FERC last week sent ISO-NE a deficiency notice regarding the RTO’s proposed rule revisions on cost of new entry (CONE), net CONE and the performance payment rate (PPR) for the Forward Capacity Auction, NEPOOL Participants Committee members heard last week.
In a memo to the committee, the RTO said it understood the notice “may cause uncertainty for participants about how the FCA 16 qualification process will proceed in the meantime.”
The notice gives ISO-NE 30 days to furnish an example of a potential site for the CONE reference unit in or near New London County, Conn., 2 miles from both a central natural gas line and the point of interconnection to the electric grid. The RTO must also provide an estimate of emissions limits and whether those limits affect the reference unit’s revenue and offer additional support for the assumption in the dispatch model that the reference unit always runs on natural gas rather than oil. Submission of that information will reset the deadline for FERC action on the filing.
The RTO said the current schedule of qualification activities for FCA 16 would continue as planned, and it will apply CONE, net CONE and PPR values for FCA 16 filed with FERC in December.
Dynamic delist bid threshold (DDBT) calculations were due last Friday, and the deadline for retirement and permanent delist bids is this Friday. ISO-NE said participants should adhere to the currently filed FCA 16 CONE values and published DDBT value for their bids.
FERC recently approved tariff revisions developed by the RTO and stakeholders on recalculating DDBT for the FCA. DDBT, which was previously updated every three years, will now be calculated annually using a tariff-based “recalibration method.” Values for each auction will be updated based on recently available supply conditions and up-to-date projected demand conditions using the estimated systemwide demand curve for the FCA. (See related story, FERC Approves ISO-NE’s New Method for Calculating DDBT.)
ISO-NE plans to respond to the deficiency notice by Thursday. The RTO added that with the limited nature of the deficiency requests, it will request expedited review to receive an order on the FCA 16 CONE filing by mid-April. FERC’s order would be issued in mid-May if it chooses to use the full 60 days available to it.
Action on ORTP Deferred
The PC had been scheduled to discuss and vote on amendments for offer review trigger prices (ORTPs) used for Forward Capacity Market (FCM) parameters for the 2025/26 capacity commitment period, which accommodate recent changes and extensions to the federal investment tax credit for solar and wind developers.
ISO-NE requested the PC postpone action on the issue until a later date in March. The RTO’s ORTP proposal, created in concert with consultants Concentric Energy Advisors and Mott MacDonald, did not receive any support from stakeholders at a recent Markets Committee meeting. It would create two new ORTP categories: solar and solar plus lithium-ion batteries.
Tariff revisions include ORTP values of $0/kW-month for solar and $6.964/kW for solar-plus-batteries, down from its initially proposed $9.371/kW. Another tariff revision clarifies that the weighted-average calculation is used only when an ORTP for the combination of technology types is not specified. New tariff language details the values for solar-plus-batteries in future Forward Capacity Auctions.
Boreas Renewables presented three amendments, which all passed with at least 73% support from stakeholders, regarding ORTP values for FCA 16, annual ORTP updates for FCA 17-18 and maintaining existing ORTP determinations for resources with a shared point of interconnection for FCA 16. Like the RTO’s proposal, the first would change the ORTP for solar to $0. The second amendment would allow for an ITC assumption of 26% for FCA 17 and 22% for FCA 18 if the tax law remains unchanged for solar developers. Should the law change again in the next two years, it would be reflected in the final assumption used for the FCA 17-18 updates. (See Revised Stakeholder Amendments on ORTPs Gain Support.)
The original timeline called for a filing at FERC by the end of March. ISO-NE’s Internal Market Monitor said in a memo to the MC that the RTO will file a proposal for ORTP values under Section 205 of the Federal Power Act, “which will include a ‘jump ball’ alternate proposal of ORTP values from NEPOOL.” The Monitor added that ISO-NE would request FERC’s decision by May.
Energy Market Valuation Rises Dramatically
ISO-NE’s energy market value for February was $716 million (through Feb. 24), up $228 million from the updated January valuation and $483 million higher than the same month in 2020, according to the monthly report from COO Vamsi Chadalavada.
The ISO-NE energy market value in February was $716 million, which was a significant rise from January and nearly $500 million higher than February 2020. | ISO-NE
Natural gas prices were up 92% from January, which spiked average real-time hub LMPs by 77% to $77.42/MWh. Average natural gas prices and real-time hub LMPs were up 320% and 281%, respectively, from the same period last year.
Average day-ahead cleared physical energy during peak hours as a percentage of the forecasted load was 99.2% during February, up from 98.4% during January, with the minimum value for the month of 94.4% posted Feb. 1.
Daily uplift or net commitment period compensation (NCPC) payments totaled $2.3 million over the period, down $1.2 million from the adjusted January value and up $1.3 million from February 2020. NCPC payments were 0.3% of the energy market value.
