LITTLE ROCK, Ark. — After a one-year drop, SPP’s administrative fee will resume its upward climb in 2020 with the Board of Directors’ approval last week.

The directors signed off on a 9.1% increase in the fee to a record high of 43 cents/MWh. The fee dropped to 39.4 cents last year following an $8 million overcollection in 2018. It is projected to reach 46.6 cents in 2022.

The Finance Committee based its recommendation to the board on a net revenue requirement (NRR) of $172.3 million next year, compared with $157.5 million the year before. The NRR is composed of operating expenses (excluding depreciation and FERC assessment), principal payments on loans for capital expenditures and a capital reserve fund.

The board also approved the committee’s recommended budget, which includes a 6.5% increase in operating expenses to $209.1 million and a slight uptick in capital expenditures of $15.7 million.

Oklahoma Gas & Electric, Public Service Company of Oklahoma and Southwestern Public Service were among those that raised concerns over the increases. Director Bruce Scherr, who chairs the Finance Committee, told members that they were looking at a “cash-flow” budget, not a “profit” budget.

“Your comments are not new to us,” he said. “We’re going to keep a close eye on cash-flow improvement. What you should be concerned about is if we didn’t care about that, and we let [the increase] go to be institutionalized without further evaluation.”

SPS opposed the motion to increase the budget, while OG&E and Liberty Utilities abstained. All three companies abstained from the Members Committee vote to approve the administrative fee.

SPS’ David Hudson reacted negatively to the increases, pointing out that his company is “fighting hard” to keep its operating and maintenance expenses flat.

“We see this year after year,” he said. “This goes into retail rates. A 10% increase is too high.”

“We’re concerned with the revenue requirement and the increase in costs we continue to see,” OG&E’s Greg McAuley said. “We understand the nature of most of it, but in the world we operate [in] today, we continue to keep our operating costs flat. We look for the organization to meet us, because that’s what the customers demand of us.”

Board Chair Larry Altenbaumer took slight umbrage at the comments, reminding members of what they get for the costs.

“The organization has done a phenomenal job of living within its budget,” he said. “I’m not trying to minimize any of the comments, but the thing that continues to gnaw at me a little bit is the other side of the equation … the pushback is always on costs. There’s never any recognition of what members get for that cost.

“I continue to believe this organization is providing significant benefits that outweigh the costs you are paying. That doesn’t reduce our efforts to keep the pencils as sharp as we can, but constantly hearing one side of the argument is unfair to this organization,” he said.

The budget does not include costs for SPP’s reliability coordination functions in the Western Interconnection, which Scherr said have been budgeted separately and will be financed through debt and paid back over time.

SPP expects its employee headcount to increase to more than 650 by 2021 because of RC West needs and additional engineers added to handle the generation interconnection studies’ workload.

2019 ITP Portfolio: 44 Projects, $336M

The directors signed off on the 2019 Integrated Transmission Planning (ITP) 10-year assessment that SPP said will reduce congestion costs by 21% on average and lead to projected future net savings of up to 23 cents on average monthly residential bills in the footprint.

The portfolio’s 44 projects have an estimated engineering and construction cost of $336 million and include 166 miles of 345-kV transmission. Lanny Nickell, SPP’s senior vice president of engineering, said the assessment projected considerable wind and solar growth, conventional generation retirements and the effect of new technologies.

Members resumed a discussion begun at the Markets and Operations Policy Committee in mid-October over the futures used in the 2021 10-year assessment. A carbon-reduction future envisioning as much as 55 GW of wind and solar energy in 2031 was eliminated. (See SPP Debate: How Green is Our Future?)

NextEra Energy Resources’ Holly Carias pointed out that stakeholders “already know we’re going to exceed” the assessment’s base case future, which projects 2 GW of additional wind energy by 2029 beyond the 22 GW already on hand. Nickell said that it’s “more likely” that 8 GW of wind capacity will be added over the next 10 years.

“Having realistic futures is extremely important. What we’re seeing out of the 2021 futures is a lot more realistic than we’ve seen previously, so I think we’re on the right track,” Carias said. “We need to look differently at how we’re looking at benefits. Currently, we’re looking at benefits to load. Maybe it’s time to look at benefits to generation. Maybe [generation] should pay for more of the costs.”

“We did assess benefits to generators not committed to load. It’s a fairly large number,” Nickell said. “What we haven’t done yet is figure out a way, or opportunity, for other parties with generators not committed to load to participate in the funding. We don’t have the Tariff mechanism.”

“We have questions, or concerns, with the way the new ITP process favors [the emerging technologies] future with more wind, which drives more transmission … and drives further costs,” McAuley said. “We’re waiting to see a confirmation that the benefits that come out of these studies will continue to increase at the same rates we’re being told they will. We’re really unsure at this point, after a year of this, about the benefits and cost allocation.”

