PJM last week asked FERC to delay next year’s Base Residual Auction to Aug. 14 to provide the RTO more time to respond to the commission’s June 29 order requiring changes to capacity market rules.
The commission ordered PJM to expand its minimum offer price rule (MOPR), which now covers only new gas-fired units, to all new and existing capacity receiving out-of-market payments. The commission’s ruling, which rejected PJM’s April “jump ball” capacity filing (ER18-1314) and partially granted a 2016 complaint led by Calpine (EL16-49), initiated a Section 206 proceeding in a new docket (EL18-178). (See FERC Orders PJM Capacity Market Revamp.)
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PJM requested the delay in an Aug. 9 filing supporting the Organization of PJM States Inc.’s (OPSI) motion to extend to Oct. 11 the deadline for filing testimony, evidence or arguments in response to the FERC order (EL16-49, et al.).
The RTO asked the commission to issue an initial order directing a compliance filing by Jan. 15 and a final order on compliance by March 15. “This proposed schedule will provide PJM and capacity market sellers with approximately five months to undertake the Tariff imposed obligations in advance of the delayed BRA,” PJM said.
PJM, OPSI and more than a dozen other parties also have requested rehearing of the commission’s ruling, including industrial customers, the American Public Power Association, Exelon, Old Dominion Electric Cooperative, Dominion Energy, FirstEnergy Services, and regulators from Illinois, New Jersey and Maryland.
VALLEY FORGE, Pa. — PJM staff are still working on how to respond to GreenHat Energy’s default in the financial transmission rights market, CFO Suzanne Daugherty told stakeholders at last week’s Market Implementation Committee meeting.
Daugherty announced at the June meeting of the Markets and Reliability Committee that GreenHat was likely to default on payments for a sizable FTR portfolio that was proving unprofitable. After the company defaulted, PJM staff realized that their current rules for attempting to mitigate the financial burden to members might instead exacerbate the situation and requested a waiver from FERC to find a more effective solution (ER18-2068).
PJM analysis shows the continuing downward trajectory of GreenHat’s FTR portfolio. | PJM
The Tariff requires PJM to liquidate the FTRs of a defaulted member by offering for sale “all” current planning period FTR positions in the next monthly balance of planning period FTR auction “at an offer price designed to maximize the likelihood of liquidation of those positions.”
PJM said a waiver is required “given the market impact by the liquidation of GreenHat’s large FTR portfolio and observed low levels of market liquidity more than one month forward (i.e., non-prompt months).” Staff found that the bids offered to take the portfolio’s positions would have been approximately four times the pre-default auction clearing prices on the affected paths. Instead of being forced to liquidate the entire portfolio at once and potentially suppress the holdings’ return in an illiquid market, PJM asked FERC on July 26 to allow it to not liquidate each FTR position until the month it becomes due in the market. FERC has not yet responded. (See “ Default Details,” PJM MRC/MC Briefs: July 26, 2018.)
At the same time, PJM also requested a waiver of its requirement to return collateral posted by Orange Avenue, another FTR market participant that is affiliated with GreenHat (ER18-1972). Orange has challenged that request, but PJM argued that it may become necessary to sue Andrew Kittell, who oversees both firms, and that Orange’s collateral would be included among Kittell’s assets.
When GreenHat acquired most of its positions starting in 2015 long-term FTR auctions, both historical congestion and the FTR auction clearing prices indicated that the portfolio would be profitable, so it had a low credit requirement. However, by April 2017, PJM staff realized the portfolio, consisting primarily of prevailing-flow FTRs, were on paths where transmission upgrades were expected to reduce future congestion.
According to PJM, GreenHat’s portfolio was estimated at $57 million based on the auction clearing prices when the positions were taken. In the 2015-16 planning year, the same portfolio would have netted $548 million. It dropped slightly in the next planning year to $481 million. However, the following year the value dropped precipitously to $126 million and continued falling in subsequent auctions. By June 2018’s auction, the portfolio would have lost $110 million.
After realizing GreenHat’s exposure, staff approached Kittell, who offered to mitigate some of the potential risk by signing over what he told PJM were the rights to receive $62 million in proceeds from several bilateral FTR contracts. PJM accepted the agreement in June 2017 and opened a bank account for the expected proceeds, but the other company in the contract, whose name was redacted from the public filings in the docket, says it paid what it owed to GreenHat well before Kittell signed the agreement with PJM. The RTO wants FERC to allow it to keep the collateral from Orange while it investigates “whether Mr. Kittell and GreenHat fraudulently induced PJM to enter into the pledge agreement.” FERC hasn’t responded to that request yet either. Kittell did not respond to a request for comment.
His attorney, David Gerger, also declined to comment but pointed to Orange’s July 27 protest, in which it told PJM it “was not making any representations or warranties about the value of the additional collateral … and that PJM must make its own valuation.”
Orange said “PJM was uniquely poised to [establish the value of the collateral] because the [$62 million] number came from applying the PJM Tariff to amounts entered into PJM’s FTRCenter System.”
In the wake of the GreenHat default, PJM received stakeholder endorsement to enhance its credit policy for FTR traders. The new rules, to be implemented on Sept. 3, will institute a 10-cent/MWh minimum monthly credit requirement for FTR bids submitted in auctions and cleared positions held in FTR portfolios. (See “Credit Requirements,” PJM Market Implementation Committee Briefs: July 11, 2018.)
However, Daugherty confirmed at the MIC meeting that GreenHat remained compliant with the credit requirements existing at the time until it failed to post a collateral call in April. Stakeholders grilled her on why PJM hadn’t previously attempted any regulatory action or policy changes if it knew about the concern nearly a year and a half ago.
“There was nothing specific in the credit policy that would have allowed PJM to make a collateral call” sooner, she said, noting that the agreement with Kittell was signed in June 2017.
Additionally, staff said that FERC lacked a quorum of commissioners at the time and that stakeholders had not yet agreed on revisions on how to analyze predicted congestion. Daugherty said staff made a “good faith effort” to bring GreenHat and Kittell to heel.
Several stakeholders pushed PJM to provide even a rough estimate of the expected losses. One, Vitol’s Joe Wadsworth, said he used recent market results to determine that it could be upward of $145 million.
“It is getting worse,” he said.
If accurate, the result would be almost triple the $52 million credit default by Tower Research Capital’s Power Edge hedge fund in 2007, which also triggered credit policy revisions. (See PJM Credit Adder Fails upon Heightened Review.)
Daugherty resisted the requests, saying that it would be impossible to accurately predict.
“We will not know the dollars until they play out or they are liquidated because we may have to pay to liquidate them,” Daugherty said.
