MISO tossed a curveball at stakeholders Tuesday when it said it will now consider two types of solutions to mitigate its Midwest-South transmission constraint before the original term of the settlement agreement facilitating transfers draws to a close.
The 2016 agreement with seven joint parties — including SPP — limits transfers between MISO Midwest and South to 3,000 MW southbound and 2,500 MW northbound. The deal is set to expire next year, leaving MISO and its members to confront escalating costs under a new arrangement.
Speaking during a conference call Tuesday, economic studies engineer David Severson revealed more details about the original solution, saying that MISO is focusing on three proposed projects to alleviate the constraint.
But Severson also posed a new option: MISO could avoid building new transmission by instead exploring ways to purchase firm capacity to supplant the settlement agreement. The revelation caused consternation among some members on the call.
Joint parties to the settlement agreement | MISO
Three Projects…
Severson explained that each of three proposed projects under consideration would create a new 345-kV line terminating at the Jim Hill substation in southeastern Missouri. Costs for the proposals range from $152 million to $262 million, with cost-benefit ratios from 2.04:1 to 1.1:1. Two of the projects would increase the existing 1,000-MW contract path by 2,574 MW, while the most expensive proposal would increase it by 2,302 MW.
MISO requires projects to demonstrate at least a 1:1 benefit-to-cost ratio over 20 years to be considered under its Market Congestion Planning Study. It used an economic model from its 2019 Transmission Expansion Plan (MTEP 19) to estimate benefits for the proposals.
“Going forward, we plan on doing some refinement, getting stakeholder feedback and doing some external outreach,” Severson said of the project ideas.
MISO had been focusing on nine possible projects after receiving 35 proposals last summer to alleviate traffic on the constraint or even eliminate the need for the settlement agreement altogether.
RTO staff extended its analysis of the projects beyond the MTEP 19 approval deadline in December. (See MISO Studying Projects to Cut North-South Tx Reliance.) That work will be completed in the first half of this year, MISO executives have said.
During Tuesday’s call, MISO staff said the three projects will now enter a more rigorous testing that includes alternative components. WPPI Energy’s Steve Leovy said MISO should examine combining elements of the three different projects.
Some MISO stakeholders warned that approval of just one of the projects might not be a panacea for all subregional transfer constraints. They called for more analysis on the nearby system.
Veriquest Energy’s David Harlan asked MISO to take a closer look at how the projects could alter flow patterns on nearby lines or tax existing substations, impacting either SPP or the joint parties to the settlement agreement.
“I would hate to see us lose all of our settlement payments … only to hit a constraint with SPP,” WEC Energy Group’s Chris Plante added.
The agreement requires MISO to make monthly payments for usage based on a capacity factor. At a 20% or less capacity factor, MISO pays $1.33 million per month, while a 20 to 70% capacity factor sends the price to $2.25 million per month. A factor higher than 70% results in a $3.17 million monthly payment.
Those payments are set to escalate annually beginning next month — by an additional 2% for up to a 70% capacity factor and 4% for capacity factors above 70%.
The agreement’s initial term ends on Jan. 31, 2021, when it automatically converts into yearly extensions which can be terminated with a 12-month written notice by any of the settlement’s seven joint parties, which include MISO, SPP, Tennessee Valley Authority, Southern Co., LG&E and KU Energy, Power South Energy Cooperative and Associated Electric Cooperative Inc. If that happens, the parties enter a four-month renegotiation period. If no agreement can be reached, MISO’s rights on the transmission systems of the other parties are terminated, leaving it once again subject to paying SPP unreserved transmission-use penalties for flows above MISO’s 1,000-MW contract path capacity.
Senior Adviser Jack Dannis said MISO is currently discussing next steps of the settlement agreement with the other parties.
…or Buy Firm Service?
Dannis emphasized that MISO has three options for increasing its contract path post-settlement agreement: building new transmission, adding a new transmission-owning member that connects the regions, or obtaining firm transmission service from another company connected to both regions.
“We’re in frequent communication with SPP and the joint parties,” Dannis said. The parties are currently “performing transmission planning analyses to identify cost-effective solutions for providing MISO firm transmission rights,” he said. Those solutions may involve upgrades to SPP or neighboring systems in order to offer MISO new firm rights.
Dannis said for every 1 MW of increased capacity on the contract path, MISO’s payment is reduced by $667/MW-month.
That MISO is considering purchasing firm transmission rights from its neighbors came as a surprise to some stakeholders.
LS Power’s Pat Hayes said MISO last year only asked that transmission developers propose solutions that could increase capacity on the transfer limit — and didn’t let on that firm service purchases were also an option under consideration.
“This is a pretty big transparency issue, and we should be able to participate, and we’re not right now,” Hayes said. “I know that there are other parties in the room that feel this way.”
Hayes said it also isn’t clear whether MISO stakeholders would have another opportunity to propose projects that would increase transfer capacity between the regions through a coordinated system plan between MISO and SPP. The RTOs will decide this spring whether to embark on a study that could result in an interregional project. MISO officials said it was too early to speculate on what type of projects would be examined under such a study.
SPP continues to add fresh blood to its leadership ranks, announcing on Thursday that two new officers will join its senior leadership team from within the RTO’s ranks.
Sam Ellis | SPP
The grid operator said its Board of Directors had elected Sam Ellis as chief information security officer and vice president of information technology, and Antoine Lucas to serve as the organization’s vice president of engineering, effective Feb. 1. The two were recommended by CEO-elect Barbara Sugg and COO Lanny Nickell, SPP said, filling the positions left vacant by their earlier promotions. (See SPP Names Nickell COO, Adds Board Member.)
“Some of SPP’s greatest opportunities for advancement will depend on our ability to build and manage relationships with our stakeholders and to innovate,” Sugg said in a statement. “Both Sam and Antoine are exactly the kind of people we need leading us into the future.”
