Page 968 – RTO Insider

March 7, 2021

Texas PUC Won’t Reprice $16B Error

Texas regulators on Friday declined to take action on the ERCOT Independent Market Monitor’s recommendation to reprice $16 billion in market transactions that may have been incorrectly priced following the February winter storm.

The Monitor said on Wednesday that ERCOT erred in maintaining wholesale prices at the $9,000/MWh systemwide price cap for 33 hours after it stopped shedding firm load following the storm’s widespread outages. Prices soared by more than $47 billion during the storm’s five-day period, the Monitor said. (See related story, “Monitor: $16B ERCOT Overcharge,” ERCOT Board Cuts Ties with Magness.)

However, the Public Utility Commission, faced with making a decision to meet a deadline for the commodity clearinghouse Intercontinental Exchange, chose not to take a chance with repricing’s unintended consequences (51812).

The PUC directed ERCOT to set wholesale power prices at the $9,000/MWh cap during the storm in an effort to add more generation and resolve the nonrotating blackouts. Prices stayed at the cap until they were relaxed in the early-morning hours of Feb. 19.

$16 billion in market transactions — ERCOT’s Kenan Ögelman testifies before the Texas Senate’s Business and Commerce Committee. | *Texas Senate*

Kenan Ögelman, ERCOT’s vice president of commercial operations, told the Texas Senate’s Business and Commerce Committee on Friday that the grid was already in a Level 3 energy emergency alert, but staff were not “seeing the pricing that was expected, given the value of lost load consistent with the protocols we have.”

He said prices would reach the $9,000/MWh cap as supplies tightened. However, when ERCOT would shed more load, additional reserves would be created that would drop the price back down, incenting resources to add more generation and leading to oscillation fears.

“Across the board, from the transmission side to the ERCOT to the generation side, people were worried if prices dropped and load came back in one very big wave, you could essentially tumble down into an unstable circumstance,” Ögelman said.

PUC Chair Arthur D’Andrea used a series of analogies to explain why he wasn’t ready to move on repricing what the Monitor referred to as ERCOT’s “inappropriate pricing intervention.”

“We just see the tip of the iceberg,” D’Andrea said, referring to hedges and other transactions that may lie below the surface. “You think you’re protecting the consumer, and it turns out you’re bankrupting a cooperative or a city.”

He said “it’s nearly impossible to unscramble this sort of egg” when “decisions were made about these prices in real time, based on information available to everybody, to all market participants.”

“They did all sorts of things they wouldn’t have ever done if the prices were different,” D’Andrea said. “I know that on the surface, it’s like, ‘Oh, no, it’s just the money the generators got. If you reverse it, it will go to the consumers.’

“That’s very simplistic, and it’s not how it works. There are people representing consumers on both sides of this question. People are looking out for the consumers who don’t want us to reprice, and there are a lot of consumers who could be hurt by repricing. The reason for that is very complicated, but it’s mostly got to do with a lot of private arrangements and transactions that happen outside the market,” he said.

D’Andrea received complete agreement from Shelly Botkin, the only other commissioner after previous Chair DeAnn Walker’s resignation on March 1. (See PUCT’s Walker Steps Down from Commission.) Late Monday, Botkin also resigned.

In reaching consensus, the commissioners said they took into consideration Sen. Drew Springer’s (R) suggestion that they “immediately” follow the Monitor’s recommendations. Springer referenced the Texas Energy Association for Marketers’ filing, supported by 37 large customers at the time, to reprice the 33 hours following the end of the load shed.

“Revising this pricing would mean significant savings for a number of commercial/industrial customers, municipals and cooperatives who are facing extremely high costs from the PUC’s actions,” he said.

D’Andrea said he was grateful for Springer’s feedback. He said the PUC and the Legislature need to be “standing shoulder to shoulder” as they work to resettle the ERCOT market and make any reforms.

