DENVER — SPP’s Z2 Task Force will likely soon be a relic of the past, but the issues with financial credits and obligations for sponsored transmission upgrades that spurred the creation of the group aren’t going away.

The Markets and Operations Policy Committee last week endorsed the task force’s request to conclude its work. Minutes later, SPP staff told the committee the RTO would have to resettle nine years of historical Z2 credits and obligations because of billing disputes, “minor” software defects and problems in calculating the present value of creditable balances.

SPP last fall identified about $200 million in revenue credits to be collected for transmission upgrades under its Tariff’s Attachment Z2, which details how to reimburse sponsors of network upgrades. The bills covered eight years of credits and obligations for 2008-2016, when staff failed to apply credits, complicating the task of trying to accurately compensate project sponsors and claw back money from members with debts for the upgrades. (See Preliminary Z2 Bills Released; Task Force Develops Options for Waiver Requests.)

SPP’s Charles Locke said the resettlement results will be similar to last year’s processing and stressed they will not produce duplicate or additional charges.

“What you pay or owe is only the difference between the original settlement and the resettlement,” he said.

However, Locke could provide few details beyond that. “Generally, the amounts will be small. I’m reluctant to say how small,” he said.

That drew pushback from members, some of whom could recall early staff estimates of $50 million for creditable transmission upgrade projects, which eventually ballooned to nearly $850 million in assigned costs. (See SPP MOPC Recommends 5-Year Timetable for Resolving $849M Z2 Bill.)

“Is there a number by what you mean by small?” asked ITC Holdings’ Marguerite Wagner. “It’s hard for me to understand what that actually means.”

“SPP assured us for years the amounts for Z2 were small, until they actually did the billing,” said Southwest Public Service’s Bill Grant. “I don’t get a lot of comfort when you say the amounts will be small. I do understand the reason, but it still tends to create regulatory issues for your members when they go back [to their commissions] and say, ‘Whoops! The calculations weren’t correct, so we’ll have to adjust it either up or down.’ It’s starting to get really painful.”

SPP COO Carl Monroe suggested that members focus on the difference between last year’s invoices and this year’s.

“What’s more important is the deltas,” he said. “We won’t know the deltas until we know the details of the resettlement. We won’t know the details until we go through the actual resettlement.”

Locke said staff intends to provide preliminary resettlement results in September, so members “at least have some indication of the numbers.” Staff will in September begin reprocessing data from March 2008, adding the months through July 2017. It hopes to post updated invoices in October to keep up with a timeline approved last year.

While chairing the Strategic Planning Committee on July 13, Golden Spread Electric Cooperative’s Mike Wise asked Locke whether the resettlement would be SPP’s last.

“We’re certainly hoping so,” Locke responded. “The last resettlement of historic data.”

In accepting the Z2 Task Force’s recommendation to let its charter expire, the MOPC also approved two recommendations from the group, with nine “no” votes (out of a potential 95 votes) and two abstentions. The first eliminated credits for non-capacity upgrades, such as substation facilities, while the second disposed of credits for short-term transmission service of less than a year.

The task force also reviewed the use of incremental long-term congestion rights (ILTCRs) as a substitute for Z2 credits — a practice by other RTOs — but was unable to reach consensus. The group said “significant concern” was expressed over SPP’s existing congestion rights processes and the “perceived lack of hedging.”

“Existing customers may prefer the risk of waiting on cash recovery versus getting ILTCR’s, which may have limited value in the future,” according to the task force’s recommendation to the MOPC.

The task force was formed last year to find “a more rounded solution” to Z2 credits. (See Board Approves Z2 Timeline Extension, Creates Task Force for Further Study.)

“We feel like at this point in time, the task force has done what it can about whether or not there is something else we can do to reduce the burden of Z2 and replace it with something else,” the task force’s chair, Kansas City Power & Light’s Denise Buffington, told the MOPC. “After many, many, many meetings, we could not get to a decision on the underlying policy or whether to socialize those costs. Unfortunately, we are where we are.”

American Electric Power’s Richard Ross, who likes to hand out gold stars to his fellow stakeholders, said he was awarding Buffington a “Richard Ross Gold Star for Cat Herder of the Year.”

MOPC Suggests 1-MW Threshold for Network Load

It came down to a single vote, but the MOPC offered direction to the Regional Tariff Working Group on how to address “inconsistency and uncertainty” over which behind-the-meter generation qualifies as network load.

The committee directed the RTWG to use a 1-MW threshold for reporting network load and to develop a list of inclusions and exclusions. In a roll-call vote, the last member to record its vote pushed approval of the motion from 65% to 66.2% — just above the 66% necessary for passage.

For customers taking network service, SPP currently follows FERC policy that sets all load at discrete delivery points as network load, which effectively sets the threshold at 0 MW for load served by BTM resources.

“At least this gives some guidance to MOPC,” Monroe said, alluding to the difficulties the RTWG has had in tackling the issue.

“If so, then make every member of the MOPC charter members of the [RTWG’s] Billing Determinants Task Force, because that is what we spent two and a half years discussing,” said Oklahoma Gas & Electric’s David Kays, who chairs the RTWG. “If 10 members were in the room, we had 10 different exceptions. If 15 members were in the room, then we had 15 different exceptions.”

