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March 9, 2021

Calif. Tries to Rein in PSPS for Fire Season

California regulators and lawmakers are trying to avoid a repeat of last year’s unprecedented use of public safety power shutoffs (PSPS) to prevent utility equipment from igniting wildfires — and the anger it provoked among ratepayers.

The California Public Utilities Commission and the state Assembly’s Utilities and Energy Committee each held hearings last week to determine what can be done in the coming months to limit PSPS use by the state’s three large investor-owned utilities.

California PSPS — Assemblymember Chris Holden chaired a March 3 hearing on PSPS. | *California State Assembly*

PSPS were used 30 times between 2013 and 2019, and 33 times last year alone, energy committee Chair Chris Holden said. “What happened?” Holden asked at the hearing, which was held at the state capitol in Sacramento.

“It’s safe to say that we’re all frustrated by the use of public safety power shutoffs by our state’s electric utilities,” he said. With climate change and aging infrastructure, “we do understand the need to use this tool, but it absolutely must be used as a last resort — judiciously, during extreme weather events, when there is no other way to ensure that utility equipment will not come into contact with vegetation and start a fire.”

Southern California Edison and, to a lesser extent, Pacific Gas and Electric bore the brunt of criticism at the hearings, while San Diego Gas & Electric received relatively little blowback.

SCE Responds

PG&E appeared to have made progress in limiting PSPS events in 2020 and communicating with its customers, Holden said. SCE, however, doubled its PSPS events from 2019 and had “repeated failures to follow protocols at the expense of customers and public safety,” he said.

“They repeatedly assured the CPUC president that, ‘We are going to [change]. We plan to. We want to,’” Holden said. “But in the moment, they did not. This raises the question of whether the [CPUC and other] agencies have sufficient enforcement tools.”

State authorities need tools “that can be used in real-time if a utility is calling events unnecessarily or failing to follow proper notification protocols for customers, public safety partners and other state agencies,” he said.

In late January, the CPUC held a hearing to examine what it called SCE’s mishandling of PSPS events. It demanded the utility produce a corrective action plan with specific goals and timelines for improvement. (See CPUC Slams SCE Over Power Shutoffs.)

On March 1, SCE presented its plan to the CPUC in a follow-up workshop.

Erik Takayesu, the SCE vice president who oversees PSPS readiness, noted that 2020 was a record year for wildfires in California with more than 4 million acres burned and an unusually long fire season in Southern California. Many of SCE’s PSPS events occurred later in the year, he said.

“Two-thirds of our deactivations occurred from November through the end of the year … [with] particular hardships experienced by customers over the holiday season,” Takayesu said.

SCE turned off power on Thanksgiving Day and Christmas Eve, sending out late or confusing notices of the PSPS events and angering residents.

“I and the members of our team have heard the concerns and frustrations of our customers and communities who have been affected by PSPS events,” Takayesu said.

The utility made significant progress in 2020 but needs to do more, he said.

“Our main emphasis in 2020 was focused on the distribution system, creating segmentation plans for every one of our 11,600 circuits in our high fire risk areas,” Takayesu said.

The utility removed 25,000 customers from the scope of PSPS events last year, but 230,000 customers were subjected to repeat de-energizations, another cause of customer frustration.

“We now need to further direct our efforts to focus on the most frequently impacted circuits,” Takayesu said.

SCE intends to turn its attention this year to circuits that have experienced four or more de-energizations since 2019. Continued grid hardening will reduce the frequency of PSPS and improve reliability across the utility’s grid, he said.

As of Feb. 19, SCE had identified 72 circuits for potential expedited upgrades such as covered conductor. It intends to complete the work by Oct. 1, when Southern California’s peak fire season typically starts, the utility told the CPUC.

In Thursday’s legislative hearing, Phil Herrington, SCE senior vice president for transmission and distribution, said that “despite the challenges posed by COVID-19, we met or exceeded nearly all the goals in our 2020 wildfire mitigation plan.”

That included installing more than 960 circuit miles of insulated wire, over 6,000 fire-resistant bolts and nearly 600 weather stations, Herrington said. SCE also removed more than 12,000 hazard trees that could have fallen into power lines.

Enhanced Oversight of SCE

Such assurances did not mollify some officials at the hearings.

CPUC President Marybel Batjer presided over the SCE workshop and testified before lawmakers last week.

The commission, she said, has been trying to get the state’s investor-owned utilities to improve their PSPS execution and limit use of the practice since October 2019, when PG&E blacked out 2.4 million residents over large swaths of the state, generating public backlash. (See California Officials Hammer PG&E over Power Shutoffs.)

Batjer agreed with Holden that in 2020, “for PG&E, we appear to see improvements … on a few fronts [including] overall reduction in scope and scale [of PSPS events] compared to 2019.” The state’s largest utility has improved its planning for community resource centers to serve residents during blackouts and has improved its PSPS event forecasting as well, she said.

The utility still needs to work on sharing information with local agencies and tribal governments, and it needs to expand its battery-backup program to help medically vulnerable customers during PSPS events, she added. (See PG&E Working to Improve Safety Blackouts.)

“Its notification protocols [for customers] also require improvements,” she said.

SDG&E also needs to improve communication with local authorities and beef up its battery backup program for medical baseline customers, Batjer said.

SCE has been more problematic. The state’s second largest utility “has required special attention and has been the subject of two public meetings at the commission” this year, Batjer said.

“There are many areas where I believe Edison did not measure up to the standards … its customers deserve,” she added.

The utility initiated 16 PSPS events between May and December last year, most of which were in November and December, including the two major holidays, Batjer noted.

“Among the various problems we observed were issues with the level of transparency around Edison’s PSPS decision-making process, inadequate notification to impacted customers, poor coordination and communication with state and local governments, shortcomings in identifying and notifying medical baseline and functional needs customers and efficient PSPS post-event reporting to the commission,” she said.

“In addition, we continue to have serious concerns with the pace at which Edison has been deploying backup power to help vulnerable customers cope with PSPS events.”

One of SCE’s major shortcomings was its under- or over-notification of customers potentially affected by PSPS, Batjer said.

“Only 20% of the customers it gave advanced notice to this past fire season were affected by a PSPS event,” she said. “While it is desirable to have as few customers de-energized as possible, there is something wrong with this planning approach if you’re consistently putting large numbers of customers on notice and then nothing happens.”

There were also too many instances in which customers were not notified before losing power, including on Thanksgiving, she said.

“Forecasting and communications must improve,” Batjer said of SCE.

The CPUC had to enhance its oversight of PG&E’s PSPS practices going into the 2020 fire season, she noted. “We’re doing this now with Edison … to ensure they live up to their commitments under their corrective action plan.”