“I don’t intend to make any huge decisions without talking to all of them first,” D’Andrea said. “I hope what I have said today addresses why I’m reluctant to reprice. I totally get how it looks like you’re protecting consumers, but I promise you, you’re not.”

The commission did rescind an order stopping late fees on customers with late electric bills and directed transmission and distribution service providers to stop charging customers for cold-load pickup spikes following lengthy outages. Many commercial customers’ bills are determined by their largest moment of usage.

Retail electric providers must still offer deferred payments to customers on requests, the commissioners said.

The PUC put off discussion on raising the low systemwide offer cap (LCAP) from $2,000/MWh to $9,000/MWh for this summer in order to allow stakeholder comments by March 26. D’Andrea indicated a preference to keep the LCAP at $2,000/MWh this summer, saying, “I’ve heard advocacy for it, but I have not heard from the other side.”

ERCOT Market Under ‘Financial Duress’

Ögelman told the Senate committee during its Thursday hearing that ERCOT’s market is still recovering from the tens of billions of dollars it has been moving through the settlement system. Noting that the market typically sees about $11 million of daily transactions during the winter and shoulder months, he said invoices amounted to about $22.5 billion for the week of the winter storm, according to his calculations — more than four times 2020’s total of about $5 billion.

ERCOT is currently short about $1.7 billion in payments to market participants, Ögelman said. Much of that came on Feb. 26, when the grid operator came up $2.1 billion short on $12.5 billion of invoices. It borrowed $800,000 from the congestion revenue rights fund to narrow the gap.

“ERCOT as a market is under a lot of financial duress,” he said. “The numbers we’ve been talking about in the billions, the folks trying to make those payments, and being dependent on those payments to pay downstream costs … the market is under extreme duress.”

Ögelman said ERCOT’s short pays are much smaller now, reaching just over $164,751 that day as temperatures and prices have returned to normal.

“It’s kind of dollar in, dollars out. I would expect additional short pays to come in, but in the single millions of dollars, not anything as you saw on Feb. 26,” he said.

Asked what ERCOT can do about short-paying market participants, Ögelman responded that they can be kicked out of the market. The grid operator has already revoked the licenses of two electric retailers, while nearly 20 others are thought to be on the brink of default. Brazos Electric Power Cooperative has already declared bankruptcy.

ERCOT staff told the Technical Advisory Committee on Friday that they expect additional defaults. Five retailers have been acquired or terminated market activity, said Mark Ruane, senior director of settlements, retail and credit.

The Coalition of Competitive Retail Electric Providers trade group and multiple retailers have filed emergency action requests with the PUC to “avoid irreparable [market] harm” by suspending immediate collections on the massive bills. The PUC is expected to file an order during its Thursday open meeting that would extend ERCOT’s 10-day settlement dispute timelines, which Ögelman teased by telling the TAC to expect a market notice on extensions to the dispute timeline.

The PUC has also opened a docket to review ERCOT’s scarcity pricing mechanism (51871).

Sen. Kelly Hancock (R), the Business and Commerce Committee’s chair, referred to the $9,000/MWh cap in saying changes need to be made.

“I don’t think anybody envisioned this, but it’s certainly shown we do have to redesign our system if we want to attract dispatchable energy into the state,” he said.

TAC Takes up Ideas for Solutions

The TAC held a special meeting Friday to identify and catalogue potential solutions to the events preceding and following last month’s severe winter storm, beginning with a list of issues submitted by ERCOT CEO Bill Magness.

“ERCOT believes it is important to immediately analyze the issues and make changes to improve the performance of the electric system if we experience another extreme event,” Magness said in a letter to the committee.

He outlined eight issues, including improved coordination with transmission and distribution providers on rotating-outage practices; working with applicable government and private entities to improve ERCOT emergency public safety communications; and expanding extreme peak load and generation outage scenario analyses in ERCOT’s seasonal assessments of resource adequacy.

