FERC last week approved SPP’s revisions to its joint operating agreement with MISO that improve pseudo-tie coordination requirements between the RTOs, effective Monday (ER20-904).
The March 19 letter order accepted revisions addressing definitions, requirements, modeling, interchange schedules and general pseudo-tie coordination. SPP said the changes would improve transmission system efficiency along its seam with MISO by including obligations already in pseudo-tie agreements where MISO is the external balancing authority.
The changes include:
adding certain definitions set forth in the NERC glossary of terms used in reliability standards;
incorporating language requiring the native BA and the attaining BA to coordinate the pseudo-tie’s modeling in accordance with the rules of the native BA and attaining BA, respectively;
adding new subsections to the JOA that outline authorities for pseudo-ties from one RTO into the other; and
revising the requirements with language that includes the impacts of pseudo-ties in the attaining BA’s market flow impacts for the purposes of congestion management procedures. “Neither MISO, nor SPP, nor the entity seeking to pseudo-tie shall tag or request to tag the energy flows from a pseudo-tie into the attaining BA,” the language says.
SPP borrowed from the MISO-PJM JOA to define pseudo-ties as involving the real-time transfer of a generating resource’s or load’s control from the native BA where resource or load is physically located to an attaining BA that is responsible for operating the grid in a different geographic location.
MISO’s control room in Carmel, Ind., where the RTO manages pseudo-tie connections. | MISO
Its pseudo-tie agreement permits load and generating resources external to the SPP BA to be served by SPP. It also allows load and generating resources internal to SPP to function as part of an external BA.
ESR Data Added to Interconnection Procedures
FERC on Tuesday accepted SPP’s Tariff revisions to include specific information related to energy storage resources (ESRs) in the grid operator’s generator interconnection procedures (ER20-918).
With the commission’s approval, the generator interconnection forms will now ask whether or not ESRs will take energy from the system when operating in charging mode and the maximum rate of charge capability.
SPP filed the request on Jan. 31, shortly after stakeholders agreed to form a steering committee charged with determining how best to integrate energy storage. (See SPP Planning Approach to Battery Storage.)
CAISO’s Board of Governors on Wednesday approved $141.7 million in transmission spending and reliability-must-run contracts covering three power plants in Central California.
The 2019/20 transmission plan covers nine projects CAISO says are needed to maintain reliability according to NERC and ISO planning standards. Seven of the projects (totaling $120.7 million) will be located in Pacific Gas and Electric’s service territory, one ($16 million) in Southern California Edison and another ($5 million) in the Valley Electric Association/GridLiance West area straddling the California-Nevada border.
In his presentation to the board, CAISO Vice President of Infrastructure Development Neil Millar characterized the plan as a “modest” capital program and pointed out that all the projects are reliability-driven.
“We did not identify the need for any policy-driven projects or economic-driven projects in this cycle. The one qualifier was that the economic-driven analysis did identify the benefit of advancing a reliability project, but the driver remains the reliability requirement for that project,” Millar said, referring to the $16 million, 230-kV Pardee-Sylmar line-rating-increase project in SCE’s territory.
Millar said CAISO’s analysis of potential policy-driven projects relied on assumptions gleaned from the California Public Utilities Commission’s 2017/18 integrated resource planning cycle. The CPUC’s IRP reference system plan assumes that California’s electricity sector will cap its annual greenhouse gas emissions at 42 million metric tons by 2030 through a generation portfolio consisting of at least 60% renewables. It includes a “generic” base portfolio concentrated in various parts of the state needed to meet that target (see graphic).
“I’m not an engineer, but as a matter of common sense, can you explain how we can go from a 33% to 60% renewable system” without spending on new policy projects? Governor Ashutosh Bhagwat asked.
Millar responded that, in past years, utilities developed renewable portfolios under the expectation that the resources must be deliverable as resource adequacy under CPUC rules. But those portfolios have “started to shift” where some of the output can be energy-only, he said.
