CARMEL, Ind. — MISO is seeking stakeholder input as it develops a conceptual study to determine how to incorporate the impact of transmission outages into its economic planning models.

MISO said transmission and generation outages are “a major contributing factor of market price volatility.” While the RTO includes concurrent generation outages in its economic model, it does not model concurrent transmission outages, though it said a 2014 exploratory study showed that transmission outages could increase system congestion by about 66%.

“Transmission outages, planned or forced, can cause redispatch of the generation. They have economic consequences,” it said.

Speaking at a June 12 Planning Subcommittee meeting, MISO adviser Ling Hua said the RTO is gathering information to create modeling options for transmission outages and evaluate their trade-offs. Its study examines transmission outage modeling based on either: historical outages; a Monte Carlo-style simulation based on statistics gathered from historical outage data; a systemwide transmission facility derate of 5 or 10%; or use of still undefined research to establish an adjusted production cost adder in the model.

Using 2016 data on 2,000 planned and forced transmission outage events on 115-kV or above facilities lasting longer than five days, the RTO said it could conservatively model about 1,460 transmission outage events in one 2017 Transmission Expansion Plan future model based on a historical outage modeling method.

Hua also said that while both the derate and adjusted production cost adder can capture the systemwide average impact from transmission outages, they fail to account for locations of transmission outages. The historical and Monte Carlo options are more labor-intensive to put together, he said.

American Transmission Co.’s Chris Hagman thanked MISO for investigating the four approaches for stakeholders and said it was important for the RTO to plan for the impact of transmission outages.

MISO Transmission Planning Engineer Amit Rao asked stakeholders to provide their reactions to the four approaches and additional modeling suggestions by July 9.

New Benefit Metrics

MISO is continuing a discussion on which benefits metrics it should account for regarding new transmission projects, as it prepares a plan to prioritize projects that avoid costly investment or reduce settlement costs on its contract path with SPP. (See Stakeholders Debate MISO Cost Allocation Plan.)

The RTO is proposing that new market efficiency projects (MEPs) that would eliminate the need for proposed MTEP reliability projects to include the value of those reliability projects in their estimated costs. The avoided cost benefit — and cost allocation — would then be spread among pricing zones where the reliability projects would have been built. The RTO plans to review all avoided projects with transmission owners.

But Customized Energy Solutions’ Ginger Hodge said she was worried about transmission owners under- or overstating the planning-level cost estimates that inform the benefit metric. She asked the RTO to conduct a historical analysis comparing TO cost estimates at the MTEP planning phase to actual costs to better determine the average variance between estimates and actuals. Hua said MISO could look into the possibility.

MISO also plans to value MEPs based on their ability to reduce annual payments to SPP for flows above the contract path capacity between MISO Midwest and South, but Hua said eligible MEPs eligible would have to physically connect the two regions. For every megawatt that an MEP increases the MISO contract path, the payment structure in the MISO-SPP agreement will be reduced by $667/MW-month, Hua said. She said the benefit would be calculated as an annuity from the in-service date over a 20-year asset life.

The benefits would be distributed to local resource zones using the load-ratio share cost allocation approach already outlined in the settlement agreement for market settlement costs, Hua said.

Hua asked for stakeholder feedback on the two proposed benefit metrics through July 2. She said the RTO would finalize the new benefit metrics for a Tariff filing in August.

Matching Modeling with Proposed Retirement Process

MISO is working to update its modeling to comply with a new generator retirement process recently filed with FERC.

The new retirement process filed last month proposes to place all generation owners submitting an Attachment Y retirement notice into a catch-all three-year suspension period (ER18-1636). Suspended units would maintain their interconnection rights for the full three years unless they formally decide to retire. After three years without a return to service, the units are presumed retired and MISO dissolves their interconnection rights. (See MISO Readies Retirement Change.)

MISO will update its dispatch assumptions to match the new process by modeling a suspended unit as initially offline for the first three years, but assumed to be participating in dispatch after three years, unless the unit is retired. Patrick Jehring, of the RTO’s expansion planning group, said more than half of generation owners submitting an Attachment Y notice decide to immediately retire.

Jehring said MISO modeling is in “limbo” for those three suspension years, but modeling must assume that suspended units will return to service, based on the Tariff.

He noted that the RTO doesn’t foresee granting conflicting interconnection rights — a concern voiced by some stakeholders in prior meetings — because its interconnection process requires that it conduct a deliverability analysis for proposed generation projects, which would flag any issues.

Generators Miss 1st Pass in Under-frequency Study

MISO will complete a NERC-required under-frequency load shedding study by fall, and, at first blush, a few generators have more work ahead to comply with one frequency requirement.

The study is required once every five years, and the RTO last conducted one for MISO Midwest in 2013. The RTO is studying seven under-frequency load-shedding islands in the region.

Anton Salib of the RTO’s expansion planning group said the frequency performance of the seven islands meets most requirements of NERC Standard PRC-006-3, although a few generators might need to take steps to ensure they don’t exceed 1.18 V/Hz per unit for more than two seconds and 1.1 V/Hz per unit for more than 45 seconds at each generator bus.

An initial examination showed that four of the seven islands’ frequency performance exceeded the NERC requirement: Michigan’s Lower Peninsula; “Gateway” in parts of Illinois and Missouri; ATC-A in Wisconsin and part of Michigan’s Upper Peninsula; and Local Resource Zone 1 in the Dakotas, Minnesota, Wisconsin and a small portion of Montana.

Salib said MISO will finish the study and present results in time to meet the October deadline.

Examining 7 Transfers for MTEP 18

MISO has begun a transfer analysis as part of its MTEP 18, due to be revealed in early December.

The analysis examines whether the RTO can reliably transfer energy and identifies potential future system weaknesses or limiting transmission facilities under NERC standard FAC-013-2.

MISO this year will study seven transfers:

• Manitoba Hydro to MISO’s northern region;
• MISO South to SPP;
• MISO’s Central Region to the Associated Electric Cooperative Inc. territory;
• MISO’s North and Central regions to MISO East in Michigan;
• PJM North Illinois to PJM Ohio; and
• A two-way transfer to and from MISO’s Central Region to the Tennessee Valley Authority.

Senior Expansion Planning Engineer Scott Goodwin said the RTO will post the final report of its analysis by Nov. 1.

— Amanda Durish Cook