VALLEY FORGE, Pa. — Stakeholders at last week’s Planning Committee meeting endorsed PJM’s annual reserve requirement study and recommendations for a 15.7% IRM and a 1.0887 forecast pool requirement (FPR) for next year’s Base Residual Auction, both slight reductions from last year. (See “IRM, FPR Reduced,” PJM PC/TEAC Briefs: Sept. 13, 2018.)

The study found a reduction in the standard deviation for the RTO-wide forced outages from the 2017 study to the 2018 study, which indicates the outliers “are slightly less extreme than they were last year,” PJM’s Andrew Gledhill said.

Staff traced the change back to a “slightly smaller” average unit size this year of 121 MW compared to 129 MW in 2017.

Ride Through

PJM’s Emanuel Bernabeu detailed the results of the RTO’s two-day workshop on distributed energy resources ride-through held on Oct. 1 and Oct. 2.

“We made tons and tons of progress,” he said, adding that staff plan to seek an endorsement vote at the Nov. 11 PC meeting on a problem statement and issue charge to address questions surrounding implementation of a new Institute of Electrical and Electronics Engineers standard on how DERs should react to system voltage fluctuations.

The PC will then vote on endorsing required settings for resources wishing to participate in PJM’s markets, but it will not vote on guidance developed by staff for state regulations on locally regulated resources. The issue raised stakeholder concerns at last month’s meeting. (See “Workshop Set on DER Ride-through Standard,” PJM PC/TEAC Briefs: Sept. 13, 2018.)

Bernabeu confirmed that several revisions have been made to the problem statement and issue charge since then, including not making the standards retroactive for existing resources and creating rules for both inverter-based and synchronous resources.

“They behave quite differently. … We are trying to tackle the entire DER space and not just focus on inverters,” he said. “We are trying to achieve both.”

Alex Stern of Public Service Electric and Gas and Tonja Wicks of Duquesne Light expressed appreciation for PJM’s willingness to address stakeholder concerns.

“We just have to be sure at the RTO level that, as we incorporate greater levels of distributed energy resources, … we’re doing it safely and reliably,” Stern said.

“That’s why we want to solve this now as opposed to California,” Bernabeu said in reference to solar generators disconnecting from the grid during wildfires. “I don’t want to be like California.” (See NERC Chief: Inverter, Fuel Assurance Standards Needed.)

Offshore Wind Interconnection

The growing wave of interest in offshore wind is finally hitting PJM. Staff announced plans to review the Tariff for revisions necessary to address the “new and creative ways” offshore wind developers are proposing to interconnect facilities, which include offshore transmission networks with multiple interconnections.

The issue was a topic of interest at a recent offshore wind conference in New Jersey, although PJM staff did not attend. (See Offshore Wind Industry ‘Really Moving;’ Coordination Key.)

“We haven’t anticipated this,” PJM’s Susan McGill said of the developers’ proposals. “There’s some ideas out there that this [current] construct doesn’t fit perfectly.”

Ken Foladare of Tangibl requested that PJM also look into other long-term firm transmission projects that sometimes cause delays with generation interconnection queue requests and asked that staff investigate ways to eliminate these delays.

“For generation project developers, these delays often cost them a considerable amount of time and money,” he said.

Impacts of the Energy Transition on Transmission

PJM’s Yuri Smolanitsky detailed plans for two new 500-kV lines and substations that highlight the changes resulting from shale gas and solar development in the RTO.

The Flint Run 500/138-kV substation west of Clarksburg, W.Va., will tap the Belmont-Harrison 500-kV line to provide extra-high voltage for Marcellus shale load growth in the area. The $40.1 million project in the Allegheny Power Systems zone — b2996 in PJM’s Regional Transmission Expansion Plan — will run 138-kV lines of approximately 3 miles each to 138-kV buses at Waldo Run and Sherwood. It’s expected to be in service by December 2019.

In addition, a $5.7 million project in Dominion’s zone will upgrade the Spotsylvania substation and construct approximately half a mile of 500-kV line to connect with the 500-MW Spotsylvania Energy Center solar farm. Smolanitsky said it will be the largest solar farm in the RTO when it goes into service, which is expected next fall. It was developed by Sustainable Power Group (sPower), which was acquired by AES and AIMCo in February 2017, according to the project’s website.

TMEP Congestion Analysis

Two recently approved targeted market efficiency projects (TMEPs) would have resolved $55 million (approximately 11%) of the total $523.2 million in congestion costs over 2016 and 2017 from the 61 facilities that MISO and PJM identified as part of study begun in the spring, PJM’s Alex Worcester announced. (See MISO, PJM Endorsing 2 TMEPs for Year-end Approval.)

Other planned system changes would have resolved $213 million (approximately 41%). Outages drove $201 million (approximately 38%), and $6 million (1.1%) were caused by situations where the congestion isn’t persistent. The remaining $48.2 million (9.3%) includes potential TMEPs, as well as ones where the effectiveness is uncertain, the upgrade is unknown or the proposal didn’t meet the necessary benefit-to-cost ratio.

RTEP Recommendations

PJM’s Board of Managers approved another $214.9 million in RTEP baseline reliability projects at its Oct. 2 meeting. The recommendations come after the board approved $629.23 million in recommended baseline projects at its July 31 meeting.

The majority of the cost comes from a $155 million plan to construct two new 69/13-kV substations in the Doremus area of the PSE&G zone.

Dominion Supplementals

Dominion’s Ronnie Bailey presented three new need assessments and two planned solutions as part of the transmission owners’ new FERC-ordered process for developing supplemental projects. Dominion has presented 19 needs assessments since the process was implemented in September. (See “First M-3 Experience,” PJM PC/TEAC Briefs: Sept. 13, 2018.)

The planned solutions address the first and second needs identified by Dominion last month. The solution for the first need, which would serve a new data center campus in Loudoun County, Va., with total load in excess of 100 MW, is estimated to cost $27.8 million.

The second solution, which would accommodate a request by Old Dominion Electric Cooperative to serve residential, commercial and industrial growth south of Fredericksburg, Va., that is expected by 2023, is estimated to cost $1.4 million. The summer load in the area is around 35 MW, Bailey said, and the winter load is expected to be around 41 MW.

— Rory D. Sweeney