Ellis, the organization’s director of cybersecurity and controls, will assume oversight of the IT department from Sugg. He will be responsible for technology development and deployment, monitoring, support and cybersecurity for SPP and its members, and for establishing IT strategy and policies. Ellis joined the RTO in 2003 from Empire District Electric and has 26 years of industry experience in transmission and generation operations and electricity and natural gas trading.
Lucas, formerly director of transmission planning, replaces Nickell and will oversee the transmission expansion plan’s ongoing development, tracking expansion projects, administering generator interconnection processes, engineering studies and supporting SPP’s real-time operations functions. He joined the organization in 2007 after five years with Entergy Services as an engineer and system operator.
Both Ellis and Lucas have played prominent roles recently in front of stakeholders. Ellis was program director of the day-ahead market’s successful implementation in 2014, while Lucas has served as the point person for SPP’s Integrated Transmission Planning process.
MISO’s first storage-as-transmission proposal has drawn several protests from stakeholders who say the plan gives transmission owners an unfair advantage in developing the resources.
Multiple entities said the ruleset, filed with FERC on Dec. 12, is geared to providing incumbent TOs an effective monopoly on storage assets functioning as transmission, harming competition. Several urged FERC to reject the filing (ER20-588).
The proposal limits storage-as-transmission assets to transmission-only functions operated by TOs. As such, MISO labeled these resources storage-as-transmission-only assets (SATOA), and they would be barred from simultaneous participation in its energy markets — for now. (See Despite Pushback, MISO Pursuing TO-only SATA.) The RTO has said its 802-page plan will avoid introducing complexities around cost recovery, particularly related to how non-TOs would be compensated for providing transmission services.
MISO’s 2019 Transmission Expansion Plan (MTEP 19) includes just one SATOA project proposed for Wisconsin, but the RTO doesn’t have a cost-recovery mechanism for such assets. (See MTEP 19 Could Yield First MISO SATA Project.) Its Board of Directors is slated to hold a special vote on approval of the project once FERC gives the go-ahead on the rules, including cost recovery.
Invenergy’s Grand Ridge Battery Storage Facility in Illinois | BYD
In comments filed with FERC, LSP Transmission Holdings said the proposal “as presented would effectively create a storage project monopoly for MISO’s incumbent transmission owners, just as this promising technology is in its infancy.”
A group of nearly 20 entities — including environmental nonprofits, consumer groups and utilities such as DTE Energy — said the ruleset was unlawful because it creates unduly discriminatory preference for MISO’s TOs.
The group also said the plan ignores FERC’s requirement that RTOs remove barriers to the participation of electric storage resources, arguing that Order 841 and MISO’s SATOA definition cannot be considered in isolation. It also contends that MISO’s Planning Advisory Committee originally wanted non-TOs and TOs alike to propose and construct SATOA, but that MISO ultimately favored the wishes of the latter.
“MISO’s decision to ignore the PAC’s recommendation in favor of the SATOA proposal demonstrates a lack of independence from the will of its TO members,” the groups wrote.
DTE representatives had promised to protest the filing during December’s board meeting, where directors voted unanimously to approve MTEP 19, which contains American Transmission Co.’s Waupaca area energy storage project meant to ease transmission reliability issues in central Wisconsin. In stakeholder meetings, DTE has repeatedly said the TO-only provision amounts to preferential treatment because generation owners cannot operate SATOA.
Not ‘Comparable’
MISO officials have said storage developers and owners who are not classified as TOs could still propose projects under existing rules on selecting non-transmission alternatives (NTAs) in the place of transmission projects. The RTO last year placed several mentions of storage resources into BPM 20, the business practices manual managing NTAs.
But storage owners and developers said the treatment remains unequal because NTAs must first clear MISO’s approximately three-year generation interconnection queue, which is not a requirement for TOs proposing SATOA, who instead submit their projects for study through the annual MTEP process.
Invenergy Storage Development complained the NTA option doesn’t offer “comparable opportunities.”
“Unlike SATOA, companies proposing NTA projects must first proceed through the multiyear generator interconnection queue, and unlike SATOA, those projects would be required to pay transmission charges with respect to the delivery of energy when the storage facility is charging from the MISO transmission grid. As a result, even though an NTA might present the very same storage solution as a SATOA, it cannot effectively compete against a SATOA, and transmission owners will maintain a monopoly on owning storage projects serving as a transmission asset,” Invenergy said in its protest.
Invenergy added that MISO’s proposed ruleset “ignores the fact that any expertise that transmission owners are assumed to have as to their respective transmission systems or in developing and owning traditional transmission, is inapplicable to SATOA — it is developers, like Invenergy, that have the relevant experience in owning and operating storage projects.”
The Michigan Public Service Commission said it was similarly “compelled” to oppose the filing because MISO isn’t proposing equal treatment for TOs’ and non-TOs’ storage projects. “No storage project should have an unfair advantage over any other project. Since the SATOA proposal discriminates against non-TO storage projects in favor of TO projects, the MPSC urges the commission to reject the proposal and direct MISO to collaborate with interested stakeholders to prepare a truly nondiscriminatory proposal,” it said.
Storage developer GlidePath said MISO’s proposal “completely misses the mark” and called it a “rushed solution.” Instead of “encouraging the development of single-use storage devices limited only to supporting the transmission system,” GlidePath said the RTO should create a more comprehensive compensation mechanism for storage resources and other generators that can support the transmission system.
GlidePath also said there are “clear competitive concerns inherent in permitting” SATOA to circumvent MISO’s interconnection process.
MISO Director of Planning Jeff Webb has predicted that the RTO will early this year begin addressing the issue of allowing storage functioning as transmission to simultaneously function in the energy market.
FERC on Wednesday accepted NERC Notices of Penalty against the Bonneville Power Administration, Idaho Power and the Niles Light Department. There were no monetary penalties.