This shows the CPUC’s determination of a “generic” base portfolio of renewables needed for California’s electric sector to meet a target of 42 million metric tons of GHG emissions by 2030. | CAISO
“So with the upgrades that were already put in place, we saw that we had considerable capability to take advantage of filling out those areas where developments had already taken place, as well as capacity to meet energy-only requirements where resources would be providing energy and not necessarily resource adequacy capacity,” Millar said.
The scope of the past transmission buildout accounts for the lack of policy-driven needs today, he said.
But Millar pointed to one “qualifier.”
“When you move to these higher [renewable] goals, we’re also seeing a steady escalation in the amount of transmission-related curtailments that’s showing up in the model, and unless there’s a policy requirement to address that curtailment, that would transition over to being an economic requirement,” he said. “Those could drive considerable transmission to address economic-driven transmission needs.”
The board additionally approved CAISO management’s recommendation to put three previously approved projects on hold for further review. The projects are all located in PG&E’s territory and include the North of Mesa upgrades, the 115-kV Morage-Sobrante line reconductoring and the Wheeler Ridge Junction substation project.
Not a Trend — Yet
The board also approved the designation of three Central California power plants as RMR resources for the summer peak season. The approvals are conditional because they will be revoked for any resource that obtains a resource adequacy contract by that time. The facilities include:
Starwood Energy Group’s Greenleaf II Cogen, which is required to help meet the 734-MW local capacity requirement (LCR) for the Drum-Rio Oso subarea within the Sierra local area. The 49.5-MW unit is not currently active in the CAISO market following termination of its Public Utility Regulatory Policies Act contract and is going through a qualifying facilities conversion process to become an ISO participating generator. The 230/115-kV Rio Oso transformer replacement project, which will mitigate the subarea’s reliability need, is not scheduled to be in service until June 2022.
California State University Channel Islands’ Channel Islands Power, which is required to help meet the 288-MW LCR requirement in the Santa Clara subarea of the Big Creek/Ventura local area. The 27.5-MW unit is currently under a resource adequacy contract set to expire on March 30. While 195 MW of new energy storage resources have been procured to meet the expected LCR shortfall in the subarea, they won’t become available until June 2021.
Atlantic Power’s E.F. Oxnard, which is also needed for the Santa Clara subarea. The 48.5-MW plant is currently under a resource adequacy contract that expires May 24. The unit will need to convert from a QF participant arrangement to a conventional market participant arrangement.
Governor Severin Borenstein noted that last year saw just one CAISO unit secure an RMR designation for the summer.
“Are we seeing an increase, or should I not think this is a trend?” Borenstein asked.
“From a local capacity perspective, we wouldn’t expect to see this being indicative of a trend,” Millar said. “Two of these units are qualifying facilities as opposed to being conventional market participants, and there’s a relatively small number of those. The other issue we’re dealing with is that we do have reinforcement projects under way generally to backfill for a number of these items, so there are individual cases that we’re going to have to deal with from a local perspective. So we don’t see this as a trend — at least yet.”
CAISO CEO Steve Berberich interjected: “I think the operative word being used is ‘yet.’ With the fragmentation of the load-serving entities in California, we expect that this could very well be the case. I agree with Neil that this doesn’t necessarily indicate a trend, but we’re going to continue to be vigilant about this issue.”
NYISO has sequestered approximately two-thirds of its operations staff on site at its two control centers to prevent possible infection by the COVID-19 coronavirus from interfering with reliable grid operations, CEO Rich Dewey told the Management Committee on Wednesday.
“First and foremost, from a reliability standpoint, we do not feel at this juncture that we have any reliability concerns specific to the pandemic or the readiness of any market participants, whether generators or utilities, to comply with what we need to do,” Dewey said.
The regular staff are working almost 100% from home, and there have been no reports of infection, he said.
“We have moved two full operational crews on site, provided trailers for sleeping [and] separate food facilities, and have walled off access to any of the individuals participating in that program,” Dewey said. “We’ve got a rotation that will help us maintain grid operations for the foreseeable future.”
The ISO also has been in regular contact with generators and transmission owners, and some of them are also beginning to implement on-site sequestration for staff, he said.
“Similarly, we’ve also been in touch with all the other RTOs and ISOs around the country … and everyone is thinking along the same lines,” Dewey said.