“There’s urgency here. We can’t just let this ride on the market,” Wadsworth said. He said engaging with GreenHat once the risk was identified was “clearly the right thing to do,” but he asked why the company was allowed to continue participating in the auctions.
“These numbers are kind of scary. We’re trying to find out … how big this is going to be,” Old Dominion Electric Cooperative’s Adrien Ford said. “I’d appreciate some sort of take on it so I can go back to the home office and say ‘roughly we think it’s about this size.’”
“I don’t think you should expect that PJM’s going to project a number,” Daugherty said.
Stakeholders also debated the best strategy for how to liquidate the portfolio if FERC approves PJM’s waiver request. Some, including Wadsworth, called for immediate action, as auction results have shown a continuing downward trend. Others, including Direct Energy’s Marji Philips, argued it might be better to wait to see if something materializes that’s better than the current guaranteed loss.
“Do you liquidate today and have a fixed number, or do you want to not liquidate today, and the number might come in lower,” she said.
PJM is working with its members to agree upon a strategy at the August MRC meeting and targeting a final approval vote at the September MRC meeting.
According to PJM’s rules, all members will be on the hook for at least some of the losses. Of the final amount, 10% will be allocated on a per capita basis to the 992 members, including affiliates, as of June 21. The per capita assessments are capped at $10,000 per year, though Daugherty confirmed the rule’s intention was for the cap to count per default event and that the language may need to be clarified.
The remaining losses will be allocated according to each member’s gross PJM activity over the three months preceding the default. The RTO said the total activity for the period was $24 billion.
So far, PJM has sent, or plans to send, bills for $42.5 million, about 18% of GreenHat’s portfolio.
Daugherty confirmed “there is no other situation like [GreenHat’s exposure] related to credit requirements.” She said PJM is working with external consultants from trading exchanges, clearing houses, other consultants and its Independent Market Monitor “to review factors that can affect future congestion levels and [perform a] gap analysis against how FTR credit requirements would address those factors.” The talks are excluding members to avoid potential conflicts of interest.
DC Energy’s Bruce Bleiweis said the incident was not a failure of the FTR market or structure but “clearly a significant failure of the credit policy.”
However, he expressed concern that PJM’s presentation indicated staff might agree with the IMM’s position that the benefits of long-term FTRs are outweighed by their risks.
In June, stakeholders endorsed changes to the long-term FTR auction construct to prohibit participants from obtaining the rights to congestion on transmission paths before the owners of the underlying auction revenue rights. The Monitor has said the revisions are improvements but don’t go far enough. (See “Long-term FTRs Undercut Annual FTRs,” PJM Market Implementation Committee Briefs: June 6, 2018.)
Kittell worked as an energy trader for JPMorgan Venture Energy Corp. when FERC fined the company $285 million and ordered it to disgorge $125 million for “manipulative bidding strategies” from September 2010 through November 2012. Kittell and two other employees named by the commission were not charged.
VALLEY FORGE, Pa. — Stakeholders at last week’s Market Implementation Committee meeting overwhelmingly endorsed PJM’s proposal for revising how it calculates balancing ratios while also rejecting several competing proposals.
PJM’s proposal received 0.88 in favor, surpassing a 0.5 threshold in the sector-weighted vote. Stakeholders also preferred it to the status quo, voting 0.69 in favor of the new proposal.
The proposal, known as Package A, would calculate the balancing ratio used in the default market seller offer cap (MSOC) and nonperformance charge rate (PPR) formulas by averaging the balancing ratios from the three delivery years that immediately preceded the capacity auction. For years that don’t have at least 30 hours of performance assessment intervals (PAIs), the actual number of PAIs would be supplemented with estimated balancing ratios calculated during the intervals of the highest RTO peak loads that do not overlap a PAI. PAIs are five minutes apiece.
Some stakeholders like the proposal because it is straightforward and maintains the same number of PAIs used in either the MSOC or the PPR. However, others argue the calculation overestimates the likely number of PAIs, which leads to an artificially high MSOC. Such conditions led Independent Market Monitor Joe Bowring to conclude last week that the clearing prices in May’s Base Residual Auction were higher than they should have been. (See related story, IMM: PJM 2018 Capacity Auction was ‘Not Competitive’.)
“This all turns on your belief that 30 hours is a reasonable number [for PAIs]. I don’t believe that. … I would say it’s pretty clearly not a reasonable number,” Bowring said.
“We don’t have any technology that can solve that problem [of accurately predicting the number of PAIs], so we’re left with what is a reasonable number to put in there,” PJM’s Adam Keech said.
“The 30 hours is definitely an issue for the consumer advocate offices I’ve talked to,” said Greg Poulos, executive director of the Consumer Advocates of the PJM States.
PJM’s Pat Bruno announced that staff planned to abandon a second proposal, Package B, unless a stakeholder offered to sponsor it. Dave Mabry, representing the PJM Industrial Customer Coalition, agreed to do so. The proposal would calculate the balancing ratio in the same manner as Package A but would also estimate an expected number of PAIs for the delivery year using data from the prior three years. That estimate would be inserted into the MSOC and PPR formulas.
Each formula would include a floor of PAIs, but they would differ: five hours for the MSOC and 15 hours for the PPR. That difference concerns stakeholders, who argue the numbers need to be the same for the formulas to maintain their mathematical relationship.
“We don’t share PJM’s thoughts that they have some problems at FERC with the” formulas, Mabry said in sponsoring the proposal. American Municipal Power’s Steve Lieberman seconded it, and it received 0.09 in favor.
Additional proposals from Exelon and Calpine differed with PJM on the PAI calculations for the formulas. Calpine’s would floor both at 10 hours and calculate a number based on the past 10 years of data. Exelon’s would use a probabilistic model to look forward. Both would keep constant the number of PAIs used in the two formulas.
“We think it’s illogical to have different assumptions for those calculations,” Exelon’s Jason Barker said.
“The heart of our proposal was to get the expected amount of performance assessment [intervals] to match. It didn’t make sense to us [to have them not match], and I don’t think it would make sense to FERC,” Calpine’s David “Scarp” Scarpignato said.
Scarp withdrew his proposal in favor of PJM’s Package A. Exelon’s received 0.36 in favor.
“I am more in favor of fixing the immediate problem of the” balancing ratio, Scarp said.
“You can’t fix [the balancing ratio] without addressing the problem on a consistent basis,” Bowring said.
A proposal from the Monitor, which mirrored Package B except that it had floors of just five hours for either formula, received 0.02 in favor.
Quadrennial Review of VRR Curve
Stakeholders endorsed a proposal from Scarp on revisions for PJM’s quadrennial review of the variable resource requirement (VRR) curve in its Reliability Pricing Model capacity market construct. Several other proposals, including one endorsed by PJM, were rejected by stakeholders.
