SACRAMENTO, Calif. — Could PG&E’s announcement that it plans to file for bankruptcy Jan. 29 be a ploy? A lawyer representing thousands of wildfire victims said she thinks it’s quite possible.
On the steps of the California state Capitol Tuesday, former state Sen. Noreen Evans, now a plaintiffs’ attorney, said she believes PG&E won’t go through with filing for Chapter 11 reorganization at the end of the month, as it has said it would.
The utility’s move likely is an attempt to get California’s new governor, Gavin Newsom, and lawmakers to intervene, Evans said.
“I think there’s a very huge possibility they won’t file as planned,” Evans said. “It would open a can of worms.”
If PG&E, the state’s largest utility, were to enter bankruptcy, it would call into question billions of dollars in energy contracts and payments to CAISO, among other obligations. (See PG&E Meltdown Could Cost CAISO Members, Generators.)
Evans, whose former district includes areas of Santa Rosa, Calif., devastated by wildfires in 2017, is now part of a legal team representing 4,000 fire victims in the state’s catastrophic blazes during the past two years.
The ex-lawmaker joined famed PG&E foe Erin Brockovich at the Capitol to protest the utility’s alleged efforts to avoid financial liability for the Camp Fire, which killed 86 residents and destroyed the town of Paradise, Calif., in November 2018. The wildfire was by far the deadliest blaze in state history.
Brockovich urged California leaders to do more than have a seat at the table in deciding PG&E’s fate. “Be the head of the table and take control of this runaway monopoly,” she said.
Brockovich gained movie fame after she helped build a case against PG&E in the 1990s for polluting the desert town of Hinkley, Calif., with hexavalent chromium. She has remained one of the utility’s most prominent critics.
Brockovich, Evans and other victim advocates don’t want PG&E to enter bankruptcy because it would put plaintiffs and their lawyers in line for payment behind PG&E’s secured creditors. A bankruptcy judge would parcel out compensation, not jurors.
Investors, too, are arguing against PG&E’s bankruptcy plan. BlueMountain Capital, a major shareholder, sent the utility a second letter this week urging it to postpone filing for bankruptcy protection and arguing bankruptcy is unwarranted. PG&E shareholders would likely lose their investments in a Chapter 11 reorganization.
Evans and other PG&E critics, notably public interest group Consumer Watchdog, have said PG&E’s bankruptcy is a ruse to get state lawmakers to do what they wouldn’t do last year — get PG&E off the hook for billions of dollars in liability.
After the wine country fires of 2017 devastated Napa and Sonoma counties, PG&E lobbied lawmakers to overturn California’s longstanding use of inverse condemnation to hold utilities strictly liable, regardless of negligence, for damage to private property caused by their equipment.
Gov. Jerry Brown sided with PG&E last year because he was worried the giant utility would renege on the billions of dollars it plans to invest in renewable energy. In passing Senate Bill 901 last year, lawmakers didn’t alter inverse condemnation, but they provided a process by which utilities could seek long-term bond financing for wildfire debts. (See California Wildfire Bill Goes to Governor.)
The process, however, didn’t apply to 2018 fires, including the Camp Fire. Lawmakers initially showed interest in amending SB 901 to include last year’s fires but have recently backed off because of public anger against the utility.
Though state officials have yet to determine the cause of the Camp Fire, PG&E has said its transmission line sparked flames near the start of the Camp Fire on the morning it began.
PG&E announced earlier this month it would file for bankruptcy because it faces at least $30 billion in financial exposure for the Camp Fire and wine country fires. Absent state intervention, it said, bankruptcy was its only viable option.
SPP saw an increase in price spikes and overall prices during October and November thanks to above-normal scarcity pricing, according to the Market Monitoring Unit’s fall State of the Market report.
The Monitor attributed the scarcity increases to higher volatility in wind output, pointing to an increase in mid- and long-term wind forecast errors as the primary culprit. It also said a 72% increase in natural gas spot prices at the Panhandle hub ($2.13/MMBtu to $3.67/MMBtu) and unplanned generator outages or derates contributed to the uptick.
Volatility of wind output | SPP
Redispatch costs increase faster with more expensive gas until scarcity occurs, the MMU said, driving up the number of scarcity events.
“Since the scarcity caps are price-based, they are reached more frequently due to increased gas prices,” the report said.
The long-term wind forecast, used for the day-ahead reliability unit commitment’s wind output, had an average error rate of 7.8% in 2018, almost double the 2016 average of 4.3%. The mid-term load forecast, used four hours ahead of the intra-day RUC processes, had an average error rate of 4.5% last year, 28% higher than 2016’s average of 3.5%.
