TULSA, Okla. — Like the walking dead, Tariff Attachment Z2 keeps returning from the grave, much to the consternation of SPP and its stakeholders.

General Counsel Paul Suskie last week laid out before the Markets and Operations Policy Committee the implications of FERC’s February reversal of a waiver it had previously issued to SPP on the attachment. (See FERC Reverses Waiver on SPP’s Z2 Obligations.)

The commission ordered SPP to refund, with interest, credit payment obligation amounts dating back to 2008, except for the one-year billing adjustment limit allowed in the Tariff. SPP has estimated the obligations to be approximately $200 million.

SPP was seeking a retroactive Tariff waiver allowing to invoice transmission service customers for Attachment Z2 credit payment obligations for the 2008-2016 time period prior. FERC ruled the waiver request to be retroactive ratemaking, saying SPP did not provide adequate notice.

“In my opinion, FERC had no idea of what it was unraveling,” Suskie told the MOPC on April 16. “We’ve listed 20 issues that are going to be challenges if we undo this.”

Included among those is how SPP will redistribute to transmission owners’ point-to-point revenues it had clawed back in the historical settlements process. Staff said it would share the full list of issues with stakeholders.

Suskie said SPP and other parties on April 1 asked FERC for a rehearing and clarification of the order (ER16-1341). He also said the RTO is developing a compliance plan to be filed with FERC no later than June 28.

Attachment Z2 details how sponsors that fund network upgrades can receive reimbursements through transmission service requests, generator interconnections or upgrades that could not have been honored “but for” the upgrade. SPP said that delays in implementing computer software kept it from listing certain creditable upgrades in aggregate facilities study reports, calculating and assessing costs, and distributing credits to transmission customers before August 2016.

SPP Proposing to Assign Kansas NTC to GridLiance

SPP’s proposal to assign the Kansas Power Pool’s (KPP) notification to construct (NTC) a 69-kV rebuild to GridLiance High Plains met pushback from the MOPC over increased costs within transmission zones and the usual turf battles between the RTO’s legacy TOs and smaller entities.

“If this was someone else other than GridLiance, or another [investor-owned utility], you would gladly accept the assignment,” Tri-County Electric Cooperative’s Chris Giles complained to the committee’s membership.

“Amen!” came a voice from the opposite corner of the meeting room.

The project was originally assigned to KPP in February 2018. Rather than reconductor 4 miles of 69-kV lines from the city of Winfield, Kan. — a KPP member — to a Westar Energy substation, KPP decided on a full rebuild and raised the initial estimate from $1.5 million to $3.6 million.

Larry Holloway, KPP’s assistant general manager for operations, said his company has been unable to gain the obligation to build from Kansas regulators, which led to GridLiance’s involvement. The five-year-old company, which partners with public utilities, announced in January a “long-term partnership” with Winfield in which GridLiance would acquire 65% of the city’s 29 miles of 69-kV facilities and invest in a “needed reliability upgrade.”

SPP said GridLiance’s own data show it will increase the annual cost to customers if it retains the NTC, largely because its tax requirements are greater than KPP or Winfield’s.

GridLiance High Plains President Brett Hooton said the cost of the project itself remains the same, regardless of the assignment from Winfield to GridLiance. He said SPP’s cost estimate over the project’s four-year life works out to $75,000/year.

“The cost difference on rates primarily relates to the fact that GridLiance is a taxable entity and the city is not,” Hooton told RTO Insider. “Any time there is an assignment from a municipal utility to a taxable utility, there will be similar cost impacts.”

Hooton said GridLiance intends to build the facilities with 138-kV capabilities, matching Westar’s existing infrastructure.

The issue is likely to receive similar pushback during the April 29-30 Regional State Committee and Board of Directors meetings. SPP’s Tariff required staff to “advise” the MOPC of the proposal, with the final decision being left to the board.

“If the board were to reject the assignment because of the small cost impact, it would set a precedent that municipal utilities would virtually be unable to ever assign or novate an NTC because of their tax-exempt status,” Hooton said.

Staff Explains 9-Month Delay to New Settlement System

Staff briefed the MOPC on its delayed new settlement system, which was supposed to go live May 1. However, a condensed project timeline and missed deliveries left developers without enough time to build software and train end-users, pushing the implementation back to Feb. 1, 2020.

SPP announced the delay to project participants on Feb. 15, saying the project was in red status because of “various system issues” and that it was pausing member testing as it reassessed the timeline, remaining work and required testing.

Settlements Director Don Shipley said incorporating additional applications and links to other systems increased the project’s risk. The settlement system replacement project will consolidate several systems and automate manual processes, reducing staff costs and improving personalized customer service, he said.

“We had several parallel paths — development, testing, training — all going on at the same time, rather than back-to-back,” Shipley said.