Despite the result, all four proposals will be up for consideration at the August meeting of the Markets and Reliability Committee meeting. Stakeholders had made that request long before the vote in an attempt to overcome the influence of companies with multiple affiliates, which can each vote separately at lower committees.
Scarp’s proposal largely mirrored PJM’s, except that it maintains the current combustion turbine configuration as the curve’s reference technology; the RTO had planned to change it to a newer model. It also maintained the curve’s current calculation, while PJM and the other two proposals would have shifted it 1% left. The shift was part of revisions recommended by the Brattle Group, who were hired by PJM to analyze the curve. (See “VRR Curve Update,” PJM Market Implementation Committee Briefs: July 11, 2018.)
PJM’s proposal received 0.39 in favor.
A proposal from the Monitor agreed with PJM on updating the reference technology, but it differed on several other factors. That proposal received 0.1 in favor.
A proposal from the D.C. Office of the People’s Counsel sought to use a combined cycle unit for the reference technology and otherwise largely mirrored the Monitor’s proposal. It received 0.1 in favor, as well.
Fuel Cost Policy
John Rohrbach of ACES, representing the Southern Maryland Electric Cooperative, presented a proposed problem statement and issue charge to review the first year’s performance of the new fuel-cost policy rules and determine if any improvements can be made.
The proposal was also endorsed by Old Dominion Electric Cooperative and Panda Power Funds. The group hopes to have any potential revisions to the current policy identified by April 19 to target a June filing at FERC. Any potential alternatives to the current policy that are identified would need to be ready for consideration by the fall to target a FERC filing in the fourth quarter.
Transmission Constraint Penalty Factor
PJM and its Monitor have developed a joint proposal to revise how the transmission constraint penalty factor is utilized. PJM’s Angelo Marcino explained that the current process uses “constraint relaxation” so that the penalty factor doesn’t set shadow prices. This “masks” transmission shortages in the market. The proposal would remove constraint relaxation and allow the $2,000/MWh penalty factor to set prices as appropriate.
The proposal received so little reaction that PJM suggested canceling the next meeting of the group overseeing the issue, which stakeholders approved.
After the meeting, PJM posted online an analysis from the Monitor on the potential impact of the proposed revisions. The Monitor found that in 2017 the revisions would have increased the balancing market in the aggregate by $10 million.
Texas regulators last week issued requests for comments on real-time co-optimization (RTC) and incorporating marginal losses into dispatch decisions, proposals that have varying levels of stakeholder support.
On June 29, ERCOT’s Independent Market Monitor filed a report at the Public Utility Commission indicating RTC could have saved as much as $257 million in reduced congestion costs and $155 million in reduced ancillary service costs during the 2017 test year.
IMM Director Beth Garza told ERCOT’s Board of Directors on Aug. 7 that a significant cost of providing operating reserves is the lost opportunity cost of providing energy.
“The cost of containing those reserves, setting them aside, is the lost opportunity of selling that energy,” Garza said. “When initially selected in the day-ahead market, the costs of providing both energy and reserves are minimized. That is, co-optimized.”
During their Aug. 9 open meeting, the commissioners approved a set of questions as part of its review of RTC (Project No. 48540). They also approved a second group of questions related to incorporating marginal losses’ costs into dispatch (Project No. 48539).
Commissioners (left to right) Shelly Botkin, DeAnn Walker and Arthur D’Andrea discuss market improvements during the PUCT open meeting. | Admin Monitor
A second report, filed by ERCOT, found the grid operator would benefit from RTC through its more efficient procurement of ancillary services and congestion management, and reduced reliability unit commitments.
The IMM and ERCOT will host a technical workshop on the two filed reports Sept. 6.
The PUC held a pair of workshops last year following a report coauthored by Harvard University’s William Hogan and FTI Consulting’s Susan Pope that recommended rule changes to address intermittent renewables and add incentives for generators. (See ERCOT, Regulators Discuss Need for Pricing Rule Changes.)
The PUC also published a list of questions on the review and approval of substations. It has scheduled an Oct. 4 workshop on the subject (Project No. 48251).
Commissioners Approve Tweaks to Retail Website
The commissioners approved staff’s suggested recommended changes to the PUC’s Power to Choose website, where consumers in Texas’ competitive areas can shop for electricity providers. The website has drawn the commission’s attention following consumer complaints of pricing gimmicks that result in unexpectedly high costs.
“We’ve been here before,” Commissioner Arthur D’Andrea said. “The commission thought we fixed this website, and now here we are again. I don’t want to be back here in two years doing the same thing.”
“Unfortunately, I think we may be because REPs [retail electric providers] adjust,” Chair DeAnn Walker said. She had reason to be pessimistic, saying she had recently met with a retail representative.
“People are already trying to figure out how to get around these” rule changes, Walker said.
Staff’s proposal adds a filter to weed out plans that offer low average prices at the 1,000-kWh usage level, when they cost significantly more for customers who average more than 1,000 kWh/month. The recommendations will also limit the number of offers a REP can list on the website to prevent them from “flooding” a page.
“Doing so will encourage REPs to use [their] available postings wisely, rather than repeating very similar offers to strategically dominate search results,” staff said.
PUC to Intervene in FERC Entergy Dockets
Following an executive session, the commissioners agreed to intervene in five dockets at FERC involving Entergy Services and cost-reimbursement agreements with its five operating companies (ER18-2079, et al.).
Entergy proposed last year to recover $5.9 million from Texas retail rates for Entergy Texas’ portion of construction costs for a pair of transmission control centers it built in Arkansas and Mississippi.
FERC set the agreements for settlement proceedings in February, but the company said the negotiations between Entergy Service its operating companies, commission staff and other parties were not “fruitful” and further discussions “would not resolve the issues in these proceedings.” The company filed cancellation notices for the reimbursement agreements with the commission in July. Entergy said no payments were made and no benefits received under the agreements.
VALLEY FORGE, Pa. — Opponents and advocates of new rules to increase the importance of cost containment in transmission project proposals found themselves in uncommon agreement at last week’s PJM Planning Committee meeting.
Both shared concerns over the RTO’s plan to delay inserting some language for the new rules into Manual 14F.
Staff explained that it was a last-second decision meant to avoid confusion for those reading the manuals, and while stakeholders didn’t fully support the explanation, they eventually agreed to endorse some of the modified manual revisions but defer voting on the cost-containment language.
The wide-ranging changes include revisions to PJM’s processes for selecting “market efficiency“ transmission projects and prequalification for submitting proposals. But stakeholders were focused on how PJM plans to implement the cost containment rules, which were endorsed earlier this year following a controversial stakeholder process. (See Cost Containment Clears MC Vote Despite PJM Plea.)
