By Tom Kleckner

Board Approves Modernized Cost-recovery Structure

NEW ORLEANS — SPP continued its effort to modernize its cost-recovery processes last week, agreeing to replace its broad single rate schedule with four targeted ones.

The Board of Directors approved the Schedule 1A Task Force’s recommended preliminary designs during its regular quarterly meeting. The group’s four rate schedules seek to better align beneficiaries with payers and include energy transactions in their design.

The new rate design was approved by the Markets and Operations Policy Committee two weeks prior. The task force will now draft Tariff language and bring it back for approval in April or July. It has targeted implementation by June 2021. (See “1A Task Force’s Fee Schedules OK’d,” SPP Markets & Operations Policy Committee Briefs: Jan. 15, 2019.)

SPP says its current cost-recovery mechanism is based on a two-decade-old structure “that no longer aligns with actual use of our system.”

Under the new rate design, four rate schedules will replace the current one. Planning, scheduling and dispatch costs will be paid by transmission customers; financial administration costs by their users; market-clearing costs by virtual and real-time market participants; and markets facilitation by real-time market participants.

The task force agreed to use a mix of demand and energy charges, with market costs recovered through energy changes and planning costs through demand. Much of the debate centered on scheduling and dispatch costs, energy billing determinants and financial instruments, said Evergy’s John Olsen, the task force chair.

“I don’t think we made anyone perfectly happy throughout the process, but it was a great compromise,” Olsen said.

Oklahoma Gas & Electric’s Greg McAuley abstained from the Members Committee vote on the issue, saying his company wants to see independent generators paying their share of the costs.

“We don’t see Tariff language dealing specifically with that,” he said. “We thought this was a missed opportunity to address what we see as an inequity that exists now. We’ve got more generation in our [interconnection] queue than we’ve got load. This was an opportunity to take that uncommitted new generation and give it a stake in this infrastructure that accommodates them.

“We think it’s a move in the right direction. We’ll be watching and participating moving forward,” McAuley said.

David Osburn, general manager of the Oklahoma Municipal Power Authority, said he agreed in principle with the proposal, as market participants would be paying more of their share of the costs.

“Our concern was going from one charge to four. We just want to be careful not to make something more complex than it should be,” Osburn said. “As the real numbers develop, hopefully, we’ll get a better comfort level as we move forward. Being a small organization, we have difficulty covering all these activities.”

The task force was only formed last summer, but some of the work goes back several years, said Director Bruce Scherr, chair of the Finance Committee.

“We put a very significant stake in the ground here,” he said. “We can make refinements as we go through time. That’s not trivial, because it will require new filings at FERC. But it’s an important step in the right direction.”

Brown: SPP’s Prime Focus is RC Services in West

SPP CEO Nick Brown told the board and members that the grid operator’s primary goal this year will be to successfully implement reliability coordination services in the Western Interconnection.

The RTO recently said it remains on track to be certified in August and is scheduled to go live with its RC services on Dec. 3. It has signed RC contracts with about 12% of the load once served by Peak Reliability, which announced last year it would cease to exist by the end of this year. (See CAISO RC Wins Most of the West.)

“Entities coming and going in our footprint is not a new thing for us,” Brown said, referring to the additions of Nebraska public utilities and the Integrated System, and Entergy’s move to MISO. “It’s a new thing for entities in the West and for NERC. We’re very aware of NERC’s anxiety for taking what was performed under a single entity’s umbrella and bifurcating that under multiple entities.”

Also foremost on Brown’s mind is the Value and Affordability Task Force, which held its first “quasi-closed” session — members were allowed one representative to attend — on Jan. 30. Reporting directly to the board and led by Board Chair Larry Altenbaumer, the group is reviewing the cost recovery of transmission investments and the ongoing benefit being delivered from that investment and SPP’s operation.

“There’s significant confidential information that will have to be shared, if that group is to do its job,” Brown told members. “It makes me nervous. I compete with every one of you for personnel.”

Other SPP goals include:

• Replacing the organization’s settlement system, which processes the more than $20 billion in annual revenues that flow through the markets. The project is behind schedule, but staff believe they can begin testing the system in May.
• Improving generation interconnection processes.
• Seeing conclusion of the work of the Schedule 1A Task Force and the Holistic Integrated Tariff Team, which are seeking to improve SPP’s transmission planning, markets and cost-allocation processes.

Members Increase Board’s Compensation

During a special Members Committee meeting, members sided with a Corporate Governance Committee recommendation and increased the board’s compensation for meeting attendance.

Directors will see their annual retainer raised from $30,000 to $50,000. Attendance at required meetings and board dinners will yield a total annual compensation increase from $81,000 to $101,500.

Brown said the CGC based its recommendation on recent research from NERC, two-year-old data from the ISO/RTO Council and a national association of board directors. On an annualized basis, he said, SPP directors’ compensation fell around the 50th percentile of the market.

Brown said SPP will work with compensation consultant Mercer this year to do a “full-blown” study.

Members also elected three representatives to three-year terms on the Members Committee: American Electric Power’s Peggy Simmons, representing the investor-owned utility sector; and Basin Electric Power Cooperative’s Tom Christensen and Tri-County Electric Cooperative’s Zac Perkins, representing the cooperative sector.

Perkins won a contest vote for his seat against Midwest Energy’s Bill Dowling, who was nominated from the floor without discussion.

GreenHat Energy Situation Unlikely in SPP, Director Says

Scherr told the board and members that an event similar to GreenHat Energy’s massive default on financial transmission rights in PJM’s market is unlikely to happen in SPP. PJM now estimates the event could cost its members more than $430 million. (See PJM: FERC Order Could Boost GreenHat Default by $300M.)

“There are significant differences in the SPP markets, such as the level of congestion and structure of [FTR] products, which reduce the likelihood of this magnitude,” he said.

Scherr said he is heartened by the Credit Practices Working Group and Market Monitoring Unit’s oversight of the grid operator’s FTR markets.

Board Approves $1.8B in Transmission Projects

The board passed a consent agenda that included the 2019 SPP Transmission Expansion Plan (STEP) report, previously endorsed by the Markets and Operations Policy Committee. The report anticipates that an estimated $1.8 billion of projects will be built over the next five years in 13 states.

Also approved as part of the agenda:

• Revision to SPP’s bylaws to allow any member to appeal to the board with a written request any action taken or recommended by an organizational group.
• A Tariff revision (TWG RR237) that 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.
• 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 the Tariff’s Attachment Z2.
• Modification of Westar Energy’s notification to construct a 345/138-kV transformer, requiring all elements and conductor to have an emergency rating of 440 MVA. The original requirement was 492 MVA.