“We’ve also initiated, at the request of the [New York] Public Service Commission, some outreach to the generation community to try to get an understanding — for each of the generation plants — what level of readiness or preparedness exists, and to get a sense if we’re going to have any concerns with respect to their ability to perform.”
2019/20 Winter 5th Mildest in 200 Years
Vice President of Operations Wes Yeomans delivered the Winter 2019/20 Cold Weather Operations report, which showed a seasonal peak load of 23,253 MW on Dec. 19, compared with a seasonal 50/50 forecast of 24,123 MW. NYISO’s all-time winter peak load was 25,738 MW on Jan. 7, 2014.
NYISO 2019/20 winter daily peak loads in perspective | NYISO
Yeomans said there were no “critical issues” to report to stakeholders after a season without “critical operating conditions.”
“It feels strange to give a winter report when the winter was so mild,” he said. “Just how mild was this? Relative to the top 10 mildest winters … dating all the way back to 1820, this one tied with 1906 as the fifth-warmest January in the last 200 years.”
Transmission performance was also excellent, he said.
Yeomans also delivered the monthly operations report, highlighting the mild weather in February that saw natural gas and distillate prices lower compared to the previous month, and natural gas prices down 32.2% year-over-year.
ESR Tariff Revisions Approved
The MC also approved Tariff modifications related to energy storage resource (ESR) participation, as recommended by the Business Issues Committee earlier this month. (See NYISO BIC Briefs: March 19, 2020.)
Energy Market Design Manager Zachary Stines presented the background material for the discussion and vote on proposed Tariff language, which spells out details regarding day-ahead margin assurance payments; the method for setting feasible day-ahead and real-time schedules; generator offer caps, mitigation and reference levels; and installed capacity supplier bidding requirements.
If approved by the Board of Directors in April, the ISO will file the changes with FERC and anticipates making them effective simultaneously with the rest of its ESR participation model.
CIO Doug Chapman said the ISO wants to activate the new software in June and would delay the rollout until September if unable to do so to avoid implementing new software in summer conditions, because it represents a significant change to the system.
“If the summer was mild enough, our operations teams might elect to go ahead, but our default decision would be to avoid the summer and its tight operating conditions,” Chapman said.
Committee Chair Jane Quin, vice president of energy policy and regulatory affairs for Consolidated Edison, announced that the MC will hold a special meeting April 15 to act on buyer-side mitigation rules.
CAISO is focused on keeping its control room running and isolating key employees from those who might be carrying the COVID-19 coronavirus, CEO Steve Berberich told the ISO’s Board of Governors Wednesday.
Some employees are working off site, Berberich said. Others have shifted to CAISO’s secondary control room at a 35,000-square-foot backup facility in Lincoln, Calif., about 20 miles north of the ISO’s Folsom headquarters near Sacramento.
“We’re doing our best to particularly make sure we protect our control room personnel and leveraging our backup site to make sure we have separation between them,” Berberich said. “Our focus though right now is to make sure we protect our staff but also ensure our primary missions of running the reliable grid and credible markets remains intact.”
Like other regions, CAISO has seen shifts in demand as a result of the coronavirus threat. The ISO has experienced a 3 to 5% load reduction, with Californians under a statewide stay-at-home order, he said. Mild weather and other factors may be disguising more pronounced effects on the state’s demand curve, he noted.
“We’re tracking that,” Berberich said. “I know [Vice President of Market Quality and California Regulatory Affairs] Mark Rothleder’s group is focused on making sure we take that into consideration as we make our forecasts.”
CAISO’s control room in Folsom, Calif. | CAISO
CAISO has had a pandemic plan in place since 2015 as part of its business continuity plan and has put it into effect, the CEO said.
The ISO is continuing with business as usual in other ways too, he said.
CAISO is continuing to perform its role as reliability coordinator for much of the West and running the Western Energy Imbalance Market, so far without significant disruption, he said.
However, Berberich acknowledged that some of RC West’s “advanced tools continue to be challenged.” CAISO’s advanced computer applications run contingency analyses based on a system model that is changing, he said.
“We’re working through some of the issues getting that system model completely correct,” he said.
