LITTLE ROCK, Ark. — SPP stakeholders narrowly rejected a Tariff change last week that would have established a 1-MW threshold for reporting behind-the-meter network load, despite having directed a working group to settle the policy debate over the resources’ inclusions and exclusions.
The debate goes on.
“We’ve been working on this for three, four years,” said Southwestern Public Service’s Bill Grant during the Markets and Operations Policy Committee meeting Oct. 17. “If we can’t reach consensus, we should take it to FERC.”
At issue is how members report — or don’t report — the network load, and who has jurisdiction over that reporting.
The Regional Tariff Working Group (RTWG) attempted to settle that issue with a revision request (RTWG-RR241) that expanded the Tariff to govern the inclusion of generation on the load side of a discrete delivery point.
The revision would include in a retail customer’s network load calculation any BTM output at a discrete delivery point and in front of the customer’s meter. The calculation would also include any BTM generator — or combination of generating units — with a nameplate rating greater than 1 MW.
The revision would exclude BTM generation that is used for emergency backup operations and is not synchronized to run in parallel with the grid.
“The way we talked about this years ago, the megawatt exemption would be used and useful behind discrete delivery points, not behind the meter,” said Golden Spread Electric Cooperative’s Mike Wise. “Those of us in the hinterlands end up subsidizing [other entities’ transmission bills] because we don’t have any huge loads. If you’re going to use that [exemption], use the nodal pricing point. It’s really important to have the number of generators out there aggregated up, so you’re not going beyond 1 MW. We believe FERC will see it that way too.”
“If that generation is wholly consumed behind the retail meter, it should not be counted as network load,” said Oklahoma Gas & Electric’s Greg McAuley. “There’s enough diversity in this system where a 1-MW generator or larger somewhere is not going to make that much of a difference. We do not want FERC regulating activity behind the retail meter, period.
“We decided the FERC precedent was pretty clear, that all generation behind a discrete delivery point should be included, but not behind retail meters unless a resource behind that meter is conducting wholesale transactions,” McAuley continued. “We came down on the side that no exclusion [behind wholesale meters] is appropriate, but then this 1-MW behind the retail meter came up.”
OG&E takes the approach that it only reports the generation it owns. The company’s RTO policy director, Jake Langthorn, said the company files an annual report of every megawatt it sells.
“If it’s behind the retail meter, and generated and consumed there, OG&E doesn’t own it,” Langthorn said. “We don’t own it, we’re not going to report it.”
“We’ve been reporting that behind-the-meter generation since Day 1. If I’m reporting the load and you’re not, then that’s a problem for me,” Grant said, offering a different perspective. “You’ve got everyone at the table saying they’re reporting BTMG differently. You can tell this is an issue. I don’t know where to go from here except file a 206 complaint, and that’s a shame.”
The measure failed on a roll call vote, receiving only 54.6% of the votes in favor. When the MOPC in July directed the RTWG to address “inconsistency and uncertainty” over which BTM generation qualifies as network load, it did so by a margin of 0.2%. (See “MOPC Suggests 1-MW Threshold for Network Load,” SPP Markets and Operations Policy Committee Briefs: July 11-12, 2017.)
OG&E’s David Kays, the RTWG’s chair, shut down a suggestion that RR241 be tabled until the next MOPC meeting. He noted that this was the third time the working group has prepared a revision request, SPP has given its legal opinion, the MOPC has provided direction and the RTWG has codified the language.
“The thing [we’ve] struggled with is that every time we showed up [for a meeting], someone had a different carveout,” he said. “You open it up to a comment period, you’re right back here. I don’t know what 90 days solves.”
After the MOPC meeting, Kays sent an email to MOPC Chair Paul Malone and SPP COO Carl Monroe, the staff secretary, to request a task force be formed to take the next stab at developing a policy that ensures consistency.
Monroe later told the Strategic Planning Committee that staff would draft and share its view of how the issue should be developed.
Stakeholders Try Again with Resource Adequacy Changes
In the wake of FERC’s second rejection of SPP’s proposed resource adequacy requirement (ER17-1098), the working group responsible for the Tariff change will begin the process of drafting a new revision request to address the commission’s denial. (See FERC Again Rejects SPP’s Resource Adequacy Revisions.)
In the meantime, it will be business as usual for the SPP market, according to Municipal Energy Agency of Nebraska’s Brad Hans, chair of the Supply Adequacy Working Group (SAWG). The 10.7% capacity margin, which is equivalent to a 12% planning reserve margin, will remain in effect along with other criteria, and SPP will continue to follow the reporting timeline of the proposed change.
The SAWG plans to bring a new revision request to the RTO’s January leadership meetings. It hopes to make another FERC filing in February.
“It will be a whole new filing,” Monroe said. “We’re trying to work with FERC in order to get these things forward in a way that we will get an approved filing. If we go outside that, we run the risk of getting rejected again.”
