By Amanda Durish Cook, Tom Kleckner and Rich Heidorn Jr.

WASHINGTON — Renewable developers and transmission planners for MISO, SPP, and PJM sparred Tuesday over the effectiveness and fairness of “affected system” studies, with RTO staff urging FERC to leave study improvements up to stakeholders and developers asking the commission to order identical requirements for grid operators.

The disagreement came during the first day of FERC’s two-day technical conference, ordered in response to EDF Renewable Energy’s October complaint that the three RTOs do not have clearly defined processes to determine cost responsibility for network upgrades on an affected system stemming from an interconnection request made in a host RTO. EDF contends inconsistencies and a lack of clarity in the RTOs’ rules for affected systems interferes with developers’ ability to judge the commercial viability of proposed projects (EL18-26, AD18-8). (See FERC Orders Review of PJM, MISO, SPP Generator Studies.)

SPP, MISO Flooded with Interconnection Requests

Both MISO and SPP planners called attention to their expanding interconnection queues in opening remarks, saying they are coordinating affected system studies while managing record volumes in planned generation.

MISO’s queue has grown to more than 95 GW this year, approximately 80% of MISO’s existing load, said Vikram Godbole, MISO director of interconnection planning.

“Coordination of such a large chunk of projects takes time. It’s challenging,” Godbole said. ” … The affected system was not a big problem back [in 2005], but … when you’re dealing with 95,000 megawatts in one queue, coordinating four subregions and different cycles with other RTOs, it takes time.” MISO divides its interconnection entrants into the Central, East, South, and West subregions.

SPP Manager of Generation Interconnections Steve Purdy said his RTO’s interconnection queue has ballooned 600% in the past four years to 70 GW, an amount exceeding SPP’s 55-GW predicted summer peak in 2021.

Even with expanding queues, Purdy insisted SPP and MISO are improving coordination of affected system studies. Purdy said SPP’s allocations of costs resulting from projects in neighboring regions “are appropriate and consistent with allocation of costs for generation interconnection in SPP.”

What Role for Stakeholder Process?

PJM Senior Engineer Edmund Franks said PJM already has a “fairly detailed set of procedures” to address network upgrades on the seam. He added that MISO and PJM already work together to coordinate affected system studies and said that any improvements should be “decided and agreed upon in the context of the stakeholder process.”

Franks noted PJM’s interconnection process is linked with its annual Regional Transmission Expansion Plan (RTEP). If FERC prescribes changes to affected system studies, “that would cause a divergence in how we evaluate our system from a baseline perspective [for RTEP] compared to how we evaluate interconnection customers. We feel they should be evaluated with the same test and criteria,” Franks said.

Godbole said the RTOs should be given “flexibility and latitude” to set their own regional planning processes, including cost allocation rules, which are “embedded” in planning.

New World ‘Churn’

However, the two renewable developers on the panel said RTOs have already been granted that flexibility, and the result is a confusing and unreliable process.

“It’s unrealistic to think that the stakeholder process is going to come up with a fair procedure to study affected systems when they have the opportunity to shift costs to their neighbor,” said Kris Zadlo, Invenergy senior vice president.

Zadlo said he didn’t doubt RTOs are currently applying their methodology correctly: “I think the debate here is: Is the current methodology that they are using still appropriate in today’s day and age? That’s what needs to get revisited.”

“I feel for these guys. They have large queues, but this sort of churn is a product of the new world,” Zadlo said, referring to newer low-cost generation technologies. ” … The days [when] you build something and forget about it for 50 years are gone. … You’ve got to man up. You’ve got to staff up accordingly.”

SPP’s Purdy said more staff is not the answer. “We’ve run into some very real physical constraints in SPP,” he said. “We’ve got, in fact, more generation requests than we have load.”

Costs ‘Out of Control’

“We don’t enter the queue on a whim, and it’s not been easy lately,” said Kate O’Hair, vice president of EDF Renewable Energy’s north region. O’Hair said EDF has been surprised by increasing affected system cost assignments and a seeming lack of explicit rules about how RTOs determine impact cost. She urged the commission to require each RTO to detail the standards used in their Tariffs and joint operating agreements.

