SANTA FE, N.M. — The SPP Board of Directors’ approval last week of the RTO’s first reduction in its planning reserve margin since 1998 almost left members wanting more.
The board accepted the Capacity Margin Task Force’s recommendation to reduce the margin from 13.6% to 12% April 26 following a unanimous vote by members. SPP said the smaller margin, amounting to a 900-MW capacity reduction, would save its load-serving members about $86 million a year in capacity costs, or about $1.35 billion over 40 years.
Lanny Nickell, SPP’s vice president of engineering, said the reduction was made possible by the RTO’s expanding footprint, its ability to dispatch more than 700 resources as a single balancing authority and $6 billion in transmission expansion during the last decade. He said another $5 billion of approved projects have yet to be built.
“Looking ahead, we need a longer-term vision,” said David Hudson, president of Xcel Energy’s Southwestern Public Service subsidiary. “If all this transmission we’re building creates benefits for our consumers, we have to see if we can achieve further savings.”
Board Chair Jim Eckelberger agreed, saying, “This is one more step in getting savings out of our transmission investment.”
Nickell said stakeholders have told him the task force’s work included “the most robust study” they have seen. Staff conducted more than 300,000 simulations and three different analyses of three test years to determine loss-of-load expectations (LOLE) at various reserve-margin levels. The so-called “limbo study” indicated SPP could go as low as 8.7% before exceeding its LOLE criteria. (See SPP Capacity Margin Task Force Shares ‘How Low’ Reserve Margin Can Go.)
The task force’s recommendation included approving a package of policies defining a load-responsible entity and its obligations, planning reserve assurance and deliverability. The package had previously been approved by the Regional State Committee, the Markets and Operations Policy Committee, the Strategic Planning Committee and the Cost Allocation Working Group.
“From my perspective, this proposal is a great platform to move forward and make improvements,” Dogwood Energy’s Rob Janssen said.
“We learned a lot from this,” Nickell said. “We debated a lot, but at the end of the day, there was a high degree of consensus. Our entire region will now benefit from improved reliability and capacity savings.”
Board Approves 2016 ITPNT
Transmission buildout will continue with the board’s approval of the 2016 Integrated Transmission Planning Near-Term (ITPNT) assessment, which recommended 86 upgrades representing $362.6 million in new engineering and construction costs. The approval is pending further evaluation of seven projects, five projects totaling $74.7 million resulting from a scenario assuming summer wind generation of almost 10 GW that some stakeholders said was unrealistic.
(A sixth project in the high-wind summer scenario, a full rebuild of a 115-kV line in a West Texas load pocket that came in at $17.7 million, was excluded from the re-evaluations.)
“Pulling these off to re-evaluate is the prudent thing to do,” said Jason Atwood, the Northeast Texas Electric Cooperative’s vice president of engineering and operations. “I just think [the] scenario pushes these projects up to the near term.”
“Those projects may be fine, but I’d like to take a second look at those projects before we issue [notices-to-construct],” Eckelberger said. “I’d like to make sure we’re not being driven by the way the model is set up. Rather than spend 92 million bucks with some questions, I’d rather get some answers.”
The board also approved requests by Basin Electric Power Cooperative and American Electric Power to conduct “accelerated reviews” of their proposed projects in North Dakota and northwest Louisiana, respectively. Staff said it could complete the further evaluations of the seven projects by the July board meeting.
The annual near-term reliability assessment included the re-evaluation of 15 projects at the transmission owners’ request. Seven of the NTCs were modified and eight withdrawn, resulting in $133.4 million in costs being pulled out of the study.
The planned development includes a $20.5 million project to address needs in the Tulsa, Okla., area; a $30.5 million project to address needs near Woodward, Okla. through the construction of a new substation and a 138-kV line; and a $145.7 million project to construct new substations and 115-kV lines to address “substantial load increases” in North Dakota’s Bakken shale formation.
Nickell said that by using a winter-peak case to reflect the Integrated System’s addition, the staff models solved many constraints before considering the effects of contingencies. He said most zones experienced a load reduction, but certain pockets — North Dakota, western Kansas and the Golden Spread Electric Cooperative and SPS’ Panhandle area — saw increases. The bulk of the ITPNT’s new investment ($261.5 million) is targeted for New Mexico, North Dakota, Oklahoma and Texas.
Staff said it would continue to consolidate planning efforts with “real” operations when determining whether projects can solve operational issues. “I would hate to ignore assumptions that go into these projects,” Nickell said. “If we can find a project that solves some of these issues, I would hate to not pursue it.”
MOPC Chair Noman Williams, COO for South Central MCN, recommended the Transmission Working Group take a second look at the high-wind summer scenario and bring it back to the board. His motion passed.
At the MOPC’s recommendation, the board also endorsed the 2017 ITPNT’s score, which will evaluate as potential violations NERC TPL-001-4 planning events that do not allow for nonconsequential load loss or curtailment of firm transmission service. (See “MOPC Approves TWG, ESWG Recommendations,” ITP Work Continues as Transmission Planning Improvements Loom for SPP.)
Eckelberger asked members to opine on how TPL events should be handled in future planning studies. The MOPC removed consideration of TPL events from the 2017 ITP 10-Year assessment during its meeting two weeks earlier.
“Essentially, this takes future requirements NERC has placed on us … out of the ITP10,” he said. “The real question: Is that something we can wait on, or do we need to incorporate it now?”
NextEra Energy Transmission’s Brian Gedrich, chair of the Transmission Planning Improvement Task Force (TPITF), said his team has included the TPL standards in its work.