FERC said SPP’s proposal was “inadequate,” failed to include a requirement that all power purchase agreements be backed by verifiable capacity to meet the RTO’s resource adequacy requirement (RAR), and omitted provisions to allow the RTO to verify the agreements are backed by capacity.
The commission called SPP’s proposed treatment of firm power purchases and sales in its determination of net peak demand unduly discriminatory, and that it had not supported its proposal to publicly post a list of all load-responsible entities that have not met their RAR.
“The issue is: How do you enforce the [RAR’s] criteria: through a contract enforcement or through a penalty?” said SPP General Counsel Paul Suskie. “The question is how do you enforce it, and that’s at FERC.”
A task force spent more than two years developing the resource adequacy package, which is projected to reduce SPP’s capacity needs by about 900 MW and save members $1.35 billion over 40 years. The board and stakeholders approved the package in January. (See “Stakeholders Endorse 12% Planning Reserve Margin, Policies,” SPP Markets and Operations Policy Committee Briefs.)
SPP’s Kelley ‘Undeterred’ by Missouri Projects’ Rejection
Saying he was “undeterred” by FERC’s rejection of a pair of joint projects (ER17-2256, ER17-2257), SPP Director of Interregional Relations David Kelley said he will take another shot at developing an acceptable regional allocation of the projects’ costs.
FERC said SPP’s proposal for regionwide/load-ratio share funding for its portion of two projects with Associated Electric Cooperative Inc. (AECI) and City Utilities of Springfield, Mo., had not shown they were “roughly commensurate with the projects’ benefits.” (See FERC Rejects Cost Allocation for SPP-AECI Seams Project.)
The proposed projects would add a new 345/161-kV transformer at AECI’s Morgan Substation and uprate an existing 161-kV Morgan-to-Brookline transmission line, while also installing a new 345-kV 50-MVAR reactor at City Utilities’ existing Brookline substation. SPP would be responsible for $17.1 million of the projects’ estimated $17.1 million to $18.75 million cost, as the benefits would accrue to the RTO.
“We’ve identified a good project that needs to be constructed. They’re the right projects,” Kelley said. “My goal is to try and bring back another plan of action you guys can consider at the January meeting.”
FERC’s order does not preclude SPP from making additional filings supporting regional funding or proposing a new cost allocation for the projects. Kelley said he will continue conversations with AECI, City Utilities and RTO stakeholders in order to better justify regionwide cost allocation or develop another cost allocation proposal for the projects.
“It’s really a cost allocation issue” on SPP’s side,” Kelley said.
During a separate discussion on proposed adjustments to the 2018 Integrated Transmission Planning Near-Term (ITPNT) assessment, City Utilities’ Jeff Knottek recommended adjusting the scope of the assessment to include the Brookline remedy as a “persistent operational need,” and identify the appropriate solution within the ITPNT portfolio. The motion passed with four abstentions.
The Transmission Working Group in September agreed to rebuild the assessment’s planning models, which will extend the 2018 ITPNT’s completion from April to July 2018.
Separately, the MOPC accepted the Seams Steering Committee’s recommendation of an interregional project with MISO, although the project has since been turned down by the RTO. (See SPP Glum as MISO Axes Last Interregional Project.)
“It takes two to dance, and we don’t have a dance partner,” said American Electric Power’s Jim Jacoby, the SSC Chair. “Without MISO, it’s a dead project.”
Z2 Resettlements Add $6.2M in Net Credits
Staff’s resettlement of Z2 credits for sponsored transmission upgrades has resulted in an additional $5.1 million in total net credits receivable for the March 2008-August 2016 historical period, a 2.5% increase from $203.4 million to $208.5 million.
The September 2016-August 2017 resettlement period resulted in a 1.7% increase, from $64 million to $65.1 million.
The resettlements were necessary because of billing disputes, “minor” software defects and problems in calculating the present value of creditable balances, staff told members in July. (See “More Z2 Woes; SPP to Resettle 9 Years of Data,” SPP Markets and Operations Policy Committee Briefs: July 11-12, 2017.)
Members will only be charged or credited the difference between the resettlements and the initial settlement of the Z2 crediting process.
Individual company results were posted on Oct. 13. Staff said 16 quarterly installments remain on payment plans, with the next invoices going out Nov. 3. Those invoices will include the resettlement net amounts.
Registered Entities Transitioning from SPP RE
SPP Regional Entity President Ron Ciesiel reminded members that applications to join new REs are due at NERC by Oct. 31. As of Oct. 17, he said, the commission had received only 40 applications.
The SPP RE announced its dissolution in July, addressing FERC and NERC concerns over its reliability oversight role. (See SPP to Dissolve Regional Entity.)
That move forced the SPP RE’s 120 registered entities to transition to others, a process NERC is managing. Entities should pick a new RE by Dec. 31, 2018, though Ciesiel hopes to complete the process next summer.
“Every entity should have been contacted by NERC multiple times,” Ciesiel told members.
