Arkansas Public Service Commissioner Lamar Davis has resigned to take a newly created position as executive director of government and regulatory affairs for MISO’s South Region.
Beginning Dec. 1, Davis will serve as MISO’s main liaison with state regulators, lawmakers and governors within MISO South, the RTO said Nov. 28. Davis resigned from the PSC effective Nov. 25.
Davis is the third former state regulator to join MISO’s staff since last year, following Vice President of Government and Regulatory Affairs David Boyd, who joined the RTO in 2015 after eight years on the Minnesota Public Utilities Commission, and former Public Utilities Commission of Ohio Chairman Andre Porter, who resigned to become vice president and general counsel in May. (See Former PUCO Chairman Andre Porter Joins MISO.)
“MISO is truly honored and excited to have Lamar join our team,” said Todd Hillman, vice president of MISO’s South Region. “We look forward to Lamar representing MISO South and the work we are doing to facilitate collaboration among state regulators, policymakers and stakeholders.”
Prior to his appointment to the PSC in January 2015, Davis served eight years as deputy chief of staff under former Arkansas Gov. Mike Beebe. Davis was also an assistant attorney general in Arkansas’ Consumer Protection Division, taught consumer law at the William H. Bowen School of Law in Little Rock, Ark., and served as a law clerk for the Arkansas Court of Appeals.
“These roles have afforded me the opportunity to work with countless public servants to serve the people of Arkansas, which has been very rewarding,” Davis said in a PSC statement. “I now have been offered a position in the private sector that will afford me the opportunity to champion policies to help advance the goals of our beloved state and region.”
Davis received his law degree from Bowen and a bachelor’s in political science from Dillard University in New Orleans.
New York’s highest court ruled Monday that the Indian Point nuclear plant is subject to state coastal waters rules — a potential hurdle in Entergy’s bid to extend the plant’s operating licenses.
The unanimous Court of Appeals ruling said that Entergy must obtain a Department of State permit under the state’s Coastal Zone Management program. Indian Point Units 2 and 3 are on the banks of the Hudson River, 30 miles north of New York City.
“In sum, the Department of State’s interpretation of the exemptions in the Coastal Management Program, and its conclusion that Entergy’s application to relicense the nuclear reactors at Indian Point is subject to consistency review, are rational and must be sustained,” the court said.
New York’s CMP, adopted in 1982, includes protections for fish and wildlife while also “meeting public energy needs in an environmentally safe manner,” according to the opinion.
License Extensions
The plants were licensed by the U.S. Nuclear Regulatory Commission in the early 1970s and are operating under extensions while the commission reviews their applications for 20-year license renewals.
Entergy applied for the license renewals in 2007 and initially conceded that its application was subject to the state review under the CMP. In 2012, however, Entergy changed its position, arguing that the plants were grandfathered.
The court disagreed, saying that relicensing applications require new permits. Nuclear power plants’ use of state waterways is listed as a regulated use.
Indian Point Nuclear Power Plant
“Entergy is reviewing the court’s decision to determine its next steps, which could include refiling its Coastal Zone Management application that Entergy previously withdrew pending issuance of the NRC’s final supplemental environmental impact statement,” the company said in a statement. “Notwithstanding this court decision, we continue to believe we will ultimately be successful in obtaining a CZM permit and relicensing Indian Point. The facility continues to safely operate in a manner that is fully protective of the Hudson River and in compliance with state and federal law.”
The 16-page decision overturned a previous ruling from an Appellate Division court, which sided with Entergy.
The state’s objections to Indian Point will now be considered as part of the record for federal relicensing. However, if the state eventually denies a coastal certification, the plant owner could appeal to the U.S. Department of Commerce, which could override the state’s action, according to the decision.
Entergy also has a concurrent challenge pending in the U.S. District Court for the Northern District of New York. It sued New York in January, claiming the state’s attempts to require a CMP review intrudes on federal jurisdiction.
According to Entergy’s 2016 Form 10-K, New York is citing “nuclear safety concerns.”
That is a persistent complaint after a series of mishaps occurred in recent years at the plant.
“Indian Point is antiquated and does not belong on the Hudson River in close proximity to New York City, where it poses a threat not only to the coastal resources and uses of the river, but to millions of New Yorkers living and working in the surrounding community,” Gov. Andrew Cuomo said in a statement.
