MISO’s participation model for electric storage resources needs a final edit before FERC declares the grid operator fully compliant with Order 841, the commission said this week.
FERC on Monday ordered MISO to remove or defend its requirement that distribution utilities and load-serving entities report real-time grid injections and withdrawals. FERC said MISO couldn’t impose reporting obligations on distribution utilities or LSEs because those companies aren’t party to its new pro forma storage participation agreement. FERC said MISO might require data reporting from companies that might not have “any relationship” with the grid operator (ER19-465).
“This reporting requirement is also unnecessary because MISO proposes to require the electric storage resource to report the same information,” the commission said.
FERC said it otherwise approved of MISO’s plan to make market participants responsible for meter installation, ownership, meter-data quality and “periodic testing of metering and related equipment.” The commission also found no problem with MISO’s requirement that storage owners report hourly real-time injections and withdrawal volumes at commercial pricing nodes or to estimate hourly injections and withdrawals if the energy storage resources don’t have a meter at a node.
| Connexus Energy
FERC in November found that MISO’s model largely complied with Order 841 but lacked detail about metering and accounting practices for distribution-connected and behind-the-meter ESRs. (See Storage Plans Clear FERC with Conditions.)
FERC’s latest order, however, rejected a group of Midwestern transmission-dependent utilities’ ask that MISO’s new pro forma agreement not be applicable to ESRs with on-site generation.
“Order No. 841 defines an ‘electric storage resource’ as a resource that can receive energy from the grid and store it for later injection back onto the grid. This definition does not specifically include or exclude, or otherwise discuss, electric storage resources that have on-site generation,” FERC said.
The commission also declined the Midwestern group’s request that it order MISO to make storage resources pay the Multi-Value Project (MVP) transmission charge. The charge funds the grid operator’s 2011 MVP transmission expansion portfolio and is allocated on a load-ratio basis to wholesale energy purchases. FERC agreed with MISO that storage resources should be exempted from the charge “because they do not consume energy as an end-use.”
“Even if the Tariff language and rate structure that existed prior to Order No. 841 allowed the assessment of the MVP charge to [ESRs] based on their monthly net actual energy withdrawals in a manner analogous to load, [ESRs] would still largely avoid the MVP charge because their withdrawals from charging would be mostly offset or netted by their discharging injections,” the commission wrote.
Finally, FERC accepted MISO’s explanation that ESRs should be excluded from qualifying as fast-start resources. The ISO said storage resources, as “offline energy-limited resources,” would “depress prices because they may be less feasible and less available due to state-of-charge management by the market participant.”
MISO has until mid-2022 to implement its ESR participation plan, as it will first have to build a new market platform.
FERC on Monday accepted most provisions in NYISO’s second attempt to comply with Order 841, which requires RTOs and ISOs to remove market barriers for energy storage resources (ESRs).
The decision specifically accepted proposed Tariff revisions to subject ESRs to transmission charges, effective no later than Sept. 30, but ordered the ISO within 90 days to clarify its proposed exemptions to such charges (ER19-467). The commission faulted the initial compliance filing for failing to apply those charges to ESRs when they are charging in the wholesale market for later retail sale but not providing services to the grid.
The commission also deemed NYISO’s Jan. 21 request for rehearing to be denied by operation of law.
Issued in 2018, Order 841 requires market participation rules to recognize the unique physical and operational characteristics of storage resources. The commission last December partially accepted NYISO’s compliance filing but faulted the ISO for lack of details on its metering methodology and accounting practices for ESRs located behind a customer meter. (See FERC Partially Accepts NYISO Storage Compliance.)
In its second compliance filing in February, the ISO proposed not to assess transmission charges to ESRs when the resource receives a real-time operating reserves schedule; receives a real-time regulation service schedule; is operating and is a qualified supplier of voltage support service; or is dispatched as out-of-merit to meet New York Control Area (NYCA) or local system reliability.
FERC accepted those provisions, but required NYISO to provide clarifications, saying that because these services are typically scheduled on top of a resource’s base energy schedule, it is unclear what portion of a resource’s megawatt withdrawals the ISO proposes to exempt from transmission charges, in particular of withdrawals during an interval when the resource is self-scheduled at a fixed megawatt quantity.
Pumped up
In its request for rehearing, NYISO argued that its proposed approach to not assess transmission charges aligns with its existing rate structure for transmission charges assessed to resources in the NYCA that withdraw energy at a node for later injection into the grid.
Specifically, NYISO said for more than 20 years it has applied a separate rate structure for transmission charges applicable to the 1,134-MW Blenheim-Gilboa Hydroelectric Power Station in the Catskills, a pumped storage facility owned by the New York Power Authority. The ISO argued that the station is located at a single generator bus that pays the nodal locational based marginal price (LBMP) to withdraw energy as a “negative injection” for later injection back into the grid.
NYISO wants to exempt resources like NYPA’s 1,134 MW Blenheim–Gilboa Hydroelectric Power Station in the Catskill Mountains from Order 841 transmission charges.
NYISO sought to apply the same separate rate structure to all nodal ESRs in in its jurisdiction and said that under Order 841, when such resources are marginal in the ISO’s dispatch of energy, loads in the NYCA would effectively be paying the related charges twice — once as part of the energy component of LBMP and again when NYISO and the relevant New York transmission owner assess charges to the loads.
But the commission said it was not persuaded by NYISO’s request for rehearing and continued to find the ISO has not demonstrated, as required in Order 841-A, that its proposal not to apply transmission charges to all ESRs is reasonable given how it assesses transmission charges to wholesale load under its existing rate structure.
“As a general matter, NYISO assesses transmission charges to all wholesale load, and it only declines to assess transmission charges to the withdrawals by one specific pumped storage facility when that facility is participating under the energy limited resource (ELR) model,” the commission said. “Thus, NYISO’s proposal not to apply transmission charges to any energy storage resource is not consistent with or reasonable given its existing rate structure, as contemplated by Order No. 841-A.”
The commission also said that NYISO’s double payment argument “is, in essence, a late-filed request for rehearing of Order No. 841 and is statutorily barred. Notwithstanding this procedural flaw, NYISO’s argument is also unpersuasive on the merits.”
Two different transactions occur, the commission said: “One that entails the electric storage resource purchasing charging energy at wholesale from the RTO/ISO market, and another that entails wholesale load purchasing energy from the electric storage resource via the RTO/ISO energy market. As such, we find that it is reasonable to apply transmission charges to both the electric storage resource and the loads associated with those separate transactions and for load to ultimately pay the two transmission charges.”
NYISO also argued that FERC’s rejection of its proposal was inconsistent with the commission’s acceptance of a CAISO proposal to exempt all ESRs from transmission charges when charging, consistent with CAISO’s existing rate structure.
Not so, said the commission.
“Unlike CAISO’s non-generator resource model, which was designed for electric storage resources, NYISO’s ELR model is designed for and primarily used by generators. Indeed, NYISO withdrew its ELR model from consideration for compliance with Order No. 841 because, according to NYISO, the ELR model could not accommodate withdrawals from ESRs.”
