LITTLE ROCK, Ark. — SPP members moved last week to eliminate Z2 revenue credits for sponsored transmission upgrades, the source of years of stakeholder frustrations and jokes.
The Markets and Operations Policy Committee unanimously endorsed a Regional Tariff Working Group revision request (RR) that eliminates Z2 credits and replaces them with incremental long-term congestion rights (ILTCRs), effective February 2020.
MOPC first overrode pushback from members seeking to delay RTWG RR374’s implementation, contingent on fully developing ILTCRs, rejecting the motion against seven “no” votes and seven abstentions. That would have allowed additional upgrades to be granted Z2 credits during the delay.
“One more sponsored upgrade that qualifies for Z2 credits is one too many, in our opinion,” said Oklahoma Gas & Electric’s Greg McAuley.
Under Attachment Z2 of SPP’s Tariff, sponsors that fund network upgrades can be reimbursed through transmission service requests, generator interconnections or upgrades that could not have been honored “but for” the upgrade. Multiple stakeholder teams have taken a crack at improving the process, which, combined with software problems, has delayed credits to transmission customers.
In February, FERC reversed a waiver and ordered SPP to refund, with interest, credit payment obligation amounts dating back to 2008. SPP has estimated the obligations to be approximately $200 million. (See FERC Reverses Waiver on SPP’s Z2 Obligations.)
Dan Simon, outside counsel for the EDF Renewables, warned RR374 doesn’t comply with FERC’s policies on interconnections (Order 2003) and long-term firm transmission rights (Order 681). To eliminate Z2 credits, he said, the commission would have to find SPP’s ILTCR rules comply with both policies.
Simon said Order 2003 allows ISOs and RTOs to directly assign upgrade costs if, in return, they receive rights that are valuable, well-defined and tradeable. By modifying ILTCR rules to limit total compensation to each upgrade’s directly assigned costs plus interest, RR374 will make the ILTCR rules non-compliant with Order 681, he said.
“If you want to go ahead and vote in favor of the Z2 credits’ elimination, it shouldn’t be filed with FERC,” he said. “It shouldn’t be effective until you develop and modify ILTCR rules to where they have some actual value. I think this will be heavily contested [at FERC].”
“We don’t know when this thing will be done to everyone’s satisfaction,” McAuley said. “It could be a quarter; it could be four years. Once you agree to Z2 credits, they’re permanent.”
“We’re tired of paying for things that have no benefit for the customers because we adopted such a complicated process,” Southwestern Public Service’s Bill Grant said. “We’re funding 80% of creditable upgrades, which was not our intention.”
The Tariff change is one of the first Holistic Integrated Tariff Team recommendations to be endorsed, following the approval of its 21 proposals to integrate the expansion of renewable energy, boost reliability and improve transmission planning and the wholesale market. (See SPP Board Approves HITT’s Recommendations.)
MOPC Approves $336 ITP Portfolio
MOPC approved the 2019 Integrated Transmission Planning 10-year assessment, a 27-month process resulting in 44 transmission projects with a total engineering and construction cost of $336 million. The portfolio, which includes 166 miles of new EHV transmission and 28 miles of rebuilt HV infrastructure, will address 145 system issues, the Economic Studies Working Group said.
SPP projects the assessment will provide a 40-year benefit-to-cost ratio of between 3.5 to 1 and 5.8 to 1, with residential customers seeing a savings of $0.04-$0.23/kWh on the average bill. Approximately 75% of the portfolio encompasses regional highway projects.
“We’re trying to evaluate whether or not the delivery [of low-cost generation] can reduce the cost to load on the SPP network,” said SPP System Planning Director Antoine Lucas. “To the extent we are unable to justify [capital] investments that have less costs than the savings to load, we think we will see projects that wouldn’t be justified. We’re saving fuel costs for load in SPP, albeit at a capital cost in transmission. We see that as a net benefit to customers.”
ESWG Chair Alan Myers, with ITC Holdings, said the assessment addresses overlapping top-ranked economic needs and reliability concerns, along with seams impacts, congestion, stability concerns and operational issues. The projects are expected to pay for themselves in less than 20 years, with customers seeing benefits in under two years.