When large wind dips are not accurately forecasted, the market will often be short rampable capacity, the MMU said. This forces SPP operators to manually force more capacity online.
The real-time marginal energy price peaked at $1,575/MWh at 2:40 p.m. on Sept. 3. Operators responded to an unexpected sudden drop in wind output by adjusting the load offset and manually committing quick-start units. It took three intervals before prices dropped back below triple digits.
The Monitor said there is no “current answer for better forecasting” fluctuations in wind energy but noted a ramp product would “help abate these price spikes” by reducing their frequency and effects.
“By reserving ramp for unexpected conditions, such as wind drops or unit trips, the market will be better positioned when these events occur,” the MMU said.
SPP’s Market Working Group is coordinating staff’s development of a ramping product. Staff is currently testing different alternatives.
The fall report covers September, October and November. The MMU will host a webinar on Friday at 1 p.m. CT to discuss the report.
The report also indicates the following:
Energy prices have climbed slightly, with fall prices averaging around $27/MWh.
The number of intervals with negative energy prices continues to decline.
Overall congestion across the SPP footprint has declined.
Commission Welcomes Legislative Input on Energy Storage
Texas regulators last week agreed to let state lawmakers help them determine who will own energy storage devices in the ERCOT market.
DeAnn Walker, chair of the Texas Public Utility Commission, said during the commission’s Jan. 17 open meeting that she prefers to hear from legislators before developing rules, reiterating a position expressed in a recent report to the 86th Texas Legislature. (See “PUC Asks Legislators for Clarity on Battery Storage Ownership,” ERCOT Briefs: Week of Jan. 7, 2019.)
“If they don’t, we can circle back in June … because we or the legislature need to address this,” Walker said. “I’d like to give them the opportunity, because we asked them to weigh in.”
The PUC has already opened a rulemaking on energy storage ownership (Project 48023) after last year rejecting AEP Texas’ request to connect two West Texas battery storage facilities to the ERCOT grid. Transmission and distribution providers have squared off against generators over the devices’ ownership.
Walker said in the meantime she wants to start a discussion on electric vehicles and asked staff to open a project on the subject. She has suggested the PUC work with the Texas Commission on Environmental Quality in planning how the distribution system will support the charging stations’ infrastructure.
“There’s going to have to be a charging station in Marfa, Texas,” Walker said, referring to the artistic community of about 2,000 people in the West Texas desert. “No one’s going to be able to get from El Paso to [Austin] without one.”
Walker hopes to have recommendations ready for the next legislative session in 2021.
Prelim Order Sets Issues in Oncor-Sharyland-Sempra Deal
The PUC issued a preliminary order identifying issues to be addressed in proposed transactions involving Sempra Energy, its Oncor subsidiary, Sharyland Utilities and Sharyland Distribution & Transmission Services — but not before first chiding the parties for clouding the issue of who will own what and where (Docket 48929).
The companies in October announced deals worth $1.37 billion, with Sempra buying a 50% stake in Sharyland D&T and Oncor acquiring transmission owner InfraREIT. (See Sempra, Oncor Deals Target Texas Transmission.)
“It would be helpful if you could file a table” listing the assets, Walker said. “Not a chart, because your charts make no sense.”
“We could have done a better job in our application setting forth exactly what we’re asking for,” said an apologetic Lino Mendiola, legal counsel for the Sharyland companies. “It’s a complicated transaction. We recognize that.”
Of specific concern to Walker is who will own the transmission assets necessary to integrate Lubbock Power & Light into ERCOT. The PUC last year approved Lubbock’s transfer of 70% of its load from SPP into ERCOT. Coincidentally, it came during the same meeting that Sempra’s acquisition of Oncor was approved. (See Texas PUC OKs Sempra-Oncor Deal, LP&L Transfer.)
The transactions would result in Sharyland T&D becoming an indirect, wholly owned subsidiary of Oncor, owning transmission and distribution lines in Central, North and West Texas. Sharyland Utilities would remain in South Texas, with Sempra owning an indirect 50% interest.
Mendiola said the geographic split between Oncor and Sharyland complicates the situation, but that the parties had worked out an 86-14 split of assets. Most of the transmission infrastructure would reside in the north with Oncor.
“Our group wants to ensure there are not things in the transmission rates that shouldn’t be in the transmission rates,” said legal counsel Phillip Oldham, representing Texas Industrial Energy Consumers, the lead intervenor in the proceeding.
A hearing on the merits is scheduled for April 10-12.
ERCOT Governance Changes Approved
The PUC approved by consent amendments to ERCOT’s Articles of Incorporation and bylaws (Docket No. 48677). The changes were approved by more than the necessary two-thirds of the grid operator’s corporate membership in September.