The commission said it would not review NP20-5 regarding BPA or NP20-6, a spreadsheet NOP. The spreadsheet included 16 critical infrastructure protection (CIP) violations against unnamed entities reported by the Western Electricity Coordinating Council and ReliabilityFirst, which were redacted to protect sensitive information about how the entities implemented controls to address security risks. Five of the violations included financial penalties totaling $525,000.
Bonneville Power Administration
BPA was cited for two incidents, the first in September 2015, when it discovered that the rating on one of its current transformers (CT) was lower than the facility ratings of two associated transmission lines. The CT should have been rated as the most limiting element when BPA established the facility ratings. However, the utility’s rating methodology assumed CT equipment “to be sized such that it would never be the most limiting element in a facility.”
According to a NOP filed Dec. 30, after BPA reported the discovery to WECC, the regional entity performed an analysis that revealed similar issues in at least 52 facilities, at least six of which were part of one or more of WECC’s major transfer paths (NP20-5). The widespread failure to effectively determine facility ratings violated the FAC-009-1 standard. Although WECC found that the violation “posed a serious risk to the reliability of the bulk power system,” BPA is not subject to monetary penalties, in accordance with a D.C. Circuit Court of Appeals ruling that FERC and NERC cannot impose such penalties against federal governmental entities.
The RE noted that the incident constituted BPA’s first violation of the standard in question; BPA self-reported the violation and cooperated during the enforcement action; there was no evidence of any attempt to conceal the violation or intent to do so; and the violation did not cause or extend a loss of load. BPA typically operates its system conservatively, and the affected facilities were never in danger of exceeding a system operating limit.
Workers upgraded the Bonneville Power Administration’s Pacific Direct Current Intertie in 2016. | Bonneville Power Administration
In addition, BPA has since implemented a mitigation plan approved by WECC to prevent future incidents. In a separate incident, BPA submitted a self-report in May 2017 saying it may have failed to comply with six transmission operator (TOP) and interconnection reliability operations and coordination (IRO) requirements resulting from an outage on Nov. 30, 2016. BPA implemented the outage as part of its boundary remedial action scheme (RAS), which includes line-loss logic for three transmission lines.
BPA did not correctly implement the study limit information memo (SLIM) required by its operating plan, which specified that a 650-MW system operating limit (SOL) should be set at the one boundary’s flowgate.
Although a dispatcher limited output of the main generating station on the lines to 650 MW, BPA did not lower the boundary SOL from 1,300 MW to 650 MW.
Because the lower SOL was not entered in the control system, the alarm monitoring did not alert to three SOL exceedances between 2:15 and 2:45 p.m.
WECC said the incident, which posed a “moderate” risk, resulted because the dispatcher mistakenly relied on a dispatch standing order rather than the SLIM.
“BPA was already operating its system with the RAS in a degraded state. If BPA were to have lost another line, the RAS could have caused a loss of load and potentially opened the remaining lines entirely,” WECC said.
It credited BPA for discovering the mistake during a routine monitoring activity nine days after the incident and said the 650-MW limit on the generating station reduced the risk.
Idaho Power
Idaho Power submitted a self-report on July 24, 2018, saying it may have failed to comply with PRC-005-2(i) R3 by failing to maintain a battery used to power communications equipment during an emergency outage at a 230-kV substation for two 18-month intervals.
The vented lead acid battery was maintained in June 2014, but the company missed its 18-month maintenance interval on Jan. 1, 2016, and did not correct the error until July 2017.
WECC said the problem resulted when a transmission and distribution engineer disabled the battery maintenance trigger because he thought the utility’s communications group was responsible for tracking the maintenance and testing. The communications group had not been notified of the change in responsibility, the RE said.
The violation posed a minimal risk because the battery voltage was continuously monitored by the energy management system, which would have produced an alarm had a battery failure occurred.
WECC said the company’s PRC-005 compliance history was an aggravating factor in the incident but imposed no monetary penalty.
Niles Light Department
During a compliance audit in spring 2018, ReliabilityFirst determined that the Niles Light Department, the distribution provider for the Ohio city, had violated COM-002-4 R3 by failing to conduct initial training for each of its operating personnel who can receive oral two‐party operating instructions.
The city did not train three individuals until March 1, 2018, although they had been receiving operating instructions from FirstEnergy before then. The training requirement was effective July 1, 2016.
The risk of harm to the grid was partially reduced because Niles’ personnel only receive operating instructions in the presence of FirstEnergy operators with written switching orders. “Although entity personnel had not been formally trained on how to receive an oral two‐party, person‐to‐person operating instruction, the entity indicated that personnel performed three-part communication in practice when receiving operating instructions,” ReliabilityFirst said.
Niles misinterpreted the standard, believing that its established communication process with FirstEnergy meant it did not need to train its own personnel.
The audit also found Niles in violation of PRC-005-2(i) R3 for failing to conduct all required testing for a battery and charger. Niles failed to perform an unintentional ground test (required every four months); a battery terminal connection resistance test (required every 18 months); a battery intercell or unit-to-unit connections resistance test (18 months); and load tests (every 18 months and every six years).
RF said Niles failed to update its protection system maintenance program with the new tests as required.
“The risk is partially reduced because the entity was performing quarterly tests and monthly tests on the protection system equipment and that testing would likely indicate to the entity any battery degradation before failure occurred,” RF said, noting the city’s peak load is only 68 MW.
The team working on NERC’s proposed standard for cold-weather preparedness is revising the draft standard authorization request (SAR) and expects to post the updated document for another round of comments by the middle of February (Project 2019-06).
Debate at this week’s standard drafting team meeting primarily revolved around the cool reception the proposal received last year, with Sam Dwyer of Ameren noting that about 60% of respondents felt a new standard was unnecessary. Even many of the commenters who supported requirements around cold-weather preparedness urged the team to re-evaluate its scope. (See Gen Operators Cool to Winter Preparedness Standard.)
Geographic Splits
The strongest opposition to the proposal came from operators in northern areas, who argued that they already prepare for extreme cold as a matter of course, and that only operators in areas where winters are typically mild need guidance on how to handle extreme events. This argument made little headway with the drafting team, although it acknowledged that regional variations would likely need to be written into the standard.
