Renewable Developers Applaud SPP’s Plan to Reduce GI Queue’s Backlog

Renewable developers were effusive in their praise as stakeholders endorsed SPP’s plan to resolve a four-year backlog of generator interconnection requests by 2024.

“You’ve set an example for the other RTOs to follow,” EDF Resources’ Arash Ghodsian said during last week’s virtual Markets and Operations Policy Committee meeting. “We see the light at the end of the tunnel.”

“When we started off this process, all of us in the development community said, ‘Naw, this isn’t going to work,’” NextEra Energy Resources’ Matt Pawlowski said. “Then we worked though the stakeholder process and came up with a proposal that works.”

The strategy is simple enough: reduce restudies through development milestones, increasing financial commitments, and simplifying and reducing study timelines.

“We are confident that advancing these recommendations will resolve the backlog within three years,” said SPP’s GI manager, Juliano Freitas.

Bold words, considering SPP’s GI queue has a backlog of just over 100 GW from 533 requests, some dating as far back as 2017. Staff have grouped those requests into seven study clusters. One cluster is already going through a restudy, while a second, with 112 active GI requests from 2017, has just begun the process.

“We don’t want to stop here. We want to push you guys. … We think we can beat this 2024 time frame by really focusing on getting those studies to be more efficient,” Pawlowski said.

Renewable resources make up the bulk of SPP’s GI requests. In March, the queue stood at 84.1 GW, with renewable and storage requests totaling 79 GW of that amount.

Antoine Lucas, SPP’s vice president of engineering, said GI request withdrawals trigger restudies, which extends the timeline. Market participants have blamed renewable developers in the past for using the interconnection queue as a means of determining their projects’ validity.

Withdrawals have “been the big driver for the backlog issue we have today,” Lucas said. “We could be more efficient, and we are working on it.”

“We’re trying to reduce the number of restudy requests. We have to reduce the uncertainty by imposing different rules in the process,” Freitas said. “Basically, we have to be more efficient in the restudies.”

The plan was developed in conjunction with and endorsed unanimously in May by the Strategic and Creative Re-engineering of Integrated Planning Team (SCRIPT). The team has been doing an in-depth evaluation and consolidation of the RTO’s various transmission planning and applicable cost-allocation processes.

Freitas said the proposal is only meant to reduce the current GI backlog and ensure FERC doesn’t create its own requirements for SPP.

SCRIPT recommended and approved doubling requests’ minimum financial security to $4,000/MW and making 25% of it at-risk after the end of the RTO’s definitive interconnection system impact study’s first decision point. Increasing the financial commitment is also expected to reduce the number of withdrawals and requests.

Staff are also developing a “transitional queue advancement” that will be vetted by SCRIPT. Eligibility would be expanded to include load-serving entities, offering requests a chance to move up into the 2018-19 cluster.

The plan is scheduled to be brought before the board in October and a filing made at FERC in November. The backlog-clearing proposal will also be filed at the commission the same time.

Tx Planning Mitigation Gets OK

The MOPC also endorsed approved staff’s recommended mitigation plan for transmission-planning work, which would clear up another long-running issue that has bedeviled the grid operator.

SPP’s planning staff, already swamped with other studies, have been trying to work on three Integrated Transmission Planning (ITP) studies at the same time. The 2021 ITP has been in red status since early this year, meaning it can’t meet its scheduled October 2021 end date even with mitigation efforts.

Staff reviewed the ITP processes and other planning initiatives and brought a mitigation plan to stakeholders. However, MOPC rejected that proposal by a couple of percentage points. (See “Overburdened with Tx Planning Work, Staff Looks for Help,” SPP MOPC Briefs: April 12-13, 2021.)

This time, the committee gave a revised version of the mitigation plan a 97% approval vote. It waives the requirements to perform all of the 2021 assessment’s benefit metrics, performing only the adjusted production cost metric. The plan also waives the tariff requirement that the 20-year ITP assessment be performed at least once every five years, pushing its due date to April 2023, skips some sensitivities and will reuse the 2022 scope in 2023.

“This keeps the 2021 ITP on track and within this calendar year,” Casey Cathey, SPP’s director of system planning, told the committee. “It will have nice ripple effects in 2022. We’re not starting from scratch … and it reduces consultants’ costs.”

February Storm Review Nearly Complete; MMU Issues Report

COO Lanny Nickell gave a high-level overview of SPP’s comprehensive review of its performance during the February winter storm, which will be presented in greater detail to the Board of Directors and Members Committee next week. (See “Winter Storm Review,” SPP MOPC Briefs: April 12-13, 2021.)

Nickell has been editing a report encompassing the work of five parallel workstreams that have been digging into February’s events, when SPP had to shed load for the first time in its 75-year history.

The teams, focused on operational, financial, communications, regulatory and market monitor reviews, have been meeting mostly behind closed doors in identifying 22 recommendations for preventing a similar event. The recommendations have been divided into three tiers: those that deal with the root cause, those that would improve SPP’s response and everything else. The categories include fuel assurance, resource planning and availability, communications, and emergency response process and planning.

Nickell declined to share much detail on the report, citing the ever changing data and the sensitive nature of documenting the findings. An executive session was held last month, drawing 254 staff members and stakeholders.