“We do expect to move forward on all our policy initiatives,” Berberich said. “The stakeholder processes will continue to go forward on a telephonic basis. We’ll continue to manage the interconnection queue, transmission planning and all the other efforts we have to support California, but also the region and its decarbonization goals.”
He said developers have asked not to postpone projects, so CAISO won’t meddle with interconnection timelines.
“We are mindful that there are a lot of strains out there on the system — local regulatory authorities, the permitting agencies, financing and all those things,” Berberich said. “We are in a position where we will do what’s right to try to make sure that people can move through the queue, [that] they can successfully bring in projects and they can add to California’s goals of decarbonizing the grid.
“To the extent that we need to work with FERC and the stakeholders to find ways through that, we will. We have explored changing the queue dates and the schedules. After consulting with the industry, we got resounding feedback that they would like to keep those dates and requirements as is, so that will be our plan.”
Berberich plans to retire this summer, and a nationwide search has commenced for his successor.
Board Chair David Olsen took time at the start of Wednesday’s meeting to tell stakeholders that the ISO’s policy goals, including the expansion of the Western Energy Imbalance Market across the West and to a day-ahead market, won’t change during the CEO transition.
“That will not change any of our current commitments and forward-looking policies,” Olsen said. “The board wanted to communicate that unambiguously.”
MISO’s weekday loads are looking more like weekends as social distancing measures to lessen COVID-19 cases take hold in more states in the footprint.
“We are starting to notice a few impacts,” Vice President of System Planning Jennifer Curran reported during the Markets Committee of the Board of Directors’ Tuesday meeting, conducted via WebEx and teleconference. (See Virus Fear Sends MISO Board Week to the Web.)
Director Tripp Doggett asked if MISO is experiencing more load shapes on par with weekend usage as more people stay home across the footprint.
“In general, it’s going in that direction; the peaks aren’t as prominent,” Executive Director of Market Operations Shawn McFarlane said.
For instance, McFarlane said, morning peaks are flattened absent the usual flurry of activity to get schoolchildren and workers out the door. In its place is a more dispersed demand over the morning hours, he said.
McFarlane said MISO hasn’t yet quantified how much load has declined across the footprint.
“Things have been evolving. Last week, it was only schools closed. Now we have shutdowns in the industrial sector. It’s very fluid at this time. It’s certainly greater than 5% — now it could be even 10%” year-over-year, he said.
Complicating matters, MISO’s load forecasting relies on historical information. “During this unprecedented time, we don’t have historical data,” Curran explained.
MISO Director Theresa Wise called the forecast challenges “completely understandable.”
Independent Market Monitor David Patton said MISO load in the first three weeks of March was about 8% lower than it was a year ago, reflecting the closure of schools and business. “We’ve noticed a significant impact,” he said.
“We expect that load effect to increase, and we’re talking to MISO about the impact. … We do think the learning of their models will improve the forecast,” Patton said, adding that in the meantime, RTO staff have manually adjusted short-term load forecasts.
MISO Director Baljit Dail asked if generators were scheduling maintenance outages to take advantage of the dip in demand as the economy slows.
“Actually, we’re seeing the opposite. We’re starting to see deferrals of planned outages,” Curran said. She said the root cause is likely that utilities are making do with fewer personnel.
Directors asked if MISO anticipates other impacts related to the pandemic.
A gentler MISO load curve at 5 p.m. ET March 25 | MISO
“It’s early days yet, so we’ll be in constant communication with our members,” Curran said.
The RTO has convened incident response teams focusing on COVID-19 that meet daily and have escalation plans at the ready to protect grid operations, if necessary, Curran said.
“MISO’s top priority is to ensure the safety of its staff and stakeholders and reliability of the bulk electric system,” she said.
Although most MISO employees are working from home, Curran noted that the RTO has operations in four sites in three states: the headquarters and Central Region Operations Center in Carmel, Ind.; the North Region Operations Center in Eagan, Minn.; and the South Region Operations Center in Little Rock, Ark. “So, we have a built-in social distancing,” she said.