NYISO’s treatment of one pumped storage facility under the ELR model is thus a limited exception and not representative of how the ISO assesses transmission charges to wholesale load under its existing rate structure, the commission said.
Evergy has decided to stay single after dalliances with several potential acquisition partners, according to a published report.
Quoting “people familiar with the matter,” Bloomberg said Tuesday that the Kansas City-based company has decided to remain independent. Evergy has decided it can create more value for shareholders through a new operating plan, which had been in development while the company explored a possible sale, the report said.
The plan’s details are expected to be shared with financial analysts Wednesday when Evergy holds its quarterly earnings call before the market opens.
Evergy’s subsidiaries in Kansas, Missouri. | Evergy
Evergy’s share price plunged 13.4% after the Bloomberg story broke, from $62.81 to $55.40. It was trading at $55.79 as the market neared its close.
Evergy has been under pressure from activist investor Elliott Management, which took a $760 million stake in the company and has pushed it to shake up its management team. Evergy said in March that it had reached an agreement with Elliott to establish a new strategic review committee to explore ways to improve shareholder value. (See NextEra Said to be Eyeing Evergy as Acquisition Target.)
Ameren, American Electric Power, CMS Energy and NextEra Energy are among those linked to Evergy as potential buyers.
Evergy, an SPP member, was created in 2018 through a merger between Kansas City Power and Light and Westar Energy. It serves 1.6 million customers in Kansas and Missouri.
The Texas Public Utility Commission last week approved the withdrawal of a certificate of convenience and necessity (CCN) rights transfer between NextEra Energy Transmission Southwest and Rayburn Country Electric Cooperative (48071).
The two entities had agreed in 2017 that NextEra would acquire Rayburn Country’s rights to own and operate a 30-mile segment of a 138-kV transmission line in East Texas. But the companies now say the transaction has been rendered moot by 2019 legislation that gave incumbent transmission companies the right of first refusal to build new transmission lines. (See Texas ROFR Bill Passes, Awaits Governor’s Signature.)
The transaction had been approved by a PUC administrative law judge in January 2019. However, that May, the state legislature passed Senate Bill 1938, which grants CCNs to build, own or operate new transmission facilities “only to the owner of that existing facility.”
In their request to withdraw their joint application, the companies said the legislation “precluded the PUC from granting the application.” NextEra and Rayburn Country also said an asset purchase agreement behind the application had been terminated, thereby mooting the transaction.
Hanna Restoration Efforts Continue
PUC Chair DeAnn Walker enjoys a lighter moment during the commission’s July 31 open meeting. | Texas PUC
The commissioners complimented AEP Texas and several other utilities for their restoration work following Hurricane Hanna’s July 24 landfall in South Texas.
“They’ve done a fabulous job of getting people back on,” said PUC Chair DeAnn Walker. She noted outages peaked at 297,000 but had dropped to nearly 2,800 by the July 31 open meeting.
AEP Texas President Judith Talavera, who called into the meeting, said crews have been repairing 700 distribution poles, 280,000 conductors and 35 transmission structures. The company has asked residents in the Rio Grande Valley to conserve electricity until Aug. 14 while it rebuilds a two-mile stretch of a 138-kV transmission line damaged by the storm.
Magic Valley Electric Cooperative said Hanna “dealt a heavy blow” to its system, and it has warned customers about prolonged outages.
ERCOT’s Virtual Meetings OK’d
The PUC granted ERCOT‘s expedited request to amend its bylaws, waiving a requirement that a proposed order be served 20 days before considering the application at an open meeting (50918).
The order clears the way for the grid operator to expand its definition of urgent matters so that its board of directors and its subcommittees can meet virtually during the COVID-19 pandemic. ERCOT stakeholder groups have already been meeting virtually since March.
“When the bylaws were written, COVID-19 didn’t exist, and we didn’t know this was going to happen to us,” Walker said. “These meetings have been awkward at best. I appreciate [ERCOT’s] efforts to fix this.”
PUC Looking at EV Charging Stations
In other actions, the PUC approved staff’s solicitation of comments as they review issues relating to electric vehicles in advance of next year’s state legislative session (49125).
The commission is considering which companies can own or operate EV charging stations, how their costs would be recovered and whether their operation would constitute retail sales.
“I appreciate everyone staying plugged in,” Commissioner Shelly Botkin said, before acknowledging her unintended pun.
“We know this is not the sum total of EV things we’ll have to address before the session starts,” Commissioner Arthur D’Andrea added.
The commission also:
Gave staff the go-ahead to begin work on a proposed rule change broadening the pool of candidates eligible to serve as the ERCOT wholesale market’s reliability monitor. The Texas Reliability Entity currently fills that role (50602).
Approved distribution cost recovery factors for AEP Texas (50733) and Oncor Electric Delivery (50734). AEP Texas’ DCRF was based on an annual revenue requirement of $39.1 million after adjustment for load growth. Oncor was granted an incremental increase of $69.9 million to its DCRF revenue requirement.
Eversource Energy on Friday reported how well it is managing the impact of COVID-19 on its financials, just as Connecticut regulators suspended a July 1 rate increase set to boost its bottom line.
The company posted second-quarter earnings of $252.2 million ($0.75/share), up from $31.5 million ($0.10/share) in the same period a year ago. The increase was due primarily to last year’s results including a $0.64/share impairment charge related to the Northern Pass transmission project, which failed to win regulatory approval in New Hampshire.
“The vast majority of our employees who either had tested positive for COVID-19 or were self-quarantined are now back to work,” CFO Philip Lembo said Friday in an earnings call.
Eversource is New England’s largest utility company, with subsidiaries supplying electricity, natural gas and water service to approximately 4 million customers in Connecticut, Massachusetts and New Hampshire.
Eversource Gas and the service areas gained in the $1.1 billion acquisition of Columbia Gas’s 320,000 natural gas customers in Massachusetts. | Eversource Energy
In terms of usage, kWh sales in the second quarter were down about 1.4% overall compared with last year. But in New Hampshire, which is not decoupled, sales were up 1.8%, the company said.
A 26% June spike in residential usage in Connecticut compounded the effects of a July 1 rate increase, resulting in consumer complaints and legislator calls for action and prompting the state’s Public Utilities Regulatory Authority (PURA) Friday to suspend the rate increase to allow for reexamination.
The order specifically affected Connecticut Light and Power’s revenue decoupling mechanism charge, which had gone up from -0.011 cents/kWh to 0.182 cents/kWh; the transmission charge, up from 2.356 cents/kWh to 3.395 cents/kWh; the non-bypassable federally mandated congestion charge, up from 1.423 cents/kWh to 2.729 cents/kWh; and the electric system improvements tracker charge, up from 0.171 cents/kWh to 0.299cents/kWh.
“We’re not shutting off customers, and we’re working diligently to help customers in this pandemic situation,” Lembo said, referring to press reports of customer complaints. “The rate overall on a customer’s bill is only up about 3.5%, mostly driven by this record level of usage.”