Upcoming Actions

The CPUC is planning to host a public workshop later this month to hear from utilities and impacted communities on lessons learned from 2020 PSPS.

“These lessons will inform another round of updating of our PSPS guidelines, which we commenced on Feb. 19,” Batjer said. “We will continue to hold public meetings as we enter the critical months of the wildfire season to assess the utilities preparedness. If required, we will utilize our expansive enforcement authority over the utilities to deliver the type of behavior customers deserve and expect from providers of an essential service.”

The results of an investigation into IOU power shutoffs, initiated in 2019, will be released soon, she said.

PSPS may continue for years as utilities upgrade their systems, but the goal is to stop needing it, Batjer said.

“I want to reiterate the CPUC’s commitment to driving the utilities towards zero need,” she said. “The use of PSPS and the loss of power causes major disruptions to households, businesses, medical facilities, communication carriers and other critical infrastructure. It strains state and local emergency and public safety personnel.

“The public deserves better, and we are working to ensure they are better served by the utilities,” she said.

March 9, 2021

Former ERCOT CEO Rejoins Board

Former ERCOT CEO Bob Kahn has rejoined the Texas grid operator’s Board of Directors as it begins to reconstitute itself after a wave of resignations following the massive February power outage.

Kahn, currently the Texas Municipal Power Agency’s general manager, was elected Friday by the municipal segment members as their representative on the board. He served as ERCOT’s CEO from 2007 to 2009 and previously served on the board from 2002 to 2006.

Kahn replaces Austin Energy General Manager Jackie Sargent, who resigned after testifying before the Texas Legislature on Feb. 26. He told the Austin American-Statesman he plans to ask questions about the February power outage that cost ERCOT half its generating capacity and led to widespread blackouts.

Also last week, the independent retail electric provider segment elected Demand Control 2’s Shannon McClendon as its representative. She replaces Just Energy’s Vanessa Anesetti-Parra, who was among the out-of-state board members that resigned Feb. 23. (See ERCOT Chair, 4 Directors to Resign.)

The additions bring the board’s membership up to 10 directors. The five unaffiliated seats and the cooperative segment’s representative remain open. Directors representing industry segments serve one-year terms and are unpaid.

Kahn joined TMPA in 2012. The public power organization ran the coal-fired Gibbons Creek Generating Station for the member cities of Bryan, Denton, Garland and Greenville. The plant hasn’t run since 2018 and was sold in February to Gibbons Creek Environmental Redevelopment Group, which will take three years to demolish it and complete environmental remediation.

Prior to being named ERCOT’s CEO, Kahn spent 10 years at Austin Energy as general counsel and then deputy general manager. He also served in the Texas Public Utility Commission general counsel’s office and represented public power in the state’s deregulation legislation.

March 9, 2021December 4, 2023

BOEM Releases Final Vineyard Wind Impact Statement

The U.S. Bureau of Ocean Energy Management (BOEM) on Monday concluded its environmental review of the Vineyard Wind I project off the coast of Massachusetts.

“More than three years of federal review and public comment is nearing its conclusion, and 2021 is poised to be a momentous year for our project and the broader offshore wind industry,” Vineyard Wind CEO Lars Pedersen said in a statement.

BOEM said it is working to issue a record of decision whether to approve or disapprove the proposed project, or approve it with modifications. The U.S. Army Corp of Engineers and the National Marine Fisheries service will sign the record of decision for their respective authorization decisions.

“We look forward to reaching the final step in the federal permitting process and being able to launch an industry that has such tremendous potential for economic development in communities up and down the Eastern seaboard,” Pedersen said.

The final environmental impact statement (EIS) signals the direction BOEM is leaning toward in its decision. BOEM could approve Vineyard Wind’s construction and operations plan with specific changes, including capping the number of turbines built for the project at 84. Depending on the final turbine capacity used, the project could have as few as 57 turbines.

In addition, BOEM could prohibit wind turbine installations in six locations in the northernmost portion of the project lease area. BOEM may also require the turbines be installed in a north-south and east-west orientation with a minimum distance of one nautical mile between them.

Project officials estimate Vineyard Wind will reduce electricity rates by $1.4 billion over the first 20 years of operation and reduce carbon dioxide emissions by 1.68 tons annually, the equivalent of taking 325,000 cars off the road each year. The project is estimated to create 3,600 jobs in Massachusetts and spur over $200 million in economic activity, according to the Business Network for Offshore Wind (BNOW).

“This is the day the U.S. offshore wind industry has been anxiously awaiting for years,” BNOW CEO Liz Burdock said in a statement. “[This] announcement provides the regulatory greenlight the industry needs to attract investments and move projects forward.”

Vineyard Wind, a joint venture between Avangrid and Copenhagen Infrastructure Partners, said it expects to begin delivering energy from the project to Massachusetts in 2023.

Impact on Fish Habitat

Fisheries along the New England coast have opposed the Vineyard Wind project and advocated for changes to mitigate the impacts of the turbines and offshore cables on scallop spawning grounds and fishing gear.

The final EIS said that “most potential unavoidable adverse impacts associated with the [project as proposed], such as disturbance of habitat or incremental disruption of typical daily activities, would occur during the construction phase or would be temporary.”

However, the project “could include effects on habitat or individual members of protected species, as well as potential loss of use of commercial fishing areas.”

Vineyard Wind agreed to provide fisheries mitigations for Rhode Island “after multiple discussions and negotiations,” according to the review, including a $4.2 million fund for direct compensation to Rhode Island fishermen for loss of equipment or claims of direct impact.

The project will also provide Rhode Island with $12.5 million to establish a Rhode Island Fisheries Future Viability Trust and work with the Massachusetts Executive Office of Energy and Environmental Affairs to establish a Compensatory Mitigation Fund for $19.2 million and a Fisheries Innovation Fund for $1.75 million.

March 9, 2021November 2, 2023

Ohio Lawmakers Struggle to Undo Nuclear Subsidy

The monthslong struggle of Ohio lawmakers to repeal the customer-paid $1 billion nuclear power plant bailout they created for a FirstEnergy Corp. subsidiary in 2019 is coming to an end, possibly this week, though not with a simple repeal of the original legislation.

Ohio Senate President Matt Huffman (R) and House Speaker Bob Cupp (R) say they anticipate approval of final legislation soon.

More than half a dozen divergent and competing bills have been offered since the first of the year in the House of Representatives and the Senate. At least three bills that would outright repeal everything in the original legislation — House Bill 6 — have languished in committees. Bills eliminating both the nuclear and solar subsidies, or just the nuclear subsidy, have been approved by one chamber or the other.