“It should be incorporated in the TPITF work, and let them sort it out,” said Phil Crissup, vice president of utility technical support for Oklahoma Gas & Electric.
The task force is scheduled to present its final set of recommendations to the board, MOPC and SPC for their approval in July.
Board Approves Z2 Level Payment Plan
The board approved the Z2 Payment Plan Task Force’s recommendation to use a level-payment plan resolving years of incorrect credits for transmission upgrades, despite continued stakeholder angst over the size of payments due.
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 “MOPC Accepts Z2 Task Force’s Level-Payment Plan,” SPP Markets and Operations Policy Committee Briefs.)
“Our general philosophy is we’re putting the cart before the horse on this issue,” Hudson said. “A lot of this is recovered through a rate case; that’s why we think a longer payback period is more appropriate. We don’t know the potential liability for our customers … it’s hard to agree to a payment plan when [you] don’t know what the payment is.”
Asked whether it would be wise to wait until July to make final decisions, OG&E’s David Kays, chair of the task force, said the financial information will not be available for stakeholder review until July anyway, and that postponing a vote until July would slide FERC responses into October or later.
Kays said software systems would be production-ready by June 1 and historical data will be available for MOPC review in October. SPP has promised stakeholders will be able to review their data and the software calculations at SPP headquarters in late May.
“Two pieces you won’t know” in May, SPP COO Carl Monroe said. “How many waivers get approved to go in … the amount of credits due on point-to-point reservations to pay for usage and, as the TO, how much we have to claw back from revenue paid previously to pay for credits.”
Monroe said much of that information won’t be available until September. “We have to get through that puzzle, before we can determine the rest of it.”
Board Pays Tribute to Ex-RE Chair Meyer
SPP CEO Nick Brown and Eckelberger led the board in paying tribute to John Meyer, the first chairman of the Regional Entity’s Board of Trustees. Meyer resigned his position earlier this year because of a conflict with the bylaws of Western Interconnection reliability coordinator Peak Reliability, where he is vice chair. (See SPP Briefs: New Trustee Chairman, Wind Record.)
Meyer remembered his early years with the RE, which began in 2007 after his retirement from Reliant Resources, with just four employees and facing a FERC audit.
“One of the strengths I see with SPP is its willingness to solve problems together,” Meyer said. “I’m really sad to be leaving, but I’ll be back to visit on occasion.”
The RE doesn’t expect to fill Meyer’s position until July, at the earliest.
FERC’s Bay Takes in Order 1000 Discussion
FERC Chairman Norman Bay was a special guest at the board meeting, attending the morning session for about 90 minutes. Given his tight schedule, the board rearranged its agenda to ensure Bay could listen to the discussion surrounding SPP’s first competitively bid transmission project under the commission’s Order 1000.
“I look forward to hearing your experiences with Order 1000,” Bay said.
Bay took note of SPP’s recent achievements, including the Integrated Marketplace’s implementation and the addition of the Integrated System, and called them a “national leader” in integrating renewable energy.
“You’re helping make the case markets drive reliability and efficiency, driving benefits for consumers,” he said. “Fifty percent wind penetration … that’s pretty amazing. Just a few years ago, people were wondering whether you could get 20%, and now you’re almost at 50%.”
Bay, a former New Mexico resident, also complimented SPP on holding its board meeting in Santa Fe. “Obviously, it shows they have good taste and judgment.”
RE Report Shows 40% Drop in Violations
New RE Trustees Chairman Dave Christiano noted that SPP’s registered entities saw a nearly 40% drop in violations of NERC standards during a rolling 12-month period that ended March 31. . The RE recorded 48 violations in the current period, compared to 78 in the previous 12 months.
The systems security management, electronic security parameters and personnel and training categories showed some of the greatest improvements.
“The registered entities have this figured out,” Christiano said. “We’ll take some credit, but most of the credit goes to them.”
He stressed the importance of CIP 5 compliance, sharing a presentation the RE viewed on the recent cyberattack against three Ukranian distribution companies. (See How a ‘Phantom Mouse’ and Weaponized Excel Files Brought Down Ukraine’s Grid.)
“This wasn’t a bunch of 15-, 16-year-old hackers in their basements,” Christiano said. “This was a very well planned-out attack over a number of months. It’s pretty scary stuff.”
The RE has scheduled a CIP workshop in Little Rock, Ark., May 24-25.
Tx Project Pulled from Consent Agenda
The board approved its consent agenda following a unanimous members’ vote, but only after pulling the Project Cost Working Group’s recommendation to reset the baseline value for a 110-mile, 345-kV transmission line in Nebraska and Missouri. It was valued at one time at more than $403 million, but received MOPC approval to reset its baseline value to $336.4 million.
“I thought we had a policy against resetting the baseline, unless it’s a different project,” Eckelberger said.
Staff was unable to recall any discussion of the project during the MOPC meeting, where it was part of the consent agenda. They promised to return the issue to the board with additional information.
The consent agenda included the addition of Basin Electric’s Mike Risan and the Missouri River Energy Services’ Ray Wahle to the SPC, reflecting the Integrated System’s addition. It also approved six revision requests from the Market and Operating Reliability working groups.
Annual Report Focuses on Relationships
As is the custom, SPP staff handed out the organization’s 2015 annual report before the board meeting began.
This year’s report focuses on SPP’s relationships, both internal and external. “We choose to highlight our relationships as a critical component of all we do and a binding agent, drawing together our staff, stakeholders and customers we serve to add value to our region,” the introduction says.
— Tom Kleckner