Zadlo said the cost associated with identified network upgrades has “spiraled out of control.”

“Addressing affected systems has transformed into an unnecessarily complicated and time-consuming process,” Zadlo said, claiming that remote projects are being forced to pay affected system costs. Zadlo pointed to Invenergy’s Deuel Harvest Wind Farm in South Dakota, which he said ended up responsible for affected system costs “on the PJM system, 800 miles away in Michigan.”

“Codifying the processes that exist today will not solve the problem. FERC needs to provide definitive guidance on what standards the ISOs need to apply [and] bind limitations to studies. RTOs can’t perform a region-wide RTO analysis. It needs to be simple, realistic, and focused on the boundaries,” Zadlo said.

Today, network upgrades are solving “chronic seams issues,” Zadlo said. “Why should generators be forced to solve these seams issues between the ISOs?” He added that he has seen network upgrades resulting from affected system studies appear months later in RTOs’ transmission expansion plans.

“If it’s ‘but for’ the generator, why is it appearing in a transmission expansion plan six months later? I think what you’re seeing here are upgrades that are really needed and folks trying to find a way to pay for these upgrades,” Zadlo said.

“The RTOs will not work it out. There needs to be clear direction by FERC as to what needs to be applied … in these affected system studies. We’re at this juncture, in this situation, because the RTOs have been trying to work this out,” Zadlo said.

‘Misunderstood Process’

“There’s no mechanism to ensure costs are shared between appropriate customers and RTOs,” O’Hair said. She said EDF had a project in the February 2015 definitive planning phase of MISO’s queue with an executed interconnection agreement that “came back with tens of millions in upgrades that had not shown up in previous studies” after PJM completed an affected system study. Eventually, O’Hair said, the costs were reassigned to another generator that dropped out of MISO’s queue.

“It’s a perfect example of how it’s a misunderstood process,” O’Hair said.

What’s the Right Model?

Zadlo said he didn’t understand why 15 years after FERC Order 2003, it’s still a struggle to get all RTOs to align their base cases and said different study methodologies produce different answers: “All of these RTOs are very proud of their study methodologies, and we’ve been in situations where we are mediators because one RTO is saying one thing, [and] the other RTO is saying another thing. Who is right?”

“You have no way to challenge the impacted system study,” Zadlo added. He suggested only projects “truly on the seams” should be evaluated for impacts on neighboring RTOs, saying it’s “kind of inconceivable” that every project requesting interconnection in one RTO is going to impact potentially the reliability of an adjacent RTO.

MISO, PJM, and SPP representatives said not all incoming project requests are evaluated for impacts on other RTOs.

“We’re not going to analyze a project in New Jersey or Delaware for impacts in Indiana,” Godbole said.

When FERC staffer Kathleen Ratcliff questioned whether the RTOs have any written rules specifying when affected system impacts should be evaluated, RTO staff agreed that pursuing a study is based on “engineering judgment.”

Zadlo suggested using more targeted generation dispatch assumptions, relying on a sub-region rather than a footprint-wide dispatch assumption.

Godbole said MISO’s dispatch assumptions have been developed over years. “We can’t create a special model just for affected systems and try to merge that with the overall planning models,” he said.

Cooper South Constraint

FERC staff steered discussion toward a $311-million network upgrade to SPP’s Cooper South constraint identified in MISO’s February 2016 queue study group, asking MISO to explain its reasoning in assigning the upgrade cost to generators.

Godbole said, in that case, MISO relied on affected system study results from SPP that indicated a need for the upgrade.

“MISO is not an expert on SPP transmission or SPP process, so we depend on the expertise of the transmission [operator]. So, when they identify network upgrades required to mitigate constraints on their system due to MISO interconnection projects, we take that information, include that in the reports, and then we have a follow-up call with interconnection customers,” Godbole said. He said although some MISO interconnection customers have said MISO should take on more of the study responsibility of the affected system, “at the end of the day, SPP really is the regional operator for that transmission [and] in the best position to provide MISO with the most accurate analysis.”

15-Day Deadline

O’Hair said the $311 million upgrade is still “not well understood.” She also complained that interconnection customers have only 15 days to review the results of affected system studies and decide whether to continue with a planned project.