But there has been no bill approved, or offered, that would eliminate subsidies to two aging coal-fired power plants that somehow got into the Ohio Clean Air Program that H.B. 6 was to have created. Because H.B. 6 was crafted to win support from disparate groups, leadership’s concern has been that a simple repeal might not be able to gain support from a majority in each chamber.

Federal investigators have alleged that FirstEnergy spent $61 million in bribes to elect officials that would pass H.B. 6. (See Feds: FE Paid $61M in Bribes to Win Nuke Subsidy.)

Change in Tune

Because the nuclear subsidy was at the heart of H.B. 6 — and Energy Harbor, the company that emerged from the two-year bankruptcy case of FirstEnergy’s power plant subsidiary FirstEnergy Solutions, would potentially make less money in the PJM wholesale market if a state subsidy remains in state law — lawmakers are trying to eliminate it first.

S.B 44, introduced Feb. 9 by Sens. Jerry Cirino (R) and Michael Rulli (R), would eliminate customer charges to finance the $1 billion subsidy for Energy Harbor. The bill won unanimous approval of the Senate on March 3. Both Cirino and Rulli are from Northeast Ohio, where the Perry nuclear plant is located.

As a county commissioner, Cirino said he fought for federal and state subsidies to keep the Perry plant open and its jobs intact. He said he accompanied company executives as they appealed to the Trump White House, as well as the Department of Energy and FERC.

Now Cirino says he does not believe Energy Harbor needs the subsidy. He added that he thinks the “federal situation” for nuclear operators is changing, referencing FERC’s expansion of PJM’s minimum offer price rule.

“After the election the federal situation had been changing, and Energy Harbor was of the view that they cannot accept state subsidies and get consideration for clean energy from PJM when they are doing the [capacity] auction,” he said in an interview. “They basically said ‘We don’t want it.’”

Neither the House Public Utilities Committee nor the Senate Energy and Public Utilities Committee have listened to public testimony directly from Energy Harbor about its need for the subsidy or desire not to receive it.

Ohio Consumers’ Counsel Bruce Weston has suggested they do so.

“It is said that Energy Harbor apparently wants its billion-dollar power plant subsidy repealed,” lobbyist Jeff Jacobson said on Weston’s behalf in testimony to the House committee on March 2. “The Ohio public, and this committee, should hear directly from Energy Harbor on this subject, under oath, in the light of day. …

“The public should have the benefit of a legislative investigation … [that] should include answers about whether the legislature and the public were misled by FirstEnergy, Energy Harbor and others,” he said.

Energy Harbor is spending money on the plant. The company is preparing now to refuel the reactor, slowly coasting to a lower output in preparation for a refueling shutdown, according to Nuclear Regulatory Commission records. The company has informed the commission that it intends to seek an extension of the Perry plant’s nuclear operating license, which expires March 18, 2026, NRC records show.

Energy Harbor’s spokesman has not returned phone calls and text messages seeking comment about its position on the state subsidy.

Solar Uncertainty

Meanwhile, Reps. Dick Stein (R) and James Hoops (R) introduced H.B. 128 on Feb. 17 to outright eliminate the nuclear subsidy — as well as the solar subsidies that were included H.B. 6 to sweeten the deal.

The two lawmakers represent counties in Northwest Ohio, home to the Davis-Besse nuclear plant, which is an important source of high-paying jobs for the region. But residents in those counties are also upset about a surge of applications from developers who want to build utility-scale solar installations.

H.B. 128 would eliminate both the seven-year $150 million annual nuclear subsidy for Energy Harbor and the $20 million annual solar subsidy authorized in H.B. 6 for a half dozen previously approved utility-scale solar farms, some of which are now being built. The bill is scheduled for a third hearing and possible vote Tuesday before the House Public Utilities Committee.

The Davis-Besse nuclear plant in northern Ohio | NRC

“I anticipate House Bill 128 will be voted out of the House Public Utilities committee this coming week and to be scheduled for vote of the full House vote shortly thereafter,” Speaker Cupp said through his spokeswoman in response to a question from RTO Insider.

Both the House and Senate are meeting Wednesday. Whether S.B. 44 and H.B. 128 could be quickly combined is another question. Senate President Huffman partially addressed how to meld the bills in brief remarks before a reporters’ gaggle after a Senate session last week.

“We have not actually sat down with the House and said, ‘Let’s do it this way or that way.’ There are a few other efforts we are working on with the House in a little bit more formal way,” he said.

“I was part of the discussions in the last month or so in the last [General Assembly]. And there were general discussions with Speaker Cupp at that time about things that collectively the House and the Senate could get enough votes to pass, and those are the first two things that we have done, in Senate Bill 44 and Senate Bill 10,” he said.

Huffman was referring to a second unanimously approved Senate bill introduced by Sen. Mark Romanchuk (R). S.B. 10 would eliminate the “decoupling” mechanism H.B. 6 created for FirstEnergy, guaranteeing that the company’s ongoing annual revenues would not be lower than its rosy 2018 revenues rather than reflect any future downturns. The concept of decoupling had been introduced when the state ordered utilities to initiate energy efficiency programs designed to cut customer demand — and potentially profits.

FirstEnergy’s then-CEO Charles Jones noted at the start of the COVID-19 pandemic that the decoupling provision had made the company “recession proof.”

Approved by the Senate on Feb. 17, S.B. 10 was crafted to prevent any utility from putting such a mechanism in place in the future.

Romanchuk appeared before the House Public Utilities Committee on Feb. 23 to introduce the legislation. He noted in his testimony that under H.B. 6, FirstEnergy would receive at least $978 million in distribution revenues annually, regardless of consumer demand. The committee has not yet held a second hearing as it has concentrated on taking testimony on H.B. 128.

Huffman said he sees significant support for both S.B. 44 and S.B. 10.

“I think those are supported by a significant majority. They were passed unanimously out of the Senate. So, we can deal with those two significant problems,” Huffman told reporters. “It was my thought that we needed to do things that we could get done. I think people are satisfied with those. That certainly does not mean it is the end of the discussion.”

He cited possible legislation to recreate energy efficiency programs as an example. “We had a bill regarding the energy efficiency program introduced by Sen. [Matt] Dolan [R]. He is obviously a supporter of that. We are going to keep having conversations.”

Huffman could not be specific as to when or how the bills would be combined, approved by both chambers and sent to Gov. Mike DeWine (R).

Another Northwest Ohioan, Sen. Rob McColley (R), recently tried to address the negative impact that H.B. 6 has had on the public’s perception of Ohio and its state government.