Entergy also has been challenging New York’s contention that closed-cycle cooling would be the “best technology available” for addressing concerns over the impact of the nuclear plants’ cooling water intakes on aquatic life.
The company has estimated that retrofitting Indian Point with cooling towers would cost more than $1.2 billion. The company proposed as an alternative the use of cylindrical wedgewire screens at an estimated cost of $250 million to $300 million.
Because of the uncertainty over whether it will succeed in relicensing, Entergy said it may enter into fewer unit-contingent forward sales contracts for output from the plants.
The Organization of MISO States was unable to achieve consensus on a response to a five-question survey asking how MISO should revise its cost allocation procedures, Wisconsin Public Service Commission staffer Randel Pilo said Tuesday.
During the Nov. 22 OMS Board of Directors conference call, Pilo said that although state regulators were not able to reach unanimity on possible revisions to MISO’s cost allocation methodology, the discussion was a “helpful exercise.”
In multiple recent stakeholder meetings, MISO expressed a desire to work on cost allocation revisions through 2017 and implement the change by 2018, when Entergy’s integration transition period — which limits cost sharing in MISO South — expires. (See MISO Stakeholders Propose Changes to Market Efficiency Cost Allocation Process.)
The RTO circulated a five-question survey on market efficiency project cost allocation in October, which asks:
Should MISO allocate all costs to benefiting local resource zones for economically beneficial projects lower than 345 kV?
Should MISO investigate additional quantifiable benefit metrics in addition to adjusted production costs for market efficiency projects?
Should MISO allocate all costs to benefiting local resource zones for economically beneficial projects lower than 345 kV?
Should MISO allocate all costs to benefiting transmission pricing zones for economically beneficial projects lower than 345 kV?
Should MISO allocate all costs to a blend of benefiting local resource zones and transmission pricing zones for economically beneficial projects lower than 345 kV?
Pilo said states are “nervous” about a blend of allocation to local resource zones and transmission pricing zones.
MISO will share and go over individual state responses at the Dec. 13 Regional Expansion Criteria and Benefits Working Group meeting and use input to make a conceptual proposal.
Pilo also noted that the questions were close-ended, and some states used an all-no answer strategy in the hopes of getting MISO to pay attention to their written responses.
“Moving forward, MISO has built in a year’s worth of time … and is planning on filing a process with FERC in December 2017,” said David Carr of the Mississippi Public Service Commission.
OMS Executive Director Tanya Paslawski also said work continues on the organization’s 2017 strategic initiative document, which identifies long-term goals similar to the 2016 document. Paslawski said the new document is set to be approved before the new year.
Paslawski also said OMS will adopt a banking resolution Dec. 1 to allow incoming OMS president and Indiana Utility Regulatory Commissioner Angela Weber to sign off on banking transactions. OMS voted to approve Weber as president at its annual meeting in October. She will replace current president and Michigan Public Service Commission Chair Sally Talberg in January.
President-elect Donald Trump said Tuesday he has an “open mind” on humans’ role in global warming, appearing to soften his campaign pledge to withdraw the U.S. from the Paris Agreement.
Trump made his comments in an interview with editors and reporters of The New York Times.
Asked by columnist Thomas Friedman if he would “take America out of the world’s lead of confronting climate change,” Trump responded that he is “looking at it very closely,” adding “I have an open mind to it.”
“I absolutely have an open mind. I will tell you this: Clean air is vitally important. Clean water, crystal clean water is vitally important. Safety is vitally important,” Trump said.
Editorial page editor James Bennet asked, “When you say an open mind, you mean you’re just not sure whether human activity causes climate change? Do you think human activity is or isn’t connected?”
Trump responded: “I think right now … well, I think there is some connectivity. There is some, something. It depends on how much. It also depends on how much it’s going to cost our companies. You have to understand, our companies are noncompetitive right now.”
Methane flaring | Bureau of Land Management
White House correspondent Michael Shear followed up with a question about the potential of foreign leaders to impose tariffs on American goods to offset the carbon that the U.S. had pledged to reduce.
“I think that countries will not do that to us,” Trump responded. “I don’t think if they’re run by a person that understands leadership and negotiation, they’re in no position to do that to us, no matter what I do. They’re in no position to do that to us, and that won’t happen, but I’m going to take a look at it. A very serious look. I want to also see how much this is costing, you know, what’s the cost to it, and I’ll be talking to you folks in the not too distant future about it, having to do with what just took place.”