McAuley, saying OG&E sees a “mismatch on the commitment side,” warned about the consequences of continuing to connect renewable generation that “far exceeds the needs of our customers.” SPP’s reserve margin sits in the mid-20% range, with more generation in the interconnection queue than the RTO “knows what to do with.”
“OG&E will be advancing this position much more aggressively in the future, not because we hit a wall today, but because we see a wall coming,” he said. “How do we impact the rest of the generation that’s already there? SPP will have an optics problem when we have a lot of renewable generation on the ground and we can’t get it to the load. Who is going to feel that pressure? Who is going to be asked to pay for that transmission to get that generation to load?”
Myers said a “significant” amount of “non-committed generation” is included in the model, “but we’ve also taken great care to make sure we’re not over-planning.”
“If the wind is there, the failure to plan for it only exacerbates the problem,” he said. “We’ve taken a number of steps to carve out commitments not tied to SPP load.”
MOPC Chair Holly Carias, with NextEra Energy Resources, relied on SPP’s new web-based voting system (see below) to vote on the ESWG’s motion. Transmission owners and transmission users both favored the ITP assessment, by 13-5 and 42-7 votes, respectively, easily clearing SPP’s 67% threshold.
Separately, MOPC also approved a revision request that adds a high-wind dispatch for the powerflow model’s sensitivity cases that measure stress on the grid. The Transmission Working Group recommended TWG RR379’s approval, saying the additional flexibility will enable SPP to demonstrate its proactive approach to continuous improvement during NERC audits for TPL-001-4.
The motion passed with three no votes and three abstentions.
Members Endorse Quick-Start Revision
Members approved a Tariff revision that complies with FERC’s directive to allow fast-start resources to set clearing prices, despite stakeholder and Market Monitoring Unit opposition.
SPP staff said MWG RR375 was limited in scope to meet only FERC’s requirements. The commission in June found the grid operator’s quick-start pricing practices to be unjust and unreasonable because they don’t allow prices to reflect the marginal cost of serving load and directed the RTO to make six Tariff changes in response. (See FERC Orders Fast-start Rules for SPP.)
FERC’s order wrapped up an investigation of several RTOs begun in December 2017 under the Federal Power Act. (See FERC Drops Fast-Start NOPR; Orders PJM, SPP, NYISO Changes.)
Staff said they believe the proposed protocol and Tariff changes comply with FERC’s order and minimize the amount of changes, staff time and vendor expenditures needed to address the order.
The MMU disagreed, saying it had significant concerns with the proposal and it would file comments at FERC noting its objections and concerns. The Monitor said the commission requires separate market solutions for dispatch and pricing and to maintain a cost-minimizing dispatch solution that would separate price from quantity in the market.
MMU Supervisor John Luallen said RR375 only mitigates the pricing run and start-up and no-load offers can be modified after commitment and used to set price.
“By separating price and quantity, you will end up with an inconsistent price for quantity,” Luallen said. “FERC was very specific about how certain things are to be done in this order.”
Golden Spread Electric Cooperative and City Utilities of Springfield (Mo.) filed comments opposing the proposal. Golden Spread said the RR “does not allow prices to reflect the cost of quickly responding resources from an offline state, which will not allow [quick-start resources] dispatchable from zero to set price in the same way that other dispatchable resources set price, and hence will not reflect the QSR cost of or value of responding quickly to unforeseen system needs.”
The cooperative was among six members to oppose the revision. Four others abstained from the vote.
The MWG withdrew four other revision requests as a result of MWG RR375: RR116, RR137, RR142 and RR256.
Members also endorsed MWG RR361, which creates ramp-capability up and down products designed to pre-position resources with that capability to manage net load variations and uncertainties and to provide transparent price signals to incent resource flexibility and economic investment.
The revision was opposed by seven members, with two abstaining.
“For some of you old guys that used to run [balancing authorities],” American Electric Power’s Richard Ross, chair of the MWG, began before catching himself. “For some of you more seasoned operators, back in the old days, we would recognize that when the morning load pickup came, you had to get those units ready to move. You might hold one of those units back a little back so you can ramp and have ramping capability.”
SPS’ Grant agreed with the need for ramping products but questioned the reliability of short-term forecasts to determine renewable energy’s availability.
