By Tom Kleckner

Stakeholders Approve Streamlined Generator Interconnection Process

NEW ORLEANS — SPP stakeholders last week unanimously approved changes to the RTO’s generator interconnection process to simplify what had become a burdensome process involving the submission of repetitive data.

The Market and Operations Policy Committee approved a revision request (RR335) that adopts a three-stage study process: thermal and voltage analysis, stability analysis, and facilities study. The RR also changes the amount and timing of security deposits, publishes study models earlier in the process, and allows penalty-free withdrawals when costs increase above certain thresholds.

The task force said the new process will be easier for SPP to administer and for users to understand and navigate, with most upgrades being identified in the first stage. That would allow transmission customers to make an informed decision before committing to a lengthy and costly stability analysis.

The group said reducing the number of withdrawal requests late in the process would reduce restudies and uncertainty. Customers will be able to withdraw after the second of three decision points without incurring financial penalties when assigned upgrade costs increase by at least 35% and $15,000/MW between study stages.

The measure was brought forward by the Regional Tariff Working Group (RTWG), which took up the issue following last year’s dissolution of the Generator Interconnection Improvement Task Force (GIITF). The GIITF was created in 2016 to identify improvements in SPP’s transmission study process, which had become clogged with more than 62 GW of interconnection requests. (See SPP Generator Interconnection Group Wraps up Work.)

20-Year RR Tabled

The committee tabled a second RR (RR334) that would add the 20-year Integrated Transmission Planning (ITP) economic-only assessment as an eligible study in determining whether projects are eligible to become competitive upgrades.

SPP has not previously issued notifications to construct (NTCs) based on long-range studies, although it is not precluded. Evergy opposed the RR within the RTWG, saying the 20-year assessment is intended to be indicative and that no NTCs should be issued without additional analysis in the annual ITP study. To do so would mean SPP was issuing an NTC for a project without studying its reliability impact on the system, Evergy said.

The MOPC asked staff to return the RR when its language is clarified to make it clear the 20-year-assessment would not result in NTCs being issued without additional study to evaluate its reliability impact and the year the project is needed.

HITT Educates MOPC on its Progress, Learnings

The Holistic Integrated Tariff Team (HITT) conducted an education session before the MOPC meeting formally began, briefing stakeholders on its work and issuing a last request for additional information. The team has been meeting since April on a plethora of presentations and proposals.

SPP General Counsel Paul Suskie, who serves as the HITT’s staff secretary, told the committee that a final report will be issued to the Board of Directors in April. The report will include details on which stakeholder groups will be tasked with working out the specifics in the Tariff language, policies, implementation and timelines.

“It’s become obvious to HITT members that technology is rapidly changing and rapidly impacting our industry,” Suskie said. “We always talk about turning the aircraft carrier in this industry. Technology is changing how rapidly the aircraft carrier is turning.”

Nebraska Public Power District’s Tom Kent, who chairs the HITT, said the group has narrowed its high-level policy recommendations to four subjects:

• Aligning SPP’s transmission planning processes and stakeholders’ resource adequacy needs with the Integrated Marketplace and Tariff requirements;
• Reviewing of existing transmission cost allocation methodologies;
• Holistically understanding of the Integrated Marketplace and essential reliability services in the face of the changing generation mix and new technologies; and
• Facilitating load-growth opportunities in the footprint.

A stakeholder panel on transmission planning and resource adequacy noted “traditional” planning processes have focused on the reliable delivery of firm capacity resources, while energy markets, public policy initiatives and other incentives have led to the increased development of

Supply Adequacy Working Group Chair Brad Hans of the Municipal Energy Agency of Nebraska said his group is working to ensure SPP maintains the “right type of resources.”

“How much variable energy resources do you allow in the footprint?” he asked. “The way we should look at it is, ‘How much dispatchable resources do you need to keep at all times from a reliability perspective?’”

Arkansas Public Service Commission staffer Cindy Ireland summarized a review of SPP’s cost allocation methodologies by saying, “At the end of the day, load is going to pay.” A member of the Cost Allocation Working Group, Ireland said the group is discussing which is the appropriate load to pay.

The market panel said SPP is considering a ramping product, but as staff’s Gary Cate said, pointing to MISO’s and CAISO’s products and ISO-NE’s exploration of the same, “We’re not breaking new ground with a ramp product.”

1A Task Force’s Fee Schedules OK’d

The MOPC approved four Schedule 1A rate schedules, an effort to recover SPP’s costs from the users of its services.

Members backed a recommendation from the Schedule 1A Task Force, commissioned last July, for:

• Planning, scheduling and dispatch;
• Transmission congestion rights administration;
• Market clearing; and
• Markets facilitation.

Evergy’s John Olsen said the group will now draft Tariff language and a white paper, which will be sent through the RTWG. He said the Tariff language would come back to the MOPC in April or July.

Olsen said the group spent much of its time discussing energy billing determinants and debated virtual transactions. He said one concern for the task force is avoiding the creation of discriminatory treatment.

The group has yet to include energy transactions in the rate design.

The measure was opposed by Oklahoma Gas & Electric Services and BP Wind Energy North America. ITC Holdings and Tenaska Power Services abstained.

MWG Withdraws 2 Revision Requests

The MOPC approved the Market Working Group’s recommendations to withdraw an RR related to the timing of real-time balancing market submittals. RR329 would have modified the market user interface (MUI) to allow market participants to “systematically” submit certain offer parameters on a continual basis. As designed, the MUI locks out users less than 30 minutes before each operating hour.