CARMEL, Ind. — With spring maintenance season approaching, MISO is opening the floor to encourage stakeholders to offer ideas to address the growing divide between resource availability and need.
MISO is commencing work on longer-term solutions in its multiphase resource availability and need project, focusing on possible revisions to its loss-of-load expectation study and load-modifying resource (LMR) accreditation. It is also exploring further changes to outage scheduling, new seasonal capacity modeling and a possible development of a seasonal capacity auction. Discussions on more major changes will continue through 2019.
During a Jan. 17 Market Subcommittee meeting, Chair Megan Wisersky said the discussions are now “de rigueur” at the large public MISO stakeholder meetings.
The RTO will this month also file a proposal requiring resources to provide 120 days’ notice for planned outages, with only one “limited adjustment” to the outage schedule allowed up to 60 days before it begins. Those outages would not be permitted during predefined periods with expected low margins.
MISO had planned by April 1 to implement a firm policy of considering outages scheduled during low-margin periods as forced, impacting a resource’s accreditation. However, the RTO is now pledging to grant an exemption to outages and derates starting between April 15 and July 29 if resource owners provide two weeks’ notice and “adequate margin is projected when requests are scheduled.” The revision comes after several stakeholders this month called for less stringent rules. (See Stakeholders Press MISO for Flexibility in Outage Proposal.)
MISO market design adviser Dustin Grethen said the Market Subcommittee should now shift focus to what’s needed to meaningfully improve price signals to spur more available and flexible supply. MISO may make at least two more FERC filings, one late this year focused on resource adequacy — if needed — and one in the first half of 2020 focused on new market mechanisms.
“The start of the 2016 planning year, we saw energy offers significantly drop. We used to see about 8 GW more in energy offers,” Grethen said, adding that since that time, MISO has used less traditional sources such as wind power and reserves to cover its load and supply requirements.
Grethen said the drop coincided with EPA’s rollout of the Mercury and Air Toxics Standards, which forced many coal-fired generators into retirement.
Some stakeholders debated whether MISO should extend its official calendar summer season, pointing out that the latest maximum generation event took place in mid-September, on a blisteringly hot day but still outside of what the RTO considers summer. Outside of MISO’s peak summer season, LMRs are not required to respond to emergencies.
MISO staff said the event technically occurred in what the RTO considers fall, despite the heat.
“Timing is everything,” Customized Energy Solutions’ David Sapper commented wryly.
Sapper urged MISO to incentivize more supply by staying away from solutions that include generator penalties. “I think you’ve heard from stakeholders that we want more carrots than sticks,” he said.
CES’ Ted Kuhn asked why MISO’s LOLE study doesn’t predict likely emergency frequency when the study projects other system conditions. He said the LOLE study could be redesigned to show when and where MISO will likely face tight operating conditions.
“When is the number of emergencies more than what we really plan on?” he asked.
Sapper asked if MISO might revive discarded market ideas, such as financially binding multiday commitments.
“I think a lot of that’s to be determined,” Grethen said. He added that any solution that MISO recommends will be supported by studies and simulations.
Grethen said he would return in February for a more in-depth discussion on long-term supply fixes and a formal request for solution submissions.
NEW ORLEANS — SPP staff have been tasked with providing “at least an outline” of comments next week for submittal to EPA in response to its proposed rulemaking under Clean Air Act Section 111b.
Usha Turner, OGE Energy’s director of environmental affairs and federal public policy, appeared before SPP’s Strategic Planning Committee last week to make the request, saying that the RTO’s role as a reliability manager “carries significance” on this issue.
EPA in December proposed revisions to a 2015 Clean Air Act rule stipulating that partial carbon capture and storage (CCS) technology was the best system of emission reduction (BSER) for new coal-fired plants. Turner said the changes would mainly revise CO2 emissions limits that apply to new coal plants but pointed out that the agency is also accepting comments on the need to revise the rule to allow more flexibility in operating simple cycle combustion turbines (SCCTs).
“It would be important for SPP to engage,” Turner told the SPC during its Jan. 16 meeting. “We found in talking with the EPA last year a lack of understanding of how this market works, and why the diversity and flexibility of resources and the diversity in technology is very important in your role of providing affordable and reliable electricity in your service territory.”
The comment period is open through Feb. 21. Turner said the deadline could be delayed, however, by the partial government shutdown.
Turner said SCCTs have a rolling 12-month efficiency-based generation output limit, but if a unit exceeds this limit, it must comply with combined cycle units’ CO2 limits.
“The rule establishes output-based restrictions for simple cycle units,” Turner explained. “If you operate those units above a certain capacity factor, you must meet the emissions standards of a combined cycle unit, which, by design, is unachievable.”
