SANTA FE, N.M. — The Markets and Operations Policy Committee voted last week to use a level-payment plan to resolve years of incorrect credits for transmission upgrades.

The Z2 Payment Plan Task Force brought two payment plan options to the committee, recommending the level-payment plan over a staggered-payment option. The task force’s recommendation cleared the 66.7% threshold for acceptance at 77.4% after a voice vote was inconclusive.

Under the level-payment plan, each entity with a net payable will be given the option to pay the entire amount at once or in equal installments every three months, beginning in November, with the final installment due in August 2017. FERC’s interest rate for refunds will apply to the outstanding balances. (See “Z2 Task Force to Present Final Recommendations,” SPP Briefs.)

The dollar amounts to be billed remain an unknown, which led to much of the members’ reluctance to approve the recommendation. Midwest Energy’s Bill Dowling called the schedule “problematic,” saying he has “zero” money in the budget to handle bills that may be coming his way.

“I’m still questioning why we have to decide now, without knowing how many zeros we’re talking about here, let alone how many commas,” he said. “It’s really tough to figure out where this money comes from, or how I get the money, until I get an invoice that says I have 30 days to pay.”

“If we wait until later to decide and some other action is needed, like going to FERC, that might prolong this process even further,” responded Oklahoma Gas and Electric’s David Kays, the task force’s chair.

“Ultimately, the amount you will pay or receive will be what it’s going to be,” said Aundrea Williams of NextEra Energy Resources. “Voting on the payment plan doesn’t really affect what you’re going to owe and receive.”

Kays said the software used to calculate the credits is scheduled to be in production by June 1. He said historical data will be available for stakeholder review in time for the MOPC’s October meeting.

SPP will review stakeholders’ data with them in late May. Kays said staff will walk through the calculations and demonstrate the software is performing correctly.

Stakeholders will be exposed to confidential data, which will require signing nondisclosure agreements. Staff assured members the NDAs would not preclude their ability to communicate with FERC.

Market Working Group Gives Updates on Revision Requests

The committee approved a Market Working Group revision request to clean up the Tariff’s out-of-merit-energy (OOME) language (RR 145) while remanding a second back to the working group for additional work (RR 154).

RR 145 is intended to correct dispatch and set point instructions for variable energy resources, clarify OOME treatment for qualifying facilities and make other minor changes to the Tariff’s OOME provisions.

The second change, RR 154, would make it clear when SPP should perform a repricing of the day-ahead and real-time balancing markets. Current protocols and the Tariff allow for the repricing in the day-ahead market “for any reason at any time,” said American Electric Power’s Richard Ross, the MWG’s chair.

Ross also:

• Updated the committee on its work regarding the SPP Market Monitoring Unit’s nine suggested improvements to the market design. (See “Market Working Group Addressing Monitor’s Recommendations,” SPP Board of Directors/Members Committee Briefs.) Two of the nine recommendations — minimizing the over-allocation of transmission congestion rights and auction revenue rights in the day-ahead market, and improved reporting on planned outages — are complete, Ross said. A final report is expected to be presented at the July MOPC and board meetings.
• Briefed the committee on the MWG’s Price Formation Task Force, which was created to “identify concerns with current pricing methodologies” and propose solutions. The task force is currently analyzing feedback gathered from the MOPC and the MWG.
• Told the committee that estimated costs for Integrated Marketplace RRs since September 2013 have surpassed $11 million. He said nine of the 10 RRs will be implemented this year and next.

SPP Pondering ‘One-Offs’ as Potential Seams Projects

SPP Principal Regulatory Analyst Sam Loudenslager brought the committee up to date on the RTO’s effort to create a new class of seams transmission projects, which was rejected by FERC in November.

SPP had proposed a new transmission category to identify projects that fall outside the Order 1000 interregional planning process or may not be eligible for cost allocation. FERC rejected it, saying the plan was too broadly drawn (ER15-2705). (See FERC Rejects SPP Proposal for Seams Transmission Projects.)

The RTO’s staff has been seeking further direction from FERC to determine whether to make another filing. Loudenslager said his recent conversations with FERC staff indicated “they didn’t think we could present a filing that would pass their legal concerns.”

He said FERC staff focused on SPP’s criteria for seams and interregional projects. “They didn’t think we had been through the process enough.

“They suggested we might need to differentiate between [seams and interregional] projects,” Loudenslager added. He said staff encouraged SPP to bring them potential projects that “didn’t pass muster with MISO” as potential “one-offs.”

SPP’s current rules designate transmission facilities of 300 kV or above as “highway” facilities whose costs are allocated entirely on a regionwide, postage stamp basis. Facilities between 100 kV and 300 kV are “byway” facilities, with two-thirds of the costs assigned to the host zone and one-third allocated region-wide. Projects below 100 kV are allocated entirely to the host zone.

“We need a more convincing argument with FERC about why this needs to be a standard one-off,” said Carl Monroe, SPP’s chief operating officer. “We do have special circumstances where these one-offs have to be done outside the Order 1000 process, especially if they don’t fall into the stipulation of shared costs. That way, parties outside MISO could agree to a process where we might be able to find agreement with MISO members that fall outside the Order 1000 process.”

Loudenslager said FERC staff suggested SPP work with Associated Electric Cooperative Inc., a member of the Southeastern Regional Transmission Planning process based in Missouri. “To the extent we came up with something on AECI that didn’t pass muster with MISO,” he said, “they encouraged us to bring it to them as a one-off.”

MOPC Chair Noman Williams, chief operating officer for SouthCentral MCN, suggested staff continue to develop a business practice to add some structure to the one-off process.