The TAC’s Retail Market, Wholesale Market and Reliability and Operations subcommittees also submitted suggested issues for evaluation. The committee leadership will work with ERCOT staff to prioritize the ideas and parcel them back out to the subcommittees during the TAC’s regular March 24 meeting.

Congressional Inquiries Grow

Congressional hearings and investigations continue to pile up for ERCOT.

The House of Representatives’ Energy and Commerce Committee wrote to Magness on Thursday to request a briefing and information on the February events. The five committee members, who include Reps. Marc Veasey and Lizzie Fletcher, both Democrats of Texas, cited the “significant shortcomings” in ERCOT’s preparation and response to the incident.

“The ongoing crisis raises significant questions regarding Texas’ grid resilience and regulatory regime and ERCOT’s stewardship of the grid prior to and during this crisis,” committee members wrote.

The lawmakers stressed more must be done to “protect communities disproportionately impacted by winter power outages.” They pointed to a 2011 report from FERC and NERC that made a number of recommendations for the electric and natural gas industries.

The Senate Energy and Natural Resources Committee has a hearing scheduled for Thursday on the reliability, resilience and affordability of electric service, while Rep. Eddie Bernice Johnson (D-Texas), chair of the Science, Space and Technology Committee, has scheduled a March 18 hearing on “Lessons Learned from the Texas Blackouts: Research Needs for a Secure and Resilient Grid.”

The House Oversight and Government Reform Subcommittee on the Environment has also requested documents and information on ERCOT’s preparations for the storm. (See related story, House Oversight Committee Pokes into ERCOT.)

The outages and ERCOT’s response is also being investigated by the Texas Legislature, the PUC and the attorney general’s office. FERC and NERC has also opened a joint inquiry into the severe winter storm.

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.

March 7, 2021November 2, 2023

Nev. Program Seeks Calif. Standards for Vehicle Emissions

A Nevada state agency is seeking approval by year-end for a program to tighten vehicle emission standards and increase availability of electric cars, bringing the state’s regulations in line with those of California.

The program, Clean Cars Nevada, was announced by Gov. Steve Sisolak in June. The Nevada Division of Environmental Protection (NDEP) has released draft regulations that would implement the program, with a goal of receiving approval from the State Environmental Commission by December.

If all goes as planned, the program will take effect for model year 2025 vehicles.

LEV and ZEV

Clean Cars Nevada has two components: the low-emissions vehicle (LEV) and zero-emissions vehicle (ZEV) programs.

Nevada’s transportation sector has grown to account for the largest share of the state’s GHG emissions with the reduction of electricity generation emissions. | Nevada Division of Environmental Protection

The LEV program would apply California’s emission standards for greenhouse gases and other pollutants to cars for sale or for lease in Nevada. Those would include passenger cars, light-duty trucks and medium-duty vehicles.

Under the federal Clean Air Act, federal standards apply to tailpipe emissions unless a state decides to implement California’s more stringent emission standards, which 13 other states have adopted. Nevada, Minnesota and New Mexico are in the process of evaluating or adopting the California standards.

Under the ZEV program, Nevada would require automakers to sell an increasing percentage of zero emission vehicles. The program uses a system of credits that are awarded based on the type of zero-emission vehicle sold and the vehicle’s range.

Ten states in addition to California have adopted the ZEV program.

However, Clean Cars Nevada faces a potential roadblock. The Trump administration in September 2019 revoked California’s waiver allowing the state to implement its own emission standards and ZEV program.

The rule revoking the waiver has been challenged in court. It’s also possible that the Biden administration will reverse it.

For now, NDEP’s authorization to implement Clean Cars Nevada states that the regulation will take effect only if the California waiver is reinstated or a new waiver is issued.

Support, Opposition

Clean Cars Nevada has the support of more than 70 organizations, including environmental, business and public health groups that have joined to form the Nevada Clean Cars Coalition, according to the National Resources Defense Council.