“This is a pretty substantial issue,” said Golden Spread Electric Cooperative’s Mike Wise, noting his company discussed the issue with EPA recently when installing its own CTs. “We’re concerned about these rules. The pool’s need for these resources shouldn’t be unduly constrained.”
“Our area is really a good laboratory,” SPP Vice President of Engineering Lanny Nickell said. “We should not be constraining these units that absolutely keep the grid’s reliability functioning properly.”
Nickell said he wasn’t sure whether the Feb. 21 deadline would provide SPP enough time to study the rule’s impact, but he said common sense told him that “new units, more efficient and economical, are being punished.”
“I believe that’s where we end up. We’ll see more emissions,” he said.
Michael Desselle, the RTO’s chief compliance and administrative officer, reminded the SPC about the organization’s agnostic view of resources.
“If there’s any advocacy we should be talking about, it’s to leave us the flexibility in the marketplace, and the RTO, for reliability purposes,” he said. “You need a diverse portfolio of resources.”
Steve Gaw, representing the Advanced Power Alliance (formerly The Wind Coalition), said he was concerned about a lack of analysis about the rule’s impact on the market. “I’m not sure SPP should be advocating for individual companies with varied interests,” he said.
Altenbaumer Continues to Exert his Influence
Larry Altenbaumer is playing a strong hand in his first year as chairman of SPP’s Board of Directors.
In the few months since replacing Jim Eckelberger last year, Altenbaumer has revamped board meetings, shortening the duration and focusing them on strategic discussions with members and the Regional State Committee. (See “Altenbaumer Tweaks New Governance Schedule,” SPP Board of Directors/Member Committee Briefs: Oct. 30, 2018.)
Pointing to stakeholder satisfaction surveys that indicate shortfalls in strategic planning, Altenbaumer said he wants to make better use of the opportunities for the board and its interaction with the Members Committee and the RSC.
Altenbaumer has also assumed chairmanship of the SPC. Long-time committee chair Wise is now vice chair.
Altenbaumer told the SPC he will also chair a task force on affordability and value, an initiative he has been pushing since last January. He hopes the group’s work will be incorporated into SPP’s 2020 operations planning and budget cycle.
“We’ll make an assessment in October this year about what further steps might need to be addressed,” Altenbaumer said.
The task force is scheduled to hold its first meeting on Jan. 30, following the board’s regular quarterly meeting. Altenbaumer said the meetings will be “quasi closed,” with each SPP member entitled to have one representative attend.
Outside groups will be invited to present best practices and their own successful experience within other organizations, Altenbaumer said. He said the group will identify ways to better communicate the task force’s efforts and will work to “keep the RSC up to speed.”
The task force will report to the board and also includes CEO Nick Brown and Directors Bruce Scherr and Julian Brix; Markets and Operations Policy Committee Chair Holly Carias, with NextEra Energy Resources; Wise; retired Director Harry Skilton; and member representatives Darrin Ives (Evergy), Jerry Peace (OGE Energy) and Jim Jacoby (American Electric Power).
SPP staff will continue to work with members as it struggles to provide a solid foundation for validating accurate network integration transmission service (NITS) data.
COO Carl Monroe reviewed staff’s 2018 efforts in surveying customers’ understanding of their responsibility to report NITS load. He said grandfathered agreements and behind-the-meter generation have hindered integrating the reported data.
Transmission customers are legally responsible for reporting their load, Monroe said, but this information may also be provided by meter agents. He said a single NITS contract can involve multiple pricing zones, with each zone comprising multiple delivery points, and that a single transmission zone can have multiple settlement locations.
Asked by Altenbaumer how close SPP is to where it should be in reporting the data on a 1-to-10 scale, Monroe said, “Eight or 9. I’m not sure it’s a 10, but that’s a Carl Monroe sense.”
While the work is not yet complete, Monroe said he is ready to facilitate a discussion with interested stakeholders to draft a revision request for mapping NITS data.
The D.C. Circuit Court of Appeals on Friday denied a petition by North Carolina to overturn several FERC decisions that kept the state from acquiring the system of dams on the Yadkin River (17-1243).
The state has been seeking the four dams collectively known as Yadkin Hydroelectric Project No. 2197 since 2009, when previous owner Alcoa announced it would close and dismantle the Badin Works aluminum smelting plant. The Yadkin Project had powered the plant, which at its peak employed about 1,000 workers, for almost half a century.
The High Rock dam, one of four that make up the Yadkin Project in North Carolina
Alcoa started curtailing production and laying off workers in 2002 amid a downturn in the aluminum market. By the time it applied for relicensing in 2006, Alcoa was only using 3 to 5 MW of the 210.5-MW project to power the plant.