Chadalavada added that seven new PV projects totaling 493 MW applied for an interconnection study, with in-service dates ranging from 2022 to 2024. There are 265 generation projects currently being tracked by the RTO, totaling about 24,600 MW.
The energy industry’s largest international gathering, CERAWeek by IHS Markit, was conducted virtually last week with “unprecedented” participation by more than 20,000 delegates from 95 countries, according to event organizers.
Some 500 speakers in over 200 sessions discussed decarbonization, affordability and energy security, while also offering their visions of post-pandemic economic recovery and growth.
CERAWeek is expected to return to Houston next year, where it typically draws more than 6,000 attendees from around the world.
This year, organizers added a pair of sessions on the February winter storm that sidelined power plants and caused widespread outages in Texas. Rebecca Klein, a principal in her own consulting firm and a former Texas Public Utility Commissioner, led her panel through a discussion of the systemwide failure.
Rebecca Klein (top left) moderates a panel with (clockwise) Lawrence Makovich, Michael Webber and Pat Wood. | CERAWeek by IHS Markit
When asked how it happened, IHS Markit Vice President Lawrence Makovich pointed to the ERCOT energy-only market’s “inherent flaw” of depressed pricing levels not incenting new generation.
“There’s an underinvestment in the amount of capital and an underinvestment in the capacity that is there and available,” he said. “The market causes supply and demand to clear in real-time at price levels too low to cover all the cost of power investment you want for customers to have efficient and reliable energy. They still had price signals that were not going to get the job done. The reliability crisis had come to pass, and you can look back on this and see all the signposts that this was going to happen.”
Michael Webber, Engie’s chief science and technology officer, disagreed. He said ERCOT’s normal prices of $25/MWh haven’t slowed the addition of capital, noting Texas has built more capacity over the last 15 years than any other state.
“Hopefully, we’ll keep building, but we’ll anticipate storms like these and weatherize,” Webber said. “All these power plants could winterize, but it increases your costs a few percentage points. You increase your winter efficiency, but you decrease your summer efficiency.”
“We design a system that’s great for the summer, but are we focusing on these one-in-10-year events? We’re absolutely going to plan for that now,” said Hunt Energy Network CEO Pat Wood. He said 158 Texas plants failed to perform during the winter storm, while generators in the northeastern RTOs don’t seem to share that problem.
Hunt Energy Network CEO Pat Wood | CERAWeek by IHS Markit
“We’re a state that doesn’t like mandates, so we set minimum standards and let the market determine how to meet those standards,” Webber said. “If you want to be in this market, you must meet these standards. Raising the standards according to weather extremes we think will happen more frequently, and that means extreme heat and extreme cold — that’s the way to go.”
Participating in a separate panel of IHS Markit power and natural gas experts, Doug Giuffre corroborated Webber’s point by describing a colleague’s recent research into 70 years of Texas weather data. It turns out the February storm was among the most extreme weather events in the state, “at least through 70 years of data,” Giuffre said, and probably the third-most extreme when looking at duration and multiple days of below-freezing temperatures.
Giuffre said ERCOT’s winter seasonal assessment included the 2011 event that led to two days of rotating blackouts as an extreme scenario. “It was probably the 34th most extreme event,” he said. “It wouldn’t even fall within the top 15.”
That 2011 event led to voluntary weatherization standards, with no enforcement.
“In 2011, the conversation was actually from the bottom up. You had the market participants and industry officials talking about potential market reform,” said IHS Markit’s Bob Ineson. “This time, the legislature has stepped in. That’s going to play an important role going forward.”
“I’ve learned as a regulator that you either pass a rule or you shut up,” said Wood, who has chaired both FERC and the Texas PUC. “Voluntary or best [weatherization] practices are great … but that’s the minimum standard. You’ve got to [weatherize]. You’ve got to ensure people don’t die.”
Gates Explains the ‘Green Premium’
Philanthropist and Microsoft founder Bill Gates helped set the framework for CERAWeek by focusing on the “green premium” — the “extra cost you pay” for products and investments that are more environmentally friendly.
“For electric cars, it’s very small. There are some upfront costs, and you give up some range. … It’s a modest green premium,” Gates said. “We can see that with volume and various initiatives, that green premium will get to zero, and that’s mind-blowing.
IHS Markit Vice Chair Daniel Yergin (left) chats with Bill Gates. | CERAWeek by IHS Markit
“I think of the green premium as what it would cost to change everything and pay the green premium,” he said. “Imagine a phone call I might make in 2050. I’m talking to India, where there are more lights at night and they’re building buildings. If the green premium at the time is over $1 trillion, India will say no. They’ll just do it the normal way. The United States and other rich countries owe more to the world than lowering our emissions by brute force.”
