VALLEY FORGE, Pa. — While some components remain to be finished, the major elements of PJM’s proposed structure for its competitive planning processes moved past the Planning Committee at last week’s meeting.

PJM’s Michael Herman presented the final version of the new Manual 14F, which outlines rules for competitive bidding on transmission projects as established in FERC Order 1000. The committee finally endorsed the manual, which has struggled to gather momentum and was sent back to staff for revisions several times in recent months.

Members have criticized the manual for its silence on how project bidders might include cost-containment provisions in their proposals and any preferential treatment such assurances might provide, but PJM has pushed to make the manual active prior to opening a competitive-bidding window later this summer. Staff have organized a series of special sessions of the committee to develop cost-containment rules, which will later be added to the manual. (See PJM Kicks off Transmission Cost Cap Initiative.)

John Farber, who represents the Delaware Public Service Commission, asked if construction contractors must meet any standards. PJM’s Sue Glatz assured him the manual includes prequalification standards for bidders.

Members also endorsed a series of design standards to be included in designated entity agreements, which successful bidders must sign with PJM. The endorsement covers standards for overhead lines, substation construction and system protection. The Designated Entity Design Standards Task Force is still developing standards for underground and HVDC lines, Herman said.

PJM is planning to transition the task force into a subcommittee that would continue to review and update standards based on biennial reviews instead of being disbanded following the completion of its charter, Herman said.

Steve Lieberman and Ed Tatum, who represent American Municipal Power, reiterated previous concerns that the design standards will not require additional endorsement from the Markets and Reliability Committee, which is the standard procedure for most rule implementation at PJM.

“I think that’s really inappropriate,” Tatum said.

Glatz explained that the standards are referenced in revisions to Manual 14C, which will require MRC endorsement. Those revisions, which require that all designated entities follow the design standards, subsequently received planning committee endorsement. (See “DEDS Task Force Ends at PC,” PJM Planning Committee/TEAC Briefs.)

McGlynn Becomes PC’s New Chair

Paul McGlynn, PJM’s senior director of system planning who has long overseen the Transmission Expansion Advisory Committee, has assumed duties as the chairman of the Planning Committee. He succeeds Steve Herling, PJM’s vice president of planning.

McGlynn acknowledged Herling “will certainly be a tough act to follow” but was confident stakeholders won’t notice much of a change in leadership styles.

He brings a decade at PJM and three decades of industry experience to the position, having started in 2007 as a manager of transmission planning and being promoted to his current position two years later. Prior to that, he worked at PECO Energy for 20 years in various engineering and operations positions.

He expects the committee to focus on evolving the planning process as needs change to integrate new technologies, such as distributed energy resources, storage and system resilience. He also plans to work with stakeholders on refining PJM’s Order 1000-compliant competitive bidding processes “to improve efficiency and transparency.”

PJM Reconsidering Planning Assumptions

PJM staff announced plans to revisit several of its planning assumptions in light of new data. The revisions come as the RTO analyzes how it plans to address resilience in system planning. PJM’s Mark Sims said the goal will be to consider potential events and create simulations to study system performance in the face of infrastructure failures such as voltage collapse or thermal issues.

“We want to think about what could happen and run the simulations,” he said. “From a planning point of view, [the focus will be to] absorb and adapt.”

“Resilience is a really broad topic,” McGlynn said. “What we want to focus on, obviously, is what resilience means from a planning discussion.”

First on the list is PJM’s light-load reliability analysis criteria, which were established in 2011. A lot has changed since then, Sims explained, including EPA’s publication of its Mercury and Air Toxics Standards and the emergence of the shale gas boom.

“At the time, the data was telling us that natural gas was barely operating during the [light-load] period,” he said.

Demand has also dipped significantly in the interim. Several of PJM’s 27 zones experience light-load conditions of less than 35% of the forecasted summer peak load for a “significant number” of hours, he said. That difference can create voltage spikes that cause problems for grid operators.

PJM plans to begin updating its light-load criteria with several changes, Sims said. First, the load-modeling assumption will be reduced from the current 50% of forecasted summer peak to a more appropriate percentage. Next, natural gas’ capacity factor for base generation dispatch will be increased from the current 0% to a percentage more in line with current usage. Additionally, PJM plans to establish a ramping limit for natural gas based on statistical data.

Finally, the deliverability ramping limit for wind would be increased from 80 to 100% of nameplate capacity.

Sims acknowledged there are other tweaks to be made, but they would be “sharpening the pencil” beyond addressing the concerns at hand.

“We have some definite issues, for example, with the lower loads and natural gas that are here today,” he said.

PJM also plans to revise its capacity emergency transfer limit (CETL) calculation methodology. Currently, PJM models firm existing transfers and assumes non-firm flows will materialize up to the transmission system’s capacity limits. But data confirms that those external zones will likely be experiencing the same capacity emergencies and unable to provide support. NYISO’s eastern region and PJM have peaked on the same day, and sometimes the same hour in four of the past six years, Sims said.

