By Rory D. Sweeney

MISO and PJM will decide by May 18 whether to undertake a coordinated system plan study this year, the RTOs said last week.

The decision could be announced at the next Interregional Planning Stakeholder Advisory Committee (IPSAC) meeting on May 11. Staff from both RTOs confirmed the timeline at last week’s IPSAC meeting, which included the issues review required as part of the process of determining whether a study is required.

“We don’t anticipate taking that long,” PJM’s Alex Worcester explained, referring to the May 18 deadline. He later added that PJM is “likely supportive” of a study.

The RTOs will provide justification for their decision, MISO’s Adam Solomon said. It will be based on whether there are projects that “make sense,” addressing reliability issues on either side of the border that are close to each other.

PJM and MISO in January jointly reviewed their separate regional issues, newly approved projects near their border, coordinated interconnection requests and historical market-to-market congestion, which RTO representatives said would form the basis of the study, if it’s undertaken. The results were presented at last week’s meeting, along with analysis of stakeholder feedback.

RTOs’ Review

Worcester reviewed projects approved through PJM’s monthly Transmission Expansion Advisory Committee analysis, including 27 baseline reliability projects near the RTOs’ shared border, six market efficiency projects and another six supplemental projects.

All reliability issues identified for 2022 are being addressed through a single proposal window open last summer. Market efficiency projects are addressed on a 24-month cycle that last identified issues in October 2016, but an addendum window to address thermal constraints on the Tanners Creek-Dearborn 345-kV line was closed in February. Supplemental projects are developed internally by transmission owners and are not driven by RTO criteria. They’re included with baseline and market efficiency projects in PJM’s Regional Transmission Expansion Plan to allow staff to identify possible reliability or operational performance issues, but they are not subject to staff oversight or approval.

Solomon reviewed the 2018 MISO Transmission Expansion Plan, which began in June 2017 and is scheduled to culminate in December 2018 with approval from the Board of Directors for recommended projects. He highlighted 52 approved projects near the RTO border that might spur interregional projects if there are needs nearby in PJM’s territory. They are all TO-submitted ‘bottom-up’ projects.

MISO is also reviewing 15 of its most congested north/central flowgates, which will be included in its Market Congestion Planning Study this year to potentially identify market efficiency projects, he said. Nearby PJM economic issues could drive the need for an interregional project. He also noted 21 congestion flowgates that were eligible for the MCPS but were excluded for individual reasons.

Stakeholder Issues

The RTOs also reviewed issues identified by stakeholders. Ameren submitted four issues, while three issues Northern Indiana Public Service Co. highlighted were included in Solomon’s presentation.

“We will look at those as appropriate and as they show up in the interregional process,” Worcester said.

NIPSCO’s final concern involved PJM’s finding of 10 facilities with infeasible auction revenue right paths. ARRs are rights to the revenue from congestion charges allocated to firm network and point-to-point customers because they fund the embedded costs of the transmission system. MISO and PJM are each addressing one of the infeasible ties with approved internal projects. Three others have projects under consideration, and two others will be included in a future proposal window. The three remaining infeasible paths are pseudo-tie flowgates. (See “ARR Analysis IDs Constraints,” PJM Planning and Transmission Expansion Advisory Committee Briefs: Nov. 9, 2017.)

Worcester said MISO has no process comparable to PJM’s ARRs, so “if it’s outside of PJM, it’s unclear how it would move through the [RTOs’ joint operating agreement] with the competitive transmission process,” he said. PJM will investigate internally ways to address the issues and engage with MISO on any potential solutions, he said.

Wind on the Wires and EDF Renewable Energy asked that the RTOs re-evaluate previously considered targeted market efficiency projects (TMEPs) that did not qualify last year if congestion has continued.

“We certainly agree with that in principle,” Worcester said. He said the RTOs aren’t planning on reconsidering the Thayer-Morrison project, which Wind of the Wires had specifically requested.

JOA Changes

Seven stakeholders provided feedback on three potential JOA changes, which informed the RTOs’ decision-making on the issues. References to joint economic models will be removed.

“NIPSCO prefers a joint model,” the company’s Clark Gloyeske said, noting past differences between the regional models in wind-unit profiles. “More coordination between the regional models to fix some of these modeling issues would be really helpful.”

The RTOs have decided against changing the number of benefit years, fixed charges and discount rates used in analyses, Solomon said. While changes were recommended, they were “wildly varying” on what the correct number of years should be.

“Considering all the feedback, the RTOs think this should be a regional discussion,” he said. “We think the regional processes are working … and that we shouldn’t be deviating from the regional criteria.”

“I understand the simplicity of working just within the regions … but if the number of years the benefits are calculated over are significantly different … I think there’s a risk of coming up against significant stakeholder or state concern about another region not paying its fair share because they haven’t calculated the same level of benefits over the same years,” said Natalie McIntire of Wind on the Wires.

Solomon acknowledged the “valid concern” but said it had to be weighed against “regional differences.”

“Each region has its own definition of how benefits should be calculated, and that’s in line with what we do with our regional projects,” he said. “Deviating from that for an interregional project would be difficult, but certainly, your point is taken.”

The generation-to-load distribution factor test will be removed, Solomon said, and the RTOs will rely on their own regional materiality tests. This removes a “triple-hurdle concern” that would require projects to pass tests for each region as well as an interregional review, Worcester explained. PJM will develop its test through its recently formed Market Efficiency Process Enhancement Task Force, while MISO is still considering where it will address the question.

“The Tariff is silent on how projects qualify materiality-wise,” Solomon said.

Ameren’s Adam Weber asked that the regions’ materiality tests be delineated in the JOA so stakeholders aren’t surprised by a project not clearing both tests. RTO staff hesitated to endorse that proposal but were aligned on addressing Weber’s concern.

The grid operators will replace the distribution factor (DFAX) cost allocation method with an approach that allocates costs to the RTO with the reliability need, with split projects allocated based on the ratio of avoided costs. Cross-border baseline reliability projects will be replaced with interregional reliability projects because no scenario exists where the baseline projects would be used. An RTO will be obligated to construct projects that benefit the other RTO, but the benefiting RTO will cover the costs.

“There’s not going to be a scenario where there’s a new project developed and we would need to come up with a new cost allocation methodology,” Solomon said.

The RTOs said they “don’t see a need for” EDF’s request to add benefit metrics for projects, but a second request to broaden the JOA’s definition of a flowgate will be forwarded to the Congestion Management Process Working Group, which has representatives from most RTOs.

The RTOs hope to have the JOA changes in place for the next interregional market efficiency project window, which opens around Nov. 1.

“We’re thinking that a filing should be made by July to allow for the FERC process to go through,” Solomon said.