“Have it at least all laid out so we don’t have to recreate the process [each time],” he said.

Staff Says No Further HPILS Construction Needed

Staff told the MOPC no additional construction is needed for the 2014 High Priority Incremental Load Study (HPILS) because of slumping oil prices and dropping rig counts.

The HPILS study, commissioned to address unexpected load growth resulting from oil and gas shale production, recommended $439 million in transmission upgrades to serve needs through 2013.

In approving the HPILS report in 2014, SPP’s board directed members affected by HPILS loads and assumed generation additions to provide updated forecasts of those loads and generators before the quarterly MOPC and board meetings. The board also directed members to notify staff should additional notices-to-construct be required.

Jay Caspary, SPP director of research, development and special studies, said 110 MW of load remains unserved in North Dakota’s Bakken Shale play through 2017 and 200-300 MW is unserved in New Mexico’s Permian Basin oil fields in Eddy and Lea counties near the Texas Panhandle. He said the loads are “consistent with previous projections” and recommended no change in HPILS project construction.

Basin Electric Power Cooperative completed a 75-mile, 345-kV line in North Dakota in December, while Southwestern Public Service has energized three projects in the Permian Basin, adding 40 miles of 345-kV lines (which operate at 230 kV) and 19 miles of 115-kV lines. SPS is working on another project between Lubbock, Texas, and Hobbs, N.M., which is scheduled to be in service by 2020.

Some stakeholders questioned the accuracy of the load forecasts, given the low price of oil and dropping rig counts.

“These forecasts coming from folks who believe the price of oil will go back up to $50 or $60 a barrel kind of flies in the face of logic,” Empire District Electric’s Rick McCord said. “It doesn’t make sense to come in here and say [the recent slowdown] doesn’t have an impact. Could [SPP planners] give us some sort of an indication [of how much] load growth doesn’t show up to change what we’re doing?”

“We feel these [projections] are right for the system,” Caspary said. “The load growth is still there. It’s not what it was, but it’s still amazing compared to the rest of the SPP system.”

Ross asked whether staff could use its SCADA system to check “withdrawals off the transmission system.”

“I’m sure we can do that,” Caspary said, “but the directive we got was to look at the forecasts.”

Consent Agenda/RRs

The committee approved in a near-unanimous vote a revision request to SPP Business Practice 7650, which defines procedures for processing competitive transmission proposals as part of the RTO’s Integrating Planning Process.

The RR clarifies the steps taken to determine which detailed project proposals (DPPs) are equivalent to a transmission project in the Integrated Transmission Plan’s Transmission Owner Selection Process’ (TOSP) portfolio. The Business Practice Working Group (BPWG) said the criteria changes will further improve SPP’s ability to “efficiently and accurately” complete the DPP process within the ITP’s required timelines. DPP projects approved for construction as a competitive upgrade may be eligible for “incentive points” within the selection process.

A review of the first TOSP found a combined 1,672 DPPs were received for the 2015 ITP Near-Term and 10-Year assessments, and an additional 1,664 DPPs were submitted for the 2016 ITPNT. Stakeholders expressed their concerns that the drain on resources would affect the 2017 ITP10 schedule and lead to less-than-optimal solutions.

McCord, the working group’s chair, said submitting better DPPs would allow staff to spend more of the 30-day assessment window on needs and solutions, rather than ensuring incentive-point qualification, and lead to more innovative solutions. The language changes to the business practice would be effective with the 2017 ITP10.

ITC Holdings’ Marguerite Wagner cast the lone negative vote, following precedent set during the stakeholder process. The RR was approved by the BPWG and two other groups, with ITC Great Plains the sole dissenting vote each time.

“We don’t oppose the language,” Wagner said, “but we oppose the application of this language in the middle of the three-year cycle.” She said technology improvements could help reduce the number of DPPs, “so it’s unclear this is necessary at all.”

The committee also approved four other RRs from the BPWG and seven additional RRs from the MWG and two other working groups as part of the consent agenda:

• BPWG-RR 147, clarifying the methodology to define a competitive upgrade’s 50% completion status;
• BPWG-RR 148, updating BP 2150 to reference the current webRegistry;
• BPWG-RR 149, updating BP 6150 to reference NERC reliability standards;
• BPWG-RR 150, updating BP 4300 to reference a NERC reliability standard;
• MWG-RR 25_MPRR 211, adding language to identify offer costs eligible for recovery with a “market” or “reliability” commitment;
• MWG-RR 128, clarifying description of day-ahead start-up eligibility recovery rules;
• MWG-RR 137, aligning enhanced combined cycle language with that for quick-start resources;
• MWG-RR 142, preventing a resource from registering as a quick-start resource and a multiconfiguration combined cycle resource;
• ORWG-RR 141, allowing use of updated ratings for facilities, elements and flowgates that reflect current ambient conditions or more relevant system conditions; and
• ORWG-RR 146, removing the criteria revision process from the SPP operating criteria, as the process is now a MOPC process.

Criteria Review

SPP Director of Planning Antoine Lucas reviewed with the MOPC a planning criteria study of the Integrated System’s (IS) transmission grid that evaluates thermal and voltage limits and includes a stability assessment.

Lucas said a 2013 criteria study of the IS members — Basin, Western Area Power Administration-Upper Great Plains and Heartland Consumers Power District — identified four projects totaling $10.56 million to be completed before joining SPP in October 2015.

The study was updated when two additional IS members, Central Power Electric Cooperative and Tri-State Generation and Transmission, joined SPP in January. The 2016 integration study added two additional projects totaling more than $3 million.

— Tom Kleckner