“Weather can change rapidly at the resource,” SPP’s Gary Cate said. He said in their analysis, staff used 36 operating days and re-ran more than 18 different scenarios, resulting in 684 day-ahead market and reliability unit commitment reruns and 197,000 real-time market reruns.
“In only five cases did the solar or wind farm clear ramp capability up,” Cate said.
The MMU said it supports RR375 after many of its concerns were addressed during its development. However, the Monitor plans to file with FERC over lingering issues, including a lack of transparency on the confidence level used to establish ramp requirements and the lack of a claw-back provision should a resource not perform.
Change Continues GI Requests’ Processing
MOPC easily approved a Business Practice Working Group RR documenting a change to generator interconnection modeling assumptions.
BPWG RR370 changes the assumptions to stop artificially forcing wind and solar on at 10% in remote areas in the off-peak case and reduces the amount of existing firm generation that must be offset to accommodate new study generation. The change, recommended by the GI improvement task force as a short-term step that allows new requests to be processed, enables the study process to accommodate larger cluster sizes.
The change is seen as a patch until a new group, the NRIS, ERIS (network resources/energy resources interconnection service) and Deliverability Task Force, can develop a longer-term solution. In the meantime, staff continues to struggle with a GI queue clogged with study requests.
“We’ve got to work our way through the queue, no question about it,” said Midwest Energy’s Bill Dowling. “We have to be sure we’re thorough about it. The [change] is intended to give us a way to complete the studies. It keeps the ball rolling.”
Entergy Comment on Seams ‘Raises Eyebrows’
Missouri Public Service Commission economist Adam McKinnie briefed MOPC on the efforts of SPP and MISO state regulators to determine the effectiveness of the RTOs’ interregional planning processes. (See MISO, SPP States Ponder Look at Interregional Planning.)
It’s a briefing McKinnie has delivered in several venues recently.
“And you’ll get it again at the [Regional State Committee] meeting,” McKinnie said, referring to the RSC’s Oct. 28 meeting in Little Rock.
A committee of RSC members and their Organization of MISO States’ (OMS) counterparts have commissioned the grid operators’ market monitors and Potomac Economics to gather stakeholder feedback as part of the analysis on the interregional processes.
One comment in particular has “raised eyebrows,” McKinnie said.
MISO member Entergy charged that SPP’s failure to conduct economic planning since 2016 has resulted in continual congestion on the Neosho-Riverton flowgate in Kansas. Market-to-market (M2M) settlements on the flowgate had reached $29.3 million in SPP’s favor through July since 2015, accounting for almost half of the $64.3 million it has accrued from MISO since the M2M process began.
“Had SPP performed an economic plan during that time, it is possible that SPP might have found a solution (and started construction) to fully address the … congestion,” Entergy said. “If an RTO is not conducting an economic plan during the planning period, the RTO should provide a well-supported explanation to stakeholders.”
SPP and MISO skipped their biennial coordinated system plan (CSP) study last year to refine their interregional process, which has yet to result in a joint project. SPP did include an economic analysis in the 2019 CSP, which, like its two predecessors, failed to identify a joint project.
“Both SPP and MISO should focus on improving their regional processes rather than increasing the already substantial time and energy each RTO spends on interregional issues,” Entergy said.
McKinnie said Entergy’s comments are likely to be part of the discussion when the OMS meets on Oct. 24.
The RSC-OMS Liaison Committee has requested two rounds of analysis. The market monitors and Potomac Economics have split up the first round of studies, which are focused on rate pancaking and unreserved transmission use charges, the M2M process and joint dispatch.
Keith Collins, executive director of SPP’s MMU, told members that the Monitor has found little evidence of pancaking on the seam, but some SPP entities have been charged for unreserved transmission use on the MISO side. The MMU expects to publish its report in November.
The Liaison Committee will have to replace Missouri Public Service Commissioner Daniel Hall when his term expires in November, McKinnie said. Hall also leads the OMS half of the committee.
SPP Uses Web-based Voting System
SPP stepped boldly into the 21st century by introducing a web-based voting system developed by a third party. The eBallot software replaces roll call voice votes, which can take up to 15 minutes at MOPC, given the group’s 82 voting members.
“That could add up to quite a bit of time in meetings where there are multiple votes,” said SPP spokesman Derek Wingfield.
