MOPC Approves Changes to Joint Model with MISO
LITTLE ROCK, Ark. — SPP’s Market and Operations Policy Committee last week unanimously approved staff recommendations to revise the SPP-MISO Coordinated System Plan by eliminating the RTOs’ joint transmission model and the $5 million minimum cost threshold on interregional projects, while adding adjusted production cost and avoided-cost benefit metrics.
The RTOs have told their stakeholders they will use only their individual regional planning models to evaluate interregional projects. Members on both sides of the seam have complained that a “triple hurdle” has contributed to the lack of interregional projects. (See MISO, SPP Loosen Interregional Project Requirements.)
“We have concerns … about getting rid of the joint model, because it is clear up front that the joint model will determine the way costs are allocated,” The Wind Alliance’s Steve Gaw said. “We lose that stability in the new process, and it remains to be seen if efficiency gains in the new process will outweigh this risk.”
MOPC Endorses Battery Storage as Market Participant
The committee endorsed several market design changes for SPP’s compliance filing with FERC Order 841.
RR323 defines batteries as electric storage resources (ESRs), capable of being dispatched and participating in price formation. Excluded as ESRs are those resources that are either contractually barred or physically incapable of injecting energy back onto the grid because of their design or configuration.
The Tariff change also creates a new registration type, “market storage resource,” to be used only by ESRs. The resources are not required to use the MSR model but must specify ancillary services offered — e.g., energy, regulation up, regulation down, spinning reserves and/or supplemental reserves — and provide at least a tenth of a megawatt to be eligible for any market product.
“The resource can be committed as a charging resource or as a non-charging resource. It’s no different than a regular resource,” SPP’s Yasser Bahbaz said. He pointed out that pumped hydro, a non-charging resource, already qualifies as an ESR.
Renewable interests were hoping to see more on capacity accreditation but were satisfied to learn that the Supply Adequacy Working Group is considering a four-hour accreditation for ESRs. Existing governing language allows ESRs to qualify for capacity credits if the resource meets the planning criteria’s testing requirements.
The measure passed with 10 abstentions.
“Our impression is this has gone little bit beyond what we need to do to comply with the FERC order,” American Electric Power’s Richard Ross said, explaining his company’s abstention. “[SPP] already [has] a storage resource, and it seems to have found a way to operate under the current guidelines.”
The MOPC also approved tweaks to the Market Working Group’s RR266, which modeled joint-owned units as single resources and the committee had approved in July. “Ownership” was changed to “interest,” recognizing that the former term doesn’t capture stakeholder intent that power purchase agreements and other non-ownership interests be included.
Stakeholders approved the change with one abstention.
MOPC Approves 2 Revised Futures in 2020 Study
The committee agreed with the Economic Studies Working Group’s recommendation to study only two futures in its 2020 Integrated Transmission Planning assessment: a reference case and an emerging technologies scenario.
It also agreed with the ESWG that there is no need to study a third future that assumes a carbon adder or carbon-emissions reduction and accelerated emerging technologies. The third future would have increased the 2020 ITP’s study costs, adding about 6,600 consulting hours.
ESWG Chair Alan Myers, with ITC Holdings, said many of the third future’s assumptions will be included in SPP’s first 20-year assessment, which will begin in 2022. “That might be a good vehicle for studying these types of things,” he said.
Staff will use the 2019 ITP’s two futures as a starting point, adding fossil fuel retirements, ESRs and an increase in utility-scale solar and wind additions to the original assumptions. Both futures will assume coal plants retire at 56 years old, a decrease of four years over previous assumptions.
“We think the shift from 60 to 56 [years] … is definitely a movement in the right direction,” said Keith Collins, executive director of SPP’s Market Monitoring Unit, which has joined the ESWG’s discussions. “But [based on] what we’re seeing in other markets, it’s not [reducing] it enough.”
Collins favored including the third future, saying SPP’s market indicates that uneconomic resources are likely operating, as evidenced by the self-commitment of generation and negative prices.
“The economics Keith talks about are driven by the inability of a coal plant to recover its fixed costs,” Board of Directors Chairman Larry Altenbaumer said. “To a large extent, that fixed cost is subject to the regulatory environment that exists. I’m not at all convinced Future 3 is the right way to [address] that.”
SPP Updates Members on Western RC Effort
Peak Reliability’s decision to cease operations may slow SPP’s pursuit of the Mountain West Transmission Group, but it is also giving the RTO some business with the group.
Operations Vice President Bruce Rew told stakeholders the 16 entities who have signed up for SPP’s reliability coordinator services include all original Mountain West members: Black Hills Energy (Black Hills Power, Black Hills Colorado Electric Utility Co. and Cheyenne Light Fuel & Power); Colorado Springs Utilities; Platte River Power Authority; Tri-State Generation and Transmission Association; the Western Area Power Administration (Rocky Mountain Region and Desert Southwest Region); and Xcel Energy’s Public Service Company of Colorado.