In approving Alcoa’s application in 2016, FERC denied North Carolina’s proposal that the U.S. government acquire the project and transfer it to the state, saying the company had failed to maintain the jobs at Badin Works, which had been cited as a benefit in the project’s original 1958 license (P-2197).
“The state’s proposal — albeit creative — lacked any basis in the law,” D.C. Circuit Judge David B. Sentelle wrote in agreement with FERC.
The Federal Power Act allows FERC to recommend that the federal government take over, maintain and operate hydroelectric facilities after a license expires. “North Carolina does not and cannot identify a single case, statute or regulation to provide authority” for the federal government to transfer a seized project to a state government, Sentelle said. The judge noted that the state could have filed its own application for the project with FERC, negotiated a sale or initiated a condemnation proceeding of the project.
“Thriftiness and political pressure do not create a legal basis for federal recapture when its sole purpose is transferring the hydropower project to a state,” Sentelle said. “Indeed, none exists.”
North Carolina also challenged FERC’s approval of Cube Yadkin Generation’s $243 million purchase of the Yadkin Project in 2017, a challenge the commission also denied. The state alleged that Alcoa misled the state and other potential applicants for the project into thinking the company intended to continue operating Badin Works.
“Alcoa disclosed the curtailment of industrial production at Badin Works every step of the way, from its initial filing of intent to relicense, through its various correspondences with FERC, to the license application itself,” Sentelle said. “The loss of jobs from the closure of Badin Works is a dark and menacing cloud that hangs over the state of North Carolina. However, Alcoa did not conceal this impending squall and, thus, FERC did not err by denying North Carolina’s request to reopen licensing.”
The state attorney general’s office could not be reached for comment Monday because of the Martin Luther King Jr. Day holiday.
Though it is no longer the owner of the Yadkin Project, Alcoa still owns the land bordering the river, though it agreed to sell it as part of FERC’s approval of its relicense application. Local conservation group Three Rivers Land Trust is raising money to purchase an initial 2,310 acres of land by September so it will be granted an additional two years to purchase the remaining 2,390 acres.
FERC last week authorized both ITC Midwest and American Transmission Co. to recover all of their “prudently incurred costs” if the Cardinal-Hickory Creek project is abandoned or canceled for reasons beyond their control (ER19-355, ER19-360). Both companies filed for the rate incentive in November.
“We agree that the project faces certain regulatory, environmental and siting risks that are beyond the control of management and which could lead to abandonment of the project,” FERC said.
Cardinal-Hickory Creek line route | ATC
The commission said the $500 million project meets the criteria for the abandoned plant incentive because it had been found to enhance reliability and reduce congestion through MISO’s annual Transmission Expansion Plan.
One of MISO’s 2011 multi-value projects, the 345-kV line will consist of 102 to 120 miles of transmission from southern Wisconsin to eastern Iowa with multiple substation updates. The project is intended to transport wind power and lessen the burden on existing 345-kV and 138-kV lines in the area.
Construction of the line is currently in a holding pattern because of the ongoing partial federal government shutdown. The Wisconsin State Journal reported that six public meetings Jan. 22-29 regarding the line’s environmental impact have been canceled. The U.S. Department of Agriculture’s Rural Utility Service had been conducting an environmental review of the line before the shutdown. The meetings cannot be rescheduled until the government reopens.
SACRAMENTO, Calif. — CAISO market participants and companies that do business with Pacific Gas and Electric could end up paying a hefty price for the giant utility’s financial collapse.
Other CAISO members are worried that PG&E, which plans to file for bankruptcy on Jan. 29, could default on its payments to the ISO and the Western Energy Imbalance Market, leaving other members to foot the bill.
PG&E’s financial collapse is being managed from its headquarters at 77 Beale St. in San Francisco.
PG&E’s troubles also have fueled talk of a wide-ranging ripple effect, particularly regarding the renewable power generators from which the utility has contracted to buy billions of dollars worth of electricity.
CAISO has tried to relieve members’ concerns about a potential default, saying PG&E has enough collateral to cover its debts and future payments.
“The California ISO has received inquiries relating to the financial status of Pacific Gas and Electric Co. in light of recent media reports,” it said in a Jan. 11 market notice. “The ISO wants to assure market participants that PG&E has posted collateral with the ISO to cover its outstanding and upcoming obligations.”
But one market participant, a major player in the West, told RTO Insider it could end up paying hundreds of thousands of dollars a month to the ISO if PG&E defaults. The representative spoke only on the condition of the utility’s anonymity.