Curran said MISO is also working with law enforcement to make sure the RTO’s control room operators can get to and from work as more states order their residents to shelter in place. She also said control rooms are being disinfected more frequently, and MISO has limited access to control rooms to essential personnel only. MISO facilities continue to be closed to visitors through May 1.
“This situation seems to change daily so keep in mind these actions can change or be extended,” Curran said.
Patton also reported Potomac Economics staff are all working remotely.
“We’ve seen no real problems in the functioning of the IMM or the software. Our software is run from a third-party data center, so we didn’t anticipate any impacts there,” Patton said.
The Texas Public Utility Commission has won extra time to respond to NextEra Energy’s efforts to void a Texas law giving incumbent transmission companies the right of first refusal to build new transmission lines.
The 5th U.S. Circuit Court of Appeals in New Orleans on Friday granted the PUC’s request for a 14-day extension to file response briefs, giving the commission until April 22. NextEra will have seven days to file a reply brief (20-50160).
| ERCOT
NextEra Energy Capital Holdings and four other NextEra transmission owner/developer entities appealed to the 5th Circuit after the U.S. District Court for the Western District of Texas in February refused their motion to overturn Texas Senate Bill 1938. (See District Court Dismisses Texas ROFR Repeal.)
On March 13, the district court also rejected NextEra’s request for an injunction delaying the court’s decision, saying NextEra is unlikely to prevail on appeal (1:19-cv-00626).
The Texas law grants certificates of convenience and necessity to the owners of a new transmission line’s endpoints, essentially allowing only incumbent transmission companies to build new power lines in the state.
District Judge Lee Yeakel | American Inns of Court
“The court concludes that plaintiffs have failed to make a sufficient showing to warrant an injunction pending appeal,” District Judge Lee Yeakel wrote.
The judge said an injunction would substantially harm the PUCT, the defendants in NextEra’s lawsuit, because it would be unable to “plan and facilitate” new transmission projects.
At issue is NextEra Energy Transmission (NEET) Midwest’s ability to build the $115 million Hartburg-Sabine Junction transmission project in MISO’s East Texas footprint. NEET Midwest won the project’s rights in 2018 through a competitive bidding process. (See NextEra Wins Bid to Build MISO’s 2nd Competitive Project.)
NextEra has said it expects MISO to make a decision reassigning or canceling the project by March 31.
Southwestern Public Service and East Texas Electric Cooperative have both appealed to the 5th Circuit to have their rejected intervention requests overturned. The district court denied both requests when it rejected NextEra’s motion in February.
PJM stakeholders seeking to improve the transparency of transmission owners’ spending on end-of-life (EOL) projects urged the RTO Tuesday to swiftly conclude work on proposals that can be brought to a vote.
Over four special Markets and Reliability Committee meetings on transparency and end-of-life planning, American Municipal Power, Old Dominion Electric Cooperative and LS Power have proposed rule changes that would require TOs to share how they make EOL determinations, create a new category for EOLs within the Regional Transmission Expansion Plan (RTEP) and open them to competition.
“I just wanted to note I’ve only heard a solution from AMP, ODEC and LS Power. I’m aware that PJM is working on a solution. But … I’m not seeing a whole hell of a lot of engagement from others,” said Ed Tatum, AMP’s vice president for transmission, during Tuesday’s meeting, held via WebEx because of the coronavirus pandemic. “I appreciate that we’re in times that no one has ever lived through before. [But] there’s not a whole lot of new stuff coming here … . We are to a point in this process that we are very close to being able to finish it up.”
Proposals
The proposals would require TOs to have a transparent process for making EOL determinations based on industry averages, manufacturers’ recommendations and “good utility practice.” Once a TO has made a determination that a facility had reached the end of its life, that information would become part of the RTEP baseline planning process.
Currently, EOL projects developed under Tariff Attachment M-3 are designed based on assumptions and needs presented in local transmission planning meetings. For TOs that include EOL projects in FERC Form 715 planning criteria, the needs are presented in Transmission Expansion Advisory Committee and Subregional RTEP meetings.
The proposals would require all TOs to have a minimum 10-year look-ahead EOL program and to present their program’s criteria and guidelines to stakeholders at least annually.