Xcel’s surprise April announcement that it was leaving the Mountain West shelved SPP’s integration of the group. (See Xcel Leaving Mountain West; SPP Integration at Risk.)
That news was followed up by Peak’s decision in June to wind down its RC operations by the end of 2019. (See Peak Reliability to Wind Down Operations.)
The other entities who have signed up with SPP are: Arizona Electric Power Cooperative; the city of Farmington, N.M.; El Paso Electric; Intermountain Rural Electric Association, in Colorado; Tucson Electric Power; Arlington Valley, in Arizona; and Griffith Energy, also in Arizona.
SPP will continue strengthen its toehold in the West with its RC services, expanding its footprint to 16 states with the addition of Arizona and Utah.
SPP’s Western RC will serve approximately 20% of the non-CAISO load in the Western U.S., accounting for 100 TWh of net energy for load, Rew said. A Western Reliability Executive Committee and a Western Reliability Working Group will provide governance. Three task forces have already been formed: Congestion Management and Seams, RC Readiness and West Modeling.
Rew said the groups are currently populating the transmission models, with the hopes of exchanging real-time data with transmission owners, balancing authorities and neighboring RCs by May 1, 2019. The Western RC is scheduled to begin shadow operations with Peak by Oct. 1, with the cutover set for Dec. 1, 2019.
Rew also briefed the MOPC on the major operations events with MISO in January and September, calling the latter a “success story” because of the improved coordination between the RTOs.
Unseasonably warm conditions in mid-September led to higher loads than forecast in SPP’s southern region and in MISO South. When several units tripped, MISO was forced to call a maximum generation alert and a Level 2 Energy Emergency Alert on Sept. 15. SPP sent 300 MW of emergency assistance for three hours to help resolve the situation. (See MISO: Sept. Emergency Response Improved by Jan. Event.)
“With our operational preparations, we were able to make it through,” Rew said.
HITT Group Continues its Education Sessions
The Holistic Integrated Tariff Team has moved into a second phase of education, listening to and discussing presentations by various stakeholders as it eyes an April 2019 deadline for delivering a report on the optimal alignment of SPP’s planning processes, cost-allocation methodologies, and market products and services.
The team, which reports to the board, was only formed in April. (See SPP’s Tariff Team Begins Carving up the Elephant.)
“I won’t disagree that it’s an ambitious schedule,” said SPP General Counsel Paul Suskie, who serves as the HITT’s staff secretary.
The HITT expects to begin its third phase in December, when it will begin drafting its recommendations to the board and Members Committee.
The team meets next Oct. 23 and has scheduled meetings through April 2019.
The meetings continue to be limited to team members, with those stakeholders not delivering presentations “encouraged” to call in to listen.
Suskie acknowledged the lack of face-to-face interaction and stakeholders’ complaints about technological problems during conference calls. “We tried to line the meetings up with board meetings as best we could, but we haven’t been able to do that,” he said.
Competitive Transmission Group Kept on Standby
The committee agreed to keep the Competitive Transmission Process Task Force on “hot standby” rather than disband it, should a future Order 1000 issue deserve its attention.
Several committee members agreed with the group’s recommendation that it disband, saying its work has been completed. But task force Chair Bill Grant, of Southwestern Public Service, argued the group’s expertise should be leveraged by keeping it on standby, rather than disbanding it.
“We had a pretty balanced group of people who had transmission experience and know how projects are put together. We also had financial people who could look at and analyze bidding forms,” he said. “If MOPC wants to disband and bring it back up if needed, I would caution you that we have the right people at the table.”
Formed in 2015, the CTPTF picked up where a previous task force left off to revise SPP’s Tariff to comply with FERC’s 2011 order introducing competition to transmission development. The group has worked to improve the competitive process following the first two solicitations, neither of which resulted in an approved project.
Admin Cost Recovery Looks at Demand, Energy Charges
Evergy’s John Olsen, chair of the Schedule 1A Task Force, told the MOPC his group will propose revisions to SPP’s administrative fee recovery mechanism at the committee’s January meeting. Olsen said that timeline would give members a year to work with their regulators before final revisions are filed with FERC in 2020.
Olsen said the group favors a mix of demand and energy charges, with market costs recovered through energy charges and planning costs recovered through demand charges. Contested issues include scheduling and dispatch costs and what “determinants” should be included in cost allocation calculations, he said.
“The debate has been whether generators or loads pay for all cost,” Olsen said.
