Wednesday, January 23, 2019

PJM Concerned About Lead Time on Transmission Needed for Wind

By Rich Heidorn Jr.

PJM is concerned that the Environmental Protection Agency was too optimistic about how quickly it can add transmission and how much help its states will receive from wind resources in meeting the Clean Power Plan.

The RTO released a report on the impact of the proposed carbon rule on July 31 — days before EPA issued its final rule — that challenged the agency’s assumptions on the pace of both generation additions and transmission expansion.

“Under some CPP scenarios — particularly in the early years of compliance — generators could retire at a faster rate than replacement generation, or the new transmission needed to solve reliability problems, could be built. These scenarios potentially could put a much greater strain on the existing transmission system,” the report said.


The report, the second of two produced in response to a request from the Organization of PJM States Inc. (OPSI), builds on the economic analysis from PJM’s first report for the group to determine the range of transmission that would be required under three scenarios for coal plant retirements: 6 GW, 16 GW and 32 GW.

“Generation needs could exceed available resources by 2024 in a 32-GW at-risk future scenario, in which units retire evenly across each year from 2020 to 2029. If retirements occurred earlier in the 2020-2029 compliance period, resource adequacy needs could exceed resources for a 32-GW scenario by 2022 and by 2028 under a 16-GW at-risk scenario,” the report said.

Final Rule Lessens Reliability Concerns

PJM COO Mike Kormos said Monday that several changes in the final rule — relaxing the initial deadlines by two years, creating an easier path to interstate trading and the inclusion of a reliability safety valve — made the regulations less of a threat to reliability. He said the RTO will likely run additional sensitivity analyses based on its observations and requests from states.

But Kormos said it was too soon to tell how the changes in the final rule would affect the conclusions PJM made in the July 31 report.

“We’ll look to do some refinements and some additional scenarios,” he said in an interview. “I can’t tell you definitively whether anything is going to dramatically change.”

Kormos said that while some states face tighter or looser emission caps under the final rule than under the draft, “they were not drastically different in aggregate.”

‘Informal’ Discussions on Trading

Kormos said PJM has thus far had only “informal” discussions with stakeholders about the prospect of interstate emissions trading as a compliance measure. “I’m unware of any specific initiatives,” he said. (See related story, Final Clean Power Plan More Suited to Carbon Trading, Experts Say.)

PJM already collects data on emissions and renewable energy credits for states and others under its Generation Attributes Tracking System and stands ready to perform a similar role under an interstate CO2 trading program. “If there’s a desire, I’m sure we would be open to having those discussions,” Kormos said.


Between the submission of state implementation plans and EPA’s interim deadline, PJM said, generation owners would need to announce retirement decisions, replacement generation would have to be identified, reliability violations must be identified and transmission solutions developed, designed, sited and constructed.

“Once the PJM board approves transmission upgrades, historical experience shows that the pace at which transmission can be completed can range from five years (the Carson-Suffolk 500-kV line) to more than 16 years (the Wyoming-Jackson’s Ferry 765-kV line),” the study said. “Moreover, if a number of large-scope transmission projects are required across the United States, the lack of equipment availability could increase lead time substantially.”

Moving Target

The location and size of both retiring generators and replacement resources will be uncertain for some time and will “remain a moving target” for transmission planners, the report said.

It notes that generation interconnection projects typically enter the queue three to five years before their desired in-service dates and that more than 80% of projects that enter the queue withdraw before reaching commercial operation.

“A successful replacement resource would have to anticipate the retirement of at-risk generators,” the report said. “Otherwise, the grid will face the likelihood of significant delays between the retirement of at-risk generators and the completion of replacement resources. Reliability studies that look more than three years out must hypothesize build rates, locations and fuel sourcing.”

The study identified reliability violations requiring new transmission in areas where deactivating coal-fired generators are less likely to be repowered with natural gas, such as those far from pipelines.

More Challenging than MATS?

PJM said its experience with EPA’s Mercury and Air Toxics Standards (MATS) “suggests that build rates may not ensure that the necessary transmission will be in service before retirements occur.”

Most transmission improvements resulting from MATS were upgrades to existing facilities. In contrast, the carbon plan will likely require more greenfield transmission to connect wind resources in western PJM to load centers in the eastern portion of the RTO.

Because they require new rights of way, greenfield projects require more time to reach commercial operation.

How much states will count on renewable resources to meet their compliance goals is a big source of uncertainty, PJM said.

“The EPA renewable portfolio standard reliance assumptions differ from PJM’s historical queue experience,” the report says. “It is likely that all the wind-powered facilities that the EPA anticipates to be available will not make it online as shown in the economic analysis. Moreover, historical transmission build-out rates are not likely aggressive enough to meet the EPA’s wind penetration rate assumptions.”

“Scenario studies suggest that overloads clustered along specific corridors would require additional review to assess the feasibility of certain types of upgrades. That, in turn, would impact both the cost of solving identified reliability criteria violations and the ability to complete construction of facilities in time to simultaneously comply with the CPP while avoiding those reliability violations.”

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