While some of the changes could be implemented immediately, two frameworks for comparing projects are being developed by PJM and its Independent Market Monitor. The first framework on construction costs is expected to be ready for use in December, while the second comparing return on equity and capital structures is expected by May. Because they aren’t ready for use, staff decided to keep language revisions related to frameworks out of the public version of the manual. They are being maintained in an internal version that will be brought for stakeholder endorsement once the frameworks are finalized.
“The manual is a reflection of what’s in effect today, and the comparative process is not a part of that today,” PJM’s Jason Shoemaker explained.
LS Power’s Sharon Segner, who led the campaign to get the cost containment language endorsed, said PJM would be “picking and choosing” which parts of the approved revisions it’s implementing.
“This is kind of different than what was communicated to me just a few days ago as far as the approach, so I’m just concerned,” she said.
Alex Stern of Public Service Electric and Gas, who largely opposed Segner throughout the cost containment battle, joined her in expressing concern because staff was not being clear with exactly what changes it was proposing from what was presented at the first reading last month and its meeting materials did not reflect the changes or represent the statements being made. His concern stemmed particularly from PJM’s representation that it was removing language from the manual that had received stakeholder endorsement. Withholding the language related to the frameworks from the revisions up for endorsement wasn’t clearly spelled out in the issue presentation PJM posted online prior to the meeting, and Stern questioned whether an endorsement should move forward when significant changes were being unclearly communicated immediately before the requested endorsement vote.
“This is a change also from my point of view,” he said. “I’m not clear as to why you’re carving it out.”
PJM’s Sue Glatz assured stakeholders that the withholding was limited to one section in the manual and a note would be included explaining that the material will be added later “so it’s not being lost.” She pointed out it would also be captured in the meeting’s minutes.
PJM’s Steve Herling said it wasn’t the first time staff had used this tactic, so he didn’t understand the “nervousness.” Including it now wouldn’t impact whether — or how quickly — the frameworks are completed, he said, and “it’s highly likely“ that additional manual language beyond what has already been approved will be needed to comprehensively detail the process.
“We can’t post language … [that] will cause confusion if it’s not ready to be implemented. People will be reading the manuals,” he said. “When it is ready to be implemented, it will be posted.”
“I think taking out the note causes more confusion than it helps,” Stern said. “I’m actually confused the other direction how it helps to carve this out when there is the confusion. … I’m really not sure what people are concerned about.”
Once the situation was explained, Tonja Wicks of Duquesne Light said she was supportive of PJM’s plan. American Municipal Power’s Steve Lieberman said he was “sensitive” to Herling’s points.
PJM eventually offered to remove the cost-containment language from the endorsement vote proceeding, with the Manual 14F changes focused on market efficiency procedures.
Following additional debate, Segner eventually decided to trust the process.
“I’m still a little confused, but I think we’re on the right path, and I’m going to support this today,” she said.
PJM’s Mark Sims reviewed staff’s planned timeline for implementing the cost containment measures. He explained that the comparative frameworks will help staff put proposals into a fuller context that includes constructability and financial data, along with risk evaluations.
DER Ride-through
Staff are asking stakeholders for the opportunity to investigate whether certain operating parameters for inverter-based generators create a reliability risk for the grid.
A PJM analysis shows how DERs not using ride through worsens system reliability, while using it improves reliability. | PJM
PJM’s Andrew Levitt presented a proposed problem statement and issue charge to determine whether the “ride-through” settings for distributed energy resources like residential wind and solar might create low-voltage risks. For safety and other reasons, DERs are configured to trip off within two seconds if they experience under- or over-voltage. As the amount of DERs grows, all of them tripping during such an event could exacerbate the situation. A new industry standard would address that issue by requiring DER to ride through certain system fluctuations.
Levitt had previously approached the Operating Committee in March about transmission owners taking the lead in implementing the new Institute of Electrical and Electronics Engineers standard. (See “Implementing DER Ride Through,” PJM Operating Committee Briefs: March 6, 2018.)
Normal conditions wouldn’t cause an issue, Levitt said, but “our relay clearing logic doesn’t always work correctly” and could exceed the two-second threshold.
“Really, we would need to change our planning criteria under that kind of a scenario,” he said. “Ride-through is good; lack of ride-through is bad.”
Stakeholders noted several challenges that would have to be addressed, including the safety of utility workers working on lines, engineering and regulatory differences between the transmission and distribution systems, and the appropriateness of focusing on one technology type.
PJM will be hosting a technical workshop on the issue Oct. 1-2, Levitt said.
CIRs
Staff announced that stakeholders impacted by planned revisions to how PJM calculates the output of generating units will have more than six years to prepare for the changes.
Changes planned for Manual 21 would revise and add detail to how PJM would test a generator’s output and determine its net capability each year. Among the changes, the capacity factors for wind and solar units would be calculated using the median factors instead of the average. Throughout the year, PJM’s Jerry Bell has been presenting analysis showing that the median more closely predicts actual performance than the average. (See “Skepticism of Gen Capability Changes Continues,” PJM Operating Committee Briefs: June 5, 2018.)
However, the changes would mean that affected wind and solar units would have their capacity injection rights (CIRs) reduced. The potential reductions have concerned stakeholders because they have to pay for the CIRs. Bell has said the CIRs could be reallocated to other projects, but they would be constrained to projects on the same transmission line.
In an attempt to placate the concerns, Bell announced that the changes won’t go into effect until the 2025 delivery year. Stakeholders will be alerted to CIR reductions by Aug. 1, 2024, and have to identify where they plan to move the CIRs by Jan. 1, 2025. They will then have until the end of that year to utilize them elsewhere. Any unused CIRs won’t technically be lost until June 1, 2026.
“When it comes to incorporating intermittent resources … this has always been a work in progress,” PJM’s Tom Falin said. “This is just a further refinement in that area as we have accumulated more data.”
The longer lead time seemed to have its intended effect.
“These changes are certainly much improved from the initial proposal,” Dayton Power and Light’s John Horstmann said.
TO Supplementals Discussion
PPL’s Frank “Chip” Richardson announced that TOs will be hosting an online conference on Aug. 28 to discuss additional details of their plan to implement FERC’s order from earlier this year requiring TOs to increase stakeholder engagement in the development of supplemental projects.
Supplemental projects are transmission construction initiated by TOs to address their own planning criteria and aren’t in response to any wider planning criteria. FERC determined that PJM TOs’ processes for developing those projects weren’t in compliance with Order 890, sending reverberations through several stakeholder initiatives that most recently culminated in the termination at July’s Markets and Reliability Committee meeting of a task force focused on end-of-life supplemental projects. (See PJM Stakeholders End Tx Replacement Task Force.)