Gates is taking that a step further with Breakthrough Energy, a network of entities and initiatives he established in 2015 with a coalition of private investors supporting innovations to help the world reach net-zero emissions by 2050. Those involved follow the same public-private partnership model Gates has used to improve health, education and public welfare around the globe. The focus has been on net-zero technologies, such as energy storage.
Bill Gates’ Breakthrough Energy initiative foresees a lowered green premium as R&D becomes policy. | CERAWeek by IHS Markit
“A cold front in the Midwest can shut down wind and solar. Electricity is only valuable when it’s totally reliable,” Gates said. “Factories and hospitals are built to run 24 hours a day. We put in all generation and transmission in our model and say, ‘What if? What type of storage would work?’
“Growing that electric network and maintaining that reliability is vastly underestimated. We need to draw in lots of people using the same model so you can’t exaggerate the benefits of different things. Utilities, we all need to be using that same model.”
Biden Administration Meets, Greets
A trio of newly minted Biden administration representatives — Special Presidential Envoy for Climate John Kerry, Secretary of Energy Jennifer Granholm and White House National Climate Adviser and former EPA Administrator Gina McCarthy — took advantage of CERAWeek to engage with the energy industry in what host Daniel Yergin referred to as a “meet and greet.”
Special Presidential Envoy for Climate John Kerry | CERAWeek by IHS Markit
The administration is counting on the environmental heavyweights to bring the U.S. back into a leadership position in the global drive to achieve net-zero carbon emissions. Kerry noted that President Biden rejoined the Paris Agreement within hours of his inauguration. The U.S. has pledged to cut greenhouse gas emissions by up to 28% from 2005 levels and is expected to make a more ambitious commitment during an April international climate summit.
“We’ve set out a most ambitious climate agenda, not as a matter of ideology and politics, but as a matter of exclusively listening to the scientists,” Kerry said in a question-and-answer session with former Energy Secretary Ernie Moniz. “This is very, very high on our agenda. This is a crisis. It’s a national security threat; it’s a health threat; it’s an economic threat. We’ve spent billions and billions cleaning up after hurricanes and storms and fires. Science is completely unified around what is happening to the planet and what will continue to happen.”
An ebullient Granholm welcomed participation in the administration’s clean energy plans, saying, “It’s a heck of an economic opportunity.”
Secretary of Energy Jennifer Granholm | CERAWeek by IHS Markit
“The processes that reduce carbon emissions will create a $23 trillion global market over the next decade,” she said. “Where will those investments be? In China? Other economic competitors to us? You better believe other countries are going to be involved. Are we going to be in the battle, or are we going to bring a knife to a gunfight?
“President Biden has demanded we be in the battle, not on the sidelines anymore. The Department of Energy is going to be one of our government’s more fierce fighting forces as we surpass our goal of a carbon-free economy,” Granholm said in continuing the warfare analogy. “We’ve got to add hundreds and hundreds of gigawatts of clean energy to the grid over time, and that will add millions of good paying jobs.”
McCarthy has been tasked with developing the nation’s national determined contributions (NDCs) to reduce emissions as required under the Paris Agreement.
“President Biden went out strong, because he knows there’s no time to waste. One of the things he said is science matters, and we’ll pay attention to it,” she said. “My job is to work across the whole of government to determine an NDC for the U.S., to put some punch behind our commitment. We’re going to work really hard … to deliver on our 2030 goal and be on track to be net zero by 2050. That’s my job, and I’m sticking to it.”
White House National Climate Adviser Gina McCarthy | CERAWeek by IHS Markit
Kerry has been charged with organizing the global summit on April 2, which he said means pulling together the world’s major GHG emitters. That would include China, the only country that emits more GHGs than the U.S., and an old foe from Kerry’s time in the Obama administration.
“Yes, there are tensions today that did not exist back then. They’re out in the open,” he said. “It’s no secret there is strong competition with China in any number of fields … but the climate crisis is not something that can fall victim to other concerns and processes. We’re not solving this with any one country alone, but you have to have China at the table. I think China can be a critical partner in this as they were before.”
A similar FERC-NERC report after the 2011 event in Texas went unheeded. The “pretty lengthy report,” as Glick recalled, recommended generation facilities be weatherized. Yet, nearly three dozen plants that failed 10 years ago also failed last month.
“Somehow, throughout the process, those recommendations turned out to be guidance,” Glick said. “In a competitive market like Texas, one competitor is not going to voluntarily make changes to weatherize their equipment if another competitor doesn’t.”
FERC Commissioner Richard Glick | CERAWeek by IHS Markit
“I’m really glad FERC and NERC are doing this study,” Wood said during a separate discussion. “I hope they don’t just change the date and give us the same report. This can’t be swept under the rug.”