Utility transmission investments by NERC region (1996-2016) | EIA
TOs would have to present the methodology of their programs “in sufficient detail that stakeholders … can understand and, to the extent feasible, replicate the results for individual facilities determined to be EOL.”
Mark Ringhausen, vice president of engineering for ODEC, said this would apply to “bright line criteria” such as triggering new infrastructure based on the volume of outages. “I don’t think there’s going to be a lot of these, but we haven’t seen the TO criteria behind the scenes that are used for end-of-life determinations,” Ringhausen said.
EOL needs solutions developed by PJM would be subject to competitive bidding and would not be considered supplemental projects assigned to the incumbent TO.
PJM would conduct planning for all TO EOL replacements and retirements to ensure they don’t compromise reliability or create new critical facilities under FERC reliability standard CIP-014.
Timing Differences
The AMP/ODEC proposal would require TOs to notify PJM and stakeholders of any EOL conditions at least six years before the EOL date so that the project could be included in five-year planning models and opened to competitive bidding. The LS Power package would require six years’ notice for lower voltage facilities and at least eight years’ notice for facilities 230 kV and above.
Ringhausen said he believed the AMP-ODEC proposal complied with FERC precedent and existing rules and agreements.
But Exelon’s Robert Taylor said “we don’t share the same view that there’s no legal or contractual problems with” the proposal. “We want to see what PJM will say,” he added.
“These exact issues have recently been ruled on by FERC in the M-3 order, and some stakeholders want to go back to FERC and take it further,” Taylor said later via email. “We supported the changes in M-3 and are engaged in conversations to further improve transparency and address stakeholder needs, but to say we have been working on this for three years and done nothing is not accurate.” (See FERC Upholds PJM TOs’ Supplemental Project Rules.)
PJM Vice President of Planning Ken Seiler said RTO staff were “really looking hard at the three issues our board has asked us to work with the stakeholders on: … transparency, authority, as well as competition.”
And the authority to make the EOL determination, Seiler said, is with the TOs. “We’ve been very consistent about that message from day one: We are not in a position to make EOL decisions on transmission assets.”
He said any package backed by PJM must be consistent with FERC precedent and “be supported from a process and staffing viewpoint.”
He noted the new rules could have impacts on the planning process, the interconnection queue and cost allocation. “Does the load pay or does the generation interconnection customer pay?” he asked. “We have to be very careful and very surgical.”
In a letter to members Oct. 4, Dean Oskvig, chair of the Board’s Reliability Committee, pledged the RTO would continue efforts to improve transparency.
“PJM does not have the authority or expertise to assume responsibility for asset management decisions or to determine when a facility is at the end of its useful life or otherwise needs to be replaced. Those decisions are the sole responsibility of the Transmission Owner,” Oskvig said. He added, however, that in developing the RTEP, “in some circumstances, PJM may be in the best position to determine the more cost-effective regional solution to replace a retired facility.”
No Rush?
Exelon’s Taylor also pushed back on Tatum’s urgency.
“It is not the time to rush. Let’s get this right,” he said. “There [are] so many interlocking pieces.”
“We’re still anxiously waiting to hear from your organization as to what [Exelon’s proposal] would look like,” responded Tatum. “And so far, we’ve heard nothing. Part of the stakeholder process is to engage and to try to be part of a consensus solution.”
Investment in transmission infrastructure by major utilities (1996-2016) | EIA
Taylor said the pandemic was occupying the minds of “a lot of folks who make these decisions for us.”
The project’s work plan is to target a vote on proposed packages at the May 28 MRC meeting, following a first read on April 30.
The MRC is scheduled to return to the issue in a special meeting April 17, but PJM staff said it may seek an earlier meeting date.
FERC on March 20 rejected Pacific Gas & Electric’s request to rehear a case in which the commission ruled that interconnection customers could be harmed by changes occurring outside of their boundaries (EL15-55–003).
The case began in 2015 when the Modesto Irrigation District and the Turlock Irrigation District claimed PG&E had denied the districts’ rights under interconnection agreements to the PG&E-owned section of the California-Oregon Transmission Project, a 340-mile, 500-KV line that runs from southern Oregon to Central California.