ARR Analysis Finds Infeasible Facilities
PJM’s Xu Xu announced at last week’s Transmission Expansion Advisory Committee meeting that the annual analysis of stage 1A auction revenue rights found one violation within PJM’s territory and eight across flowgates to MISO. The analysis assesses the simultaneous feasibility of the ARRs’ paths for a 10-year period.
The internal violation is expected to be addressed through a project that should be in service in 2020. Proposals to address the others are being considered in interregional planning with MISO.
Cost of Dominion’s Haymarket Line Triples with Undergrounding
A decision by Virginia regulators to settle a controversy over a transmission line planned through a historical community through partial undergrounding will triple the cost of the line, staff confirmed.
A 6-mile 230-kV line planned for the area of Haymarket, Va., to feed new data centers received national attention after protesters raised concerns about Dominion Energy’s plan to site it through a historically African-American community inhabited by descendants of emancipated slaves. The Virginia State Corporation Commission stepped in to approve project revisions under a newly enacted underground transmission pilot program as part of the Grid Transformation and Security Act of 2018, which went into effect July 1.
Dominion’s supplemental project around Haymarket, Va. | PJM
The revisions will underground roughly half the project, increasing costs from an initial estimate of between $45 million and $57 million to the new estimate of $174 million.
Because the proposal was a supplemental project initiated by Dominion, PJM confirmed that the entirety of the cost will be billed back to customers in Dominion’s zone. However, that might change after the D.C. Circuit Court of Appeals rejected earlier this month PJM’s cost allocation rules for supplemental projects that involve high-voltage lines. The rule, which had prohibited cost sharing for all supplementals, was remanded back to FERC for revision. (See DC Circuit Rejects PJM Tx Cost Allocation Rule.)
WASHINGTON — Industry opinions vary on the prospects for a full-fledged RTO in the Western Interconnection, with some optimistic and others thinking there are too many snags for it to work.
But that doesn’t mean market services can’t expand there in some other form, attendees of the Western Power Issues Roundtable said last week.
The 11th annual gathering, held by the Western Power Trading Forum in the offices of law firm Skadden Arps, came after several shakeups in the interconnection this year, including SPP pressing pause on its plan to integrate Mountain West Transmission Group and the announced demise of Peak Reliability. (See Still ‘Committed,’ SPP Halts Mountain West Integration Effort and Peak Reliability to Wind Down Operations.)
SPP’s efforts took a hit in April when Xcel Energy’s Public Service Company of Colorado (PSCo) subsidiary, representing 40% of Mountain West’s load, said it would leave the group. Peak, the reliability coordinator (RC) for most of the interconnection, had been attempting to create a new energy market in partnership with PJM. But in July it said would shut down as early as next year after CAISO moved to leave and provide its own RC services, attracting interest from nearly all of Peak’s customers by offering lower-cost services.
Kenna Hagan, senior manager of planning, policy and strategy at Mountain West member Black Hills Corp., said Xcel’s announcement, made late Friday, April 20, “floored many of us.” She said she called PSCo on Monday morning, saying, “‘I’m just checking to see if your executives were participating in Colorado’s state holiday.’”
But she assured attendees that Mountain West “is not dead.” She said group members are still examining the costs and governance structure of joining SPP without Xcel, but the current priority for everyone in the interconnection, not just Mountain West, is finding a new RC provider. CAISO has said most of the interconnection have signed letters of intent with it, but Hagan said at least two balancing authorities have pledged with SPP.
“I don’t think you can underestimate the time, creativity and effort that it takes to solve” the issues related to integration, Hagan said.
Stu Bresler, PJM senior vice president of market operations, said that though it has ended its relationship with Peak, “to the extent that there is a desire for folks in the West to continue talking about the possibility of developing their own market, we’re still interested in being involved.”
The plan remains the same as before Peak’s end: provide energy, ancillary and financial transmission rights markets. Then, should members “want to go down the path of an RTO,” expand to transmission and interconnection planning.
“We certainly are not saying it’s now or never,” Bresler said. “If now is not the right time to look at this, PJM is certainly not going anywhere.”
All Eyes on California
CAISO has also suffered setbacks in its efforts to expand, but those plans now appear closer than ever to becoming a reality.
A bill that would allow the expansion, AB813, passed the California State Assembly last year, and it’s now before the State Senate’s Appropriations Committee after passing two other committees in June. (See CAISO Regionalization Bill Edges Toward Senate Vote.)
“We are still very optimistic about 813 passing this year,” said Phil Pettingill, CAISO regional integration director. The two-year legislative session ends at the end of this month. If the bill passes the Senate before then, “it’s just a matter of the two houses reconciling it and sending it to the governor.”
But many at the conference expressed skepticism that CAISO would become an RTO, even if the bill passes. The bill would only allow CAISO to expand if it agrees upon a modified governance structure — and at least one transmission owner outside the state agrees to join.
Some in the West are concerned that a new RTO would be subject to California’s influence more than any other state’s. California has been one of the most aggressive in the U.S. in trying to curb carbon emissions and address climate change, while states such as Wyoming and Utah still heavily favor coal.
Former FERC Commissioner Tony Clark, senior adviser at Wilkinson Barker Knauer, wondered, even with “the most independent board you could possibly imagine … can you still get to a broader regional market, because you still have the inherent tensions between competing state public policies, state mistrust of each other… Maybe the [Energy Imbalance Market] is as far as we get.”
Wyoming Public Service Commission Chair Bill Russell said, “It’s probably a bigger risk for California than it is for the rest of us. I think California would be giving up more than the rest of us, and I don’t know if that happens.”
He noted that California wants to offload its abundance of renewable energy. “California is trying solve a problem. … We are open to the idea of an RTO, but for us, it’s just an option. We’re not trying to solve a problem.”
Russell opened the roundtable by admitting that “everyone in this room knows more about [RTOs] than I do.” When PacifiCorp told the PSC it was working with CAISO on expansion in 2015, none of the commissioners had even heard of RTOs, he said.
Now, he said, they are watching CAISO, SPP and PJM very closely. Given the concerns over governance, “the best solution for the West might be two markets, or three, that have various comfort levels for whoever’s doing those markets,” Russell said.
[EDITOR’S NOTE: An earlier version of this story incorrectly stated that AB813 would not allow CAISO to expand unless at least one transmission owner outside the state agrees to join by the end of 2018.]
VALLEY FORGE, Pa. — PJM is hoping to simplify its communication of items that require stakeholder action through a new “stakeholder impact slide” in appropriate presentations, PJM’s Rebecca Carroll told members at last week’s Operating Committee meeting.