Travis Madsen, transportation program director with the Southwest Energy Efficiency Project, said electric vehicles are almost three times as efficient as their gas-powered counterparts.

“That translates into major benefits, including saving consumers money, improving public health and reducing climate-changing pollution,” Madsen said during a public listening session that NDEP hosted in January.

But Madsen had concerns about a provision in the proposed regulation that would award ZEV credits to automakers based on their balance in California’s credit bank. That would in effect give automakers a pass for several years of the Nevada program, Madsen said. Instead, he’d like to see the state focus on awarding ZEV credits to automakers who act early to increase the availability of electric cars.

Andrew MacKay, executive director of the Nevada Franchised Auto Dealers Association (NFADA), said regulation of fuel economy and emissions should be left to the federal government to provide more regulatory certainty. NFADA opposes Clean Cars Nevada.

MacKay said the affordability of new vehicles to consumers should also be considered.

“If we lose affordability, we will lose vehicle sales,” MacKay said during the NDEP listening session. “And if we lose sales, all that we will do is keep older, less safe, less fuel-efficient vehicles on the road, potentially shifting our environmental goals into neutral or reverse.”

Next Steps

NDEP hosted a webinar introducing Clean Cars Nevada in December, followed by the listening session in January. Last month, the agency held a technical session to discuss the LEV program.

The next steps are a technical session on the ZEV program on March 30, from 9-11 a.m., and a technical session on the ZEV credit bank sometime in April.

NDEP will analyze the impacts of the program on air quality and small businesses and post the findings on the program’s website.

NDEP expects to revise the proposed regulations based on feedback. That will be followed by a public workshop in June. The regulation is tentatively scheduled for a State Environmental Commission hearing in September.

The Nevada Department of Motor Vehicles will also review the proposal.

Meeting GHG Goals

Clean Cars Nevada is intended to help the state meet greenhouse gas reduction goals set by Senate Bill 254, which was signed into law in 2019. The state aims to reduce GHGs to 28% below 2005 levels by 2025, 45% below by 2030, and achieve zero or near-zero emissions by 2050.

NDEP projections show the state falling short of meeting those targets, with a 24% reduction in greenhouse gases by 2025 and a 27% reduction by 2030.

The transportation sector has been the biggest contributor to GHG emissions in the state since overtaking the electricity generation sector in 2015, according to the agency’s most recent greenhouse gas inventory. As of 2017, the transportation sector accounted for 36% of the state’s GHG emissions, followed by electricity generation at 30% and industry at 15%.

When broken down by fuel type, gasoline accounted for 59% of Nevada’s GHG emissions from transportation in 2017, followed by diesel at 23% and aviation fuels at 16%.

March 5, 2021

NERC RSTC Briefs: March 2-3, 2021

NERC’s Reliability and Security Technical Committee took a number of actions in a two-day meeting this week.

DER Standard Request Denied

The committee rejected a standard authorization request (SAR) to revise reliability standard TPL-001-5.1 (Transmission system planning performance requirements). The SAR was proposed by the System Planning Impacts from Distributed Energy Resources (SPIDER) Working Group based on a white paper endorsed by the RSTC at its meeting in October. (See “Consent Agenda Items Approved After Debates,” NERC RSTC Briefs: Oct. 14, 2020.)

Only 19 of the 31 members present voted to endorse the SAR, short of the two-thirds majority required for passage; eight voted against endorsement, while four abstained.

Several members said that while they agreed with the need to update NERC’s standards to account for the growing penetration of distributed energy resources (DER), the decision to put forward a SAR seemed premature. For example, David Jacobson of Manitoba Hydro reminded the committee that it had only just voted to endorse the guideline for verifying aggregated DER models the same day and warned that starting the standards development process without reliable data and models seemed to put the “cart before the horse.”