He reminded members that the SPP RE is still the compliance and enforcement authority for its registered entities. “We’re in business as usual,” he said.
SPP has joined ReliabilityFirst but will also have to register in other REs where it does business.
Generator-Interconnection Task Force Extended for 1 Year
Members approved the Generator Interconnection Improvement Task Force’s (GIITF) request to spend an additional year developing a three-stage study process that would replace SPP’s current process built around feasibility studies, preliminary and then definitive interconnection system impact studies, and facility studies with multiple entry points.
The group is proposing stages devoted to thermal and voltage analysis, stability analysis and a facilities study. The task force’s chair, Sunflower Electric’s Al Tamimi, said the simplified process would be easier for SPP to administer and simpler for customers to understand and navigate.
Tamimi said by tying financial security to upgrade cost allocation, the proposal would encourage customers to weigh the risks of proceeding at an earlier stage and reduce the number of interconnection requests being withdrawn late in the process.
The GIITF also requested a stakeholder group with “appropriate background and expertise” be tasked with re-evaluating the purpose, scope and study requirements of network resource interconnection service to align it more closely with SPP’s current and future market structure. MOPC Chair Malone said he would work with staff to put together a task force.
The MOPC also approved the group’s recommendation to publish study models earlier in the process and eliminate the “standalone” analysis to reduce study costs and improve timeliness. SPP’s Tariff requires each interconnection request be evaluated as if it is the only request in the queue, although binding results are based on cluster evaluations.
MOPC Says Goodbye to Two Member Reps
The MOPC said goodbye to two veteran representatives: Vice Chair Todd Fridley, who is retiring from Transource Energy but will begin a new career with Public Service Company of New Mexico, and OG&E’s Langthorn, who is retiring at the end of the year.
“I remember when [SPP CEO] Nick Brown was a staff engineer,” Fridley said in thanking the committee and SPP for their support. “That’s how far back I go.”
Langthorn said that while he is ready for retirement, he has always enjoyed his work.
“This is the middle of the country. This is the heart of the country,” he said, referring to SPP’s flyover country footprint. “We really make a difference for people.”
MOPC Clears 8 Revision Requests
The MOPC approved a measure targeting potential gaming related to the regulation deployment adjustment settlements charge type. The revision (MWG-RR243) minimizes credits and maximizes charges related to the charge type, using the lesser of the as-dispatched energy offer curve and mitigated energy offer curve for the regulation-up adjustment, and the greater of the as-dispatched offer curve and mitigated energy offer curve for the regulation-down adjustment.
Keith Collins, executive director of SPP’s Market Monitoring Unit, recommended the change, saying manipulation of regulation-down offers has cost the market more than $1 million in recent years. He said that combined with MWG-RR242, which was on the consent agenda, the change addresses the MMU’s gaming concerns.
The MOPC passed two other Market Working Group revision requests, with a total of five abstentions:
- MWG-RR231: Removes locally committed resources from the economic mitigation tests and creates a 10% cap for resources committed for local reliability. Addresses the practice among some resources of “self-mitigating” to pass the conduct threshold test and avoid possible mitigation with by submitting competitive energy offers 10% above the mitigated offer.
- MWG-RR239: Allows market participants to incorporate fuel cost uncertainty into their mitigated offers, recovering the difference between forecasted and actual costs.
Members also unanimously approved five RRs on its consent agenda:
- MWG-RR235: Corrects RR200, which removed bilateral settlement schedules (BSSs) at hubs and generation settlement locations from the over-collected losses (OCL) distribution calculation. The RR modifies two equations in RR200 to accurately reflect its true intent.
- MWG-RR236: Changes the commercial model implementation from a bimonthly process to monthly. Previously implemented on only even-numbered months (February, April, etc.), the process hindered market participants with contracts becoming effective at the beginning of the year from submitting model updates on the remaining odd-numbered months.
- MWG-RR242: Adds a fourth criterion, based on a resource’s cleared energy offer, for prioritizing the order in which they are deployed for regulation-up and regulation-down and addressing a potential gaming opportunity. The higher the offer, the less likely a resource will be deployed for regulation-up, and the lower the offer, the less likely it will be deployed for regulation-down.
- RTWG-RR238: Addresses the financial exposure to SPP and its market participants stemming from a defaulting transmission customer avoiding responsibility for the full amount owed for the full term of a service agreement. The change also restricts the ability of SPP, transmission owners and transmission customers from recovering attorney’s fees related to performance of a service agreement, and clarifies that each party to an arbitration under the Tariff is responsible for its own fees.
- RTWG-RR244: Eliminates credits from new upgrades that do not add transfer capability under Tariff Attachment Z2, and eliminates credits from short-term service under the same attachment, as recommended by the Z2 Task Force. (See “Z2, Two Other Task Forces Expire,” SPP Board of Directors/Members Committee Briefs: July 25, 2017.)
— Tom Kleckner