He said eBallot improves the integrity of the voting process and reduces the chance for human error in counting the votes. Voting members log in to a secure system where they cast and certify their votes. A report is then generated that calculates whether motions pass or fail based on the averages of the transmission owners’ and users’ approval percentages.
The system was used to approve the 2019 ITP assessment’s report.
“We do not have any indications that the Russians tampered with this,” Chair Carias said in announcing the final tally.
RTWG Chair Kays Announces Retirement
Last week’s meeting marked David Kays’ last appearance before MOPC. Kays recently announced he will retire from OG&E at the end of the year after 21 years with the utility.
Kays became active with SPP in 2004, joining the RTWG two years later and serving as its chair and vice chair for eight years. He will still lead three more RTWG meetings before handing over “the scepter of power,” an aluminum softball bat, to his successor.
Following the committee’s decision favoring the elimination of Z2 credits — eventually — Kays cracked, “I’ve now seen the birth and death of Z2 revenue credits in my career.”
OG&E’s McAuley, who announced the “sad news” to MOPC, said, “We’re really going miss that guy. He is a very significant contributor to both SPP and OG&E.”
SPP Halts Consolidation of Working Groups
The consolidation of working groups has been paused in order to do more analysis, brainstorming and creative thinking “as if we were redesigning the MOPC organization from scratch,” said the committee’s staff secretary, Senior Vice President Lanny Nickell. (See “SPP Stakeholders React to Proposed Working Group Consolidation,” MOPC Briefs: July 16-17, 2019.)
Nickell said he, Carias, SPP Board of Directors Chair Larry Altenbaumer and MOPC Vice Chair Denise Buffington will be working together on a consolidation business case to be shared with members. The group hopes to have a new organizational structure in place by May 2021.
In the meantime, SPP has already moved the Balancing Authority Operating Committee and its responsibilities into the Operating Reliability Working Group.
“It was an incremental change we felt was worth doing,” Nickell said.
COO Carl Monroe, who has been overseeing a survey of behind-the-meter resources, said staff will propose a policy for the proper treatment of BTM resources and load. The white paper will also include energy storage resources, the subject of FERC’s Order 841. (See FERC Partially OKs PJM, SPP Order 841 Filings.)
Consent Agenda Clears RRs, Baseline Resets
The committee unanimously passed the consent agenda, which included the annual violation relaxation limits analysis, a sponsored upgrade study, a pair of baseline resets for approved projects, nine revision requests and scope changes for 12 stakeholder groups.
Staff recommended an approval of APEX Clean Energy’s upgrade to the Neosho–Caney River 345-kV line in Kansas, scheduled to go in service next year.
The Project Cost Working Group recommended both baseline resets:
- Evergy’s $54.1 million update for a 345/138-kV transformer and 138-kV transmission line project, estimated at $67.1 million in 2017.
- Evergy’s $34.4 million update for network upgrades on a 138-kV circuit, which was originally projected to cost $58.3 million.
The approved RRs included:
- BPWG RR372: Documents the practices to evaluate energy storage resources in the interconnection queue.
- BPWG RR378: Clarifies the detailed project proposal’s (DPP) data-validation process by limiting the number of times a submitter can correct data errors, allowing staff more time to assess the projects.
- ESWG RR367: Revises the Integrated Transmission Planning Process (ITP) manual to incorporate separate, optional load forecasts into the ITP conventional resource plan.
- RTWG RR366: Ensures TOs consistently account for point-to-point (PTP) revenue by eliminating overpayments to customers when TOs don’t reduce their annual transmission revenue requirement with PTP revenue.
- RTWG RR381: Revises Tariff language to indicate transmission invoices may also include adjustments for prior services furnished under the Tariff.
- TWG RR363: Defines existing transmission facilities’ “material modification” as being “based on engineering judgment” in NERC’s facility interconnection studies (FAC-002) compliance.
- TWG RR364: Reduces the planning criteria’s language on equipment rating, which is already covered by NERC Reliability Standard FAC-008.
- TWG RR368: Clarifies how local planning criteria will be considered in ITP studies.
- TWG RR384: Clarifies the ITP manual to better meet compliance with firm transmission service modeling requirements for planned retirements of generator resources in the base reliability models.
— Tom Kleckner