“We have had to deal with an awful lot regarding these provisions,” he said of H.B. 6, in remarks before the Senate unanimously approved S.B. 44. “It’s been something that has … placed a black eye … on our institution. We need this as a learning opportunity … as a teachable moment for ourselves and even for those who will come after us.

“To realize that when we are passing legislation, we need to look at it in the context of what is best for the citizens of Ohio. [S.B. 44] is something that will undo an awful lot of damage that has been done, not just to our institution, but to the state of Ohio. We all need to support this bill.”

FirstEnergy Names New CEO

On Monday, FirstEnergy appointed Steven Strah as CEO and a member of its board of directors, effective immediately.

Strah has served as acting CEO since October 2020, when the company fired Jones over the bribery investigation. Strah will continue as president of the company, a position he has held since May 2020. His base annual salary was set at $1.1 million.

March 7, 2021

RA at Risk in NWPP-Central, WECC Finds

The southern portion of the Northwest Power Pool (NWPP) region could fail to meet resource adequacy requirements for three hours this year under even the most generous buildout scenario, according to a new WECC report.

That risk rises to seven hours in 2024 as WECC’s NWPP-Central (NWPP-C) subregion retires more baseload coal-fired generation while taking on growng amounts of intermittent solar, increasing the likelihood that utilities will be stressed to serve load under tight supply conditions, WECC found. The summer-peaking area covers Utah, Colorado, most of Nevada, and parts of Idaho and Wyoming.

“There’s variability in the system — and more and more variability added every day,” WECC Manager of Performance Analysis Matt Elkins said March 2 during a webinar to discuss the report for the summer-peaking NWPP-C region. The meeting also covered separate reports for NWPP’s winter-peaking Northwest (NWPP-NW) and Northeast (NWPP-NE) subregions, which were each studied discretely because of the transmission constraints between them.

All three reports expand on WECC’s more general Western Assessment for Resource Adequacy, which found the Western Interconnection could this year experience one to eight hours in which some of its subregions fail to meet the one-day-in-10-years (ODITY) threshold for RA. (See Western RA Planning Must Change, WECC Says.)

A descent below that threshold could threaten a repeat of last summer’s energy emergencies, which prompted CAISO to initiate rolling blackouts in California during an extended heat wave while neighboring balancing areas prepared similar measures in the face of regionwide resource shortages.

Possible shortfalls have become a growing concern in the West as states direct utilities to replace retiring fossil fuel generation with variable renewable resources to meet climate change goals. Industry stakeholders in the Northwest have expressed worries that a lack of transparency around RA could leave the region’s load-serving entities inadvertently drawing on the same contracted resources in periods of tight supply.

To address that concern, the NWPP is developing an RA sharing program that has so far attracted 20 members spanning the group’s footprint. A first — nonbinding — iteration of the program is slated to roll out in the third quarter of this year. (See NWPP RA Program Taking Shape for Q3 Launch.)

Central Risk

That program might arrive just in time as the NWPP-C heads into summer, based on WECC’s findings, which show the subregion’s supply and demand patterns align more closely with the neighboring Desert Southwest (DSW) and California-Mexico (CAMX) subregions to the south and west than with its NWPP partners to the north. (See Southern Calif. Could Fail RA Test, WECC Says.)

Like the DSW and CAMX, the NWPP-C, with an estimated 3,747 MW of solar resources, tends to experience net-peak loads in the late afternoon and evening as solar rolls off the system. For that reason, it also shares with them a greater potential for a loss-of-load event in the near future.

WECC’s RA analysis applied two scenarios to all five subregions to explore a range of future resource possibilities and factor in known and expected resource retirements. Scenario 1 — the “standalone” scenario — assumes each subregion will be meet its load with internal resources, while Scenario 2 allows for imports.

The regional entity then overlaid each scenario with three variations of RA. Variation 1 includes all resources currently in service and expected to run in future forecasts. Variation 2 includes existing resources and those under construction and expected to operate in the forecast year (Tier 1 resources). Variation 3 — the most optimistic assumption — includes existing and Tier 1 resources as well as those in licensing or siting phases but not yet under construction (Tier 2).

Based on historical analysis of resource performance, WECC estimates that NWPP-C should have about 42,400 MW of resources available this year to meet an expected peak demand of 36,400 MW. But it also found a 5% probability that only 30,500 MW of capacity would be available during the peak hour. Furthermore, there’s a 5% chance that load could actually peak at 42,200 MW, representing a 16% uncertainty in the load forecast.

Under a “standalone” scenario, the NWPP-C region would face 722 hours this year with demand at risk. But Elkins acknowledged the unlikelihood of such an outcome, given that the Western Interconnection “is built with a lot of benefits” to accommodate resource-sharing among summer- and winter-peaking areas.

“If you don’t have risk in the standalone scenario, then you’ve overbuilt the system,” Elkins said.

With imports included in the assumptions, the subregion faces 14 at-risk hours this year, rising to 50 hours in 2024 as more coal plants retire. And even under the most optimistic assumption that includes imports and a full buildout of proposed resources (Scenario 2, Variation 3), NWPP-C faces three hours this year in which load is put at risk, rising to seven hours next year, followed by one hour in 2023 and three hours in 2024.

While WECC said that a 21% planning reserve margin (PRM) is sufficient to maintain the median ODITY threshold for the subregion this year, it cautioned that a 32% PRM might be required in the future to sustain that standard during those periods with the highest variability in supply and demand.

“If a flat reserve margin were applied to all hours of the year, for example 15%, almost 100% of the hours would not meet the ODITY threshold,” the report said.

Lower Risk up North

The other two NWPP subregions fared better under WECC’s analysis.

In the standalone scenario with existing resources, the hydro-rich NWPP-NW, which includes British Columbia, Washington, Oregon and parts of California, Idaho and Montana, faces 208 hours this year in which the ODITY threshold is at risk. Risk under that scenario declines to 195 hours when Tier 1 resources are added and to 194 hours when factoring in Tier 2. The risk falls to zero with the addition of imports, a pattern that holds through 2024.

The report found that a 15% reserve margin will be sufficient for the NWPP-NW subregion this year but recommends future PRMs as high as 42% to accommodate supply/demand variability during the spring months.

The NWPP-NE subregion, which covers Alberta and parts of Montana, Idaho, Wyoming, South Dakota and Nebraska, faces a potential 4,196 hours of unmet demand under all standalone scenarios this year (including with Tier 1 and 2 resources), a figure that steadily rises into 2024. The addition of imports brings the risk to zero for all years.