The RTWG, through the BDTF, has been working on the problem since 2014 and has haggled over two revision requests (RR158 and RR 232). The task force developed the first and defined network load to include load served by certain BTM generators at discrete delivery points, while excluding load served by other BTM generators where load is shed automatically. The second revision request was developed with input from the SPC and excluded load served by a BTM generator or group of generators totaling 1 MW or less.

Members were never able to reach consensus on the proposed Tariff language. The RTWG in June rejected RR158 and RR232.

“We spent significant time on RR232 trying to cover as many issues related to behind-the-meter generation as possible,” said BDTF Chair Heather Starnes, legal counsel for the Missouri Joint Municipal Electric Utility Commission. “Different people interpret the Tariff provisions related to network load … differently. Maybe it’s not so straightforward to some folks.”

The RTWG will bring back its list of exclusions and inclusions to the October governance meetings. Assuming clarity and approval of the network load list, Starnes said, the RTWG will then develop Tariff language once again subject to the stakeholder process.

“This is a need, an immediate need,” Wise said. “I think there may be some cross-subsidization going on because of the way the network load is actually reported. I want to make sure we have consistency across the entire footprint and where the whole load gets reported accurately, because we do have substantial costs paid by the network load. All these loads need to pay their fair share of those costs.”

Staff to Review AECI Joint Project After Cost Increase

David Kelley, SPP’s director of interregional relations, told members he would spend this week reviewing an alternative to a previously approved transmission project that recently saw a 50% cost increase.

The joint project with Associated Electric Cooperative Inc., originally estimated at $9.2 million, was endorsed by the MOPC and SPP Board of Directors in January and included in the RTO’s 2017 Integrated Transmission Planning 10-year assessment. It involves installing a new 345/161-kV transformer at AECI’s Morgan substation and an uprate of a related 161-kV line, both near Springfield, Mo.

“As luck would have it,” Kelley said, AECI notified him July 7 that it raised the project’s cost estimate to “just shy of $14 million.” Because the costs increased more than 20%, the parties can revisit the initial cost-sharing agreement.

“We had another alternative that wasn’t a seams project. It provided comparable benefits but, at the time, significantly more expenses,” Kelley said. “I’d like to spend the next few days making sure we’re still making the right decision.”

Kelley said if his revised analysis is not ready for the July 25 board meeting, he will present it during the October governance meetings.

The Morgan project would be regionally funded, as it solves congestion issues on SPP’s side of the seam, and is contingent on reaching an agreement for compensating AECI. SPP was to assume responsibility of $8.7 million of the original cost estimate. AECI will own the project and be responsible for its construction, operations and maintenance.

MWG to take Another Shot at MWP Manipulation

Members remanded back to the Market Working Group a previously rejected revision request (RR221) that addressed potential manipulation of make-whole payments (MWPs) related to mitigated energy offers and no-load offers for resources with a three-day minimum run time or greater.

RR221 would have added language that establishes a permissible percentage threshold above the mitigated offer at the time of the original commitment. Ross, the MWG’s chair, said that as structured, RR221 would force SPP to report to FERC’s Office of Enforcement deviations as little as a penny.

“Monitoring is not always clear and concise,” Ross said. “We have concerns with moving forward with that request. There’s no room for error when updating offers for fuel-price changes, and the burden of implementation is on the market participants to run the calculations. You could be one penny over the line because of a rounding error. You could violate the Tariff without any impact to the market.”

Keith Collins, the Market Monitoring Unit’s newly installed executive director, agreed with Ross. (See SPP Names CAISO’s Collins to Lead MMU.)

“There has to be a bright line. Yes, it’s a violation, but let’s exercise some judgment first,” he said. “It’s been my experience with manuals and protocols that … they’re nice guidance, but if you get to a circumstance where [they have] to be enforced, they don’t carry the same weight.”

Staff and members, in agreeing to send RR221 back to the MWG, said the issue was more of a market design problem.

“Let the market design experts take another shot at this,” said Midwest Energy’s Bill Dowling. “I’d prefer to see them deal with this issue one more time. Maybe there’s a way to navigate this.”

Wind Integration Study’s Recommendations Move On

The MOPC unanimously approved staff study recommendations for how much wind energy the SPP system can reliably absorb. The RTO has routinely broken the 50% penetration level for wind and has said it can go even higher. (See SPP Eyes 75% Wind Penetration Levels.)

SPP set a record for North American RTOs in April when wind energy served 54.47% of its load — 58.67% with the addition of solar and hydro. The RTO had 15.7 GW of installed wind capacity when the study began last year and currently projects 17.2 GW by the end of 2017.

Casey Cathey, SPP’s manager of operations analysis and support, said wind has exceeded 50% penetration several times and exceeded that mark for hours at a time.

“We’re meeting all NERC standards, but there are things out there we can continually improve on,” he said.