The slide will identify what action is needed, the deadline and which stakeholders it impacts.
“It will spell out very clearly what the action is that is required for the stakeholder,” Carroll said.
The concept will be piloted in the OC and the Tech Change Forum before it’s rolled out elsewhere, she said.
Low Frequency
Grid operators handled an unusual number and variety of issues in July, staff explained.
Chief among them was a low-frequency event on July 10 between 3 and 4 p.m. Operators had been targeting a frequency of 59.98 Hz to account for a “time error correction,” but it fell to 59.903 Hz by 3:45 p.m. The event occurred in two frequency drops, and staff are puzzled over what caused the first one.
A timeline of the July 10 low-frequency event with brief analysis of several events. | PJM
In the five minutes after 3:30 p.m., the frequency gradually dropped by 0.04 Hz, and PJM staff are working with NERC’s Resource Subcommittee to determine why. PJM’s Chris Pilong said the analysis is “not to point fingers” and that RTO tools intended to determine the cause of such issues “right now … aren’t pointing to anything.”
“It’s going to be outside the PJM system,” he said. “We’re thinking there may be some data errors in there somewhere.”
A second 0.03-Hz drop that began around 3:40 p.m. was caused by an 800-MW pseudo-tied unit tripping, Pilong said. Just before the drop, PJM initiated a synchronized reserve event, which deployed all the RTO’s synchronized reserves. PJM’s pseudo-tie error was roughly 900 MW under its target leading into the reserve event, and it dropped further down to 1,800 MW at the frequency’s lowest point.
PJM called a “simultaneous activation of reserve” (SAR) with the Northeast Power Coordinating Council at 3:50 p.m., about five minutes after the second frequency drop. The frequency rebounded to above its target level within five minutes.
Staff said the event isn’t normal but does happen every three years in the Eastern Interconnection. While this was the lowest they’d seen, it would have had to fall another 0.1 Hz for operators to call for a load action.
The puzzle for staff is what caused the initial drop, which drifted down rather than dropping immediately in a way indicative of a unit tripping.
“We drifted low. It wasn’t a step function low,” PJM’s Glen Boyle said.
Spinning Events
Grid operators also dealt with “obviously a higher volume of spinning events” than usual during July, Pilong said. The cause was multiple generators tripping, he said, but initial analysis indicates they were all unrelated. He said staff would analyze whether the system is experiencing more generators tripping or if there are any other takeaways.
“This could have just been a fluke month, or it could be a trend of something more,” Pilong said.
Load Shed
Staff confirmed that the load shed ordered July 18 was dissimilar to the load shed that occurred just months earlier in the same transmission zone.
The July 18 event occurred in the Lonesome Pine area on the border of Virginia and West Virginia after tripped equipment caused low voltage in the area. The events in American Electric Power’s zone were the first since PJM implemented Capacity Performance and its financial penalties and bonuses for generator performance during reliability events such as load sheds, though neither event triggered those calculations. (See 2nd Load Shed of PJM’s CP Era Follows Closely on 1st.)
A diagram of the area around the July 18 load shed. | PJM
Staff said the events differed in that the Lonesome Pine event was in response to actual system conditions while the previous Twin Branch event was based on concerns identified through simulations.
“That was a little more complex,” Pilong said. “This one was a little more straightforward.”
Citigroup’s Barry Trayers asked if PJM would develop additional CP event categories for situations like this with no financial repercussions. Staff confirmed the Lonesome Pine event did not create a balancing ratio since no generators were involved.
User Interface Fuel Security Changes
PJM’s Brian Fitzpatrick announced “voluntary” gas usage data requests, but stakeholders were skeptical whether the requests would be implemented that way.
Fitzpatrick said PJM is asking gas-fired generators to report through its Markets Gateway online interface all gas nominations made to the appropriate city gate. PJM is attempting to correlate the amount of gas requested at a location with its ongoing study of gas pipeline contingency plans.
“We’re not looking for what the [local distribution company] is nominating,” Fitzpatrick explained. “We’re looking for what the generators are nominating to the LDC.”
PJM’s Dave Souder confirmed that “it’s not a mandatory field” that must be completed for a generator’s energy market bid to be accepted, “but it is information we’re asking for” and staff will be contacting those who don’t comply to help them become “comfortable” with providing the information.
“It’s voluntary to the extent that if you don’t enter it, we won’t reject your bid … but this is information that we want so that we can move this gas contingency process forward,” Souder said.
SPP’s Schedule 1A Task Force last week kicked off an expected monthslong effort to develop an alternative rate structure to the RTO’s current method for recovering its administrative costs.
The Finance Committee and SPP staff have both discussed changing the fee’s billing units from transmission metrics to energy metrics by charging market transactions. The administrative fee, currently 42.9 cents/MWh, is collected under Schedule 1A of SPP’s Tariff on contracts between transmission providers and customers. (See SPP Stakeholders to Study Admin Fee Changes.)
“From an SPP standpoint, what we have now works fine,” CFO Tom Dunn told the group Aug. 8. “From a members’ standpoint, feedback indicates it’s not necessarily fine.” He said transmission customers have complained of difficulty recovering the charges “through their rate base process.”
While SPP’s costs have increased with the addition of the Integrated Marketplace, “the number of folks paying [the costs] is not necessarily growing,” Dunn said.
The task force discussed Dunn’s July presentation to the Markets and Operations Policy Committee, which led to the group’s creation. Members also took a first look at other grid operators’ recovery mechanism.
The task force is scheduled to present a recommendation to SPP’s Board of Directors and Members Committee in January.
SPP, MISO to Discuss Seams Transmission with Stakeholders
SPP and MISO are bringing stakeholders into the conversation as they continue efforts to improve transmission service along their seam.
The RTOs have agreed to remove their $5 million cost threshold and joint modeling requirement for transmission projects, two barriers that have prevented them from agreeing on interregional projects. (See MISO, SPP Loosen Interregional Project Requirements.)
The Interregional Planning Stakeholder Advisory Committee has scheduled a conference call on Aug. 27 to review with stakeholders the proposed changes to the interregional planning process.
Adam Bell, SPP’s interregional coordinator, told the Seams Steering Committee on Aug. 8 that feedback to the changes has been “somewhat split,” but staff are working to address stakeholder concerns.
“We need to move the conversation in a direction that everybody is happy with,” Bell said. He said the grid operators plan to file the revised process this year so they can begin a new study in 2019.
The RTOs are also working to schedule a meeting this fall with staff and stakeholders to further explain the January “Big Chill” and actions being taken to prevent a reoccurrence. Colder-than-normal weather and generation shortfalls in MISO South on Jan. 17 led to MISO exceeding its regional dispatch limit on transfers between its northern and southern footprints across SPP’s system.