“The assessment indicates that entities in the NWPP-NE subregion need to build the resources currently included in the construction queue as part of the solution to maintain the ODITY threshold,” the report said.

The report recommends a 15% PRM for the subregion this year but calls for future margins as high as 22% for high-variability periods.

Elkins noted also that while the northern areas of the NWPP scored well on RA on the subregional level, some individual balancing authority areas are at higher risk of not meeting reliability standards under all scenarios.

“The system is built to rely on others, but how much do you want to rely?” Elkins said.

March 7, 2021

Texas RE: Post-COVID Cyber Safety Requires New Priorities

The cybersecurity lessons of the COVID-19 pandemic must not be forgotten as industry stakeholders return to normal operations, representatives from Texas Reliability Entity warned in a webinar on Thursday.

Speaking at the regional entity’s regular Talk with Texas RE event, Jason Moehlman — the organization’s manager of internal cybersecurity and compliance — admitted that many organizations were caught flat-footed when COVID-19 “[came] in and [hit] us like a ton of bricks” in March 2020. While most entities had a business continuity plan for riding out relatively brief disruptions to normal operations, nobody had contemplated having to extend those emergency measures for a year or more.

“We had a two-week mindset when this decision was made, thinking we’d be back in the office within a month. … For most organizations that’s not quite how it worked [out],” Moehlman said. “In general a lot of [information technology] organizations weren’t quite ready to go fully remote, so there were a lot of on-the-fly decisions being made as to how those users who had never been remote and didn’t have laptops … [were] going to all of a sudden be 100% remote. … The security side of this process may have taken a bit of a backseat to the operational component.”

As the pandemic wore on, those ad hoc remote work arrangements have gradually come to feel permanent in some regards, with many employees coming to enjoy the convenience of working from home and entities even noting some efficiency benefits from not having to keep offices fully staffed.

But as managers consider allowing some of these arrangements to continue, they must be ready to put long-term cybersecurity measures in place as well.

Pandemic Highlighted Existing Issues

Cyber hygiene was viewed as a major risk early in the pandemic, with NERC, among other groups, observing that the expanded remote workforce posed an attractive “attack surface” for malicious actors. (See PPE, Testing Top Coronavirus Concerns for NERC.) Those concerns have borne out; Moehlman said security firms have seen “a real uptick in phishing campaigns” aimed at tricking users into giving up their credentials over the past year.

“It could be that threat actors are thinking it’s a good opportunity to go after these credentials when an organization’s security posture may be [weaker] than it would during non-pandemic times,” he said.

These campaigns can have real consequences, such as the cyber intrusion into a water treatment plant in Oldsmar, Fla., in early February, when an employee at the plant noticed the cursor on his screen apparently moving under its own control to set the levels of sodium hydroxide dispensed into the water to many times a safe amount.

The unauthorized user was quickly locked out and the changes were reversed before any water was affected. However, the incident highlights the danger of allowing unrestricted internet access by computers handling important processes, especially when coupled with a sudden rise in employees working remotely.

There is plenty of blame to go around in the case of the Oldsmar intrusion: The attacker appears to have gained access to the system via the remote access software TeamViewer — the password for which was shared between employees in violation of common cyber hygiene practices. Furthermore, all computers at the plant used an outdated version of Windows 7 with no firewall and were connected to the plant’s supervisory control and data acquisition (SCADA) system.

But Moehlman warned that focusing on the corners cut by a single entity misses the larger point that many utilities may be more vulnerable than they realize. The convenience of remote access requires organizations to compromise on security in ways that may not be visible but are just as potentially damaging as far more obvious breaches.

Too Much Trust Leaves Open Doors

Attempts to rethink cybersecurity in recent years have given rise to the “zero-trust” model, in which organizations treat all users, devices or traffic as inherently untrustworthy until proven otherwise. This is a fundamental change from traditional approaches in which communications were allowed by default with the primary goal of making business functions easier, and it marks a widespread recognition that malicious cyber actors are a growing threat for everyone.

Texas RE Cybersecurity — Approaches to corporate cyber defense | *Texas RE*

One consequence of the trusting approach is that corporate networks allow the installation of third-party software products with the ability to conduct their own communications. This practice became a global disaster at the end of 2020 when the SolarWinds Orion network management software was found to have been compromised by outside hackers “likely Russian in origin,” according to U.S. security agencies. (See FERC Pushes Cybersecurity Incentives.)

About 18,000 public- and private-sector organizations are confirmed to have been impacted by the SolarWinds compromise, which took the form of a backdoor installed by the hackers into updates for the software as early as March 2020, if not before. Last month SolarWinds Recovery May Require Extreme Actions.)

Moehlman said the SolarWinds breach was a perfect illustration of the risk of giving too much freedom to third-party software. IT staff may not have been able to avoid getting a compromised copy of the Orion software, but a healthy level of suspicion could have kept it from conducting the communication through which the hackers were able to exfiltrate additional information.

“Was there any reason or need for that SolarWinds server to be able to connect to anything on the internet other than its update service, and possibly a Windows update service if it was hosted on a Windows server? I would suggest not,” he said. “So why don’t we block that traffic? If that traffic was blocked, there’s a good chance that beacon would never be received and those attackers would never be aware that that server was infected.”

Moehlman acknowledged that zero-trust “is a relatively new concept in the IT world … [that] does require a leap of faith,” and that most organizations are in “stage zero or stage one” of the maturity curve as defined by security firm Okta. But he encouraged attendees to give it serious consideration as they chart an increasingly connected future in which outsiders gain ever more access to their internal operations — even with the best of intentions.

“It could be a third party that’s managing a portion of your IT infrastructure; it could be the … company that’s changing your air filters, or even the guy who’s stocking your vending machines,” Moehlman said. “You’ve given them some kind of access into your environment and created a possible threat vector that didn’t exist before.”

March 7, 2021November 2, 2023

Carbon Tax Bill Gains Supporters in Wash.

A proposed Washington state tax on carbon emissions drew strong support at a Thursday legislative hearing.

Environmentalists and activists for low-income residents and communities of color praised the tax bill introduced by Democratic state Sen. Liz Lovelett. The legislation garnered a mixed response from industrial and corporate players, and a few anti-tax advocates were strongly opposed.

“This is not a bill that makes everybody happy off the bat. This is not going to be a silver bullet for climate change. … We need more work on the low-income mitigation piece,” Lovelett said at the hearing. In a separate interview, she said, “We worked hard to enfranchise everyday people in this.”

Her bill (SB 5373) would implement a tax of $25/ton of carbon emissions beginning Jan. 1, 2022. The tax rate would increase by 5% a year. Breaks would be given to energy-intensive industries vulnerable to foreign competition — a category whose exact criteria still needs to be finalized by the state government. The tax would be levied on Washington’s five oil refineries for motor fuels sold in the state but not for fuel exports.