“My take on that would be that standards should always be stuff you’re already doing. So, to the extent that you’re already doing it, great — it shouldn’t be hard for you to meet the standard,” Kenneth Luebbert of Evergy said. “[On the other hand], I think it’s going to be key [to] allow a lot of variations. … The approach that different plants take will be quite a bit different, whatever requirement we put into place.”
Some members suggested that the team address the geography-based objections by expanding its focus beyond low temperatures to cover any kind of extreme weather such as droughts or hurricanes, with Don Urban of ReliabilityFirst calling the new standard a “golden opportunity” to consider the impact of extreme weather in general.
This idea had little support from the majority of the team, however. Chair Matthew Harward of SPP reminded members that the impetus for the project was a joint FERC-NERC report on the Jan. 17, 2018, cold-weather event in the South Central U.S. Harward warned that trying to tackle too wide a remit could bog down the team and prevent it from reaching a meaningful result.
At the same time, members backed off from attempts to narrow the scope too much, as with Luebbert’s suggestion to focus on coal- and natural gas-fired generators, which accounted for 97% of performance issues cited in the joint report. Michael Brytowski of Great River Energy pointed out that when temperatures in the Upper Midwest dropped to -30 degrees Fahrenheit in early 2019, MISO lost almost 10 GW of wind generating capacity for 36 hours because of cold hydraulics, indicating that any form of generator can suffer from extreme temperatures.
NERC Guidelines Debated
Another topic of disagreement was what role the existing NERC cold-weather guidelines should play in the SDT’s work. Several industry respondents had said that the guidelines were sufficient and that no further requirements were needed; several team members favored simply adopting the guidelines as the new standard in whole or in part.
However, others felt more work was needed. For example, NERC Senior Standards Developer Jordan Mallory observed that “out of the past 12 years, there have been six blackouts [from extreme cold] — that is a problem. … Obviously, the NERC guidelines may not be enough.”
Responding to Mallory, Venona Greaff of Occidental Chemical cautioned that extreme weather events, by definition, are hard to predict and that it is impossible for even the best standard to cover all conceivable scenarios.
“You can do everything right all the time … you [can] look at where the wind blows from [historically] and how low the temperature gets, [but] you can have a one-off [where] the wind blows from a different direction and your wind blocks aren’t there,” she said. Greaff added that issues are more likely to arise at backup facilities, which aren’t used often, than at baseload generators.
“It’s like if you have a car that sits for a month and doesn’t drive — there’s no guarantee it’s going to start when you need it to.”
Observers from FERC urged the team to making their recommendations with the actual working conditions that utilities deal with in mind. Even when generator owners can point to their own cold-weather preparedness plans, they must be prepared to follow through and execute on them, they said.
“They’ve all got plans, and they’re good. … The generator operators [and] owners are very professional about getting plans out,” said Nick Henry of FERC. “The issue would be, after a period of time with moderate winters, and then another one hits you about five or six years later — now your pants are back down around your ankles because you just quit executing.”
U.S. renewable investments jumped 28% to a record $55.5 billion in 2019, showing the clean energy revolution is thriving despite the federal government’s failure to enact climate policies.
“We’ve seen renewable energy capacity double [in the U.S.] since the beginning of the decade,” said Ethan Zindler, Americas chief for BloombergNEF (formerly Bloomberg New Energy Finance), who released the data during a webinar by the American Council on Renewable Energy (ACORE) on Wednesday. “Solar capacity is probably 40 times what it was a decade ago.”
Renewable generation has increased about 75% to 761 TWh in 2019. Renewables now represent 18% of U.S. generation nameplate capacity. Including nuclear power, 38% of the country’s generating capacity is carbon-free.
U.S. renewable investments 2004-19 | BloombergNEF
Zindler said the biggest reason for the results in the U.S. was “a bit of a frenzy ahead of [the] anticipated step downs in tax credits.”
Globally, investment grew to $282 billion, a $1 billion increase from 2018, as the U.S.’ strong performance overcame a slowdown in China. The peak was $315 billion spent in 2017.
Although global spending was virtually flat in 2019 from 2018, Zindler said, declining costs meant developers were able to add 180 GW of generating capacity, up about 20 GW from the prior year. Wind edged out solar slightly in total investment worldwide, rising 6% to $138 billon while solar dipped slightly to $131 billion.
Growth was fueled in part by corporate power purchases, which totaled 50 GW, most of them in the Americas. The RE100 — 221 companies that have committed to 100% renewable electricity — have total electric demand about equal to that of South Africa, Zindler said.
Zindler said Congress’ one-year extension of the production tax credit is likely to result in a 1.5- to 2-GW increase in wind growth through 2025. Bloomberg projects 28.5 GW of new renewables in 2020, which would be the largest ever “by a pretty decent amount,” Zindler said.
Separately Wednesday, the American Wind Energy Association reported that 2019 was the U.S. wind industry’s third strongest year, with developers adding 9,143 MW of capacity. An additional 44 GW of wind projects, totaling more than $62 billion, are under construction or in advanced development, AWEA said.
Global corporate purchase power agreements (2009-19) | BloombergNEF
Challenges
Other panelists on ACORE’s “Outlook for Growth & Investment in 2020” webinar discussed industry trends and challenges.
“The conversations taking place today are slightly different than they were a couple years ago,” said Craig Gordon, vice president of government and regulatory affairs for Invenergy. “Companies like Invenergy aren’t just doing wind. They’re doing wind, solar and storage in the renewables space.”
Gordon cited the challenges of developing new generation at a time of record low power prices and flat demand. “We’re pushing new megawatts onto a grid that’s already oversupplied. That’s very apparent in places like PJM,” he said.
New production tax credit (PTC) schedule for onshore wind projects | BloombergNEF
Gordon also complained of “regulatory uncertainty” in New York, citing Gov. Andrew Cuomo’s Jan. 24 budget address.