Shipley said the inability to run the system end-to-end meant staff couldn’t do day-in-the-life testing, which also meant members couldn’t “appropriately” test their internal systems. Even then, there were frequent errors in the software’s calculations, he said.

“The right decision was to delay and ensure we have a system that worked. The most catastrophic thing that could happen is if we couldn’t settle the entire system when we cut over,” Shipley said.

Following several weeks of analysis and review, SPP has worked to improve its communications both internally and with the vendor, Symphono. Daily meetings, called “scrums,” are held to “understand what is going to be happening” and to discuss any issues at the vendor level. Staff are now focused on the “total development effort,” with a June 28 deadline to complete all code, and internal testing and training has been increased.

“We don’t want this to become a pattern. What are we doing to learn from mistakes like this and Z2 to ensure it doesn’t happen again?” asked Kansas City Power & Light’s Denise Buffington, the MOPC’s vice chair.

“I understand where you’re coming from, with the Z2 followed by the settlement system,” Shipley said. “We’ve already applied some of the lessons learned from Z2, so it’s an incremental process. We still have to understand how we efficiently deliver projects.”

“Communication is critical. Everyone has to be talking to each other,” said SPP’s engineering vice president, Lanny Nickell. “We tend to overcomplicate things, and we tend to be optimistic. We tend to set very aggressive schedules.”

Shipley was reluctant to lay the blame on Symphono, which built a similarly customized system for MISO. He said because of SPP’s larger footprint and “the way we settle,” SPP needed “something different.”

“I do think we underestimated some of the complexities of adding [other capabilities] to our systems,” he said. “This vendor worked very hard with us. They made mistakes and missteps, but we did as well. We all bear some responsibility of where we were in February. We all bear the responsibility of the new timeline.”

The project was approved two-and-a-half years ago with an estimated capital cost of $5.3 million. The implementation delay has not increased those costs, SPP said, but will likely result in additional maintenance costs because the existing settlement system and other legacy systems and software will run longer than planned.

FERC on Thursday granted SPP’s request to defer several Tariff changes because of the settlement system’s delay (ER17-1568). The Tariff revisions were filed because of changes to other systems as a result of the new settlement system. (See related story, “SPP Granted Delay for Tariff Revisions,” FERC Tells SPP to End Exit Fee for Some Members.)

SPP Broadens PMUs’ Reach with Revision Request

SPP will get another chance to widen the use of phasor measurement units (PMUs) within its footprint with the MOPC’s approval of a revision request (RR) that addresses a FERC rejection of a previous RR.

RTWG RR340 changes the PMUs’ installation location from the point of interconnection to the point of change of ownership and classifies equipment as “transmission owner interconnection facilities” to fully address cost responsibility. The RR also adds language to allow existing equipment to serve as a PMU.

“This just clarifies the cost issue and where [PMUs] will be installed,” said American Electric Power’s Richard Ross during the heat of discussion.

The recommendation was passed over two opposing votes and a half-dozen abstentions, primarily over installation costs.

RR340 is a response to a previous change request that would have required PMUs at new generator interconnections but was rejected by FERC in August. The RTWG said the commission found the language regarding the PMUs’ installation funding unclear. The commission directed SPP to clarify how TOs will treat PMU installation costs to avoid including them in transmission rates. (See “Commission Rejects PMU Proposal over Cost Concerns,” 3rd Time’s a Charm for SPP Resource Adequacy Proposal.)

“This RR is trying to get in front so that we can capture more PMU data as it is brought on,” said Cody Parker, SPP’s supervisor of operations support.

Parker said the RTO has completed the first phase of its PMU project, creating an informational-only system not used in real-time operations. Subsequent phases will be dependent on increased PMU coverage, he said.

SPP defines PMUs as monitors that provide precise grid measurements for synchrophasors. PMU measurements are taken at high speed, typically at 30 observations/second. Each measurement is time-stamped according to a common time reference, allowing measurements from different locations and utilities to be synchronized and combined to provide a precise and comprehensive view of the entire interconnection.

DER White Paper Gains Endorsement

The MOPC endorsed a Supply Adequacy Working Group policy paper that further defines the requirements for demand response programs and behind-the-meter generation and addresses whether to treat them as a load modifier or capacity.

The Distributed Energy Resources Policy is intended to ensure that all net peak demand is carrying the appropriate capacity, as required by SPP’s resource adequacy requirements. SPP’s Tariff allows a load-responsible entity to reduce its forecasted peak demand through DR programs and controllable and dispatchable BTM generation.

MOPC members debated the need to require DERs to attest to having firm transmission service to load, as the paper’s draft required. Oklahoma Gas & Electric’s Greg McAuley suggested the phrase “attest to having firm delivery to load” be used instead of “transmission service,” which helped to gain approval against one dissenting and one abstaining vote.