Trump did not specifically mention EPA’s Clean Power Plan, which he has vowed to block. Still, his moderate tone was a marked contrast to his previous bombast on global warming.
In a 2012 tweet, he called climate change a hoax created “by the Chinese in order to make U.S. manufacturing noncompetitive.” During the campaign, he said he would “cancel” the U.S.’s involvement in the Paris Agreement, which aims to limit global warming to 1.5 degrees Celsius above preindustrial levels. (See CPP, FERC’s Bay, Honorable Among Losers in Trump Win.)
But in a video released Monday, Trump also made clear that he will steer a different course than President Obama on energy policy, renewing his promise to “cancel job-killing restrictions on the production of American energy, including shale energy and clean coal.”
Trump and the Republican Congress could use the Congressional Review Act to cancel some of the Obama administration’s most recent regulations, including a Nov. 15 Interior Department rule requiring oil and gas producers to use “currently available technologies and processes” to cut methane flaring in half at oil and gas wells on federal and Native American lands.
The act allows an incoming Congress to reject regulations finalized within 60 days of the end of either the House’s or Senate’s sessions.
The Congressional Research Service has concluded the act would apply to regulations finalized after May 30, if Congress holds no more sessions this year, The Washington Post reported Wednesday.
In contrast, an EPA regulation intended to reduce methane gas leaks was finalized on May 12, making it likely exempt from being reversed under the act, the Post reported. EPA said the rule, designed to reduce methane emissions from new or modified oil and gas wells, will prevent 11 million metric tons of carbon dioxide equivalent emissions by 2025.
A consumer advocacy group filed a complaint with FERC on Monday saying PJM’s recent rate-increase request is “unprecedented” and failed to consider mitigating costs by limiting employees’ pay increases (ER17-249).
Public Citizen’s Energy Program, based in D.C., filed the complaint in response to a member fee increase that PJM stakeholders approved in October. (See “Members Committee Endorses Revised Fee Hike,” PJM Markets and Reliability and Members Committees Briefs.)
It asks FERC to deny the rate filing “until PJM offers options on controlling certain expenses.”
The complaint argues that the largest factor necessitating the increase is accommodating PJM’s projected 4.8% average annual growth rate in the financial compensation paid to PJM employees over the next eight years.
“PJM already commands premium salaries paid to its employees, particularly to its top executives,” the complaint contends. “For many of Public Citizen’s members, it remains a tough economy. There aren’t many industries or companies within PJM’s service territory that are projecting a 4.8% annual growth rate for employee financial compensation over the next eight years.”
| PJM
“The impact on consumers of PJM’s proposed administrative rate revisions is 7 cents a month, phased in over eight years,” PJM spokesperson Paula DuPont said in an emailed statement. “Consumer advocates representing the PJM region support our proposal and were involved throughout its development. The proposal was unanimously approved by members.”
Public Citizen argues that neither PJM nor its stakeholders — which include state consumer advocates — “ever formally considered dampening growth in employee compensation as a measure to mitigate the rate hike.”
West Virginia Consumer Advocate Jacqueline Lake Roberts defended PJM’s request in a response to the complaint, also filed Monday. Consumer advocates are “active participants” in PJM’s stakeholder process and aren’t treated differently than other members, Roberts wrote in the response.
“As the steward of consumer interests, [Roberts ] takes rates and proposed increases very seriously,” the response reads. “[Roberts] believes that the stated rate as filed will ensure that consumers continue to benefit from these services. For these reasons, [Roberts] submits that the allegations of Public Citizen are erroneous.”
A representative of the Pennsylvania Office of Consumer Advocate was on PJM’s Finance Committee, Roberts noted, and the committee considered several proposals before unanimously endorsing the one filed with FERC — however, all of them assumed cost increases that necessitated rate increases.
While Public Citizen’s complaint said PJM employees “deserve praise and respect for administrating duties on behalf of FERC under the Federal Power Act,” it also noted that PJM’s audited financial reports indicate employee financial compensation grew from more than $98 million in 2011 to more than $124 million in 2015, for an average annual growth rate of 6.1%. Over this five-year period, employee compensation grew from 35.6% of total PJM expenses in 2011 to 37.4% in 2015.
PJM’s request doesn’t detail other “concerning” expenses, the complaint says, such as payments to outside political lobbying organizations and “expensive social events available to select PJM members.”