In response to an inquiry from RTO Insider, the ISO said it couldn’t reveal the amount or type of PG&E’s collateral, calling the information confidential. CAISO officials declined an interview request. “We have shared all we can on this subject,” an ISO spokeswoman wrote in an email.
PG&E did not respond to a request for comment.
Scott Miller, executive director of the Western Power Trading Forum (WPTF), said he thought there was little chance PG&E would default on its CAISO payments.
“When it comes to CAISO charges, you’ve got to be concerned,” Miller said. “But because it’s necessary for the grid to operate, and PG&E wants to emerge from bankruptcy as a going concern … I suspect that would be the last thing they wouldn’t pay.
“Defaulting on the CAISO charges could cause all sorts of financial shortfalls in CAISO, and that has reliability implications,” he added. “I just don’t think PG&E would not pay its CAISO charges.”
Scott Miller, executive director of the Western Power Trading Forum, says PG&E is unlikely to default on its CAISO obligations. | WPTF
Miller served until 2017 as a senior market adviser in FERC’s Office of Energy Policy and Innovation where he worked on RTO credit reforms. He said RTOs and ISOs have assumed roles as financial clearinghouses, for which they’re not ideally suited.
It could cast some doubt on whether CAISO can adequately assess PG&E’s creditworthiness, he said.
PJM has been scrambling to strengthen its credit policies following the collapse of GreenHat Energy, whose default is expected to cost members more than $100 million.
“This is an area that’s problematic for RTOs,” Miller said. “They’re extending credit and taking risk. That’s not in their traditional wheelhouse. They’re not in as strong a position as a clearinghouse normally is for assessing credit risk.”
Ripple Effect
PG&E, California’s largest utility, has seen its fortunes fall since the catastrophic wildfires of 2017 and 2018, for which it has received much of the blame. That blame was based on state investigations in some cases, and circumstantial evidence mixed with public distrust in others.
The utility’s stock price plummeted from more than $70/share prior to the 2017 fires in Northern California’s prized wine country to slightly more than $6/share following November’s Camp Fire, the deadliest in state history. The roughly 90% collapse in PG&E’s stock price represented a $33 billion loss in market value.
The utility announced Jan. 14 it would file for bankruptcy by the end of the month because it was facing at least $30 billion in wildfire liability. At least 750 lawsuits have been filed against it on behalf of nearly 5,600 plaintiffs, it said. (See PG&E Files Bankruptcy, as CEO Steps Down.)
On Wednesday, S&P Global Ratings further downgraded PG&E’s credit rating from CC to D status, the lowest grade used by the major ratings firms. The downgrade was based on PG&E missing a $21.6 million interest payment on $800 million in senior notes.
“We do not expect the company to make this payment during the [30-day] grace period given the company’s announcement that it expects to file for bankruptcy protection and commence a reorganization under Chapter 11 of the U.S. Bankruptcy Code,” S&P said in a news release.
The fallout from PG&E’s bankruptcy announcement is already beginning to hit its renewable suppliers.
“PG&E is the biggest utility in the biggest market in the West. It’s not just the RTO activities that people are concerned about,” Miller said. “It’s the bilateral contracts they’ve got for resource adequacy — renewable contracts, storage contracts, things like that.”
One generator, the 550-MW Topaz Solar Farm owned by Berkshire Hathaway Energy, recently had its credit rating downgraded to junk status — the same as PG&E’s — because it had signed an exclusive 25-year power purchase agreement with the utility, and analysts said it might not get paid. (See PG&E’s Credit Woes Spread, Worrying CAISO Members.) Also downgraded was NextEra Energy’s 250-MW Genesis concentrating solar thermal plant, built in 2007. PG&E is its sole purchaser.
PG&E reported to FERC in its 2017 Form 1 filing that it had signed about $40 billion in PPAs covering 2019 to 2043, including agreements to buy approximately $34.5 billion in renewable energy such as wind and solar.
In 2017, PG&E generated about 53% of its 61,397 GWh in bundled retail sales according to a security filing, with purchases making up the remainder. PPAs represented $42 billion of the company’s $78.8 billion in contractual commitments as of the end of 2017.
Once in bankruptcy, PG&E could attempt to cancel or renegotiate these contracts. Analysts say generators with above-market contracts signed years ago will be most vulnerable to having their prices reduced.
Credit Suisse analysts estimate that PG&E could save $2.2 billion a year by renegotiating its renewable contracts to current market prices, The New York Times reported. The analysts said PG&E is paying Consolidated Edison solar plants an average of $197/MWh, almost eight times the $25 to $30/MWh new solar plants are charging.
Jan Smutny-Jones, CEO of the Independent Energy Producers Association, said in an interview that his organization will push PG&E to honor its commitments to generators.