“He said he would like the state government to begin doing the siting and transmission and development and then bring in developers after the fact to build the projects that they’ve cleared the way for,” Gordon said. “That’s really not helpful in a state where we’ve already seen significant regulatory burdens in getting projects done.”
He also slammed FERC’s Dec. 19 order directing PJM to expand its minimum offer price rule.
“If FERC was really hoping to just allow coal, I think they miscalculated … big time,” he said. “I think they may have taken a sledgehammer when a scalpel would have been more appropriate to deal with the issues around the capacity market.”
On the one-year anniversary of its bankruptcy filing, Pacific Gas and Electric appeared to be closing in on its goal of exiting Chapter 11 reorganization, while lawyers representing shareholders, fire victims and the government wrangled in court to secure a share of the multibillion-dollar pot the utility will have to pay out.
At the same time, California Gov. Gavin Newsom persisted in his threats to take over PG&E if it doesn’t leave bankruptcy “transformed.”
“If PG&E can’t do it, we’ll do it for them,” Newsom told an audience at the Public Policy Institute of California in Sacramento on Wednesday.
In San Francisco, lawyers argued in U.S. Bankruptcy Court over the division of a $13.5 billion trust that PG&E has promised fire victims. Because the details of the trust have yet to be made public, some potential beneficiaries were concerned they might not get their share.
Santa Rosa’s Coffey Park neighborhood was leveled in the Tubbs Fire in October 2017.
Attorneys representing more than 1,000 victims of the Camp Fire — which killed 86 people and destroyed 18,800 structures in the town of Paradise in November 2018 — tried unsuccessfully to convince bankruptcy Judge Dennis Montali to unseal terms of PG&E’s settlement with some victims of the Tubbs Fire, which killed 22 people and leveled a large part of the city of Santa Rosa in October 2017.
The lawyers argued that the confidential settlement with 19 elderly and infirm victims of the Tubbs Fire could jeopardize payments to Camp Fire victims because all must draw on the same fixed amount that PG&E has promised to put in the trust account.
Camp Fire victims “will soon be asked to vote on a restructuring plan that purports to provide $13.5 billion in funds for wildfire victims, including themselves. But that $13.5 billion figure is literally meaningless if an outsized portion has already been set aside for a select few claimants, the lawyers argued in a court filing.
Montali overruled their objection Wednesday, saying it was outweighed by PG&E’s agreement to settle the entire Tubbs case, which otherwise had been set to go to trial this month with an uncertain outcome. State investigators found a private landowner’s faulty wiring, not PG&E equipment, had started the fire.
A group of PG&E shareholders who had filed a securities fraud class-action lawsuit against PG&E argued they had been denied sufficient notice of the claims procedure in the bankruptcy case. Montali seemed skeptical of the argument, while agreeing with PG&E attorney Stephen Karotkin that a decision in the shareholders’ favor could “gum up” the case.
Montali heard briefly from lawyers representing federal and state agencies that are trying to recoup nearly $4 billion in funds dispersed to deal with catastrophic fires ignited by PG&E equipment in recent years. The agencies, primarily the Federal Emergency Management Agency, are concerned that their payment may come from the $13.5 billion to be set aside for fire victims and are asking the judge to help sort out the situation. (See FEMA Wants $4 Billion from PG&E in Bankruptcy.)
Montali said he would hear more from the government lawyers at the next bankruptcy hearing Feb. 4.
Newsom Repeats Takeover Threat
As the bankruptcy hearing played out in San Francisco, Newsom repeated his threat of a state takeover and said he had been talking with legislative leaders, readying a plan, several news outlets reported.
“It has to be a completely reimagined, transformed company,” Newsom said, according to the Associated Press. “Its culture has to change; its mindset has to change; its framework away from short-termism and situational thinking has to be replaced with a culture that focuses on you and me, not just shareholders.”
The governor said his staff had been in talks with PG&E to work out a solution, Bloomberg reported. He has called for PG&E to replace its entire board, adding more Californians, and to provide the state a mechanism for a quick takeover, should it be needed.
If a deal can’t be reached within the next few weeks, Newsom said he will lay out a detailed plan for a takeover.
PG&E filed for bankruptcy on Jan. 29, 2019, following two years of devastating blazes caused by its equipment. In recent months, the company has reached settlement agreements with most fire victims, insurance companies and local governments.
The utility most recently settled with bondholders that had offered their own reorganization plan for PG&E, amounting to a hostile takeover bid. The bondholders, led by several hedge funds, agreed to drop their plan in exchange for PG&E agreeing to pay or refinance its long- and short-term debts. (See PG&E Settles with Bondholders; Governor Objects.)
SANTA FE, N.M. — The SPP Cost Allocation Working Group (CAWG), composed of regulatory staff from across the RTO’s footprint, told their state regulators Monday that they plan to establish a narrow byway facility cost allocation review process, rather than just evaluate the process as first directed.
CAWG Chair John Krajewski, a consultant with the Nebraska Power Review Board, explained to the Regional State Committee that the group determined the Holistic Integrated Tariff Team’s recommendation that it evaluate a process through which costs for specific 100- to 300-kV projects can be fully allocated on a regionwide basis was not sufficient.
“‘Evaluate’ really means ‘go out and do it,’” Krajewski said. “The consensus of the group was that HITT’s intention was for us to put together a process for how this will look.”
Krajewski said the CAWG is “working towards having language” the RSC can adopt in the form of a white paper. The HITT’s timeline has the group completing its work in July, a schedule he called “aggressive.”
The CAWG is also recommending that projects eligible for the byway cost-allocation review process should include both new and existing Schedule 11 facilities. The recommendation excludes directly assigned upgrades.
RSC Approves Renewables’ Capacity White Paper
The RSC unanimously approved a staff white paper proposing a methodology for prioritizing and allocating the available effective load-carrying capability (ELCC) from wind and solar generating facilities that qualify as capacity in SPP’s balancing authority area.