“Some of the potential resources in [the controllable and dispatchable resource] category are behind retail meters and, as such, may never impact the transmission system and, therefore, would never need or have firm transmission service,” McAuley explained.

The nine-page white paper, which has been approved by the SAWG and the Cost Allocation Working Group, will be turned into a business practice and eventually become an attachment to the Tariff’s Attachment AA.

HITT Working to Finalize Report to Board

Suskie told the committee that the Holistic Integrated Tariff Team hopes to complete its yearlong work by the end of the month and present a final report to the Board of Directors for its April 30 meeting.

Composed of stakeholders, regulators and staff, the HITT has entered the third phase of its work in drafting and finalizing a report to the board. The team has been meeting since April 2018 to determine the optimal alignment of SPP’s planning processes, cost-allocation methodologies, and market products and services. (See SPP’s Tariff Team Begins Carving up the Elephant.)

“We remain positive we can get through the end of the month, but we have left the most contentious issue for last,” said KCP&L’s Buffington, referring to zonal transmission cost allocations.

“Like when the U.S. Constitution was drafted, there are a lot of different people on different sides,” Golden Spread Electric’s Mike Wise said. “I’m very optimistic that as a group, we are going to achieve what we set out to do, which is achieve value for members of the pool. Not everybody is going to be happy with it. I have compromised; Denise has compromised. I’m encouraged, very encouraged, where we are right now.”

The HITT meets in Dallas on April 25 to complete the report. It has posted a draft version on its website.

MWG Proposal Improves RR Impact Analyses

The MOPC unanimously approved a recommendation by the Market Working Group and RTO staff to improve the RR process’s impact analysis by revising the cost data that go into calculations.

SPP’s Gary Cate said the new methodology will provide a clear view of estimated vendor costs by no longer including capitalized costs, including those staff salaries that are already accounted for in the capital budget. The changes will also add transparency into staff time by adding the “true impact” to staff within the implementation timeline.

Staff costs will only include staff hours and remove redundant cost reporting between the capital and foundation budgets. Cate said the current method inflates staff cost by lumping average salaries into the cost of impact assessments.

With the change, impact analyses will provide a range of vendor costs rather than a single value with a rough order of magnitude +/- 50%.

Boston Marathoner Henderson Earns her Applause

Members greeted Golden Spread’s Natasha Henderson with applause when she joined the meeting, fresh off completing her second Boston Marathon the day before. Henderson battled unexpectedly warmer temperatures that slowed her pace, but she used a finishing kick to reach the finish line in just under four hours.

“I thought about dropping, but who drops out of the Boston Marathon? Not me,” Henderson told RTO Insider. A personal best and qualifying for next year’s marathon out of the question, she said, “this was now going to be a very long training run.”

Henderson was scheduled to run a half-marathon in early June in Steamboat Springs, Colo., but has changed her registration to run the full 26 miles in an attempt to qualify for next year’s Boston Marathon.

“Some days, like my second Boston Marathon, are not what I hoped they would be, but they make me stronger,” Henderson said. “For me, running is about pushing myself and being a better person. I learned from the experience and hope to have another Boston Marathon in my future.”

Members Pass 10 RRs on Consent Agenda

The MOPC unanimously endorsed its consent agenda, which consisted of 10 revision requests:

• BPWG RR343: Automates a manual task with installed software to prevent interchange overscheduling.
• BPWG RR344: Retires Business Practice 2500, which was implemented when the aggregate transmission service study could take years to complete. The study’s methodology has been revised to include a six-month completion requirement, making the practice obsolete.
• MWG RR346: Includes transition major maintenance among the costs associated with start-up and no-load operations to be included in mitigated no-load and start-up offers beginning with the April 18, 2019, operating day.
• ORWG RR338: Expands and clarifies the description of “most severe single contingencies” and other potential contingency events used to determine the reserve sharing group’s contingency reserve obligation.
• ORWG RR349: Requires responsible entities to use the reliability communications tool (R-comm) instead of telephones to communicate with the SPP balancing authority.
• RTWG RR345: Limits to three the number of identical transmission service requests impacting a DC tie during the submission window, as outlined in NAESB Business Standard WEQ 001-8.3.
• RTWG RR347: Removes grandfathered agreements that have expired or are no longer in service.
• RTWG RR353: Revises language in Tariff Attachment V to account for changes in RR335, which adds a three-stage generation interconnection study process and implements required changes in FERC Order 845-A.
• STAFF RR351: Clarifies and modifies the RR process requirements, allowing change requests to be withdrawn without requiring MOPC review and action. Any actions may still be appealed by qualified entities to the MOPC.
• TWG RR350: Eliminates language in the criteria that is already covered by NERC standards or other SPP standalone documents, minimizing inconsistencies or conflict with current and future NERC standards and revisions.

— Tom Kleckner