“If you haven’t reviewed the details of the report, there will be a lot of opportunities in the future,” Nickell said. “As we develop the policies and perform the assessments, there will be many, many opportunities for your involvement and feedback.”

The day after the MOPC meeting, SPP’s Market Monitoring Unit released a report it developed independently in conjunction with the RTO’s comprehensive review. The report covers lessons learned and offers recommendations in pointing a finger at the unavailability of natural gas supplies, as have similar studies on the storm’s devastating effects on the ERCOT grid.

“At the very heart of the cold weather event, natural gas plants were unavailable to generate,” the MMU’s report says. It notes gas-fired plants could not obtain fuel because they did not have enough credit when prices soared into triple figures, or there was not gas available at any price.

That led the Monitor to recommend accounting for “more granular approaches” to measuring capacity, including seasonality and forced outage rates. “Availability may require resources to have secondary or backup fuel sources, or alternatively storage capabilities,” the MMU said.

The Monitor also recommended “meaningful incentives” for availability, a seasonal or more frequent resource adequacy requirement and that SPP plan for shocks to generator availability.

Uncertainty Product Endorsed

The Market Working Group ended several years of work on an uncertainty product by gaining the MOPC’s strong endorsement of a revision request (RR449) that will add the product to SPP’s market offerings.

America Electric Power’s Richard Ross, who chairs the MWG, said his company still has some concerns over the product, “but at this point, we don’t have a better solution.”

“We’re ready to move forward and see about getting this approved at FERC,” he said.

Southwestern Power Service’s Bill Grant agreed that SPP doesn’t have a better product for the time being, but pointed out that it gives the operators another tool.

“I don’t think this is a finished product by any means. It will have to be monitored and modified,” he said.

The change, a Holistic Integrated Tariff Team recommendation, is designed to enable a market-based approach to manage uncertainty by procuring resource flexibility to respond to net load variations within a defined time horizon. The MWG said the product will increase reliability by factoring statistical uncertainty impacts into both commitment and dispatch; reduce make-whole-payments and the price suppression resulting from out-of-market actions to maintain reliability; and provide transparent prices and a new revenue stream for online and offline resources that participate.

The Strategic Planning Committee (SPC) unanimously endorsed the measure during its meeting Wednesday.

The MOPC also endorsed:

• • • a joint recommendation (RR414) by the Operating Reliability Working Group and the Operations Congestion Management Task Force to develop recommended initial effective limits for reliability coordinators based upon previous experience or analysis that can be used for flowgates during congestion management events and reduce system operating limit exceedances. The revision’s 74% approval was the lowest of the votes taken.
    • the Regional Tariff Working Group’s revision request (RR432) that defines which generation outages qualify for compensation, removes opportunity costs from consideration for compensation, removes the preliminary transmission provider approval step prior to rescheduling an outage and specifies the provider’s use of revenue neutrality uplift to recover generation outage compensation costs.
    • the Supply Adequacy Working Group’s proposal to replace the planning criteria’s current accreditation methodology for wind and solar resources with effective load-carrying capability methodology (RR418). The change takes into account the variability of wind and solar resources during peak load hours.

Continental Resources, L&O Power Join MOPC

The committee increased its membership to 93 with the addition of Continental Resources and L&O Power Cooperative. Both companies have been assigned a MOPC mentor as part of their onboarding process.

Oklahoma City-based Continental, a petroleum and natural gas exploration and production company, became SPP’s 105th member on May 1. It is the RTO’s third-largest retail customer, next to Walmart and Google.

Iowa-based L&O joined SPP earlier this year. (See “L&O Joins the RTO,” SPP Board/Members Committee Briefs: April 27, 2021.)

SPP to Receive Inverter-based Data

Members approved RR430 by 89% after it was pulled off the consent agenda over concerns about the level of information it required from manufacturers of inverter-based resources. Without all the necessary data on the machines, SPP will have to use generic information that could result in more conservative operations and increased costs, MOPC Chair Denise Buffington, with Evergy, said in a report to the SPC the next day.

The Advanced Power Alliance’s Steve Gaw said the RR’s language implies the required data would pass through the developers to SPP, without a provision “that necessarily protects the manufacturer.”

“We’ve had multiple calls with members as well as the original equipment manufacturers. We handle confidential data all the time,” Cathey said.

Cathey said NERC staff believe they have the ability to require the data and they are working on a standard authorization request. In the meantime, the RR will allow SPP engineers to use a screening tool to analyze connecting the resources in weak areas of the transmission system to avoid control interactions leading to inverter instability.

The MOPC unanimously approved an otherwise light consent agenda that included four RRs:

• • • CPWG RR446: provides an alternative method for a credit customer unable to meet SPP’s minimum capitalization requirements to participate in the Integrated Marketplace by including transmission congestion rights credit-exposure calculations in the financial security requirements.
    • MWG RR440: adds language to outline the registration process for dispatchable demand response resources.
    • RTWG RR439: resolves a conflict between business practice 7070, related to the assignment and novation of designated transmission owners in SPP’s competitive transmission process, and the tariff.
    • TWG RR438: corrects omitted revisions in the modeling policy for GI requests, adding that it should apply to off-peak periods during the light-load season.