Staff last year completed the study, which revealed that while wind resources’ total capacity increased with penetration, the accredited percentage of capacity related to the nameplate of each individual resource decreased.
The committee also approved Landmark Certified Public Accountants’ selection to audit its 2019 financial statement and the Business Practices Working Group’s revisions (BPWG RR369) to a business practice (BP 7060) that establishes cost-estimating processes and reporting requirements if project costs are projected to go outside an established bandwidth.
The changes close oversight gaps for projects that receive base plan funding but are not issued a notification-to-construct; clarify when oversight begins; and provides that the project owner is required to submit certain information as part of closeout processes.
Louisiana PSC’s Francis Joins Committee
The meeting marked NPRB Member Dennis Grennan’s first as RSC president and Louisiana Public Service Commissioner Mike Francis’ first as a member. Francis replaces Foster Campbell, who made a memorable appearance during October’s RSC meeting in Little Rock, Ark. (See “Louisiana’s Campbell: SPP Spending ‘Extravagant’,” SPP Regional State Committee Briefs: Oct. 28, 2019.)
By Michael Kuser, Christen Smith and Rich Heidorn Jr.
Transmission owners this week defended PJM’s, ISO-NE’s and SPP’s designations of “immediate-need” reliability projects while state officials complained the grid operators are frustrating FERC Order 1000’s intent to open transmission construction to competition.
More than a dozen stakeholders and groups filed comments on the RTOs’ responses to FERC’s Oct. 17 orders opening investigations under Federal Power Act Section 206 into their use of Order 1000’s immediate-need exemption. The exemption allows the RTOs to assign projects to incumbent TOs. FERC said it was “concerned that the responding RTOs may be implementing the exemption in a manner that is inconsistent with or more expansive than what the commission directed, and therefore may be unjust and unreasonable.” (See FERC to Probe Order 1000 Competition Exemptions.)
The TOs agreed with ISO-NE (EL19-90), PJM (EL19-91) and SPP (EL19-92), which insisted in their Dec. 27 filings that they were following Order 1000 and that no changes to their transmission planning practices were warranted.
Exception ‘Swallowed’ the Rule
But state officials disagreed, with several New England state agencies saying, “the exception has swallowed the rule.”
“The three-year, immediate-need deadline is a fiction that has not been respected in theory or in practice in New England,” the Connecticut and Massachusetts attorneys general, Connecticut’s Department of Energy and Environmental Protection and Office of Consumer Counsel, and the Maine Office of Public Advocate said in a joint comment.
FERC should order ISO-NE to amend its Tariff and revise or eliminate the time-sensitive-needs exemption to encourage competition, they said.
The New Jersey Board of Public Utilities argued that PJM applies the exemptions too broadly, resulting in “increased transmission rates from projects not subject to competitive pressures.”
Ending the Federal ROFR
Order 1000 required RTOs to eliminate from their tariffs a federal right of first refusal for incumbent transmission developers for facilities selected for cost allocation in a regional transmission plan.
In allowing PJM, ISO-NE and SPP to create the exemptions, FERC set out five criteria, including that a project is needed in three years or less to solve reliability criteria violations. It also required the RTOs to post information about the exemptions to ensure transparency. (CAISO, MISO and NYISO did not seek such exemptions.)
The commission said “it is unclear how each responding RTO determines whether an immediate-need reliability project is needed in three years or less,” noting that PJM designated 19 immediate-need reliability projects between 2017 and 2018 with need-by dates prior to or in the year they were designated. In other cases, FERC found, the projects were projected to be in service after the need-by date.
The commission also faulted the RTOs for a lack of transparency, saying it was difficult to locate where they identify and post explanations of reliability violations and system conditions with time-sensitive needs.
It suggested potential changes, such as shortening the three-year rule for projects deemed immediate-need, approving exemptions based on the in-service date versus the need-by date, increasing transparency into how the RTO determines a competitive process is unfeasible and requiring more frequent project re-evaluations.
SPP: Small Share of Projects Exempted
FERC noted that SPP designated an immediate-need reliability project in December 2018 that is needed by June 1, 2020 but has an expected in-service date of June 30, 2023.
SPP said the five projects it designated as short-term reliability projects (STRPs) represented only 3.5% of 144 total reliability upgrades between 2015 and 2018.
Of the five, one was canceled, and two others designated in July 2016 and December 2018 have not yet been energized. Two projects designated in June 2015 were completed in June and November 2018.
The RTO said the process for designating STRPs “is working as intended” and that changes contemplated by FERC “would have very little impact on increasing the number of projects subject to competition and could increase reliability risks incurred due to delays in construction caused by implementing the competitive bidding process.”
American Electric Power defended both SPP and PJM in its filings, saying immediate-need reliability projects “are a necessary component of reliability” that allow RTOs to adapt to “retirement of conventional generation, the rapid addition of variable resources and the addition of block load, such as data centers and shale gas facilities.”
PJM Late to ID Needs?
In its critique of PJM, FERC had questioned the RTO’s approval of the Flint Run 500/138-kV substation upgrade as an immediate need, saying the size of the project — intended to serve load growth in the Marcellus Shale region in West Virginia — “raises questions about why PJM did not identify this need earlier.”
PJM’s 137-page response clarified that the number of immediate-need projects approved between 2015 and 2018 totaled 63, slightly more than a quarter of the 241 transmission proposals exempted from competition in that time frame.
The RTO said it arrived at the smaller number after sorting out projects that claimed other competitive exemptions, including the lower voltage threshold, thermal reliability violations solved with substation upgrades and Form 715 projects. It also argued that the relative size of the population it serves contributes to the number of immediate-need projects in its Regional Transmission Expansion Plan (RTEP) as compared to SPP and ISO-NE.