The districts, which supply power to large areas of California’s Central Valley, are members of the Transmission Agency of Northern California and hold shares in TANC’s entitlement to capacity on the project. They use those entitlements to transfer energy from the Pacific Northwest.
The districts’ interconnection agreements with PG&E provide that either party can request a joint study of any proposed “modification, new facility addition, or long-term change to operations that may reasonably be expected to result in an adverse impact.”
“If an adverse impact is identified through either study process [the interconnection agreements impose] the obligation on the primary party to avoid, fully mitigate or compensate the coordinating party for all costs incurred due to the adverse impact,” FERC said.
The Modesto Irrigation District (MID) supplies water and power to a section of California’s agricultural Central Valley. | MID
The California Department of Water Resources (DWR), which owns generation and pumping resources connected to the transmission project, had been part of a remedial action scheme to maintain reliable operations during disruptions. When DWR dropped out in March 2015, PG&E “reprogrammed” the scheme but didn’t notify the irrigation districts and then refused to conduct a study of the potential impacts.
The districts sought FERC intervention. The commission initially denied the districts’ complaint, finding that the relevant terms of the interconnection agreements did not apply to resources beyond their immediate control.
“The districts do not own or control any portion of the California-Oregon Transmission Project [and it cannot] be considered part of the districts’ systems as defined in the interconnection agreements,” FERC wrote.
The districts appealed to the 9th U.S. Circuit Court of Appeals, which decided in September 2018 that FERC had read the agreements too narrowly in “concluding that an adverse impact must be a direct, physical effect on a line or component inside the districts’ systems and did not include a physical effect on a line or component outside the districts’ systems that makes it more difficult for the districts to transfer power into their systems.”
On remand, FERC ruled in favor of the districts and ordered PG&E to conduct a study of potential adverse impacts.
PG&E sought a rehearing, claiming that it had not breached its interconnection agreements and that no adverse impact had occurred. It said the 9th Circuit and the commission misread the interconnection agreements.
FERC rejected all of PG&E’s arguments.
“Although PG&E asserts that the commission ignored the plain meaning of the interconnection agreements, PG&E essentially focuses on whether PG&E, in its own estimation, believed that it was not making a long-term change to operations on its system that may reasonably result in an adverse impact to the districts’ systems.
“However, the commission in the remand order found that PG&E breached the interconnection agreements by failing to undertake a study … which considers the perspective of the coordinating party, here, the districts.”
“Equally unavailing,” FERC said, “is PG&E’s assertion that the term ‘adverse impact’ under the interconnection agreements was not intended to cover changes occurring outside the districts’ systems. As an initial matter, the Ninth Circuit already ruled that adverse impacts should not be so narrowly construed. From a technical perspective, the districts’ ability to transfer power into their systems may be affected by changes occurring outside of their boundaries, and this specific scenario could result from PG&E’s re-programming of its remedial action scheme … PG&E must participate in a study to assess the potential adverse impacts to the districts’ systems.”
FERC on Thursday approved a new MISO Tariff provision that allows transmission owners to recover interconnection facility operations and maintenance costs from interconnection customers.
The decision allows MISO to include a new rate schedule — Schedule 50 — to allow TOs to recoup costs from interconnection customers for “reasonable expenses, including overheads, associated with operation and maintenance, and repair” of TO-owned interconnection facilities (ER20-170).
MISO TOs filed in October for the new rate schedule.
“While relevant provisions of a MISO generator interconnection agreement … already explicitly provide that interconnection customers ‘shall be responsible’ for all reasonable [operations and maintenance] expenses, there is presently no mechanism in the Tariff to enable the calculation and recovery of such expenses from interconnection customers,” the TOs explained to FERC.
MISO joined the filing as administrator of its Tariff but took no stance on the proposed revisions.
The TOs plan to allocate O&M annual charges based on a calculation involving the interconnection facilities’ installed costs as a share of a total annual transmission gross plant. When installed costs aren’t available for calculation, TOs will have to submit filings so FERC can review the alternate calculations.