He also cited the utility’s contract to provide payment “and subsidy, some might say, to Millstone Nuclear Plant” as a contributing factor.
The Connecticut Department of Energy and Environmental Protection in December 2018 negotiated a 10-year contract for about 50% of the plant’s output after deeming it to be at risk of retirement. (See Conn. Zero-Carbon Awards Include Nukes, OSW, Solar.)
Grid Mod
Lembo also highlighted the company’s plans to file three proposals that day in PURA’s grid modernization proceeding to help the state reduce its carbon footprint by at least 80% by 2050.
The company plans over the next five years to replace 800,000 meters with automated meter infrastructure; wire 2,500 homes for electric vehicle charging and build 3,000 additional charge stations in the state over a period of three years; and incentivize installation of 30 MW of residential energy storage and 20 MW of commercial storage.
In Massachusetts, the company continues to implement the grid modernization plan authorized by regulators more than two years ago, he said.
“We expect to complete the authorized projects, including infrastructure to connect 3,500 charge ports and utility storage projects on Cape Cod and Martha’s Vineyard, in 2021,” Lembo said. “In mid-2021, we’ll be filing a new three-year plan with implementation in the 2022 through 2024 time period.”
In other matters, the company expects to receive regulatory approval by Sept. 30 for its $1.1 billion acquisition of Columbia Gas’s 320,000 natural gas customers in Massachusetts.
Eversource reports the New England states have aggressive renewable and GHG targets. | Eversource Energy
Lembo also cited the June 9 release of the Bureau of Ocean Energy Management’s (BOEM) supplemental environmental impact statement for the Vineyard Wind project, which also affects development of about 22 GW of offshore wind generation off the Atlantic coast.
“This was an important step in BOEM’s evaluation process for the different applications that have been filed to date, including two of our joint proposals with Ørsted, one of those being [130-MW] South Fork, the other [704-MW] Revolution Wind,” he said. (See Developers Seek 1-Mile Spacing for Vineyard Wind.)
The company expects BOEM later this summer to release its schedule for review of South Fork, though it is “very unlikely” that South Fork will enter service before the end of 2022. It still expects Revolution Wind to be in service by the end of 2023, Lembo said.
The joint venture’s 880-MW Sunrise Wind project in New York is slated to go into service at the end of 2024, he said.
The Massachusetts Department of Energy Resources (DOER) said last week it will not require the state’s electric distribution companies to solicit proposals for a coordinated independent transmission network for the 1,600 MW of offshore wind energy already procured, but recommended bundling transmission in its next OSW solicitation.
“Following a thorough investigation, DOER finds that the costs and risks of a solicitation for independent offshore wind energy transmission outweigh the potential benefits that could be captured by 1,600 MW of transmission capacity,” Commissioner Patrick Woodcock said in a letter to the legislature’s Joint Committee on Telecommunications, Utilities and Energy. DOER said it feared the solicitation could delay upcoming OSW generation procurements and complicate contracting and permitting issues.
The purple line marks the cables and pipelines geographic analysis area for the Vineyard Wind project. | BOEM
Instead, the agency is recommending a bundled solicitation of 1,600 MW of generation and transmission, which it said could reduce cabling and use onshore interconnection points efficiently. The state — which has selected Mayflower Wind and Vineyard Wind 1 to build the first 1,600 MW of offshore wind in federal leasing areas south of Martha’s Vineyard — initially planned two additional 800-MW procurements.
DOER said that a larger solicitation for bids up to the full 1,600 MW currently authorized would allow developers greater flexibility in project design. First, a larger solicitation would allow developers the option of using HVDC cables, which can transmit up to 1,400 MW on a single cable versus 400 MW for HVAC cables, for offshore wind, the agency said. Second, a larger solicitation would allow developers the option to interconnect onshore at the maximum capacity allowed by ISO-NE (1,200-MW single contingency limit), which could help ensure that the limited number of onshore interconnection points in Massachusetts is used to maximum potential.
“In sum, a larger solicitation would give developers maximum flexibility to use transmission infrastructure efficiently, thereby helping ensure … bids that minimize the environmental and socioeconomic impacts of siting offshore wind structures in the ocean and on land and achieve many of the potential benefits of the independent transmission solicitation without the added costs and risks,” DOER said.
DOER also said it would consider joining with neighboring states on a backbone transmission plan.
A network transmission “initiative could be achieved more effectively at a larger scale of offshore wind build-out and with regional coordination among New England states … than through a single state procurement with limited size,” Woodcock said.
Comments in Favor
Recreation and tourism geographic analysis area for the Vineyard Wind project | BOEM
Massachusetts hosted a technical conference in March to explore whether it should solicit proposals for a transmission network for offshore wind generation. (See Mass. DOER Explores Transmission for OSW.) The planning choice was between generators developing the transmission — the generator lead line, or radial system — and independent transmission construction and ownership, or a network system.
The DOER letter noted significant stakeholder support for a networked or backbone-independent transmission approach at a larger capacity.
Included in a second round of stakeholder comments published April 22, State Rep. Patricia Haddad, speaker pro tempore of the Massachusetts House of Representatives, said in a letter to DOER that “we have been successful with the two recent offshore wind bids with generator lead lines. I feel the next procurement should include crucial shared transmission opportunities.”
The Responsible Offshore Development Association (RODA), a fishing industry group, submitted a letter urging independent transmission development if it would mean using less cable and having fewer environmental impacts.
Upping the Target
Meanwhile, the Massachusetts House amended its climate change bill Friday to increase the amount of offshore wind energy the state and utilities must contract from 3,200 MW to 3,600 MW. It also would cut the time between procurements from 24 months to 18 months.
Earlier last week, the Senate amended its economic development bill to mandate procurement of an additional 2,800 MW of OSW by 2035, which would raise total authorization to 6 GW.
The two houses will have to reconcile their differences in conference committee.
SPP‘s Board of Directors last week approved a staff recommendation that resolves six months of uncertainty over the weighting of futures in the 2021 transmission planning assessment.
Staff said a 50/50 weighting of the two futures in the 2021 Integrating Transmission Planning (ITP) study would acknowledge the lack of consensus over each future’s relative probability. They also suggested that any project that could not be justified under a 60/40 weighting be highlighted for further consideration.
The Markets and Operations Policy Committee earlier in July rejected the 50/50 weighting and two other suggestions during its third fruitless attempt to approve an issue that left stakeholders flummoxed. (See “Members Unable to Agree on Weighting Futures in 2021 Tx Plan,” SPP MOPC Briefs: July 15-16, 2020.)
The Economic Studies Working Group (ESWG) in January recommended a 60/40 split between Future 1 and Future 2, respectively. The “business-as-usual” Future 1 reflects current trends, while the “emerging technologies” Future 2 case assumes that distributed generation, demand response, energy efficiency and energy storage will have a major effect on load and energy growth rates.
The Members Committee approved the recommendation 13-5, with a mix of transmission owners and users in opposition.
Stakeholders have struggled over Future 1’s assumption of 32 GW of installed wind capacity in 10 years and where the primarily renewable resources would be sited. SPP has said it will have 27 GW of wind capacity by the end of this year.