FERC questioned PJM’s approval of the Flint Run 500/138-kV substation project as an “immediate need” reliability project, saying the size of the project, to serve load growth in the Marcellus Shale region, “raises questions about why PJM did not identify this need earlier.” | PJM
FERC’s proposed changes, PJM said, ignore the unpredictable nature of the siting and eminent domain processes and would require RTO staff to “prognosticate” about complex government processes for which they lack expertise. Its existing practice of posting information about immediate-need projects online three days before the monthly Transmission Expansion Advisory Committee meeting gives stakeholders a chance to review and ask questions about the proposals, eliminating the need for greater transparency, PJM said. Further, mandated re-evaluations for projects that fail to meet a projected in-service date “would be highly disruptive and lead to further delays.”
“Thus, it is necessary that PJM continue to have the authority given the relevant facts and circumstances to direct transmission owners to resolve an immediate-need reliability issue when identified and that those entities designated responsibility to construct the project will have reasonable assurance of recovery if they proceed with the project as approved,” the RTO said.
TOs: No Changes Needed
In separate filings, Exelon, Old Dominion Electric Cooperative and AEP said that PJM’s response demonstrates effective implementation of the immediate-need exemption and supported no further policy changes.
“Exelon agrees with PJM that the additional conditions and restrictions on the use of the immediate-need reliability project exemption that the commission introduced in the show-cause order would either undermine the effectiveness of the immediate-need reliability project exemption or fail to meaningfully increase opportunities for nonincumbent transmission development,” Exelon wrote.
The New Jersey BPU took aim at PJM’s argument that its immediate-need projects were “artificially inflated,” noting that the subset still accounts for 13% of all baseline upgrades in the RTEP.
After the last of PJM’s competitive exemptions went into effect in 2017, more than $3 billion in transmission projects were planned “without the benefit of competition,” the BPU said. The issue hits close to home for New Jersey regulators, who have charged that more than a third of PJM’s transmission expansion has occurred within their state, increasing transmission rates 124% since 2013 for “certain customers.”
“Taken together, these facts undercut PJM’s use of other exemptions as support for the justness and reasonableness of its existing rules,” the BPU said. “To the contrary, the substantial portion of noncompetitive PJM transmission investment, particularly in New Jersey, confirms the commission’s concerns about the expanding scope of transmission exemptions.”
Because PJM has demonstrated the operational capability to maintain a reliable transmission system when construction on such projects extends beyond three years, competitive transmission developer LS Power said, the commission should eliminate the blanket immediate-need exemption and require the RTO to seek FERC approval of exemptions on a case-by-case.
LS Power said the total value of transmission additions classified as immediate-need exceeds $4.5 billion over the last six years — far beyond what the commission envisioned when it approved the “limited” exemption.
“The commission must require PJM to fully explain why this staggering amount of transmission spending in PJM is in immediate-need reliability exemption projects and why PJM’s planning process is insufficient to prevent this level of immediate-need reliability projects,” LS Power said. “Significant reform is warranted.”
American Municipal Power said PJM’s process for approving RTEP projects is flawed because incumbent TOs hold all the relevant information and don’t provide it to the RTO on a “timely basis.”
“The commission should direct PJM to improve the RTEP process to ensure that it has timely information from processes that feed into the PJM planning process to avoid immediate-need reliability projects resulting from changes in topology, facility rating methodologies or other modifications controlled by the PJM transmission owners,” AMP said.
ISO-NE’s Lack of Annual Tx Planning
FERC also was critical of ISO-NE, saying that because the RTO does not conduct an annual transmission planning process, and instead relies upon needs assessment studies, “it appears that all reliability needs in ISO-NE may be classified as immediate-need reliability projects.”
ISO-NE and New England TOs Avangrid, Eversource and National Grid stood alone in defending the RTO’s use of immediate-need exemptions, with most stakeholders urging FERC to curtail or abolish the exemption.
The RTO said it has 31 reliability projects for which the need-by date is earlier than the projected in-service date, all resulting from either its Boston 2028 or its Southeast Massachusetts/Rhode Island 2026 needs assessments.
“The solutions are addressing the time-sensitive needs described in the two assessments,” the RTO said. “ISO-NE believes that the exception is working as intended in the New England area and that no changes are necessary at this time.”
After the RTO in December issued its first competitive transmission solicitation — to address reliability concerns over the planned retirement of the Mystic Generating Station near Boston — it told the commission it “intends to conduct a ‘lessons learned’ process, during which time ISO-NE will revisit its processes to determine if overall improvements can be made.” (See ISO-NE Issues First Competitive Tx RFP.)
The New England Power Pool urged the commission to restrict the use of such exemptions “as much as possible, consistent with ensuring that reliability needs are met in a timely way.”
NEPOOL said it continues to support the immediate-need exemption for transmission facilities that are needed within three years of the identification of a reliability need. However, it “should be the exception and not the rule,” the organization said.
The New England state agencies said the “fiction” of the three-year immediate-need deadline is demonstrated by the data. Of 30 completed and ongoing immediate-need projects, they said, 24 (80%) were not completed within three years; 15 (50%) are expected to take at least five years; and 20 (67%) had need-by-dates predating the assessment study that identified the need. Another four had need-by-dates in the same year as the need was identified.
The New England States Committee on Electricity (NESCOE) said it is concerned that ISO-NE’s practices could cause all reliability needs to be met outside of the competitive process.
“Given the unique circumstances and system conditions giving rise to the identified need, the Boston [request for proposals] does not appear to signal a fundamental shift away from ISO-NE’s use of the exemption,” NESCOE said.
The limited competition in New England raises obvious questions about whether consumers are paying more than necessary for transmission, it said, noting that revenue requirements are forecast to increase from $2.1 billion in 2018 to $2.7 billion in 2023, a jump of more than 25%.
“Even before these increases take effect, an ISO-NE analysis shows that most residential retail electric customers in New England paid transmission costs representing 11 to 18% of their total retail rates,” NESCOE said. “If needs were classified as time-sensitive years ago but ISO-NE has not yet selected projects to meet those needs, it raises questions regarding whether the appropriate criteria is being used to assess the time-sensitivity of those needs.”