The tax revenue would be distributed to transportation programs, low-income residents and communities of color to make homes more energy efficient and address pollution-related health problems. Funds would also help rural areas reduce carbon emissions, including transportation improvements.

The bill would require the state government to review the proposal in 2025 to see if it is meeting the goals set by a 2008 law to trim carbon emissions. In 2018, Washington’s carbon emissions totaled 99.57 million tons. The 2008 law set emission goals of 50 million tons by 2030, 27 million tons by 2040 and 5 million tons by 2050.

The committee’s staff calculated that the proposed tax would raise $1.587 billion in the 2021-2023 budget biennium, $4.162 billion in 2023-2025 and $4.595 billion in 2025-2027.

Fifty-three of 68 people testifying Thursday supported the bill. The majority belonged to environmental and social advocacy organizations. They also included some local government officials, a few farmers and labor interests.

Supporters liked money going to transportation programs and pollution mitigation measures for low-income communities, arguing that polluting industries tend to be in low-income neighborhoods and communities of color. Allocations to help farms deal with carbon-emission costs and equipment upgrades also drew fans.

“It solves multiple problems at one time,” said Bobby Righi, representing Puget Sound Advocates for Retirement Action. Judy Twedt of the Union of Academic Student Employees and Postdocs Local 4121, said, “It generates much needed revenue for unhealthy communities.”

Tax Resistance

Opponents zeroed in on taxes.

Tim Eyman, Washington’s leading anti-tax activist, noted that the state voters defeated carbon tax initiatives by 59% to 41% in 2016 and by 57% to 43% in 2018. (See High Failure Rate for Western Ballot Initiatives.) “I think people are angry and frustrated, and rightly so because people in Olympia are ignoring them,” Eyman said. Washington resident Jeff Peck added, “What you see are two-legged ATMs running around.”

The Washington Farm Bureau opposes carbon taxes on general principle but liked that some revenue would go to agriculture — with the caveat that farming should be a higher priority in distributing that money.

The Association of Washington Business, the state’s leading business-lobbying organization, and the food processing organization Food Northwest opposed Lovelett’s bill because it does not sufficiently protect facilities vulnerable to foreign trade or define the criteria for designating such facilities.

The Western States Petroleum Association (WSPA) is neutral on the bill, waiting to see how subsequent tweaks turn out. Those tweaks include how the final bill addresses industries vulnerable to foreign competition. However, U.S. Oil & Refining supported the bill, believing it incentivizes industry to lower emissions.

WSPA representative Jessica Spiegel voiced concern about the multiple carbon emissions bills currently in play in the legislature. These bills include a complicated cap-and-invest program (SB 5126), a plan to trim the carbon content in motor fuels (HB 1091) and a requirement that all new car sold in Washington be electric by 2030 (SB 5256). (See Wash. EV Bills Spark Concern About Buildout.)

“We need a single approach. Unfortunately, right now we have a scattershot approach,” Spiegel said.

The two biggest bills in play are Lovelett’s and Democratic Sen. Reuven Carlyle’s cap-and-invest bill, which is a more complex version of a cap-and-trade program.

In her interview, Lovelett said both bills can coexist because they largely complement each other.

But Dr. Annmarie Dooley of Physicians for Social Responsibility disagreed. “Cap-and-invest is like allowing public smoking in a hospital as long as they donate to the hospital,” she said.

March 7, 2021November 2, 2023

Green Transition Sparks Comeback for Utility Securitizations

Utility securitizations, once used to reimburse power companies for assets that became stranded under electricity market deregulation, are making a comeback. Utilities and state governments are using the ratepayer-backed bonds to deal with the huge costs associated with green energy transition, climate change and even the COVID-19 pandemic.

“Utility securitizations are set for a resurgence as electric utilities deal with costs surrounding the transition out of hydrocarbons into green energy,” said Joseph Fichera, CEO of utility securitization advisory expert Saber Partners. “There are also attempts being made to apply the ratepayer securitization model to costs from the COVID epidemic, as well as the increasing costs associated with climate change.”

Saber Partners’ forward calendar for ratepayer bond issuance lists five states — California, North Carolina, Wisconsin, New Mexico and Michigan — that have legislation in place for utility securitizations. Utilities in these states are expected to issue as much as $24 billion of ratepayer bonds in the near future.

Colorado and Montana have also recently passed utility securitization enabling legislation. In addition, six states — Kansas, Missouri, Minnesota, Iowa, South Carolina and Arizona — are considering new utility securitization authorizations.

To give an idea of the extent of the resurgence, only $51.1 billion of ratepayer bonds were issued 1997 through 2019, with just $4.1 billion in principal currently outstanding, according to Saber Partners.

“If securitization were used for early retirement of all coal plants in the nation, as well as to pay for COVID costs, perhaps hundreds of billions of dollars in ratepayer bonds would need to be issued,” Fichera said. “Not all coal plants and COVID costs will be dealt with using securitization. Ratepayer issuance going forward, however, very well could surpass the $50.8 billion issued from 1997 through 2019.”

California: $12B+

California’s three investor-owned utilities are seeking to issue more than $12 billion in bonds.

After a long absence from the ratepayer bond market, Southern California Edison in mid-February issued $338 million of ratepayer bonds designed to mitigate future damage from wildfires. Over the last three years, California has seen an unprecedented series of wildfires — fires that some, including California Gov. Gavin Newsom, have attributed to climate change.

Legislators in Sacramento have approved unprecedented levels of utility securitizations, Saber Partners says. SoCal Edison’s February ratepayer issue is likely to be the first in a series of ratepayer bonds as the utility has been authorized to issue up to $1.6 billion worth.

Troubled Pacific Gas and Electric has authorization to issue $3.2 billion for wildfire mitigation costs and is seeking another $7.5 billion of ratepayer bonds to pay wildfire victims, Saber Partners said.

California consumer advocates are vigorously litigating the 7.5 billion securitization authorization, claiming the interests of ratepayers aren’t being adequately considered, though PG&E has promised that securitization deals will be neutral with respect to overall electricity rates for consumers.

“If utility securitizations are to be done on a best practices basis, the interests of consumers must be of paramount importance,” Fichera said. “Ideally that means consumers must be represented in the negotiations where the structure of securitizations are laid out.”

Last June, Saber Partners was retained by the Public Staff of the North Carolina Utility Commission to advise on Duke Energy’s $1 billion proposed securitization to pay for storm damage. In total, Saber Partners has advised on more than $9 billion of utility securitizations, mostly retained by utility regulators who wanted guidance on protecting consumers.