Public Citizen says it has tried to become a voting PJM stakeholder, but it can’t afford the RTO’s $2,500 annual membership fee.
“It’s certainly easier to balance budgets if you can tap into a pile of someone else’s money to close the gap,” Tyson Slocum, Public Citizen’s Energy Program director, said in an emailed statement.
“The right thing to do would be for PJM to shrink its out-of-control growth in executive pay,” he said. “FERC should not allow PJM to pay for excessive executive compensation through an unprecedented hike in electric rates paid by household consumers. PJM must learn fiscal discipline and recognize that its salary structure is bloated.”
With winter looming, FERC last week adopted a rule that would double the “hard” offer cap for day-ahead and real-time markets to $2,000/MWh in every RTO and ISO.
Order 831 was a response to the 2013-2014 polar vortex, which caused natural gas price spikes that left some generators in the Northeast complaining they were unable to recover their costs (RM16-5).
The commission also noted that the $1,000/MWh offer caps effective in most RTOs could suppress LMPs below the marginal cost of production “given that recent history demonstrates that resource short-run marginal costs can exceed” that cap.
“We find that the currently effective offer caps may prevent a resource from recovering its short-run marginal costs, which could result in that resource operating at a loss,” the commission said in its decision to adopt the rule.
The commission’s revised offer cap rule sets out three requirements:
Incremental energy offers must be capped at the higher of $1,000/MWh or a resource’s cost-based energy offer, with $2,000/MWh being the maximum bid.
An RTO must verify the costs underlying a resource’s bid above $1,000/MWh before that offer can be used to calculate the market-clearing LMP.
All resources — regardless of type — will be eligible to submit cost-based incremental energy offers in excess of $1,000/MWh.
The final rule modifies FERC staff’s original proposal, which would have converted the current $1,000/MWh cap into a “soft” cap — without implementing a new hard cap. (See FERC Proposes Uniform Offer Caps Across RTOs.)
The commission said the absence of a hard cap could be problematic for RTOs and their market monitors, who might have only “imperfect information” ahead of the market clearing process to verify the short-run marginal costs for resources bidding above $1,000/MWh.
“While a hard cap may diminish the ability to fully address the shortcomings of current offer caps identified above in all circumstances, we find that, on balance, a hard cap is necessary to reasonably limit the adverse impact that any imperfect information during the verification process could have on LMPs,” the commission said.
Opposing the rule was CAISO, which said that the current $1,000/MWh ceiling far exceeds the highest cost-justified offer from any ISO resource. CAISO further contended that any natural gas-driven price spikes would be too infrequent and short-lived to warrant a change. ISO-NE said it saw no need to increase the cap, but it didn’t contest the rule change.
Market monitors for ISO-NE and SPP also protested, arguing that new sources of gas supply have provided sufficient stability in fuel prices in recent years.
The commission dismissed those contentions, pointing out that three RTOs — PJM, MISO and NYISO — had made previous filings to temporarily waive or change the level of their offer caps.
“The waiver requests and high natural gas costs experienced during the polar vortex, which could have caused some resources to experience costs above $1,000/MWh, demonstrate that the deficiencies of current offer caps, in particular the $1,000/MWh offer cap, are concrete rather than hypothetical.”
In its Nov. 17 presentation to the commission explaining the rule, FERC staff made the case for applying the change to all organized markets.
“Adopting the same offer cap structure in each RTO and ISO would avoid seams issues that could arise if offer caps differ materially across markets,” staff said.
The new rule will be effective 75 days after publication in the Federal Register.
A U.S. appeals court last week ruled Energy Future Holdings must pay hundreds of millions of dollars to certain bondholders, adding a cloud of uncertainty to the bankrupt company’s attempts to emerge from Chapter 11 protection.
Lamar Plant | Luminant
On Thursday, the 3rd Circuit Court of Appeals in Philadelphia reversed lower court decisions and directed EFH to pay holders of the company’s first-lien and second-lien notes. The bondholders had argued that by repaying its debt early in the bankruptcy proceeding, EFH owed them prepayment premiums — or make-whole payments — of $431 million and $351 million, respectively. The payments don’t include several years of interest.
The decision affects $6.2 billion in debts that were refinanced after EFH declared bankruptcy in 2014. The company has said that disallowing the make-whole claims is a condition of its reorganization and that the added litigation would reduce the funds available to other creditors.