“The 2011 report and circumstances should be a warning to all of us,” Glick said. “I’m making a commitment that we’re not going to let this report be a report that sits on the shelf. It’s just disturbing that the 2011 recommendations didn’t lead to action. We need to make sure that doesn’t happen this time.”
Glick also said long-haul transmission will remain a priority for the commission. While FERC has no control over siting, it can pull other levers to encourage bringing renewable energy from rural areas to metropolitan load centers.
“If we don’t act, I don’t think we’re going to reach those clean energy goals,” he said. “With our targets, we’re going to need all the renewable resources we have. We need a lot of transmission, whether offshore or in the middle of the country. We do have authority over [transmission] planning and cost allocation. … We have a responsibility to ensure that we only allocate costs to those who benefit.”
Will Carbon Price Drive Change?
Rostin Behnam, acting chairman of the U.S. Commodity Futures Trading Commission (CFTC), said financial markets will only be able to channel resources to reduce GHG emissions if an economy-wide price on carbon reflects the true social cost of those emissions.
Behnam led a 34-member CFTC committee that produced a report last year on the policies needed to address climate-related risks to the U.S. financial sector.
“The conversation has changed since the Obama administration,” he said, noting the committee’s diverse group of stakeholders, from agriculture to the financial sector. “It was a very strong statement for all of them to coalesce around the importance of having a price on carbon … creating a cost such that market participants will then adjust their actions around that cost. We’ll see what happens, but I’m encouraged by the current administration’s efforts to address the climate crisis. A carbon price is going to be a high-level subject of conversation in the coming weeks and months.”
Some communities will need to consider where they can “sacrifice trees for clean energy generation that mitigates catastrophic climate change,” Kelly Friend, vice president of policy and regulatory affairs at solar energy company Nexamp, said Thursday.
Likewise, Friend said, energy companies must compromise with the communities where they want to site projects.
“It’s a false choice between do we develop [distributed] solar at scale, or do we protect open lands and forests,” Friend said at the Northeast Energy and Commerce Association’s Renewable Energy Conference. “I don’t think it has to be either-or.”
Some states, like Massachusetts, have a high-load, high-density population and aging infrastructure, so it is not feasible to site all clean energy in built-environment areas. And when it comes to siting renewable energy projects, community opposition is not just a case of “not in my backyard;” it is critical that communities have a say in what is happening in their neighborhoods, Friend said.
Creative project siting, like this solar farm in a cranberry bog, along with compromise between developers and communities will be critical to building out the clean generation states need to meet climate objectives. | Nexamp
People who speak English as a second language and frontline workers are not always able to participate in public meetings organized by state boards, but their communities tend to have disproportionately more energy infrastructure and greenhouse gas emissions. Black and Hispanic families in Boston experience 38% higher air pollution concentrations compared to white families, according to research from the Boston University School of Public Health.
“Unfortunately, because of where we are in our fight against climate and the unequal cost that [minority and low-income communities] have had to bear, we’re now trying to solve a lot more problems,” Friend said.
Environmental justice communities are reluctant to allow more infrastructure into their neighborhoods, preferring to preserve the open space they have, while environmentalists push to conserve vital ecosystems. Friend said collaboration between utilities and communities is vital to meet Massachusetts’ ambitious climate goal of net-zero emissions by 2050.
Last month, Gov. Charlie Baker returned a comprehensive climate bill to the Massachusetts legislature with amendments that would strengthen the definition of environmental justice communities and identify climate change as a burden on the communities. There are no mechanisms in place to ensure an equity lens when building new energy generation or distribution infrastructure, “short of a developer choosing to calculate that within their own perspective on a project,” Courtney Feeley Karp, senior counsel at Klavens Law Group, said at the conference.
The challenge energy companies and regulators need to address is how to avoid “making mistakes of the past with respect to the siting” of clean energy infrastructure to achieve net-zero emissions and energy justice, Feeley Karp said.
The Massachusetts climate bill would direct the Department of Public Utilities to incorporate a holistic equity approach to analyzing the cumulative impact of an energy facility project. But Friend said additional complex regulations and regulatory imperatives for utilities at the state level leave less room for them to be creative in finding a solution that benefits the community and the utility in transitioning to clean energy.
“There’s all of this room in between that probably leaves space for innovation, but utilities can’t move because they’re being regulated to the letter by this,” Friend said. “And we don’t have a lot of time to waste in bickering over the details.”
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.
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.
Phil Herrington, Southern California Edison senior vice president of transmission and distribution, responded to criticism of the utility. | California State Assembly
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.)
CPUC President Marybel Batjer and Executive Director Rachel Peterson discussed PSPS performance by the state’s investor-owned utilities. | California State Assembly
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.
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.
Bob Kahn | ERCOT
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.
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.
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.
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.
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.
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.
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.