Sunflower Electric Power opposed the recommendation during the Members Committee vote. OG&E, Oklahoma Municipal Power Authority, Golden Spread Electric Cooperative and Tri-County Electric Cooperative abstained.

Board Sends Fast-start Tariff Change to FERC

The board approved a Tariff revision that complies with FERC’s directive to allow fast-start resources to set clearing prices, while also supporting the Market Monitoring Unit’s opposing filing with the commission.

MMU Executive Director Keith Collins told board members that the Monitor has identified two major market-design flaws in the revision request (MWG RR375): It applies the mitigation process in the price calculation and not the dispatch instruction’s calculation, allowing market participants to potentially manipulate the market; and it allows market participants to change start-up offers and no-load offers after the fast-start resources’ commitment has occurred.

Collins said that because the offers can set price for other resources, the MMU believes “this sends an inappropriate price signal and allows market participants to manipulate the market.” The Monitor has proposed applying the mitigation process in calculating both the dispatch instruction and price, and that the start-up and no-load offers evaluated at the time of commitment be used in the fast-start resource’s modified energy offer. (See “Members Endorse Quick-Start Revision,” SPP MOPC Briefs: Oct. 15-16, 2019.)

SPP staff said RR375’s scope was limited to meet only FERC’s requirement. The Members Committee voted unanimously in favor of the motion.

Golden Spread opposed the revision at the MOPC and said it would likely file comments at FERC.

“This is an incremental step,” the co-op’s Mike Wise said, noting it has engaged the Brattle Group for support. “We don’t believe SPP has complied with FERC’s desire on this.”

“I’m concerned some of what has to be done has to be resolved by FERC,” Altenbaumer said. “We can appropriately get the issue to FERC and have them resolve it in a constructive manner.”

The commission in June found the grid operator’s quick-start pricing practices to be unjust and unreasonable because they don’t allow prices to reflect the marginal cost of serving load and directed the RTO to make six Tariff changes in response. (See FERC Orders Fast-start Rules for SPP.)

FERC’s order wrapped up an investigation of several RTOs begun in December 2017 under the Federal Power Act. (See FERC Drops Fast-Start NOPR; Orders PJM, SPP, NYISO Changes.)

Last Meeting for Eckelberger, Skilton, Bernard

Expressing a need for “fresh thinking and planned transition,” SPP CEO Nick Brown announced to stakeholders that the board meeting was the last for Directors Emeritus Jim Eckelberger and Harry Skilton, and Director Phyllis Bernard.

The three have served together since 2003 and have a combined 55 years of experience as directors. Eckelberger served as the board’s chairman for 14 years before stepping aside last year. (See Eckelberger, Skilton Step Down from SPP Board.)

Eckelberger, Skilton and Bernard were all honored with resolutions from SPP and standing ovations from its members. Bernard participated by phone.

The board’s membership currently stands at nine active members following the approval of Julian Brix and Mark Crisson to three-year terms that begin in January. Brix has been a director since 2008 and Crisson since 2017.

The Corporate Governance Committee later this year will interview candidates for Bernard’s vacancy.

SPP to Pay up to $8.6M in Pension Benefits

Directors approved the Human Resources Committee’s recommendation to offer lump-sum payments to terminated SPP employees vested in the RTO’s pension plan but not yet drawing a benefit. The proposal would amount to an $8.6 million payout if all 164 eligible former staffers draw from it.

Based on annual premium savings of $100,000, current interest rates and actuarial tables, SPP would break even with just one participant in the buyout, staff said. They said advisers have told the RTO to expect a “take rate” of about 100 eligible participants.

Members and the board also approved the Value and Affordability Task Force’s recommendation to accept its report and recommendations and dissolve the group. (See SPP Value Group Finds No ‘Silver Bullets.)

Consent Agenda Clears Project Resets

The consent agenda was passed without dissent, resulting in the approval of APEX Clean Energy’s upgrade to the Neosho-Caney River 345-kV line in Kansas, scheduled to go in service next year, and a pair of baseline resets:

• Evergy’s $54.1 million update for a 345/138-kV transformer and 138-kV transmission line project, estimated at $67.1 million in 2017.
• Evergy’s $34.4 million update for network upgrades on a 138-kV circuit, which was originally projected to cost $58.3 million.

Two revision requests were on the consent agenda:

• TWG RR363: Defines existing transmission facilities’ “material modification” as being “based on engineering judgment” in NERC’s facility interconnection studies (FAC-002) compliance.
• TWG RR364: Reduces the planning criteria’s language on equipment rating, which is already covered by NERC Reliability Standard FAC-008.

— Tom Kleckner