Funding Deregulation

Utility securitizations saw their genesis during the electric utility deregulation movement of the late 1990s. Vertically integrated utilities in many states were required to separate transmission, which remained regulated, from power generation, which was opened to competition.

The idea was to promote efficiency by allowing unregulated generating companies to compete with each other to offer electricity at lower prices to win market share.

Importantly, electric industry reformers also wanted market price signals to start determining when and in what form new generation assets would be built or disposed of — unlike the centralized, command and control under the utility industry model that prevailed for more than 100 years.

But splitting transmission and generation created some headaches, not the least of which was the fact that many generation assets had yet to be fully paid for in the utility customer rate base. As a result of deregulation, generation assets were held in unregulated entities that had zero ability to amortize costs through a normally captive customer base.

These generation assets became known as “stranded assets,” a term that is now in ubiquitous usage in the electric power industry. Among the stranded assets were generators such as Philadelphia Electric Co.’s Limerick nuclear plant, which produced power at a cost that was no longer competitive in the deregulated environment.

Enter utility securitization. Ratepayer-backed bonds were used to refinance utility holding company balance sheet debt, as well as to pay back equity associated with the investments in the newly stranded assets.

By going to state utility boards and through special legislation, electric utility holding companies were given permission to float these new ratepayer bonds to get reimbursed and spread the costs to ratepayers over time at a lower cost of funds. This idea then spread to massive storm damage costs, starting with Hurricane Katrina and Rita in 2005, and for rising environmental costs. PG&E and other California utilities are planning to use ratepayer bonds to reimburse COVID related costs, according to Saber Partners.

In a ratepayer bond deal, a special purpose vehicle (SPV) — a trust, basically — is set up that holds an irrevocable claim to a new charge on customer bills, a charge specifically levied to reimburse for any utility costs approved by state legislators. Regulators monitor the SPV trust and every six months adjust the special charge to ensure that there is enough money in the SPV to pay off the ratepayer bond on time.

Enthusiastic Reception

Credit rating agencies have given ratepayer bonds AAA ratings based mostly on the irrevocability of the claim to the cash flow from the special charge. Another credit positive is the fact that regulators periodically adjust the level of the special charge to ensure adequate funding of the trust.

Judging by the enthusiastic reception investors gave So Cal Edison’s $338 million transaction in February, there should be no problem selling upcoming utility securitizations. The offering was eight to 10 times oversubscribed, sources say.

Utility securitizations have brought together interest groups that have traditionally been adversarial.

“Environmental groups and renewable energy advocates have joined utilities in pushing for securitizations,” said J. Paul Forrester, partner at Chicago-based law firm Mayer Brown. “It’s not often that you see utilities and environmentalists working hand-in-hand, but it makes sense because utility securitizations will smooth and accelerate the path for power company green energy transition.”

In 2019, the Sierra Club threw its weight behind utility securitizations. “Securitization is a key financing tool that can help electric utilities accelerate the retirement of uneconomic, polluting coal plants and move more quickly toward a grid powered by clean, safe renewable energy,” the group said in announcing a report on the subject.

While utility securitizations will lower overall costs for dealing with stranded coal assets and climate change costs, the extremely complex nature of the deals means that the costs of structuring securitized utility transactions are very high.

Saber Partners said that some deals have had structuring costs north of $20 million, costs that Forrester is working to mitigate.

While he would not name his client because of confidentiality concerns, Forrester says he has been retained by a nonprofit to build a utility securitization deal template — a kind of “plug and play” solution — that utilities and state governments can use to allow for more securitizations while also reducing costs considerably.

March 7, 2021November 2, 2023

Virginia Takes $43.6M in its 1st RGGI Auction

Virginia sold $43.6 million in carbon dioxide allowances in its first Regional Greenhouse Gas Initiative (RGGI) auction since joining the cap-and-invest program in January.

“Virginia’s participation in RGGI signals our commitment to addressing climate change while creating economic and health benefits for communities across the commonwealth,” David Paylor, director of the Virginia Department of Environmental Quality, said in a press statement Friday. “Through the work of our agency partners at the Virginia Department of Conservation and Recreation and the Virginia Department of Housing and Community Development, auction proceeds will protect those most vulnerable to the risks of sea-level rise and flooding and apply badly needed upgrades to new and existing residential buildings.”

RGGI’s 51st auction on Wednesday generated $178.4 million for the 11 participating states from the sale of 23,467,261 allowances at a clearing price of $7.60, 19 cents higher than that for the 50th auction in December and 78 cents higher than the 49th auction’s in September.

Allowances in the 11.98 million cost-containment reserve remained unsold, and no allowances in the 11.31 million emissions-containment reserve were withheld. The fixed cost-containment reserve supply was available if allowance prices exceeded $13, while the emissions containment reserve supply was available for withholding if the clearing price fell below $6.

The minimum bid price was $2.38, and the maximum bid price was $12.86, according to the “Market Monitor Report for Auction 51″ prepared by Potomac Economics.

There were 44 winning bidders in the auction, with five bidders purchasing 1 million tons or more and 21 bidders purchasing 200,000 tons or more, the report said. Each allowance represents the authorization to emit 1 ton of CO2. The highest three bidders purchased 4.75 million, 4.075 million and 4.07 million allowances, respectively, according to the report.

Bidders in the auction, the report said, represent organizations in the following categories:

organizations that acquire and hold allowances primarily for their compliance obligations;
investors that have compliance obligations but hold allowances in excess of their compliance obligations, potentially for transfer to unaffiliated firms; and
investors without compliance obligations.

Organizations with compliance obligations and investors with compliance obligations together purchased 44% of the allowances sold in the auction, while organizations with compliance obligations alone purchased 42% of the allowances, the report said. In addition, 31 organizations with compliance obligations and 17 investors submitted bids, and 63 entities were qualified as potential bidders.

RGGI Hopefuls

North Carolina or Pennsylvania could be the next state to join RGGI.

Pennsylvania is in the middle of a rulemaking process to authorize RGGI participation. The Department of Environmental Protection started that process under a 2019 executive order from Gov. Tom Wolf. The department is considering public comments on its proposed rulemaking before issuing a final rule.

The plan to enter RGGI has met significant opposition from the state legislature, which passed a bill last year that said the state could not join the program without legislative action. Wolf vetoed the bill, but Rep. Jim Struzzi (R) reintroduced the legislation (HB 637) at the end of February. The bill now is in the House Environmental Resources and Energy Committee.