The U.S. Bankruptcy Court in Delaware, which has jurisdiction over the case, is to begin hearings to consider confirming the Texas company’s reorganization Dec. 1.
EFH’s reorganization plan hinges partly on the sale of its Oncor wires business to Florida-based NextEra Energy for $18.4 billion. NextEra and Oncor filed for approval of the sale with the Public Utility Commission of Texas on Oct. 31. (See NextEra Energy Talks Up its Oncor Acquisition.)
It’s unclear whether the additional debt would affect NextEra’s acquisition of Oncor, which relies on eliminating debt and replacing it with equity.
EFH has already spun off its Luminant and TXU Energy businesses into a standalone company, since rebranded as Vistra Energy. (See Luminant, TXU Energy Emerge from Bankruptcy.)
Vistra Energy and NextEra both declined requests for comment by RTO Insider on the court’s ruling and its potential effect on the Oncor acquisition.
Meanwhile, NextEra and Oncor are plunging ahead with their merger application in Texas.
Friday, the state’s Public Utility Commission filed an order finding their application to be sufficient (Docket 46238) and an administrative law judge affirmed hearings before the PUC will begin Feb. 21.
The ALJ also granted all motions to intervene in the case. Those intervening include the Texas Office of Public Utility Counsel, NRG Texas, TXU Energy, Local 69 of the International Brotherhood of Electrical Workers, Texas Industrial Energy Consumers and a group of cities currently served by Oncor.
PUC staff has requested Oncor address a set of questions focused on the utility’s rating agency reports, its five-year capital plan and the tax status of the EFH spin-off.
FERC last week rejected Entergy Texas’ attempt to terminate a power purchase agreement with qualifying facilities at Goodyear Tire & Rubber’s Beaumont chemical plant (EL16-105).
Goodyear filed a complaint with the commission in August, alleging that Entergy Texas’ plan to terminate its PPA with the tire company’s QFs in Southeast Texas violated the utility’s obligation to purchase energy and capacity in accordance with the Public Utility Regulatory Policies Act of 1978.
Goodyear’s Beaumont Chemical Plant | Goodyear
Entergy contended it had the right to cancel the PPA based on FERC’s January order that terminated the utility’s obligation to purchase from QFs larger than 20 MW in MISO. (See FERC: Entergy not Required to Buy from Large QFs.)
Goodyear’s Beaumont/West QF was self-certified in 1987 with a net capacity of 13 MW. Its Beaumont/East QF was self-certified in 1999 with a net capacity of 18.8 MW.
Entergy argued that the two QFs should be considered as one. It noted that the QFs are located less than a half-mile apart on the same site and that their energy “is commingled behind the meter.”
Goodyear contended that because it had self-certified two cogeneration plants each smaller than 20 MW, the January order did not affect Entergy’s obligation.
The commission agreed. It said its January order concluded that “a QF’s size for purposes of being relieved of the mandatory purchase obligation is determined by its certified size.”
The commission’s January order was based on a 2006 ruling, which said that QFs with net capacity above 20 MW were presumed to have “nondiscriminatory access” to wholesale markets in RTOs such as MISO.
CARMEL, Ind. — MISO and PJM are close to implementing a targeted market efficiency project (TMEP) type and poised to approve six such projects with cross-regional benefits.
During the Nov. 15 MISO and PJM Joint and Common Market meeting, Jesse Moser, MISO manager of infrastructure studies, said the RTOs must make a FERC filing to change their joint operating agreement in addition to individual filings on how they plan to handle cost allocation.
Moser said the RTOs prefer making the necessary three filings simultaneously, but they would file standalone JOA changes before the end of the year if certain regional cost allocation details are not finalized in time.
“We’re happy to see this move forward,” Moser said.
The two RTO’s staff say the final six projects are expected to cost about $17.25 million and deliver $111.6 million in reduced congestion on market-to-market flowgates, an average 6.5:1 benefit-to-cost ratio.
The RTOs examined 50 market-to-market flowgates and produced the final six from a pool of 13 potential upgrades. The final six exclude the previously recommended Klondike-Purdue 138-kV project in north-central Indiana, which did not advance because of the discovery that the congestion the project was designed to relieve was outage-driven. (See 7 Sites Eyed for MISO-PJM Targeted Market Efficiency Projects.) “These are meant to be lower cost projects … that have near-term economic benefits,” Moser explained.