He shared a picture of Grant and Tenaska’s John Varnell, wearing seemingly identical plaid shirts and body language during a task force meeting.
“That’s what five hours of talking about denominator billing determinants will do to a person,” Olsen said, drawing laughs.
The task force has been asked to simplify the rate structure and include energy transactions into the design. The RTO’s administrative fee of 42.9 cents/MWh is budgeted to recover $164 million in the current budget year. The administrative fee is collected on contracts between transmission providers and customers. Point-to-point contracts are billed against reserved transmission capacity, and network service is billed against the prior year’s average monthly zonal peak. (See SPP Stakeholders to Study Admin Fee Changes.)
MOPC Approves Order 845 Compliance Language
The MOPC easily endorsed the Regional Tariff Work Group’s revisions to the pro forma large generator interconnection procedures and large generator interconnection agreement to comply with FERC Order 845. The commission’s order is designed to address delays in interconnection queues, a common complaint among SPP’s membership.
RTWG Chair David Kays, with Oklahoma Gas and Electric, said Revision Request 325 will not be filed until a pending rehearing request before the commission is resolved, which would likely add another 90 days to the timeline.
The vote was unanimous, with only ITC abstaining.
The MOPC rejected a change to the ITP’s operational model development, agreeing that ESWG/TWG RR317 would be undoing the Transmission Planning Improvement Task Force’s work.
The change would have removed the day-ahead reliability unit commitment to evaluate economic flowgates in planning models. It was removed from the consent agenda, with two members abstaining from the vote.
The committee unanimously approved the rest of the agenda, which included 10 revision requests, updates to the 2019 ITP assessment’s scope, removal of references to the SPP Regional Entity from the MOPC’s scope, the MWG’s annual violation relaxation limits analysis, and charter changes for the Operating Reliability, Operations Training Project Cost and Regional Compliance Working Groups. (RR318 was discussed separately but also passed unanimously.):
- BPWG RR319: Standardizes market import service (MIS) over all SPP ties by adding MIS to the Miles City DC tie in Montana, which is partially owned by the Western Area Power Administration.
- ESWG/TWG RR321: Cleans up several items, grammatical errors and small improvements in the ITP manual that were discovered since its approval.
- MWG RR288: Allows non-dispatchable variable energy resources converting to dispatchable to use control statuses not originally available to them. SPP’s control statuses are: offline (the resource is not operating); non-regulating (online and capable of following a dispatch instruction or contingency reserve deployment but not eligible to clear regulation service); regulating (online and capable of following dispatch or contingency reserve instruction, and regulation deployment); and manual (online but not able to follow dispatch; e.g., start-up, shutdown, testing, etc.).
- MWG RR316: Updates the multi-configuration (combined cycle) resource market design by adding two additional commitment parameters: group minimum down time and plant minimum down time. Also removes sync-to-min and min-to-off times from the submitted minimum down time or group minimum down time when the resource transitions between operational configurations. The current design only allows individual registered configurations to submit a minimum down time.
- MWG RR328: Allows the automation of out-of-merit energy and RUC make-whole payment calculations when a contingency reserve deployment test is issued.
- MWG RR332: Corrects protocol calculations from designs implemented in RR200 (design change for bilateral settlement schedules and over-collected losses (OCL) distribution) and RR235 (correction to RR200) necessary to ensure bilateral settlement schedules are receiving their correct OCL. The change — which also must be approved by the Regional Tariff Working Group — ensures corrected resettlements back to the original May 1, 2018, release date. The RTWG next meets Oct. 25.
- MWG RR333: Modifies four charge types necessary to implement RR229 (FERC Order 831 compliance) and discovered by staff during a recent settlements system replacement project. It also must go before the RTWG for approval.
- ORWG RR318: Changes the contingency reserve requirement calculation to allow the use of the “most severe single contingency” as the basis of the minimum contingency reserve requirement on an hourly basis. SPP said the revision allows it to more accurately and reliably set the reserve requirement.
- RTWG RR305: Updates Tariff language following modifications to the aggregate facilities study process by removing the requirement to file a service agreement before modeling new transmission service in the ITP models. Also removes the requirement that SPP issue notifications to construct (NTC) and notifications to construct with conditions (NTC-C) before filing a service agreement. Adds a financial commitment date of four years to the issuance of an NTC or NTC-C.
- RTWG RR322: Changes the Tariff and other documents to reflect that the RTO is no longer using U.S. Energy Information Administration data in monthly load forecasts. SPP said the data in the EIA report are not granular enough because they are at the balancing authority level, rather than the local balancing authority level required. In January, the RTO began using forecast data that are available through the NERC system data exchange (SDX) and historical data where forecasts are not available.
— Tom Kleckner