The Connecticut Public Utilities Regulatory Authority said, “Any competition is superior to no competition,” and that the RTO “appears to prefer not using the competitive process to address transmission needs and to being unable to identify any transmission need that is more than three years away.”
The PURA suggested limiting the percentage of transmission need projects that can have a noncompetitive solution, based on either the number of projects or on the dollar expense.
The agency “believes that 25% is the appropriate limit to place on the amount of dollars that can be spent on noncompetitive solutions. This percentage level ensures that the majority of dollars spent on transmission need solutions benefit from competitive forces, yet should be amply sufficient to handle those few occasions when reliability concerns arise and cannot be mitigated.”
To Proceed or not to Proceed
The immediate-need exemption has given incumbent TOs in New England exclusive rights to construct nearly all new transmission in the region, and they are at the same time “failing almost universally to complete or, in some cases, even commence projects on or before the need-by date,” Massachusetts Municipal Wholesale Electric Co. and New Hampshire Electric Cooperative said.
The immediate-need exemption is “out of step with its intended purpose and should be eliminated,” they said, suggesting a more streamlined competitive solicitation process.
ISO-NE asserts that in-service dates are based on realistic appraisals by the affected TOs of how long it is likely to take for the preferred solution. “But that does not advance the ball; it merely describes the problem,” the public systems said. “If the TO cannot build the project within the [RTO’s] need-by timeframe, then the project should be put out for bid.”
The public systems proposed a competitive solicitation process they said could be completed in less than half the time of the RTO’s method, “or just 279 days, compared to the 630-day time frame ISO-NE has established for the Boston 2028 RFP.”
Avangrid tried to parry the thrust of the commission, asserting that “a litigated proceeding based on a misunderstanding of need-by dates versus in-service dates does not signal to the industry that the commission intends on maintaining the reasonable balance struck between eliminating barriers to new entry and ensuring participating transmission owners are able to address immediate reliability needs on the New England transmission system without unnecessary delay.”
The company suggested giving up “a one-sided view of post-Order No. 1000 transmission planning measures” in favor of a technical conference as “the most transparent and balanced manner to manage this discussion.”
Eversource Energy said, “The benefits of adjusting the three-year exemption … to increase competition are minimal.”
ISO-NE independently determines what reliability needs to put out for competitive solicitation, and stakeholders can challenge its use of the three-year exemption, the company said.
There would be “little benefit to creating more process” for the kinds of projects that are needed within three years, which typically involve upgrades to TOs’ existing assets or on their rights of way, which FERC explicitly reserved for the public utility transmission provider, Eversource said.
“Near-term reliability should not be compromised for such little, if any, benefit. There is ample evidence for the record of the significant time needed to conduct competitive solicitations,” Eversource said.
National Grid reported nine of 13 immediate-need projects identified through the SEMA-RI report as “progressing satisfactorily against their key milestones,” with the remaining four “less advanced due to factors outside of National Grid’s control.”
FERC on Thursday rejected requests for rehearing of its order directing PJM to allow two merchant transmission operators to convert some of their firm transmission withdrawal rights (TWRs) to non-firm.
The New Jersey Board of Public Utilities and Public Service Electric and Gas had challenged the commission’s December 2017 finding that the RTO and PSE&G’s interconnection service agreements (ISAs) with Hudson Transmission Partners (HTP) (EL17-84) and Linden VFT (EL17-90) were unjust because they did not permit the conversions. (See NJ Merchant Tx Operators Win Relief on Upgrade Costs.)
The transmission companies own facilities that carried power into New York City as part of the “Con Ed-PSEG wheel,” in which 1,000 MW were exported from upstate New York to PJM through PSE&G’s facilities in northern New Jersey, and then exported to the city. Consolidated Edison and PSE&G canceled the agreement in April 2017. HTP and Linden had sought the conversions to relieve themselves of cost allocations under PJM’s Regional Transmission Expansion Plan.
Linden VFT’s exterior | Joseph Jingoli & Son
PSE&G argued that FERC erred in applying the just-and-reasonable standard of the Federal Power Act to the ISAs, rather than the public-interest standard of the Mobile-Sierra doctrine, which presumes the rates established through a negotiated contract are just and reasonable unless they’re found to harm the public interest. The commission had found the ISAs’ terms to be generally applicable to all PJM participants — and thus excluded from Mobile-Sierra — but the utility said the TWRs and provisions in the ISAs were unique, not pro forma.
In rejecting PSE&G’s argument, FERC pointed to the fact that Section 232.3 of PJM’s Tariff governs the conditions under which a transmission interconnection customer receives firm and non-firm TWRs. “Because PJM determined the TWRs available to HTP [and Linden] following [studies] conducted under terms and conditions that are generally applicable (even though the results of that study were specific to [the companies]), we regard those terms as generally applicable and therefore subject to the ‘just and reasonable’ standard, rather than the Mobile-Sierra presumption,” the commission said.
PSE&G also argued that the commission erred in finding no operational or reliability rationale preventing it from directing that PJM convert the TWRs and that it ignored the utility’s affidavit that raised concerns about the operational, reliability and LMP impacts from the conversions, rather relying on “one sentence written by an attorney in a PJM pleading, unsupported by any independent evidence or expert testimony.”
“We disagree with these PSEG arguments,” FERC said. It “reasonably relied on statements from PJM that reducing [the] TWRs from firm to non-firm presented no operational or reliability risks to PJM’s system.” The commission also noted that the utility’s affidavit relied on NYISO’s 2016 Reliability Needs Assessment, which made no reference to the TWRs in question.
The New Jersey BPU argued that FERC failed to consider whether the conversions would result in preferential rates to NYISO customers. But the commission said that argument was outside the scope of the proceeding, as Schedule 12 of the PJM Tariff calculates merchant transmission facilities’ cost responsibilities for RTEP projects based on their firm TWRs.