IEP sent a letter to California’s political leaders Jan. 15 urging them “to seek immediate assurance from PG&E that its energy-supplier contracts will be affirmed and that generation interconnection deposits supporting new renewable energy projects will be protected and used to develop the transmission upgrades necessary to interconnect those projects.”
Evaluating Exposure
While CAISO has said little publicly about the potential effects of PG&E’s meltdown, conversations are going on behind the scenes as market participants try to sort out their exposure.
The market participant that spoke to RTO Insider on background, for example, said it had been struggling to determine how much collateral PG&E had posted with CAISO and whether other participants would be obligated to pay its share and for how long.
Another concern is the tens of millions of dollars in grid management charges (GMCs) that PG&E pays to CAISO each year, for which other members also could find themselves on the hook. In 2017, PG&E paid $51 million to CAISO in GMCs. Those grid fees fund the ISO’s fixed revenue requirement and any default must be covered by other participants.
Fallout from a PG&E default could spread to the Western EIM as well. Because the EIM falls under CAISO’s Tariff, EIM members have an obligation to cover defaults, similar to other CAISO members, in proportion to their market activity. Their voluntary day-to-day participation in the EIM, however, could allow them to reduce transactions to minimize exposure, and even ultimately withdraw from the market.
CAISO members whose assets are controlled by the ISO have no such recourse. They must cover a defaulter’s payments under the ISO’s tariff provisions once the defaulter has exhausted its collateral or “financial security.”
The ISO’s tariff provisions on creditworthiness require participants without unsecured credit to post collateral in the form of “an irrevocable and unconditional letter of credit issued by a bank or financial institution,” a prepayment to the ISO or a combination of the two. It remains unknown what kind of security PG&E posted.
CAISO requires financial security sufficient to cover a participant’s “estimated aggregate liability,” which represents all unpaid obligations plus five trading days, providing the ISO a cushion before the participant responds to a call for additional collateral within the required two business days. Posted collateral must be sufficient to cover other liabilities as well, such as a congestion revenue rights portfolio that has gone into the red.
In a situation where a market participant defaults on its payments to the ISO and has no collateral left, section 11:29:17 of the CAISO Tariff lays out a process by which the ISO can spread the costs to other members proportionally based on their market activity. Section 29.11 of the Tariff stipulates that those provisions also apply to EIM members.
Another potential consequence of PG&E’s bankruptcy: CAISO’s own financial position could be adversely affected.
In awarding the ISO an A+ credit rating in 2016, Fitch Ratings said one of the key factors it considered was the “solid credit profiles of California’s three largest investor-owned utilities.”
That was before S&P and Moody’s Investors Service stripped PG&E of its investment-grade credit status, downgrading it to “junk” because of its dire financial outlook from the fires and the fact that California politicians weren’t riding to its rescue, as some had expected.
S&P still gave CAISO an A+ credit rating as of Thursday. CAISO’s current annual debt service costs of $16.9 million are well below the 2006 peak of $80 million, and the 2009 construction of the ISO’s Folsom headquarters accounts for most of its $181 million (as of 2017) in long-term debt.
‘Out the Window’
State Assemblyman Chris Holden, chairman of the Utilities and Energy Committee, who co-authored last year’s Senate Bill 901 to aid PG&E, said he wasn’t inclined to do more right away.
SB 901 contained provisions allowing the state’s IOUs to issue long-term bonds, with approval of the California Public Utilities Commission, to cover costs of the 2017 fires. Holden had said he intended to offer legislation to make the bill’s provisions applicable to the Camp Fire and other 2018 fires. A PG&E bankruptcy wouldn’t be good for the state or its ratepayers, he said.
Holden recently backed away from that effort, telling the San Francisco Chronicle, “Our purpose was to keep PG&E from going into bankruptcy, but that’s out the window now. Now the courts are getting out in front.”
CARMEL, Ind. — Staff engaged in MISO’s ongoing market system replacement will this year focus on moving the platform to the cloud and creating a single means of submitting modeling data, stakeholders learned last week.
MISO plans to move its system from a server-based platform to the cloud some time in 2020, IT Senior Director Curtis Reister said during a Jan. 17 Market Subcommittee meeting. The RTO will phase in use of the new system gradually from 2020 to 2024.
“We’re going to do what’s called a private cloud,” Reister said.
He explained that while the cloud platform will function like a public network to staff, equipment to support it will be built solely for MISO and be kept on RTO premises, keeping systems more secure.
The new platform will be designed to accommodate market changes more quickly, Reister said. “With a big monolithic system like today, it is difficult to find the impacts of even a modest change.”