In accepting the new schedule, FERC disagreed with renewable energy proponents that the Schedule 50 approach would “unduly” shift costs to interconnection customers. Some had argued that a process including transmission facilities didn’t translate well for interconnection facilities because they’re newer and less prone to maintenance charges. But the commission said the average useful life or O&M costs of an interconnection facility aren’t much different than the average useful life or O&M costs “of other similar transmission facilities.”
Other clean energy advocates said O&M costs should be assigned directly to interconnection customers instead of using a calculation. FERC again disagreed.
” … [E]ven in the instances where transmission owners utilize direct billing, not all costs are able to be directly assigned, some are assigned based on various allocators, and some costs are not even recovered,” the commission explained.
FERC on Thursday accepted changes to the New England Transmission Owners’ (NETOs) interconnection study deadlines and the scope of their feasibility studies (ER19-1952).
However, the commission only partially accepted a separate Order 845/845-A compliance filing by ISO-NE and NETOs to reflect the orders’ changes to the commission’s pro forma large generator interconnection agreement (LGIA) and large generator interconnection procedures (LGIP), ordering a further compliance filing within 120 days (ER19-1951).
Renewable developers EDF Renewables, E.ON Climate & Renewables N.A. and Enel Green Power N.A. had argued that the revised deadlines — extending the feasibility study from 45 to 90 days and the system impact study (SIS) from 90 to 270 days — are unreasonably ambitious. They noted ISO-NE’s severe backlog, with feasibility studies averaging 229 days and SIS averaging 443 days.
But the commission said it expects “that the average study lengths will drop due to the reduced scope of the feasibility study and due to the other interconnection process improvements,” citing expanded use of consultants and a streamlined approach for managing SIS models and data.
EDF Renewables’ Williston solar project in Vermont became operational in 2016. | EDF Renewables
Under the previous rules, many interconnection customers that chose the separate feasibility study later modified their projects before the SIS, reducing the time savings from conducting the feasibility study first. The new rules eliminate the option to integrate the feasibility study within the SIS and allow customers to forgo the feasibility study. Feasibility studies will be reduced to a limited power flow analysis, instead of the full power flow analysis allowed previously.
Regarding the LGIP filing, the commission found that it proposed, “without justification, language that differs in one respect from the commission’s requirements related to the process for analyzing surplus interconnection service requests.”
The filing parties explained in their transmittal letter (but did not specify in proposed Tariff revisions) that ISO-NE would limit the analysis it performs to its existing 10-business-day material modification framework for accommodating technological changes. The commission said it “may be inadequate to complete the evaluation required under Order No. 845.”
The commission required a further compliance filing to address the stand-alone network upgrades definition; interconnection customers’ ability to exercise the option to build; NETOs’ proposal to recover actual costs rather than a negotiated amount for oversight costs related to the option to build; the method for determining contingent facilities; requests for interconnection service below generating facility capacity; provisional interconnection service; and both the process and definition for surplus interconnection service.
FERC Partially Accepts Emera Maine Filing
FERC on Thursday also accepted amendments to Emera Maine’s LGIA and LGIP but ordered a further compliance filing within 120 days (ER19-1887).
The commission found that the revised dispute resolution procedures in the company’s LGIP comply with Orders 845/845-A and that the variations are “consistent with or superior” to them. “However, the deadlines in Emera Maine’s proposed dispute resolution timeline contain an apparent incongruity,” the commission said, ordering a further compliance filing to address a five-day discrepancy in stated terms.
The commission found that the LGIP’s method for determining contingent facilities is in partial compliance but that proposed criteria for identifying contingent facilities “lack the requisite transparency.” It ordered the company to describe the specific technical screens, analyses, triggering thresholds or criteria it will use to identify such facilities.
The commission also ordered further compliance filings to incorporate pro forma revisions to section 3.1 of its LGIP; to revise section 4.4.6 to clarify how it will assess changes to a generating facility’s technical specifications; to clarify the deposit amount the interconnection customer is required to tender; and to specify that Emera Maine will complete its assessment and determination of whether a proposed technological change is a material modification within 30 days of an interconnection customer submitting a technological change request.
