a not-for-profit utility to a for-profit business with a different capital structure, tax obligations and the need to earn a return,’” the commission wrote, citing a previous decision.

In each of those transactions, applicants contended that the rate increases were justified by the non-quantifiable benefits of transmission company ownership and therefore not “adverse.”

But in Wednesday’s decision, the commission pointed out that its approvals were based on the specific facts at play in each request. GridLiance, the commission said, failed to back up its promised benefits, or show that they would offset the proposed rate increases.

FERC questioned GridLiance’s claim that the acquisition would increase reliability for retail customers receiving service over People’s transmission system, noting that only 47 MW of load are being served by the transmission feeds being acquired.

“Without further evidence as to the reliability benefits of the transaction, we cannot find that the benefits of increasing the reliability of service to this relatively small amount of retail load is sufficient to offset the rate increase resulting from GridLiance’s acquisition of the assets,” the commission said.

The commission also rejected GridLiance’s contention that the transaction would provide the non-quantifiable benefit of promoting transmission company ownership of facilities.

“This argument simply restates the general holding of the commission’s cases described above without explaining how GridLiance’s ownership of the assets provides benefits that offset the projected rate increase,” FERC said.

The commission also rebuffed GridLiance’s claim that its ownership would improve operations and efficiency in SPP, pointing out that while the lines could be made more reliable if looped into the RTO’s system, they would still be primarily serving the same small volume of industrial load. “GridLiance has failed to demonstrate how placing the assets under SPP’s control would maximize the use of the assets, minimize the need for new transmission or provide new avenues for transmission expansion,” the commission said.

Finally, FERC rejected GridLiance’s argument that the acquisition would further the commission’s goal of increased RTO participation among publicly owned utilities.

“Here, the addition of 55 miles of transmission facilities whose only use is to deliver power to industrial customers does not materially add to the size or scope of SPP, nor has it been shown to provide other material benefits to SPP,” the commission concluded.

March 8, 2019

Capacity Market Sellers Anxious over Uncertain PJM Auction Rules

By Christen Smith

VALLEY FORGE, Pa. — Capacity market sellers expressed anxiety Wednesday over PJM’s “parallel path” for its upcoming Base Residual Auction, urging staff to consider delaying the auction until FERC clarifies the minimum offer price rule (MOPR).

Stu Bresler, PJM senior vice president of operations and markets, said the RTO is asking capacity sellers to adhere to BRA timelines under current rules as a preventative step in case the commission provides no additional guidance before the auction, which has already been delayed to Aug. 14.

FERC last summer granted PJM’s request to delay the auction in response to the commission’s June ruling requiring the RTO to revamp its MOPR to address price suppression from rising state subsidies for renewable and nuclear power (ER18-2222). (See FERC OKs Delay of PJM Capacity Auction.)

PJM filed its proposed MOPR changes Oct. 2 and said a FERC ruling by March 15 would keep the August schedule on track (EL18-178, ER18-1314, EL16-49).

But at Wednesday’s Market Implementation Committee, PJM’s Jeff Bastian said the RTO had no indication when a ruling would be made.

Bastian then walked stakeholders through the upcoming deadlines in what he called its “parallel path” to the August auction, for delivery year 2022/23. The document called for sellers to confirm whether they will be offering resources with “actional subsidies” by March 17 — a deadline stakeholders said was unreasonable.

Staff said they believe only the MOPR will be subject to change in the pending ruling. But they acknowledged the auction might need to be pushed back again if the ruling is not issued soon.

“I would concede that at some point we would get to where it would be impossible to proceed and we would have to look at delaying the auction,” Bresler said. “I don’t have a specific date I can give you at this point.

“I think any delay has some kind of a consequence, so that’s why we are trying to avoid it,” he continued. “We wouldn’t want to go past next May’s auction, obviously. Anything in between has a certain level of negative consequences with it, but I think it gets worse as we go through time.”

Stakeholders balked at the plan, insisting it contradicted the arguments made in PJM’s original delay waiver that its market suffers without certainty.

“It’s hard, as sellers, to know what to provide for MOPR,” said Jason Barker of Exelon. “This new path no longer allows us as sellers to evaluate FERC’s new conditions. This is going to be problematic for market sellers. You guys realize that and wrote it in your Tariff waiver request. Now we seem to be slavishly following a schedule and not the needs balanced in the FERC order.”

Adrien Ford of Old Dominion Electric Cooperative echoed Exelon’s sentiments and complained about the persisting uncertainty across PJM’s markets.

“I don’t feel like there is a single market I can give an update [to colleagues] on with any certainty,” she said. “Then to add this on top of it? I just think it’s going to be really problematic for capacity market sellers.”

John Horstmann, Dayton Power & Light | © *RTO Insider*

John Horstmann of Dayton Power & Light pressed PJM for more time.