Oklahoma Gas & Electric’s Greg McAuley, one of five members to oppose the motion, advocated for a 70/30 weighting of the futures that leans more toward uncertainty.
“If you assume solar begins to expand at the same rate wind has over the last 10 years, is it reasonable to assume that expansion will take place in similar locations or be closer to load?” he asked. “These assumptions about resources, without associated firm transmission, kind of leaves us exposed. We will have built transmission to accommodate resources no longer available to the market.
“If you put transmission in the ground, we’re committed to it. Our customers will be paying for those facilities for a long time,” McAuley said.
Board Chair Larry Altenbaumer | SPP
SPP Vice President of Engineering Antoine Lucas pointed out that either weighting would not have affected the last three ITPs’ project portfolios.
“The best way to address this is to focus more on the sensitivity analysis of individual projects and the assumptions that drive the benefits for those projects,” he said. “If [a project] says more wind [will result], we believe we should run sensitivities around it and test the assumptions. We already do that, whether it’s the amount of wind or fuel prices.”
“What staff has proposed is to basically provide all of us with a bit of a safety net,” said Board Chair Larry Altenbaumer during the July 28 web meeting. “If there is something that is justified in the 50/50 weighting, but not in the 60/40, that allows us to dig into more detail to understand the ramifications, [then] this has taken us a step in the right direction, while recognizing there are more steps we need to take.”
Agreement on Competitive Project’s Path Forward
Stakeholders were able to reach an agreement over the suspension of a competitive project that SPP agrees would provide numerous benefits to the eastern edge of its footprint, where congestion remains a problem.
Several members wanted to lift the suspension and issue a request for proposals. However, staff cautioned the move would open a seven-day window during which they would have to issue the RFP. The RTO would also be within an 18-month window to issue funds for the project.
The 345-kV Wolf Creek-Blackberry project in Kansas and Missouri with Associated Electric Cooperative Inc. (AECI) was approved by the board last year and was included in the 2020SPP Transmission Expansion Plan passed in January. Part of the 105-mile project, projected to cost $152 million, would be on the AECI transmission system and constructed by the cooperative. SPP cannot allocate funds to AECI without FERC approval.
The board in April suspended the project, pending negotiations with AECI and FERC’s approval of a cost-and-use agreement. Staff said AECI has reached a verbal agreement but has not yet provided SPP a signed document. (See “Directors Suspend Competitive Upgrade,” SPP Board/Members Committee Briefs: April 28, 2020.)
General Counsel Paul Suskie said several risks preclude lifting the suspension. “First, whether or not we can reach a timely agreement with AECI,” though he admitted an agreement is expected within days.
Other risks include FERC’s perspective after a pre-filing meeting with commission staff and potential protests that could delay a final order, Suskie said.
“Once an agreement is signed and filed at FERC, we’re in a much better position when we see whether any protests are filed,” he continued. “The risks are further minimized as we move further out on the timeline.”
Altenbaumer suggested members wait until the agreement is executed and filed with FERC “as soon as possible.” That would open a 20-day period for any protests, during which time SPP staff could prepare the RFP.
“One thing I’m concerned about is if challenges are made to that filing, and not knowing what those objections are or FERC’s action on that filing, and how they could undercut the AECI agreement,” Altenbaumer said. “We will then have been out there with an RFP that would not be a viable RFP.”
By late August, he said, “we’ll know … more information than where we are with the FERC filing.”
“We can work with you on trying to find a path forward,” said Evergy’s Denise Buffington, who helped pen a letter from four member utilities asking that the suspension be lifted. “Keep in mind this project is likely to be delayed even if the RFP is issued by Oct. 1. We are looking for an outside date of Oct. 1, and the path you have outlined will accommodate that.”
Evergy was joined by American Electric Power, Liberty Utilities and City Utilities of Springfield (CUS) in asking the directors to issue the RFP no later than Oct. 1. The signatories said the suspension’s initial rationale was that the cost of the AECI Blackberry termination point was unknown and noted that “these costs are now known, negotiations are complete, and the [agreement] … is about to be filed.
“Because of the critical importance of the proposed line and the benefits provided to SPP customers, the board should not further delay the RFP process,” the companies wrote.
“We own the Wolf Creek substation. It will take a minimum of four years to get work done inside the substation. The longer the delay on the NTC, the less likely we will get that in time,” Buffington said during the discussion. “We’re also worried there will be protest … we think the FERC proceeding should run in parallel with the RFP. All the information needed to issue the RFP is available to SPP today.
“As the letter points out, there are a bunch of reliability issues at stake,” she said. “This project was very, very close to being a reliability project. If it gets restudied, it could be a reliability project.”
Board OKs 4 HITT Recommendations
The board and members approved four recommendations stemming from last year’s Holistic Integrated Tariff Team report, bringing the total of completed recommendations to eight out of 21.
The board sided with MOPC and the ESWG’s recommendation to keep the ITP’s benefit/cost ratio for economic projects at 1.0, rather than increase it to a range between 1.05 and 1.25. Members approved the recommendation by a 15-5 vote.
Golden Spread Electric Cooperative’s Mike Wise, one of those opposed to the 1.0 B/C ratio, said transmission buildouts are “problematic” going forward when looking at benefits and costs.
“The costs are well-known ahead of time. The real issue here is [that] the benefits are estimated and not well-known,” he said. “[The benefits] are engineering estimates 40 years into the future. It’s really difficult to grasp the benefits that come from this.”
Wise found support from McAuley and Oklahoma Municipal Power Authority’s (OMPA) David Osburn.
“This is yet another example of where we are, as Mike would put it, doing this as usual, when business is anything but usual,” McAuley said. “At what point do we stop building transmission, so our transmission rates stop going up?”
“I want to stress the point [Mike] made is very valid,” Osburn said. “We make these decisions and invest in 40-year assets. We’re spending consumers’ money here, and I think they would like to see a benefit-to-cost ratio much greater than one, and one that doesn’t take 40 years to get there.”
While Dogwood Energy’s Rob Janssen and NextEra Energy Resources’ Holly Carias supported the motion, they agreed the motion warrants further analysis.
“Greg made a good point about looking out at the future and looking at economic projects more broadly,” Janssen said.
“I can’t disagree with Mike Wise and Greg that we’re in a different scenario,” Carias said. “We need to reconsider benefits.”
The board also signed off on the Cost Allocation Working Group’s white paper that evaluated SPP’s cost allocations for transmission projects between 100 and 300 kV that are primarily used to move power out of the local transmission pricing zones.
The Members Committee approved the motion to accept the white paper by an 11-5 vote. CUS, OG&E Transmission, OMPA, Public Service Co. of Oklahoma and Xcel Energy’s Southwestern Public Service Co. (SPS) opposed the motion.
The Regional State Committee earlier voted to endorse the white paper by a 6-5 margin.
SPS President David Hudson asked that the minutes reflect that the white paper “is a controversial issue.”