At a Nov. 17 conference call of MISO’s Regional Expansion Criteria and Benefits Working Group, transmission engineer Adam Solomon said the RTO will pursue a bifurcated cost allocation for the TMEPs. MISO proposes to assign cost to a local transmission pricing zone when the constraint is on the transmission of one or more transmission owners. For constraints wholly within PJM, MISO is seeking a postage stamp allocation for all of the MISO North region.
Solomon said MISO decided on a postage stamp for projects within PJM because all local transmission pricing zones would gain from lowered congestion.
PJM officials did not discuss their cost allocation plans at the meeting. Spokeswoman Paula DuPont said the regional cost allocation is being developed by PJM’s Transmission Owners Agreement-Administrative Committee.
The two-option proposal would apply to both RTO’s current batch of TMEPs. “We’re certainly open to looking at it in the future if we can get a better cost allocation,” Solomon said.
Shelly-Ann Maye, representing Midwest Power Transmission Arkansas, said she didn’t understand why a postage stamp allocation could be justified when local beneficiaries in MISO could be identified.
“These projects are avoiding future congestion in MISO, and that congestion gets pretty well spread out in the footprint,” Solomon explained.
Of the six TMEPs currently being considered, the Marysville-Tangy 345-kV project in central Ohio is the only project that would qualify for the postage stamp allocation, as it is located wholly within PJM, Solomon said.
| MISO
Solomon also said the cost allocation rules will only apply to the PJM-MISO seam. MISO staff said they plan to collect more SPP day-ahead market-to-market information and expect to begin discussions with SPP on a similar project type.
“Having this cost allocation spelled out in the JOA and Tariff, I think, will help these projects go through and we can get the benefit of those projects we’re forecasting,” Solomon said.
Wisconsin Public Service’s Chris Plante said his utility was hoping for 50% local pricing zone allocation and 50% postage stamp allocation for all TMEPs.
“We think this is the best proposal that we have at this point with stakeholder feedback considered,” Solomon said.
Retirement Coordination
Neil Shah, MISO adviser of seams administration, also said that both RTOs are planning to file a generator retirement coordination process with FERC by Dec. 15. Shah said the final language was largely unchanged from what was proposed last month. (See MISO Outlines Retirement Coordination with PJM.)
LA QUINTA, Calif. — While the loss of the San Onofre nuclear plant complicated California’s response to the closure of the Aliso Canyon natural gas storage facility last year, planners did benefit from actions taken in the wake of the plant’s 2013 shuttering, according to California Public Utilities Commissioner Catherine Sandoval.
“All of that work helped us to better withstand Aliso Canyon when the number one source of natural gas was no longer available,” Sandoval told an audience at the National Association of Regulatory Utility Commissioners’ 128th Annual Meeting.
In response to the shutdown of San Onofre — the largest generator in the state’s most populous area — officials ordered transmission upgrades, installation of synchronous condensers to facilitate the flow of electricity into the Los Angeles area and “a variety of things to help keep the system up and running electrically,” Sandoval said.
The loss of Aliso Canyon prompted the CPUC to authorize additional measures to shore up the region’s grid, including accelerated deployment of energy storage and expedited interconnection procedures. The state also stepped up implementation of demand response to shave summer electricity — and, by extension, natural gas — demand.
“This isn’t your father’s demand response; this is auto-DR,” Sandoval said. Among the most successful auto-DR programs: air-conditioner cycling, which allowed utility customers to select from a range of potential curtailments of their cooling units during periods of high electricity demand.
Aliso Canyon | California Governor’s Office of Emergency Services
The program yielded 300 MW in DR, Sandoval said. “That’s a peaker plant. So we were able to get a negawatt peaker through auto-DR,” Sandoval said.
Southern California weathered the summer without incident on either the gas or electricity system. Now planners are turning their attention to winter, when heating requirements create a second peak for gas demand not driven by electricity generation. (See CAISO Seeks to Extend Aliso Canyon Gas Rules Through Winter.)
While Aliso Canyon owner Southern California Gas has been testing the storage facility for leaks, the CPUC still hasn’t authorized reopening. No set timetable has been established for bringing the facility back online.
“We really have to come up with new messages [for consumers] that are actually well-tailored to the winter side,” Sandoval said. “We have to think about what sorts of programs can we adopt to really ensure that there’s gas sufficiency so that we don’t run into problems, especially if we’re not able to bring Aliso back online.”