“A lot of questions came out of the [Regional Transmission Expansion Plan] planning parameters,” he said. “We’re assuming our neighboring systems can support us, but maybe that doesn’t make sense.”

Sims also noted that, unlike HVDC lines that can adjust power flows quickly, phase-angle regulators must be manually adjusted and “take time.” Several of the ties between NYISO and PJM are controlled by PARs.

Many of the insights Sims noted were pointed out by Public Service Electric and Gas in a letter the utility sent to PJM’s Board of Managers in May. (See “Following PSE&G Complaint, PJM to Discuss Updated CETL Requirements,” PJM Planning Committee/TEAC Briefs.)

Analysis Strategy Announced for Market Efficiency Projects

The plan for analyzing market efficiency project proposals in the 2016-17 window begins with interregional projects, PJM’s Nick Dumitriu said at last week’s meeting of the Transmission Expansion Advisory Committee. The window is part of PJM’s RTEP.

Interregional projects will be considered first, he said, because they require the most lead time when factoring in interregional coordination. Both energy and potential capacity benefits will be examined, he said.

Proposals for the PPL region will be analyzed next, followed by those in the Baltimore Gas and Electric region. “Slam dunk” projects — considered low-cost upgrades with high benefit-to-cost ratios and minimum competition — will be analyzed in parallel. All other regional projects will be analyzed last.

Responding to an inquiry from LS Power’s Sharon Segner, Dumitriu confirmed that PJM will re-evaluate previously submitted projects in parallel and present them after the base case is completed, likely at the July or August TEAC meetings. PJM hopes to have the interregional, PPL and “slam dunks” ready for presentation to the board at its meeting in October, with BGE and all other projects ready for the board’s December meeting.

Accelerated AEP Project Won’t Increase Costs

PJM staff noted that an American Electric Power proposal to speed up the timeline of a planned reconductoring project won’t incur any incremental costs.

The previously approved baseline projects 1-11B and 1-11C to reconductor the Dequine-Eugene-Meadow Lake 345-kV line in western Indiana will provide Reliability Pricing Model benefits by improving CETL values, along with energy benefits for reducing congestion. The projects are scheduled to be in service by 2021, but AEP has offered to complete them by 2019, saving two years of congestion costs.

“Anything divided by zero turns into a pretty big number pretty quick, so I think we’d continue to recommend that the project get done by 2019,” McGlynn said.

Detail of Proposal Descriptions Still a Concern

Stakeholders reiterated concerns about what they felt was a lack of information about project details. While PJM staff were attempting to clarify the complicated history of proposals to alleviate constraints on the Olive-Bosserman 138-kV line in northern Indiana, Tatum took the opportunity to log the frequent complaint.

“You are aware, though, that we don’t share your opinion that the information provided and the methodologies shared so far are adequate?” he asked Sims in reference to the information AEP provides about its proposals.

“I thought we were getting pretty close,” Sims said, noting that AEP has held several regional meetings — attended by Tatum — at which company representatives have explained their internal methods. Tatum acknowledged that the meetings were informative, but he asked for a greater level of detail in the TEAC slides.

Mark Ringhausen of Old Dominion Electric Cooperative asked when PJM plans to implement meetings for localized planning and stressed the importance of seeking input throughout the process from the stakeholders such as ODEC and AMP, who pay for the upgrades.

Sims acknowledged the importance of getting their buy-in. “We want to know upfront what are the expectations so we can work toward that instead of getting to the end and having to change things,” he said.

Segner noted that because some states don’t have certificates of public convenience and necessity, local planning is even more important there.

Project Delay Creates Controversial Cost Increase

Recent analysis by PJM shows that a once-approved Virginia project is still needed to alleviate reliability violations but will now cost nearly twice as much.

The PJM Board of Managers in 2014 approved rebuilding Station C in the Dominion zone along the Potomac River and installing a new 230-kV line from there to the Glebe station at a cost of $165.4 million.

The project was never constructed. Since then, the estimated cost has nearly doubled.

Several alternatives were considered, Sims said, but ultimately the cheapest option turned out to be connecting the two stations via a line under the river. However, local regulations require expensive “micro tunneling” for the line, and Station C must be rebuilt as a gas-insulated substation. Add in construction of a PAR, and the new estimated cost is nearly $300 million.

Given the substantial cost increase, Ringhausen asked PJM to revisit the alternative solutions and see if any of them are comparatively cheaper now.

“I think we owe it to the folks paying the bill to look at it again,” he said.

“I’m not sure it’s going to be fair to put them all side by side,” Sims said, as it would compare the current estimate for the proposed solution with 2014 estimates for the alternatives. But Ringhausen suggested updating the estimates should be a quick process.

Stakeholders also inquired whether the project could be reopened to a competitive bidding window, but PJM staff were concerned it might throw off project timing.

– Rory D. Sweeney