Kansas’ Sunflower Electric Power is among those that stand to benefit from the paper’s recommendation to establish a “narrow” cost-allocation review that regionally distributes the revenue requirements for the lower voltage levels. Sunflower CEO Stuart Lowry said that while the review would grant waivers from the methodology, “by no means is that a guarantee a waiver will be granted.”
“We would have to make that case before MOPC and the Board of Directors,” he said. “Bear in mind that action today does not mean byway cost-allocation relief will be granted to Sunflower or anyone else.”
Members unanimously approved two other HITT items, a staff report on essential reliability services (ERS) and other reliability services (ORS) and a revision request (MWGRR402) that improves the Integrated Marketplace by using near real-time economic dispatch to evaluate intraday reliability unit commitment for committing fast-start resources near real time.
The ERS/ORS report evaluated the region’s reliability challenges with a changing resource mix by conducting three separate engineering studies on reactive supply, primary frequency response and flexible capacity supply. The Market Working Group will now be asked to work on an ERS/ORS compensation mechanism.
Gaw’s Voice Becoming More Prominent
Advanced Power Alliance’s Steve Gaw, a ubiquitous presence at SPP meetings for more than 17 years, took some good-natured ribbing when his name mistakenly appeared on a Members Committee list as the board meeting began.
“Steve Gaw … that’s a strange name,” Altenbaumer said, taking a jibe at SPP’s newest member representative. “I’m not sure why he’s on the list, but we’ll let it go this time.”
A former chair of the Missouri Public Service Commission, Gaw was among the founding members of SPP’s Regional State Committee in 2003. He has since frequently voiced the wind industry’s concerns in stakeholder meetings, taking advantage of SPP’s practice of allowing non-members to add their input during discussions.
When Gaw commented during the ITP futures weighting discussion, he first asked whether he could be heard.
“I hear you fine. I’ve never had a problem hearing you, Steve,” Altenbaumer responded.
The APA, an industry trade association supporting renewable generation and energy storage in SPP and ERCOT, recently joined the RTO as its first alternative power/public interest member. As a member, the organization now has a vote and can officially join stakeholder groups. (See “Advance Power Alliance Now an SPP Member,” SPP Briefs: Week of July 20, 2020.)
SPP said a clerical error resulted in Gaw’s name being included among the Members Committee’s list of 21 names. The Corporate Governance Committee must first nominate Gaw as representing the alternative power/public interest sector and the nomination be approved before he can cast a vote.
“I can only speak, “Gaw said later, noting he was invited to the board and committee’s executive session.
No Virtual Roll Call
With more than 250 persons calling in to the webcast, SPP’s Dustin Smith, who facilitated the meeting, declined to take attendance through a roll call.
“That’s virtually impossible to do virtually,” he said.
Consent Agenda Passes
The board’s consent agenda included approval of:
The Finance Committee’s 2021 operating plan, which includes developing a strategic plan for the next five years, implementing the HITT recommendations and completing generator-interconnection study requests from 2019 and before.
MOPC’s approval of RR404, which further defines the resource adequacy requirements for demand response programs and behind-the-meter generation, and its recommendation for a $20.7 million cost reduction to Basin Electric Power Cooperative’s Multi-Kummer Ridge-Roundup project in North Dakota.
A waiver of financial obligations under the membership agreement to East Texas Electric Cooperative for its transfer of transmission facilities and load from MISO to SPP and from SPP to ERCOT. The cooperative transferred facilities and load from MISO last year and is scheduled to transfer facilities and load to ERCOT between October and January. ETEC requested the waiver because it will wind up transferring more load into SPP than out, which would have triggered a partial termination.
Staff’s recommendation for out-of-cycle re-evaluations for notifications to construct an Evergy Metro 161-kV project in the Kansas City area and an OG&E 138-kV project.
Appointment of Omaha Public Power District’s Joe Lang to an open transmission owner’s seat on the Human Resources Committee. He replaces Nebraska Public Power District’s Tom Kent, who in March was promoted to CEO.
CAISO’s proposal to develop new capacity products through its day-ahead market enhancements (DAME) initiative could radically transform California’s resource adequacy landscape while not yielding expected benefits, a key skeptic of the plan said last week.
“I agree that in the vast majority of situations having a market price is an extremely valuable thing [and] I’m not trying to come down on either side of this one right now. I’m just saying it’s a philosophical change in the way these [RA resources] are being paid that we should think about,” Mike Castelhano, an analyst with the California Public Utilities Commission, said during discussion of the proposed capacity products at a CAISO Market Surveillance Committee (MSC) meeting Thursday.
The ISO launched the DAME effort earlier this year to expand its day-ahead market with two new nodal product offerings that would significantly alter market operations:
a reliability capacity (RC) “up/down” product to help the ISO match its net load forecast (the load forecast minus the variable energy resource forecast) with sufficient non-VER supply for one-hour intervals; and
an imbalance reserves (IR) product procured for 15-minute intervals “to provide flexible capacity to accommodate the increasing uncertainty and variability of real-time net load.”
Both products would be offered on a nodal basis, an approach CAISO thinks will best guarantee those supplies will be available when and where they’re needed to ensure flexibility on a grid increasingly dependent on VERs. The DAME straw proposal envisions co-optimizing procurement of both new products — along with day-ahead energy and ancillary services — to improve scheduling efficiency.
Graph illustrates price differences for the same intervals among CAISO’s day-ahead (blue), hour-ahead (orange), 15-minute (green) and 5-minute markets (purple). The ISO’s DAME initiative is particularly aimed at closing the discrepancies between day-ahead and 15-minute prices. | CAISO
That new process would replace the existing residual unit commitment (RUC) process for ensuring resource sufficiency, in which the day-ahead market procures the incremental capacity needed to meet reliability requirements after the ISO has run its co-optimized integrated forward market (IFR) for day-ahead energy and ancillary services. The incremental capacity obtained through RUC represents the delta between what the IFR has cleared from economic bids and “the amount needed for reliability based on the net demand forecast and potential uncertainty,” the ISO notes in the straw proposal.
“The disadvantage of this sequential RUC process is that the capacity it procures is not co-optimized with the resource commitment and energy schedules produced by the integrated forward market,” CAISO said in explaining the move to the new model.
‘Vanilla’ RUC vs. Spot Market
While CAISO has counterposed two methods for compensating suppliers of the two new products, it clearly favors one option over the other.
Under the “vanilla RUC model” (as ISO Market Design Policy Specialist James Friedrich put it), resources that have been awarded contracts under the CPUC’s RA program could offer into the market at zero price and forego being paid market clearing prices for RC and IR. In that scenario, CAISO would assume the prices of RA contracts — which subject holders to a must-offer obligation (MOO) in the ISO market — “would, in part, reflect owner expectations about magnitudes and frequency of short-run costs incurred to provide RC/IR.”
According to the ISO, the RUC model approach to compensating the new capacity products would be the least disruptive to California’s current RA system because it wouldn’t require renegotiation of existing RA contracts, changes in CPUC rules around cost recovery for RA assets or revisions to CAISO’s MOO Tariff provisions. It would also avoid the need to mitigate market power for RC/IR offers.