SPP’s Market Monitoring Unit said it could not support the RR because it doesn’t include language requiring generators’ parameters be based on physical limitations. The Monitor said it believes that physical parameters included in a resource offer should be based on “true, accurate and verifiable physical capabilities or limitations of the resource.”

The MWG said it was also withdrawing RR337, which calls for the MMU to file an annual review of frequently constrained areas (FCAs). FERC’s acceptance in December of SPP’s revised plan for a timely update of FCAs eliminated the requirement for an annual update. (See “FERC Approves SPP’s Streamlined FCA Process,” SPP FERC Briefs: FCAs, NPPD Complaint, Refunds.)

Staff Reports: MISO Event, Western RC Services

Staff told stakeholders that a FERC inquiry into last year’s emergency event with MISO is expected to be completed by early in the second quarter.

In January, severe cold weather and generation shortfalls in MISO South led MISO to exceed its regional dispatch limit on transfers between its northern and southern footprints across SPP’s system. MISO made emergency energy purchases from Southern Co. before operations returned to normal.

The two RTOs have been working since then to improve coordination across their seam.

Operations Vice President Bruce Rew told stakeholders that SPP’s effort to provide reliability coordination services in the Western Interconnection remains on track to be certified in August. He said the RTO has added about half of the necessary staff and expanded some of its models to incorporate Western entities.

SPP has signed RC contracts with about 12% of Western Interconnection load. It is scheduled to go live with its RC services Dec. 3.

Staff reported that the 2019 ITP process is off to a slow start with a couple of slipped milestones but said that won’t affect the downstream schedule. The study’s economic model and its balancing authority reliability power-flow models are scheduled to be completed in November.

The detailed project proposal window opened Jan. 8 and will close Feb. 6.

At the same time, the 2020 ITP process has just begun. Director of Transmission Planning Antoine Lucas requested stakeholder engagement, saying staff would soon be soliciting information for load and generation profiles.

MOPC Adapts to Leadership, Other Changes

The Jan. 15 MOPC meeting was the first in 18 years without SPP COO Carl Monroe serving as staff secretary. He was replaced by Lanny Nickell, SPP’s vice president of engineering.

“I guess we finally got it right enough, so we can let him step aside,” cracked board Chair Larry Altenbaumer.

The meeting was also the first that stakeholders could access over the Internet.

Staff and members also recognized outgoing MOPC Chair Paul Malone for his “passionate, devoted and conscientious service.” Malone is retiring from NPPD in February.

Among the several changes facing the committee is the newly delegated authority to approve Tariff- or criteria-related changes without sending them on to the board for final approval. Stakeholders can still appeal a MOPC decision to the board but must do so within a week of the decision.

The committee passed two such changes:

• Its unanimous endorsement of the 2019 SPP Transmission Expansion Plan (STEP), which lists all transmission projects needed over a 20-year planning horizon. The plan consists of 568 upgrades totaling $5.2 billion and documents the completion of $779 million worth of upgrades and the issuance of 23 NTCs last year.
• Its approval of East River Electric Power Cooperative’s sponsored upgrades of a new 115-kV line and a 115/69-kV transformer near Aberdeen, S.D. The project will be a creditable upgrade eligible for incremental long-term congestion rights or cost recovery through Attachment Z2.

Staff Withdraws 4 Mountain West Tariff Changes

The MOPC’s consent agenda included the withdrawal of four RRs related to SPP’s proposed integration of the Mountain West Transmission Group: MWG RR281, MWG RR282, MWG RR284 and MWG RR286.

The RRs were approved by the MWG in April 2018 but were rendered moot by the halt of integration efforts last year.

The 2020 ITP assessment scope’s approval was pulled from the consent agenda because of concerns over its age-based retirement of certain generating units. It was approved separately despite opposition from Southwestern Public Service and Xcel Energy Southwest Transmission.

The consent agenda’s unanimous approval also resulted in a charter revision for the Model Development Working Group, expanding its voting membership to “up to” 24, and in the Event Analysis Working Group’s (EAWG) dissolution. Created in 2017 to review major bulk electric system events, the EAWG was never called into action. Its responsibilities will now be picked up by other working groups.

Approved RRs included:

• BPWG RR331: Clarifies and reorganizes interchange tagging business practices for denial of schedules and emergency tags.
• MWG RR326: Updates expired language (replacing “bill statements” with “settlement determinant report”) and removes a redundant requirement to create documentation for a miscellaneous charge already included in the asset owner determinant report.
• MWG RR341: Aligns the Integrated Marketplace protocols and Tariff to comply with FERC Order 745 by modifying how the net benefits test is calculated.
• MWG RR342: Modifies attributes, definitions and names of determinants, and restructures a calculation to be consistent with existing calculations. The changes are necessary to implement automated contingency reserve deployment tests.
• RTWG RR330: Changes non-firm daily service submissions to no later than 10 a.m. CT and closes the daily non-firm submission window when the non-firm hourly submission window opens, matching the release of unscheduled firm transmission service to the non-firm market.
• TWG RR237: Removes duplicative or unnecessary language in the SPP criteria to make it consistent with NERC Standard TPL-001-4’s requirements and account for the differences between NERC’s requirements and SPP’s Tariff.