By 2021, the cloud-based platform will also include a “model manager,” a single integrated system for model data submission and validation. MISO currently relies on several different means to collect and process grid information for modeling.
“The model data comes in through a lot of different sources. We’re looking at a much more seamless way to gather and verify that information,” Reister said.
Also by 2021, MISO will launch a new user interface for members to submit market transactions such as bids and offers.
MISO plans to update the current interface early this year to address browser incompatibility, behind the originally scheduled release in late 2018. Members have reported having to rely on old versions of web browsers to use the current interface.
Stakeholders asked for an update on current vendor General Electric’s overall performance on the early stages of the multilevel project.
“We’re currently on schedule with our deliveries with GE,” Reister said in response to stakeholder inquiries about the company’s performance. GE has steadily shown it has the resources and ability to meet the RTO’s demands, he added.
MISO continues to “monitor” news around GE and the company’s performance, Reister said. Last week, at least one financial analyst predicted that GE’s financial performance will begin to rebound.
The RTO has said it will not announce a recommended final platform vendor until the fourth quarter, when it finishes evaluating alternatives. (See “Market Platform Replacement Enters Year 3,” MISO Board of Directors Briefs: Dec. 6, 2018.)
MISO has committed to another stakeholder update of its platform replacement in April.
At Least 1 Market Project Delay
While MISO expects to continue carrying out improvements to its current platform, at least one market upgrade will be placed on hold until the new system is operational.
Implementation of more sophisticated modeling software that can accommodate different combinations of combined cycle units and their dependencies will be postponed until mid-2023, MISO said. The RTO originally planned to have the improvement in place by 2020 but last year announced a delay until 2022. (See MISO Delays Combined Cycle Model Update.)
MISO Executive Director of Market Operations Shawn McFarlane said there are “technical issues in installing it on the legacy system,” explaining that day-ahead market clearing could experience delays if the project were implemented in the current system.
Director of Market System Enhancement Dhiman Chatterjee said market systems would experience a “significant amount of uncertainty” if the RTO implemented combined cycle modeling on the existing platform.
However, MISO’s proposed, short-term reserve product, which will furnish capacity within 30 minutes, will still move ahead as planned, supported by the current market platform. The RTO hopes to roll out the new type of reserve in mid-2021.
MISO last week published a conceptual design of short-term operating reserves in which online and offline resources can either register as a supplier or provide availability through hourly offers in the day-ahead and real-time markets. Resources would clear according to opportunity costs, offer prices and a demand curve when insufficient amounts of the reserves exist. Clearing resources will be paid their respective zonal market clearing prices. The early design doesn’t account for participation by storage resources, but the RTO said later versions will include storage participation “where appropriate.”
MISO said 30-minute operational needs are “not efficiently modeled” in the current market, and that a new reserve product would help better manage its Midwest-South contractual limit on SPP’s transmission, manage constrained load pockets and meet systemwide energy needs even during times of load and supply volatility. The new reserve type would be especially helpful in MISO South, where operators rely on less transparent out-of-market commitments to address the Midwest-South transfer constraint and load pocket needs.
CARMEL, Ind. — MISO last week posted draft 2019/20 Planning Resource Auction data that are virtually unchanged from last year’s early predictions.
The RTO released the data as it prepares for its usual spring resource adequacy activities, including organizing its annual resource adequacy survey.
MISO is currently forecasting a 121.6-GW systemwide coincident peak and 125.3-GW total zonal coincident peak for the planning period. It also estimates an approximate 134.4-GW planning reserve margin requirement and a combined 152.6 GW in local resource requirements. The estimates are subject to change, but they don’t materially stray from last year’s preliminary data reflecting low demand but declining margins. (See MISO RASC Briefs: Little Change to Capacity Forecasts.)
Speaking at a Jan. 16 Resource Adequacy Subcommittee meeting, Tim Bachus, MISO capacity market administration analyst, said he doesn’t expect much change to the data through March, when auction numbers will be finalized.
This year’s auction conduct threshold, calculated as 10% of cost of new entry, ranges from $22 to $25/MW-day depending on zone, Independent Market Monitor staffer Michael Chiasson said.
Late last year, MISO said it would require a 16.8% planning reserve margin requirement for June 2019 to May 2020. At the time, it said it had nearly 154 GW of installed capacity on hand to meet the requirement.
Meanwhile, the RTO will send voluntary surveys to market participants by late March as part of its annual resource adequacy survey with the Organization of MISO States. Completed surveys are due back April 15. Results of OMS-MISO surveys are typically released in June.
“The last decade has seen a lot of changes in our fleet mix … and this survey is an important tool to continue dialogue on the change,” MISO resource adequacy team member Stuart Hansen said of the survey.