MISO Adds $213,189 in M2M Payments to SPP
June’s market-to-market (M2M) payments between SPP and MISO came in at $213,189 in SPP’s favor. While the amount was the lowest since last August, June was also the 11th straight month and 19th of the last 21 in which the payments have been in SPP’s favor.
| SPP
The RTO has recorded $53.8 million in M2M payments from MISO since the two began the process in March 2015.
ERCOT’s Board of Directors last week approved an ISO request to correct real-time prices following a July event that caused brief market palpitations. (See “Stakeholders, Staff Discuss Price Investigation Notices,” ERCOT Technical Advisory Committee Briefs: July 26, 2018.)
The correction changes 25 security-constrained economic dispatch intervals and nine settlement intervals between 4:30 and 6:30 p.m. on July 18. The average revision across all settlement points was a $10.67/MWh decrease, while the average change in 15-minute settlement price points was a $8.78/MWh decrease.
The ISO was required to seek board approval for the price correction when staff missed a two-business-day deadline to correct the July 18 error on their own.
A data-input mistake in ERCOT’s weekly operational model resulted in two double-circuit contingencies on a 138-kV line east of Dallas being identified as two triple-circuit contingencies. Kenan Ogelman, ERCOT vice president of commercial operations, said the contingency bound when it shouldn’t have, restricting nearby generation and affecting both system prices and prices near the generating units.
The issue, which wasn’t caught until July 19, affected the July 18 real-time operating day and the July 20 day-ahead operating day. Corrected day-ahead prices were published on July 23.
Woody Rickerson, ERCOT vice president of grid planning and operations, said staff have changed the operational model’s automated process to avoid similar mistakes in the future. Each model includes about 7,000 contingencies.
“We fixed the problem; we’ve validated the contingency files; we’re moving forward with the same process,” Rickerson said.
Staff Continues Southern Cross Work
Compliance Director Matt Mereness briefed the directors on ERCOT’s progress in accommodating the Southern Cross Project (SCT), a 2-GW DC tie in East Texas that would connect the ISO with SERC Reliability Corp.
Because ERCOT’s largest existing DC tie is 600 MW, Texas’ Public Utility Commission last year directed the grid operator to address several issues as a condition for energizing SCT, asking it to respond to 14 directives (Project No. 46304).
Mereness said ERCOT has begun work on six of the directives and is engaging members through the stakeholder process. Two other directives are updates to the PUC and are ongoing.
The board approved staff’s recommendation that no protocol or binding documents concerning primary frequency response are necessary in determining whether SCT or any other entity scheduling flows across the tie should be required to provide or procure the service.
The project is scheduled to be energized in 2023.
ERCOT Reports $16.7M Net Revenue Favorable Variance
ERCOT CEO Bill Magness told the board the ISO’s revenues continue to be favorable, thanks mostly to the record demand this summer.
“It’s load and weather that drives ERCOT,” he reminded the directors.
Magness reported system administration fees were $5 million overbudget through June because of the weather and Texas’ stronger economy. Including $4.2 million in interest income, the ISO is $16.7 million above its year-to-date projected net revenues.
Staff is projecting a year-end total of $19.8 million in favorable net revenues.
ERCOT has also made “significant progress” on a delayed congestion revenue rights software update, Magness said. He said a go-live date is expected to be finalized in September, now that communication has been improved with the vendor and a better process for managing bug fixes is in place.
Special Membership Meeting to be Set
The board voted to call a special meeting of ERCOT’s corporate members “as soon as reasonably practicable” to hold votes on amendments to the ISO’s Articles of Incorporation, which has been renamed the Certificate of Formation, and to the bylaws, which clarify the definition of affiliates and affiliate relationships. The board unanimously approved both sets of amendments.
The members’ annual meeting isn’t until Dec. 11, but ERCOT’s legal department wants to ensure the amendments are effective for the 2019 membership year.
The directors also approved the 2019 schedule for board meetings and accepted a favorable audit report on ERCOT’s employee 401(k) plan.
Board Clears 15 Change Requests
The board unanimously approved its consent agenda, which included a Nodal Protocol revision request (NPRR) it had remanded back to the Technical Advisory Committee in June.
NPRR847 incorporates an intraday weighted average fuel price into the mitigated offer cap. It unanimously cleared the TAC in May, but the board sent it back over concerns that the calculation of blended fuels was “vague and confusing.” (See “Board Approves 8 Change Requests,” ERCOT Board of Directors Briefs: June 12, 2018.)
The measure is intended to ensure resources are capped at the appropriate cost during high fuel-price events and that LMPs reflect the true incremental cost of fuel.
Director Nick Fehrenbach, who represents the commercial sub-segment within the consumer market segment, said he was satisfied with the language changes. He thanked ERCOT for taking his comments into consideration.
The consent agenda also included seven other NPRRs, a revision to the Nodal Operating Guide (NOGRR), two changes to the Planning Guide (PGRRs), an update to the Resource Registration Glossary (RRGRR), a system change request (SCR) and two changes to the Verifiable Cost Manual (VCMRR).
NPRR856: Clarifies that for day-ahead make-whole settlement purposes, the “offline but available for SCED deployment” status is considered an online status and will be considered an offline status after system implementation.
NPRR862: Incorporates a number of revisions addressing recent changes made by the PUC’s rulemaking related to reliability-must-run service (Project No. 46369).
NPRR866: Addresses two objectives related to mapping registered distributed generation and load resources to transmission loads in the network operations model by codifying the existing process for mapping a load or aggregate load resource to its appropriate load point in the model; and by outlining how to map a registered DG facility to its appropriate load point in the model.
NPRR873: Outlines expectations for posting information pertaining to intra-hour wind power and load forecasts on the Market Information Systems public area. The NPRR also proposes two new definitions and acronyms for the intra-hour wind power and intra-hour load forecasts (IHWPF and IHLF, respectively).
NPRR874: Changes the “net allocation to load settlement” stability report by breaking out the load-allocated CRRs monthly revenue zonal amount from the other load-allocated charges, and by providing dollars per megawatt-hour by congestion management zone.
NPRR875: Adds clarifying language to sync the protocols with NPRR864, which modifies the reliability unit commitment engine to scale down commitment costs of fast-start resources with less than one-hour starts.
NPRR877: Allows for use of actual metered interval data for initial settlement of an operating day for electric service identifiers that currently require BUSIDRRQ load profiles.
NOGRR174: Harmonizes the automatic voltage regulator and power system stabilizer testing requirements with the recently approved NERC Standard MOD-026-1.