In North Carolina, the Southern Environmental Law Center (SELC) filed a petition for rulemaking with the Environmental Management Commission (EMC) for the state to join RGGI.

The petition, which SELC filed on behalf of Clean Air Carolina and the North Carolina Coastal Federation, piggybacks on the state’s effort to identify prudent state carbon policy, Nick Jimenez, staff attorney at SELC, said Thursday during a public outreach webinar. The state released a clean energy plan in 2019, but it did not select any specific policy action. Instead, Jimenez said, the plan called for an academic review of carbon policy options.

The North Carolina Clean Energy Plan “didn’t turn into action,” he said. “It sat on a shelf, and we just don’t have time for that to happen this time.”

The petition to join RGGI sets a timeline to act, he added, but it does not exclude other actions that might come from the academic policy review.

Jimenez said that SELC filed the petition on Jan. 11, and the EMC has 120 days to act on it.

“We don’t expect action sooner than May, but the clock is ticking, and action will come soon,” he said.

The EMC’s Air Quality Committee will hold a public meeting on March 10, during which it will hear a summary of a report on carbon-reduction policies for the North Carolina power sector, as recommended by the energy plan. The report was conducted by Duke University’s Nicholas Institute for Environmental Policy Solutions and the University of North Carolina’s Center for Climate, Energy, Environment and Economics.

March 7, 2021November 26, 2023

Hawaii Report Poses ‘Living’ Shoreline to Counter Sea Level Rise

A new report by the University of Hawaii Community Design Center explores the idea of creating “living” shorelines to fight sea level rise in Oahu’s urban and tourism core.

Authored by University of Hawaii professor Judith Stilgenbauer and funded by the state’s Office of Planning, the report focuses on the South Shore of Oahu, from Diamond Head through Waikiki and Honolulu, all the way to the Honolulu International Airport and Pearl Harbor.

The report explains that a sea level rise of 3.2 feet would flood 9,400 acres of land, displacing 13,300 residents and swamping 3,880 structures and nearly 18 miles of major roads. It would amount to “over $12.9 billion in economic loss and uncalculated number of billions of dollars in critical infrastructure loss.”

In addition to submerging sections of the shoreline, a 3.2-foot sea level rise, would increase the risk of flooding from tsunamis and hurricanes enough to put the entire urban core at risk. A 6-foot rise (assumed in the report to be reached by 2100) would put many of Waikiki’s famous beaches and hotels — and portions of Honolulu’s airport and central business district — underwater.

The project report explores a multifaceted approach to mitigate this risk: creating a living shoreline, adapting infrastructure to sea level rise and performing a “managed retreat” to higher elevations when necessary.

Much of Oahu’s South shoreline has been modified, with coastal wetlands filled to expand the airport, create harbors and extend land for public use and private construction. The report recommends reversing this development and creating a living shoreline, defined as “wetlands, tidal marshes and other vegetated coastal buffers that rely on ecosystem services and increase the distance between water and development, retain and absorb inundation, slow erosion and provide habitat.”

The value of a living shoreline would not only be its resilience to the evolving effects of rising sea level, but also in providing opportunity for “improved waterfront access, non-automobile circulation, recreation, culture, placemaking and education,” in addition to “traditional and productive Hawaii-specific biocultural land-water practices where possible and appropriate.”

Adapting infrastructure and conducting a managed retreat are simpler affairs, at least conceptually. For adaptation, the report recommends a combination of elevating structures, “floodable” development (structures designed for an occasional influx of water), and floating development. Suggestions conjure science fiction imagery: “floating buildings, transportation elements and infrastructure; elements are designed with fluctuating water levels in mind.”

Managed retreat would be a “withdrawal of development from the shoreline over time through managed abandonment of areas subject to frequent inundation.”

‘Catalytic’ Sites

In order to explore proof-of-concept, the report devised five criteria to help identify valuable areas: areas affected by a 3-foot sea level rise and exacerbated by tsunami or hurricane events; areas that could regularly be affected by a six-foot rise by 2100; properties large enough to avoid causing too many ownership conflict issues; tax parcels that have been affected by the previous criteria; and areas that would be affected by a 3-foot sea level rise by 2050.

The report identified three areas as “catalytic” sites: Ala Wai Canal in Waikiki, Ke’ehi Lagoon near the airport and the surrounding areas of the Pearl Harbor Visitor Center and Aiea Bay Recreation Area.

Perhaps the most important catalytic site would be the Ala Wai Canal, which runs from mountain streams behind Waikiki to the ocean. Long known as a polluted waterway with runoff from rivers and human trash dumping, its reach from the east side of Waikiki around the back of the area creates a pincer-like danger from rising sea level. The report cites a 2015 US Army Corps of Engineers study saying that damages associated with a 100-year flood event in the canal’s watershed are estimated at $1.14 billion.

Bordering the canal on one side is an 18-hole golf course, a park and canoe launching site, a public library and an elementary school; on the other side, the three-lane Ala Wai Boulevard and an additional lane for parking. The proof-of-concept design would reduce the golf course to nine holes and, over time, eliminate it completely, changing the entire site into a mixed-use area of an amphibious habitat, wetlands and urban agriculture. It would also, over the long term, eliminate automobile use of Ala Wai Boulevard and convert it for “multimodal transit, as well as improved pedestrian and bicycle connectivity and water access — all while providing flood-control for Waikiki (Ala Wai side), facilitating the elevation of critical infrastructure elements and, more generally, the adjacent urban fabric’s phased adaptation to increasing climate-crisis threats over time.”

The entire site would include walking paths, raised viewing platforms, water access and public facilities for recreation. The canal would use natural methods to keep the water clean, such as oysters, which are known to filter water and aid in water health. The Gowanus Canal in Brooklyn, New York, for example, is one of the most polluted waterways in the U.S., but programs such as the Billion Oyster Project are using this idea to help clean the polluted water.

Catalytic sites 2 and 3 — Ke’ehi Lagoon to the east of the airport and the Pearl Harbor Visitor Center and surroundings, respectively — would commit to many of the same practices: slowly changing the shoreline into coastal wetlands using native plant species and building public facilities to engage with the area and provide water access.

The report recommends connecting these three catalytic sites with the rest of the urban core via multimodal transit. Dubbed the South Shore Promenade, it would be a bicycle and pedestrian path along the urban core’s entire waterfront. This path would coincide with stations of the Honolulu Area Rapid Transit (HART), a raised rail transit system currently under construction.

The report also recommends the creation of a water taxi and ferry system with stations linked to the promenade to further reduce reliance on cars. This plan would help the traffic-jammed streets and highways of Honolulu, which for years has been rated one of the worst cities in the nation for traffic.