Those advantages notwithstanding, CAISO — and the MSC — are advocating implementing a “spot market model” as much as possible to compensate providers of the new capacity products, with the hope that short-term market offers will more precisely reflect variable costs for making capacity available, including natural gas costs and the opportunity costs of not bidding into the real-time market. That arrangement would provide suppliers a stronger incentive to make resources available, according to the MSC.
Use of that model would also eliminate the must-offer obligation for contracted RA resources, which should reduce the number of zero-price offers and increase clearing prices (while also increasing the risk of double-payment before RA contracts can be renegotiated, CAISO acknowledged). That would have the upshot of opening up California’s capacity market to non-thermal resources, helping the state achieve its ambitious carbon reduction goals, one MSC member noted.
“One of the characteristics of the current design is that … demand response can’t compete to provide RUC capacity because thermal RA units are free,” said the MSC’s Scott Harvey. “And they’re not really free, but it gets rolled into the RA price, so you don’t see a separate price signal for [whether] demand response [could] provide this RUC capacity, which is really back-up capacity that we don’t need but we want to have in reserve in case we do need it. And that’s probably an ideal role for demand response … so that’s another long-run goal that could be achieved if we make this change.”
MSC member Jim Bushnell said a long-term focus of the committee is providing “short-run marginal incentives to reward units that provide truly valuable reliability capacity” and incentivizing resource availability.
“The problem with RA has been that we don’t know a year in advance and a month in advance exactly when and what types of units provide what type of value. That’s constantly changing, so the importance for short-run incentives is large here,” he said.
CPUC Concerns
CPUC’s Castelhano said he understood Harvey’s concerns about DR being unable to function as RA capacity in the CAISO market. But Castelhano noted that the RA zero-bid requirement is a CPUC capacity designation rule and not “really a RUC rule.” He cautioned CAISO against making changes that could alter the zero-bid practice in the wholesale market or pushing to revise market rules in a way that would allow DR to function as RA in California.
“The rules for RA and DR are not as well-developed, and that’s a process that’s ongoing, and I think we have to recognize that’s not something that should change at the CAISO necessarily,” Castelhano said.
“I wasn’t arguing for a change in the rules regarding DR that is RA capacity,” Harvey said, clarifying that his focus is on enabling DR — “whether or not it’s RA capacity” — to compete to provide RUC. “That’s the CAISO issue.”
Castelhano also called out CAISO for not discussing how transformative the ISO’s changes could be for California RA, potentially transforming the program from a structure based on contracts to one reliant on a spot market.
“Sure, it gets the costs out of the RA contracts, potentially, but it also then pays a market mechanism-based price to everybody that clears in that market, whereas right now the RA costs are individual” and cost based, said Castelhano. A system based on a clearing price could allow some suppliers to earn inframarginal rents — where a supplier gets paid above its costs in an otherwise competitive market.
MSC Chair Ben Hobbs acknowledged that consumers could benefit if the utilities contracting for RA hold prices down because of monopsony market power and pass on those savings. But he said it is not clear that would happen because visibility into RA contract prices “is not exactly a strong point” in California’s market.
“RA contracts tend to be near some market-clearing level, but from an efficiency point of view, hearkening all the way back to the early days of the California market of pay-as-bid versus market-clearing price, folks who have been on the MSC have tended to favor [a] single market-clearing price for its transparency and incentives,” Hobbs said. “But you might have a point. If the utilities can price-discriminate on RA perhaps there will be less ability to do that in the future, which might conceivably increase what consumers pay and provide more of the inframarginal rents to resources.”
Castelhano also questioned CAISO’s presumption that the new capacity products would reduce some of the “guesswork” behind calculating the costs of RA contracts because income for RA resources would be based on actual short-run costs rather than on a longer-term estimation of those costs.
“My speculation is that it would go very much in the opposite direction because right now part of the RA contract depends on one variable stream of income from sales into the ISO market, and you’re going to create another possibly more variable stream of income,” he said.
Hobbs countered that the proposal’s provision allowing RA resources to buy out their must-offer obligation or bid costs in the ISO market would reduce the cost risks of having a fixed MOO negotiated far in advance of potential deliveries.
“I guess that needs some more analysis, but I don’t agree with what you’re saying there,” Hobbs said.
Castelhano concluded with “a really big concern” that CAISO is considering limiting the participation of energy storage resources in the imbalance reserve markets. He noted that the CPUC’s integrated resource planning process is assuming that storage resources will play a key role providing flexibility needed to integrate variable renewables.
“If [storage] resources are not able to participate in this imbalance reserve market, then I’m very concerned about that,” Castelhano said. “If we’re paying hourly dispatchable resources instead of the stuff that can move really fast, then that’s another concern.”
Wind energy is on track to be SPP’s No. 1 fuel source this year, executives said last week during the grid operator’s quarterly stakeholder update.
Wind production averaged 11 GW for the month of June and has accounted for 33.8% of the grid operator’s fuel mix halfway through the year. During the last three months, SPP has set footprint records for the amount of wind energy produced (18.3 GW on July 17) and the amount of wind in the fuel mix (73.2% on April 27).
“The wind continues to blow,” SPP CEO Barbara Sugg told stakeholders July 27.
SPP CEO Barbara Sugg delivers her quarterly report. | SPP
Over the last 12 months, wind has provided an average of 31.2% of the fuel mix, compared to 29.8% and 26.6% for coal and natural gas, respectively.
That has caused Bruce Rew, the RTO’s senior vice president of operations, to reconsider his prediction of when wind energy would become the No. 1 fuel source.
“I used to say wind would be our No. 1 fuel in 2021, but wind should become our No. 1 fuel this year,” he said. “It seems to be happening quite a bit faster than we thought.”
SPP currently has 24 GW of installed wind capacity, a figure it expects to grow to 27 GW by the end of the year.
Rew said the RTO’s electricity demand had fallen as much as 8 to 10% below forecasts as the COVID-19 pandemic took hold. Load has since returned to normal, he said.
In her CEO’s report, Sugg said cancelling in-person meetings and stopping business travel in March is expected to result this year in the over-recovery of $12 million in system administrative fees. That could contribute to reductions in SPP’s 2021 net revenue requirement, she said.
Sugg assured stakeholders the RTO is committed to remaining affordable and will continue holding most of its meetings virtually next year.
“Cost containment is a big item for me,” she said.
Sugg spoke from an empty conference room at the company’s corporate center in Little Rock, Ark. “It’s much better wi-fi than at home,” she said.
The corporate center has been closed to most of SPP’s staff since March. Sugg said she is hopeful of allowing employees to voluntarily return after Labor Day but said the campus won’t be fully staffed until sometime next year, “hopefully earlier, rather than later.”
Complicating matters is that Arkansas has become one of the country’s COVID-19 hot spots. The state has recorded more than 43,000 cases and 458 deaths through Aug. 1, with cases still trending up.
“You can’t go anywhere else unless you quarantine first,” Sugg said. “It’s not something we’re proud of.”