PGRR061: Includes locations for registered DG facilities in the annual load data request process.
PGRR062: Proposes new processes, communication and document sharing and storage requirements to be included in the new generation interconnection or change request application.
RRGRR017: Supports NPRR866 by providing a process for mapping registered DG facilities to their appropriate load points in the network operations model.
SCR796: Modifies the Market Management System’s validation rules for bids and offers to exclude resource nodes within a private-use network site as valid settlement points for day-ahead market energy-only offers and bids, and for point-to-point obligation bids.
VCMRR021: Aligns the VCM with the language proposed in NPRR847 by removing references to make-whole payments for exceptional fuel costs. The costs will be recovered in NPRR847.
VCMRR022: Directs ERCOT to contract a coal index price with a fuel vendor and includes a methodology for calculating the quarterly fuel adder for coal-fired and lignite-fired resources based on that index.
SACRAMENTO, Calif. — The state’s three investor-owned utilities want lawmakers to limit their liability for forest fires sparked by power lines, but the companies’ proposal met with stiff opposition Thursday at a capitol wreathed in smoke from fires burning in nearby mountains.
The plan, advanced by Gov. Jerry Brown at the behest of Pacific Gas and Electric and others, calls for the state to change a longstanding rule that holds private and public utilities strictly liable when electric lines cause wildfires. Under current law, the utilities must pay for all destruction of private property through the legal remedy of “inverse condemnation” if their equipment was a substantial cause of a fire.
Brown’s plan would still allow suits for inverse condemnation but would require judges to balance the public benefits of the electric infrastructure with the harm caused to private property and to determine if a utility acted reasonably in a particular circumstance. It would also require the utilities to pay proportional damages and not be entirely responsible if others were also at fault.
In addition, the proposal requires utilities to submit wildfire mitigation plans and to harden their grids with upgraded equipment more resistant to weather and fire damage.
Last year’s infernos in California’s famed wine country and the Sierra Nevada foothills resulted in billions of dollars in damage to homes, vineyards and businesses. The current fire season, which is less than half over, appears to be keeping pace.
At Thursday’s hearing, some lawmakers said the proponents’ timing couldn’t have been worse. The largest fire in state history, the Mendocino Complex Fire, raged in the coastal mountains north of San Francisco, and another major fire had closed Yosemite National Park during the peak of the summer tourist season.
The smoke from the fires turned the air in Sacramento into a yellowish haze.
“I don’t know if you noticed, but there’s smoke in the air,” State Assemblywoman Eloise Gomez Reyes told James Ralph, chief of policy and legal affairs for the California Public Utilities Commission. Ralph presented the governor’s plan on behalf of his boss, CPUC President Michael Picker.
Brown originally sent his proposal in writing to the legislature on July 24 with the understanding that it would be part of SB 901, a measure dealing with wildfire prevention. To take effect, the bill must clear the legislature by the end of August, when lawmakers adjourn at the end of a two-year session.
To that end, members of the State Senate and Assembly have held a series of conference committee hearings — on July 25, Aug. 7 and Aug. 9 — to take testimony and gather information. Powerful interests on both sides have argued for and against the proposal.
New Normal
Among those fighting the plan are ratepayer groups, the state’s trial attorneys, insurers, farmers, and cities and counties. They all stand to lose financially if the utilities are given what some call a bailout.
The utilities — PG&E, San Diego Gas & Electric and Southern California Edison — argue multibillion-dollar payouts threaten their financial stability, undercut fire-prevention efforts and result in rate hikes for consumers.
Last year’s fires, which among other damage wiped out a large area of the city of Santa Rosa, caused destruction on an unprecedented scale. Many in California attribute such long and destructive fire seasons to climate change and say they are the “new normal.” (See Wildfires Reshaping Regulator’s Role, CPUC Chief Says.)
That makes the utilities nervous because they tend to receive much of the blame and pay most of the costs.
So far, investigators with the California Department of Forestry and Fire Protection (Cal Fire) have concluded that 16 of last year’s Northern California fires were caused by trees or branches hitting PG&E power lines, along with a power pole failure and a conductor that crashed to the ground.
Eleven of the 16 cases have been referred to county prosecutors to review for possible criminal violations of a state law that requires adequate clearance between power lines and vegetation, according to Cal Fire news releases in May and June.
Altogether, the fires killed 18 residents, destroyed nearly 3,000 structures and burned more than 180,000 acres. The cause of dozens of other blazes, in what Cal Fire calls the “October 2017 Fire Siege,” remain under investigation.
‘Insurers of Last Resort’
The financial fallout for PG&E is huge. Last quarter the company posted a net loss of $1 billion and took a $2.5 billion pre-tax charge for third-party claims related to 14 of the fires. Fitch Ratings downgraded the company’s stock in February, estimating that it could face $15 billion in liability over the next 10 years.
The amount is so massive because California is the only state that relies on inverse condemnation to hold utilities primarily liable for wildfire damage, even when the companies complied with all safety requirements and were only partly to blame for fires.
The current law unjustly “makes utilities the insurers of last resort,” Henry Weissmann, a lawyer for Southern California Edison, told the legislative panel Thursday. He said utilities should be held to a negligence standard of liability, which would require proof of wrongdoing, rather than facing strict liability, which does not.
Weissmann said utilities still would have an incentive to prevent fires under the less-stringent standard because they would continue to be subject to lawsuits and government oversight.
Jan Smutny-Jones, CEO of the Independent Energy Producers Association, told lawmakers that the state’s progress in sourcing energy from geothermal, solar and other sustainable power producers was threatened by California’s insistence that utilities, and ultimately ratepayers, foot the bill for catastrophes.
“All of this is predicated on the financial stability of the companies,” he said. “If a utility goes broke … that’s a significant impact.”
Freeing up funds for fire prevention would lead to a safer state, proponents argued.
Skeptics, however, said they found it hard to believe that utilities would behave more responsibly if their potential costs were lessened.
Sen. Hannah-Beth Jackson noted that one rationale behind inverse condemnation is that utilities are given the power of eminent domain for easements on private property. They are therefore fully liable for damage to private property, she said.
“Shouldn’t we expect you’ll do everything possible to protect our property?” Jackson, also a lawyer, asked a panel of utility executives and advocates.
Another major goal of California’s policy has been to make wildfire victims whole as quickly as possible without subjecting them to years of litigation to determine negligence. Applying a strict liability standard skips that fight and moves the parties directly to the issue of damages, Jackson said.
The lawmaker said she had trouble grasping how holding the utilities to a lesser standard of liability would increase public safety, as they contend.
“Why should we reduce their liability and expect they’re going to do more with less liability?” Jackson asked. “I don’t understand the logic here.”