Last year’s Variable Generation Integration Study (VIS) stressed the transmission system to a point of instability, identifying reliability impacts during high-wind and low-load scenarios. Staff analyzed 45% and 60% wind penetration levels and examined transient stability, frequency response, voltage stability and a targeted five-minute ramping.

The VIS recommends seven solutions and improvements to increase reliability, including the installation of online transient-stability and voltage-stability analysis tools. Staff has estimated the software will cost a combined $3.2 million.

Members OK Re-baselining Out-of-Bandwidth Projects

Members unanimously approved re-baselining four out-of-bandwidth projects, three of which were a combined $95.5 million less than original estimates once project owners lowered material, engineering and construction costs through more accurate data.

One estimate, an OG&E 500/161-kV transformer project, went from $15.1 million to $25.6 million because of an increase in internal costs, unforeseen site work and the need to keep the 161-kV lines energized throughout the project.

All four projects were regionally funded, with operating voltages of greater than 100 kV and cost estimates of more than $20 million. (The OG&E project was a legacy project.) They became eligible for re-baselining when their updated cost estimates exceeded the +/-20% variance bandwidth after receiving notifications to construct.

MOPC Approves 9 Revision Requests

The MOPC approved a modified two-year-old revision request (RR82) that ensures combined cycle units do not lose eligibility for start-up cost MWPs because of a physical or environmental limitation, avoiding outage deviation penalties in the process.

RR82 adds a previously discussed increase in the MWPs’ grace period for commitments from one hour to two. The revision’s implementation date was scheduled for this August to allow SPP to complete development of software that allows market participants to register and submit separate offers for combined cycle units’ multiple configurations.

Final approval of the revision request is contingent upon the Regional Tariff Working Group’s endorsement of Tariff language changes. RR82 was approved by the MOPC and board in October 2015, but staff identified the additional changes while developing the FERC filing letter.

The committee approved eight other revision requests as part of its consent agenda, which passed unanimously:

• MWG-RR185: Clarifies which SPP criteria document (Planning Criteria or Operating Criteria) is referenced when used in the market protocols and the Tariff’s Attachment AE, and correctly directs users to the specific document.
• MWG–RR210: Changes the process for testing a contingency reserve deployment (CRD) by adding a deployment test instruction issued in conjunction with the out-of-merit energy dispatch, allowing sufficient time to review test results and provide accurate data. Also changes SPP’s communication of the CRD’s test results from 60 minutes to within one business day. Should a resource retest be requested, SPP agrees to complete the test within two business days, subject to its assessment of system stability.
• MWG-RR222: Includes a multiconfiguration combined cycle resource’s (MCR) committed and actual configuration for each interval in a bill determinant report, allowing MCRs to shadow the configuration SPP is using to settle these resources.
• MWG-RR225: Cleans up confusing and misleading Tariff language on incremental long-term congestion rights (ILTCRs) that could construe ILTCRs as load-serving entities or non-LSEs.
• MWG–RR226: Changes settlement location pairs that have potential for unconstrained flow to electrically equivalent settlement locations during the auction revenue rights process, to comply with a FERC order (ER17-310). SPP will post the settlement locations before the annual ARR allocation process, along with the system topology and other data.
• MWG-RR229: Satisfies FERC Order 831’s requirements on energy offer caps by using actual costs for make-whole payments on offers above $1,000/MWh. According to the order, costs underlying a resource’s cost-based incremental energy offer above $1,000/MWh must be verified before that offer can be used to calculate LMPs.
• ORWG-RR228: Clarifies existing planning criteria language for system operating limits to reduce the potential of misinterpretation by entities complying with NERC reliability standards.
• RTWG-RR233: Ensures that eligible network customers will not be billed twice for the same delivery. Customers will also not be assessed charges against a specific use of a single owner’s facilities that do not receive the benefit those charges provide to other transmission owners under the Tariff. The Southwestern Power Administration (SPA) and SPP have entered into a contract (Attachment AD) that provides for SPP to offer transmission service on SPA’s facilities, including network integration transmission service (NITS), and allows SPA to participate in the RTO’s transmission planning. SPA also voluntarily contributes to Schedule 11 representative of the grandfathered transmission service agreements (GFAs) it has in place for non-federal uses of its transmission facilities. SPA and SPP are transitioning customers with GFAs to NITS under the Tariff, creating implications for new customers who also receive federal hydropower deliveries.

The consent agenda also included:

• Modifications to the revamped revision process, adding the Integrated Transmission Planning Manual and certain technical documents to the approval process. (See “Changes Proposed for Revision Process,” SPP Markets and Operations Policy Committee Briefs.)
• The scope for the expedited re-evaluation of the Kummer Ridge-Roundup 345-kV line. (See “MOPC Endorses Re-evaluation of Basin Electric Project,” SPP Markets and Operations Policy Committee Briefs.)
• A waiver request to FERC restating settlement prices for transmission congestion rights (TCRs) at Omaha Public Power District’s Fort Calhoun nuclear plant site. The plant was retired Dec. 1, 2016, but incorrect modeling of shift factors from Dec. 1 to Dec. 14, 2016, resulted in the marginal congestion component being overstated and the TCR settlements sourcing at the location being understated.

— Tom Kleckner