SPP has had several positive cases but no hospitalizations. The operations staff remains unaffected, Sugg said.
“Our employees are able to work from home, and work effectively,” she said. “It’s a lot of strain on our company, but things are going really well.”
RSC Approves Tx Allocation White Paper
Meeting before the quarterly stakeholder update, the Regional State Committee narrowly endorsed the Cost Allocation Working Group’s (CAWG) white paper evaluating the RTO’s cost allocations for transmission projects between 100 and 300 kV that are primarily used to move power out of SPP’s local transmission pricing zones
The RSC signed off on the white paper 6-5, with commissioners from Arkansas, Louisiana, New Mexico, Oklahoma and Texas in opposition.
SPP refers to lower-voltage economic and reliability projects as byway projects, with 33% of the costs regionally funded based on member utilities’ load-ratio share and 67% funded by the facility’s transmission pricing zone. Projects above 300 kV are considered highway projects and regionally funded according to load-ratio share.
New and old wind technology | Oklahoma Municipal Power Authority
Following a year of work, the CAWG report recommends establishing a “narrow” cost-allocation review so that the revenue requirements for certain facilities with byway voltage levels can be fully distributed on a regionwide basis.
The group also recommended that the review process include new and existing Schedule 11 facilities and that the review criteria be based on the use or expected use of the transmission facility. Schedule 11 rates reflect the costs of facilities whose costs are shared in whole or in part on a regional postage stamp basis. The rest of the costs are allocated to the facility’s transmission pricing zone.
The CAWG’s recommendations would apply to facilities with notifications to construct issued after the 2010 implementation of SPP’s highway/byway methodology. The methodology includes an exception for base plan upgrades below 300 kV and associated with wind generation. In that instance, 67% of the upgrade costs are allocated to the region, and the remaining 33% are directly assigned to the transmission customer requesting service.
The white paper would allow affected entities to request a waiver from the allocation methodology. Directly assigned facilities would not be eligible. The CAWG used the Tariff’s language on dual-voltage transformer waivers, based on their usage, as a model for the byway cost-allocation waiver process, noting only four transformer waivers have been requested.
The CAWG said that in some zones with more generation than load, upgrades identified through SPP’s transmission-planning process “are being used regularly on a more regional basis.”
“In such cases, allocating 67% of the cost of an upgrade may not be roughly commensurate with the benefits received and thus it may be more appropriate that such lines be regionally cost allocated,” the group said in the white paper.
“I keep hearing it’s a surgical approach and that not very many people will apply, but that’s only an assumption,” said Oklahoma Commissioner Dana Murphy, asking for more time to build consensus.
DeAnn Walker, Texas PUC | SPP
Texas Public Utility Commission Chair DeAnn Walker said two of her state’s three largest utilities have concerns with the issue and questioned whether they had been heard during the stakeholder process.
“I don’t disagree … that there has been a lot of work on this and that it has high potential,” she said. “I know concerns have been voiced to me that people believe a lot of entities will end up applying for this. I would like to see language added to try and make sure the words ‘narrow process’ are truly that.”
Al Tamimi, vice president of transmission planning and policy for Sunflower Electric Power, has spent the last several years pushing to resolve the issue facing utilities in wind-rich areas, like his in western Kansas. He applauded the CAWG’s white paper, which includes a Sunflower presentation, and noted the importance of revising allocation ratios based on “the ratio of power exported to other zones versus local-zone usage.”
“It’s actually the right solution at this moment,” he said. “We have pricing zones sitting out there in generation-rich areas that export three to four times their load through byway facilities. We’ve been working for three years on this. We brought data and we brought facts to come up with this conclusion. This process helps sustain the highway/byway methodology as it is.”
Albrecht Honored for 6 Years of Service
Stakeholders gave former Kansas Commissioner Shari Feist Albrecht a virtual send-off after six years on the RSC. Albrecht, having served eight years, cycled off the Kansas Corporation Commission after her term ended in March.
“I’m humbled and honored by the recognition. My success can only be measured [by] and credited to the people I was surrounded by,” said Albrecht, who presided over the RSC in 2018. “I found myself to be a much better commissioner, a better-informed commissioner, as a result of my service on the RSC.”
“I agreed, reluctantly, to step into her shoes. I don’t think I’ll do as good a job as her, but I will try,” she said, borrowing a page from the legendary football coach and his equally legendary propensity for “poor-mouthing.” (“Bryant … elevated it to such an art that listeners would wink and smile at his dire pregame evaluations,” Sports Illustrated wrote in 1994.)
Albrecht’s RSC seat has been filled by Andrew French, who was appointed to the KCC in June. A commission staffer for five years, French has worked with the CAWG and RSC.
“He has SPP blood in his veins,” said SPP Board Chair Larry Altenbaumer.
Two Revision Requests Approved
In other business, the RSC endorsed a pair of revision requests and approved a clean audit of the committee’s 2019 budget.
RR373 includes base plan funding for transmission upgrades identified by SPP’s generator retirement process. The process includes screening criteria to filter out resources that do not require analysis before retirement. Resources that meet the criteria would be assessed by both planning and operations staff to identify potential system impacts.
The Transmission and Operating Reliability Working Groups agreed during the July Markets and Operations Policy Committee meeting to modify the measure’s language for a planned filing at SPP MOPC Briefs: July 15-16, 2020.)
Murphy addressed the use of reliability must-run policies that would keep a generator operating. She noted utilities tend to follow regulatory orders requiring a shutdown.
“Given a choice between breaking the law and breaking SPP’s rules, they’ll break SPP’s rules,” Murphy said.
RR404, previously approved by MOPC, defines the requirements for demand response programs and behind-the-meter generation to ensure their availability for meeting resource adequacy requirements and winter season obligations. The change addresses whether the resources are treated strictly as an offset of a load-responsible entity’s load or as a resource with capacity, specifying which resources can or cannot reduce load.
RSC President Dennis Grennan of the Nebraska Power Review Board said Arkansas’ Kim O’Guinn will chair a nominating committee that will bring the RSC’s 2021 officer candidates to the October meeting. Murphy and New Mexico’s Jeff Byrd will also participate on the committee.
FERC on Friday sent SPP back to the drawing board, saying its proposed Tariff for its Western Energy Imbalance Service (WEIS) market fails to respect transmission rights of non-participants and could improperly burden reliability coordinators. The commission also cited shortcomings on supply adequacy, market power protections and line-loss calculations (ER20-1059, ER20-1060).
“We recognize the potential benefits that the WEIS market could bring to utilities and customers in the Western Interconnection … and we appreciate the efforts by SPP and the market participants to develop regional solutions,” FERC said. “… Although we reject SPP’s proposed WEIS Tariff, we do so without prejudice and provide guidance on other aspects of SPP’s proposal that may require revisions to ensure SPP’s proposal is just and reasonable.”
SPP said it is reviewing the order and plans to “address [FERC’s] concerns” in a subsequent filing.
On Monday, SPP’s Market Monitoring Unit (MMU) posted a market power study on the WEIS market that concluded it presents “significant structural market power concerns” for energy and imbalance energy that should be addressed before the market’s implementation.
