Tuesday, March 19, 2019

PJM PC/TEAC Briefs: March 7, 2019

RTEP Removal Discussions Scheduled

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.

Aaron Berner, PJM | © RTO Insider

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 presentation 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.

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