“This could be life and death for your unit,” he said. “You’ve heard from a number of stakeholders how there’s going to be huge impacts. And yet you want us, without any real Tariff, to comply with all these data submissions because they might be enforced. Of course, they might not. ‘Oh yeah, and we want it in a week and a half.’ Where’s the reasonableness in that?”

“What we appear to be doing is asking people to make irreversible decisions based on rules that may change,” said Joe Bowring, PJM’s Independent Market Monitor. “It sounds like PJM’s theory is move forward with existing rules and just be prepared for changes.”

March 7, 2019

PJM Operating Committee Briefs: March 5, 2019

VALLEY FORGE, Pa. — PJM’s Operating Committee breezed through a light agenda during its March meeting on Tuesday.

Frequency Response Performance Underwhelms

The number of generators providing primary frequency response (PFR) in 2018 fell short of PJM’s expectations, according to the RTO’s most-recently analyzed d a ta.

Danielle Croop, PJM senior engineer of operations and analysis, told the Operating Committee PFR-capable generators didn’t respond as anticipated during five low-frequency events selected for evaluation throughout the year, at times providing less than half the megawatts PJM expected.

“These five events are the only ones that met the [PJM] criteria for 2018,” Croop said. “There’s usually about 25 or 30 events that meet [NERC’s] BAL-003, so you can see how narrow the evaluation selection is.”

At last October’s OC meeting, PJM shared frequency response data from 13 BAL-003 events between December 2017 and April 2018 that showed similar results. (See “The Right Metric on Frequency Response” in PJM Operating Committee B riefs: Jan. 8, 2019.)

PJM assesses generator performance during events in which the system frequency goes outside a +/-40-mHz deadband for 60 continuous seconds and the minimum or maximum frequency reaches +/-53 MHz. (See “Utilities Question Primary Frequency Response Calculation” in PJM Operating Committee Brief s : Feb. 5, 2019.) The five events fitting into the narrower criteria occurred on Jan. 27, April 7, June 30, Sept. 13 and Sept. 20.

Count of units that provided PFR by % of response compared to expected response. Only units expected to respond are in evaluation. | *PJM*

While generators provided 130 MW of the anticipated 165 MW during the January event, available energy dipped to 50% or less of what PJM expected during the April 7, June 30 and Sept. 13 events.

Brock Ondayko, of AEP Energy, refuted PJM’s expectation for more output, calling it “incorrect.” He said PJM’s existing dispatch software often oversimplifies a resource’s anticipated PFR capability because it doesn’t account for physical operational hold points.

“Until PJM modifies [its] dispatch software to take into account how resources actually operate and then subsequently begins to preposition capable units to respond, ‘expected’ numbers really need to be taken with a grain of salt,” he said in an email Tuesday. “While I sympathize with PJM’s dispatch issues and understand the limitations of [its] current estimates, my continuing to bring up the topic/issues for what has seemed like years has never stopped PJM from continually sharing what must be considered suspect data, without disclaimers.”

Croop defended the numbers during the meeting Tuesday, noting more accurate data will come from analysis of individual generators — to which Ondayko agreed.

“This is not absolute … but it’s a good line in the sand to see if we are getting the PFR we are expecting or not,” Croop said. “I think more intricate details will work through at the generator evaluation level.”

Ondayko requested PJM consider accounting for future PFR sources and those scheduled for retirement, referencing FERC Order 842 requirements.

“It would give us a better sense of how successful the FERC order is going to be or not going to be,” he said.

2018 Primary Frequency Event Response by Megawatts. | *PJM*

Stakeholders Ponder Meeting Changes

As the schedule for upcoming Operating Committee meetings fills up with obligations from new and continuing task forces, stakeholders pondered getting an earlier start.

OC Chair Dave Souder suggested starting April’s meeting at 8:30 a.m. to account for agenda items related to non-retail behind-the-meter generation business rules. Stakeholders approved a problem statement and issue charge revising the existing manual language during Tuesday’s meeting. (See “PJM Continues Review of Non-retail BTM Generation Business Rules” in PJM Operating Committee Briefs: Feb. 5, 2 0 19.)

“I think the 8:30 start time is a little early,” said Sharon Midgley, of Exelon. “And the beginning of the meeting is sometimes important, particularly if there are any controversial endorsement items.”

Jim Benchek, of FirstEnergy, agreed an earlier start time would prove difficult for stakeholders commuting and instead suggested staying an hour later.

Souder proposed implementing a working lunch for future OC meetings, to which no stakeholders voiced any objections. He said PJM’s Dave Anders also suggested moving meetings to Thursday mornings beginning in 2020 so staff could have more time to provide accurate and updated reference materials. Planning Committee meetings would occur Tuesday mornings, instead.

— Christen Smith