The MMU said market share, supplier concentration, residual supply index (RSI), and pivotal supplier analysis all indicate “high potential structural market power in the WEIS Market.”
Given its “substantial concerns,” the MMU recommends SPP and WEIS market participants consider developing a system-wide mitigation measure and using cost-based offers if the mitigation measures cannot be implemented before the market goes live.
SPP had hoped to launch WEIS in February. At launch, WEIS will include eight members and cover the Western Area Power Administration’s (WAPA) Colorado Missouri (WACM) and Upper Great Plains West (WAUW) balancing authority areas.
During the July 27 quarterly stakeholder update, Bruce Rew, SPP’s senior vice president of operations, said the RTO has received interest in WEIS from “a couple of other entities” who would sign on after the launch. Staff was preparing to begin market trials in August. (See “WEIS Market ‘At Risk,’ Waiting on FERC Approval,” SPP Briefs: Week of July 20, 2020.)
Use of Non-participants’ Transmission
Colorado utilities Xcel Energy-Colorado, Colorado Springs Utilities, Platte River Power Authority and Black Hills Energy, all of which plan to join CAISO’s Western Energy Imbalance Market, protested the WEIS filings. They contend that an existing and neighboring joint dispatch agreement could be impaired by the WEIS market dispatch and that its market flows may harm the Western Interconnection Unscheduled Flow Mitigation Plan. They also contend SPP’s proposal disregards the Northwest Power Pool’s activities and could island Xcel’s balancing authority area from the NWPP reserve sharing group.
The commission agreed with some of those concerns, saying SPP proposed using non-participating entities’ transmission in a manner that would violate Orders 890 and 890-A.
“Under the pro forma OATT, a transmission customer must reserve and pay for transmission service on a transmission provider’s system. Although SPP indicates its intent to use transmission that is reserved and contributed by participating entities, SPP also argues that it appears just and reasonable to allow all unused transmission capability within participating [balancing authority areas], whether reserved or otherwise unused on an intra-hour, as-available basis, to be made available to the WEIS Market’s least cost dispatch.”
SPP RTO, RC and WEIS footprints | SPP
FERC disagreed with arguments by SPP and WAPA that because the balancing authority is currently permitted to use any transmission in the WACM and the WAUW BAAs to serve imbalance, the WEIS market could also use all available, unused transmission in these BAAs.
“Although non-participating entities who take imbalance service from WAPA under existing contracts may currently have an expectation of WAPA’s use of their transmission to serve imbalances on their systems, SPP has not justified its proposal to alter WAPA’s current use of transmission to serve customers’ imbalance needs to a potentially more expansive use of transmission for the WEIS market,” FERC said. “As Xcel points out, this proposal would allow the WEIS market to use a far greater amount of a customer’s transmission capacity than the customer’s amount of imbalance in order to serve other customers.
“In fact, as Black Hills Service Co. asserts, it appears that under the proposal the WEIS market could use non-participating entities’ transmission capacity without compensation, even when those non-participating entities have no need for imbalance service in a particular hour, because the reorganized dispatch will likely involve wheeling of power across multiple transmission systems. SPP’s proposal therefore may limit the use of non-participating entities’ transmission capacity that is currently available for other purposes, such as the [Public Service Co. of Colorado joint dispatch agreement].”
The commission said any future proposal should ensure that the WEIS market respects the transmission capacity of non-participating entities with appropriate constraints in its security-constrained economic dispatch (SCED). “If SPP is not able to reach an arrangement with non-participating entities to use their transmission capacity, SPP must include constraints in its market model to appropriately respect the transmission rights of non-participating entities when calculating the market solution,” it said.
The commissioners noted that CAISO’s Western EIM offered a memorandum of understanding among the ISO, Bonneville Power Administration and PacifiCorp to ensure that EIM transfers would not adversely impact non-participants. “We encourage SPP to coordinate proactively with its neighbors to address these operational concerns prior to resubmitting any proposal,” FERC said.
Role of Reliability Coordinator
FERC also found SPP presumptuous in expecting that reliability coordinators and transmission operators will provide WEIS with data on the availability of transmission, saying the RTO had not proven its proposal will ensure accurate, real-time information about available transmission and congestion.
“While this obligation is not currently a concern because SPP is both the reliability coordinator and market operator for the entire WEIS footprint, SPP states that the WEIS market is flexible to operate across multiple reliability coordinator footprints. If the market expands to include participants that are not within the SPP West RC footprint, it could potentially impose an obligation on neighboring reliability coordinators to act as a conduit for market-related information in a way that is outside of the role for reliability coordinators envisioned by NERC,” the commission said.
It said SPP could propose a different arrangement to obtain information on transmission availability and other system conditions that do not rely on roles defined by NERC.
Other Issues
FERC also said it was unclear how SPP’s proposal would incentivize market participants to maintain supply adequacy.
“While the NERC reliability standards establish requirements for the reliable operation of the bulk electric system, it is not clear that reliance on these standards and after-the-fact reporting to the commission is sufficient to avoid market participants excessively leaning on the other market participants for energy supply,” it said. In the Western EIM, it noted, CAISO limits the imbalance imports of EIM entities that fail a resource sufficiency test.
SPP’s proposal to use the “average cost” method of accounting for line losses also was criticized by the commission, which cited prior rulings finding that under LMP, the use of marginal losses “better represents the optimal and efficient solution for settlements.”
It said SPP should consider including marginal losses in dispatch and LMP to “minimize imbalance costs, provide prices that accurately reflect marginal costs and preserve resources’ incentives to follow dispatch. The omission of marginal losses from dispatch prevents production costs from being minimized and could result in a less efficient market solution, especially in a geographically large market such as the WEIS market.”
Finally, FERC called for more assurances on market power mitigation.
“Other than an unsupported reference to the SPP [Market Monitoring Unit’s] analysis of six hubs, SPP has not provided any justification for its proposal to automatically increase the threshold below which energy offer curves are not subject to mitigation and the LMP impact threshold,” it said. “… SPP should either remove the automatic increase provisions or otherwise justify their inclusion.”
In its market power study Monday, the MMU said its RSI analysis revealed that if the WEIS market’s largest supplier was removed, generation can still meet demand about 50% of the time.
“This result can provide a basis for implementing mitigation measures for system-wide market power, similar to those implemented in other markets,” the MMU said, using as an example an ISO-NE mechanism that identifies system market power. “This approach … can act as a blueprint for the WEIS Market.”
“The mitigation measures in the proposed tariff and in the response to [FERC’s] deficiency letter will provide sufficient protections for participant conduct to exercise of market power with implementation of system wide mitigation measure(s) as recommended in this study,” the Monitor said.
The MMU said it relied primarily upon FERC precedent in assessing structural market power for approval of market-based rate authority applications in conducting its study. The MMU analysis defined relevant product market(s) and a relevant geographic market as two components of the market. It then assessed structural market power with the help of market concentration, market share, RSI and pivotal supplier analysis metrics within those defined product and geographic markets.