“If we’re coordinating, this doesn’t feel coordinated,” O’Hair said.

Zadlo said a new line on the Cooper South constraint will solve chronic congestion issues in SPP.

“So, is it fair and just to just fully allocate the cost of that line to the generators when there is going to be congestion relief to SPP customers?” Zadlo asked. He added that interconnection customers assigned the cost of the Cooper South upgrade all changed their network resource interconnection service requests to an energy resource interconnection service designation to avoid paying the costs of the new line.

Purdy pointed out that SPP’s interconnection studies focus on reliability, not economics or congestion.

Ratcliff asked if impacted system studies frequently shift upgrade costs to interconnection customers. RTO staff said how dramatically cost allocation shifts is entirely situational.

Delays

During the afternoon session, O’Hair complained that study delays have impeded the ability of interconnection customers to assess their projects’ commercial viability. EDF’s complaint noted that MISO produced its February 2016 West cluster phase I system impact study after 250 days, despite a Tariff requirement to do so in 120 days. It said MISO was at least six months behind schedule in processing the cluster, causing delays to cascade through to successive clusters.

“It’s difficult to manage, and extraordinary amounts of risk and capital are tied up wondering when studies will be delivered,” O’Hair said. “It’s feasible and doable to coordinate timely affected system studies; it’s simply a matter of the commission finding the current process is no longer just and reasonable and ordering the RTOs to hash out the details.”

Jennifer Ayers-Brasher, director of transmission and market analysis for German developer E.ON, echoed O’Hair’s complaint: “To my knowledge, [the RTOs] have no detailed procedures governing scope and timing for affected systems processing, and any provisions are vague and outdated. The lack of transparency contrasts with clear commission-approved procedures that each RTO has to process interconnection requests in their own footprint.”

Chad Craven, manager of transmission for Tradewind Energy and a former MISO staffer, called for a “more cohesive process” through improved coordination of the study process.

“I don’t think it’s a secret to anyone here, or [anyone] who follows this issue, that every RTO has its own process and timelines. Even if they have the same basic time frame, they may start and stop at different points in time,” Craven said. … So, the essential ask here is for the commission to come up with a ruling, preferably not even a recommendation, but some sort of mandate to better align these processes.”

PJM’s Aaron Berner said many study delays come from customers withdrawing or reducing the size of their projects, “which has a ripple effect.”

FERC staff asked the RTO representatives whether it was feasible to use a consistent base-case model across their regions. Berner said while the RTOs do have consistent base-case models that are coordinated at different times, “changes must continue to occur.”

“Those changes have to be just passed through to our affected systems, neighbors, and updated in models as is necessary,” he said.

“If we do not maintain that link, if we change that interconnection customer model to be something that is some type of dispatch consistent across the entire Eastern Interconnection but disregards differences in the markets … I’m not sure I would understand how we could have a consistent set of assumptions,” Berner said.

Seven Immediate Changes

Judah Rose, chair of ICF’s energy advisory practice, called for six changes that could be made “right away,” starting with an adequate description of the base case being used by the host or affected system.

Rose also called for clear standards, the prompt availability of models, a comparison of the studies’ inputs and outputs, documentation of missing data and causes of delays, and a clear description of the RTOs’ responsibilities and requirements to ensure adequate staffing and other resources.

“These are things that can be done immediately and without prejudice to more complicated issues that may need to take longer to achieve,” Rose said.

Given a chance to comment before the afternoon session concluded, Tradewind Vice President of Transmission Derek Sunderman said he had written down at least nine variables that differ among the RTOs. Multiply those nine variables across the three entities, and the number of permutations and outcomes is astronomical, he said.

“The only way to make a complex problem less complex is [to] remove some variables,” he said. “The best way is for FERC to actually provide some orders on a lot of these issues. Over time, each RTO has developed its construct for reliability procedures, under their own stakeholder silo. What we need are orders that fix what variables mean because, right now, you have everybody making a different interpretation what the variable means.”

Second Day

The second day of the conference Wednesday will focus on broader affected systems issues raised in the generator interconnection NOPR (RM17-8). (See FERC Proposes Changes to Interconnection Rules.)