By Tom Kleckner

DALLAS — Stakeholders working to improve SPP’s cumbersome Z2 crediting process for network upgrades met here last week to learn about how potential solutions might affect the RTO’s other functions — leaving one stakeholder pining for the good old days when he worked in an operations center.

Another stakeholder, the Kansas Power Pool’s Larry Holloway, expressed mild frustration as the Nov. 29 conversation turned to long-term and incremental long-term congestion rights (LTCRs and ILTCRs, respectively) and their potential addition to the Z2 process.

“There seems to be a bit of mission creep. I thought we were looking at a better way to do business with Z2,” said Holloway, KPP’s assistant general manager of operations. “I thought we were looking at a less complex way of handling [Z2] going forward and handling the burden of these historic costs. Now it sounds like we’re keeping Z2 and having another process moving forward.”

“Our goal is to come up with a better process,” Bruce Rew, SPP’s vice president of operations, reminded the task force. “We’re working through the process of how we would transition to a different process.”

SPP staff suggested LTCRs and ILTCRs could serve as potential alternatives to Z2 credits. LTCRs cover the entire June-May year and can be renewed annually or converted into TCRs. ILTCRs, already used by most RTOs, would provide the option of long-term rights for participant-funded transmission upgrades.

“The TCR process tries to forecast what the [congestion] pool will be,” said Charles Cates, SPP’s manager of transmission services, explaining that solving congestion at one point on the system can create congestion elsewhere. “A TCR is your share of the congestion pool. The value of the TCR may increase as more transmission requests come onto the system. Some bidders may try and predict where that congestion will be and seek TCRs.”

‘Nightmare’

“I’d like to ditch this Z2 nightmare, but the problem is, [when] you give away the TCR to a project sponsor whose project resolves the issue and there’s no congestion, he’s getting nothing [of value],” American Electric Power’s Richard Ross said. “I’m afraid this will give incentives for some sort of twisted sponsorship where sponsors will want to solve some, but not all, of the congestion. If there’s still congestion and you’ve given that TCR away to that sponsor, it’s not available for that transmission customer that wants, needs and expects it.”

“I keep hearing the word ‘incentives,’ but we’re really looking at reimbursement mechanisms,” said Oklahoma Gas & Electric’s Greg McAuley, agreeing with Ross. “We’re looking to pay [upgrade sponsors] back and make them whole for what they’ve added to the system, but we’re not trying to provide incentives for new transmission construction.”

Cates noted SPP’s TCR market is still going through growing pains since it was implemented as part of the RTO’s Integrated Marketplace in 2014. In recent months, the TCR market’s funding has just reached a 90% funding level.

“To be fair, we don’t have much of an ILTCR market because no one takes them,” SPP’s Lanny Nickell said.

The TCR market’s inability to provide a one-for-one offset with hedges against congestion has become a growing concern for load-serving entities. They point to wind farms being granted non-firm service while being allowed to put physical energy on the system.

“How do they get away with not paying for non-capacity upgrades, and why are we being forced to pay for sponsored upgrades?” Ross asked rhetorically. “That doesn’t make a bit of sense. Why are we paying $10 for something that’s not worth a nickel?”

Kansas City Power and Light’s Denise Buffington, the task force’s chair, asked staff to provide more information on how the capacity versus non-capacity issue is handled in other markets. The task force will meet again before January’s Markets and Operations Policy Committee meeting in Dallas, where it will take an even deeper dive into SPP’s ILTCR proposal.

‘And’ vs. ‘Or’

The group also discussed SPP’s aggregate and planning studies, generation interconnection process and the auction revenue rights and TCR processes. Staff also explained the Z2 process was used as a mitigation for FERC’s concern about “And” pricing for service, embedded costs and any other upgrade costs.

In a 2001 order, the commission said the pricing of transmission service could reflect either the greater of the network’s average cost (with expansion costs rolled-in) or the incremental cost of the expansion, known as “Or” pricing. It prohibited pricing based on a combination of average and incremental costs, known as “And” pricing.

SPP’s Tessie Kentner said any changes to the Z2 crediting process must not violate those principles. She said the commission accepted the RTO’s compliance filing and its use of Z2 credits for sponsored upgrades for Order 681, which requires organized electricity markets to make available long-term firm transmission rights.

“I think we have a deeper understanding of the complexity of Z2 and may have highlighted that Z2, as implemented today, still has many unknown impacts to participants,” Buffington said.

Ross did provide a moment of levity when he presented “Richard Ross Gold Stars,” in the form of Christmas ornaments, to SPP’s Steve Purdy and Charles Locke. Ross said it was a sign of appreciation to the two for representing the RTO’s position on Z2 credits.

“Somebody has to take the shots for the organization,” Ross said.

KEPCo Files FERC Complaint

The Kansas Electric Power Cooperative became the first SPP member to pursue legal action over the Z2 revenue-crediting process when it filed a complaint with FERC under Sections 206 and 306 of the Federal Power Act and Rule 206 of the commission’s Rules of Practice and Procedure (EL17-21).

KEPCo said in its Nov. 22 filing that SPP’s direct cost assignment of approximately $6.2 million to KEPCo violated the RTO’s Tariff and the filed rate doctrine, and is “otherwise unjust, unreasonable and proscribed” by the FPA. The complaint seeks relief from directly assigned Z2 obligations and a refund for payments already made.

KEPCo COO Les Evans had hinted at the filing when his request for a waiver from directly assigned Z2 network upgrades was rejected by the SPP board in October. (See SPP Board Lets Action on Z2 Stand; Litigation Likely.)

Seven parties have already intervened in the case, including SPP members KCPL, Sunflower Electric Power, Western Farmers Electric Cooperative and the Arkansas Electric Cooperative Corp.

Competitive Transmission, Strategic Planning, Other Groups Meet

The Z2 task force’s meeting was just one of several held in Dallas last week in and around AEP’s offices.

The Competitive Transmission Process Task Force met Wednesday to revise draft revision requests that reflect input from the October Board of Directors meeting and to incorporate changes in SPP’s annual transmission revenue requirement template. The group will conduct a conference call next week to prepare for the January board meeting.

The Strategic Planning Committee met Thursday to review and discuss the operational challenges facing SPP as a result of the 22,000 MW of wind power in the interconnection queue.

Stakeholders shared their concerns that the expected expiration of renewable tax credits is leading to a surge of additional generation being added to the system, citing congestion concerns. Wind and solar resources account for 98% of SPP’s current generation interconnection queue.