NERC RSTC — Brian Evans-Mongeon, Utility Services Inc. | *NERC*

Brian Evans-Mongeon of Utility Services Inc. raised several questions for SPIDER Chair Kun Zhu of MISO: first, whether the working group intended for the proposed changes to take effect before July 2023, the enforceable date of TPL-001-5.1; second, why the SAR did not specify its applicability to non-bulk electric system devices; and third, whether SPIDER and the Inverter-based Resources Performance Working Group (IRPWG) deemed MOD-032-1 (Data for power system modeling and analysis) sufficient “to provide the necessary data collection to support … these planning assessments.”

In response to the first and third questions, Zhu told Evans-Mongeon that the groups had not taken “specific … positions” on the issues he raised; on the second, he said “the applicability [of the existing standard] doesn’t change” with regard to non-BES devices. Evans-Mongeon suggested that more revisions were needed to make the SAR “ready for prime time.”

“I just think that there’s additional clarification and the need to eliminate confusion as we move forward … and I just feel that this SAR does not go far enough,” Evans-Mongeon said. “I think it can be expanded upon [and] can be improved, but right now I just don’t think it’s ready … especially if we’re looking at something that’s not going to be enforceable for two-plus years.”

The vote not to endorse the SAR does not mean the effort to revise TPL-001-5.1 is dead, as SPIDER can bring the proposal to the Standards Committee without endorsement. However, Howard Gugel, NERC’s vice president of engineering and standards, recommended that because members agreed on the importance of the project, the committee should try to work with the group to address their concerns.

“Since the RSTC, or its predecessors … authorized this group to begin its work [and] is now saying that it shouldn’t proceed, there should be some specific information … provided to this team” to help rework the SAR into an acceptable form, he said.

Approvals

Members approved scope documents and work plans for several of the RSTC’s subcommittees, working groups and task forces. Included were the scopes for the Performance Analysis Subcommittee, Event Analysis Subcommittee, Security Working Group and Standing Committees Coordinating Group, as well as the scope and work plan for the Energy Reliability Assessment Task Force (ERATF).

The RSTC also approved its own work plan, comprising “consolidated and updated” subgroup work plans.

The ERATF documents were approved with an amendment proposed by Evans-Mongeon regarding language in the draft that would allow the task force to “evaluate whether [SARs] are needed to enhance existing or create new reliability standards” to address potential fuel assurance concerns. His amendment allows for the issuance of reliability guidelines or the use of other NERC processes that might “get something out there quicker and more effectively … to help the industry along.”

Two reliability guidelines — “Model verification of aggregate DER models used in planning studies” and “Battery energy storage systems and hybrid power plant modeling and performance” — were approved as well, as was a white paper on possible misunderstandings of the term “load loss” developed by the System Analysis and Modeling Subcommittee in 2020.

The committee also endorsed a special assessment on the performance of NERC’s Energy Management System (EMS), intended to “gain a better resolution on the contribution of EMS outages to the loss of situational awareness risk and the effect of [reliability standard] EOP-004-4.”

Subgroups Disbanded

The committee agreed to disband two of its subgroups this week: the Security and Reliability Training Working Group (SRTWG), formed last year by the merger of the Reliability Training Working Group (previously part of the now-defunct Operating Committee) and the Security Training Working Group.

RSTC Vice Chair David Zwergel of MISO said the committee had concluded that this group is neither relevant to the RSTC’s mission nor necessary in the broader sector.

“We went back and looked over what the SRTWG was doing and looking at its deliverables. It’s really redundant with other efforts in industry as a whole,” Zwergel said. “It’s not that the RSTC doesn’t endorse or support training. It’s really [that] the training that this group was doing [was] focused on how to be a trainer, how to improve training techniques, [which is] covered elsewhere.”

Also shuttered was the Geomagnetic Disturbance Task Force (GMDTF), which last year concluded its two-year effort alongside the Electric Power Research Institute (EPRI) with the publication of EPRI’s white paper Research Findings for Geomagnetic Disturbance Research Work Plan. As recommended in the task force’s final report, the RSTC agreed to add GMD monitoring to the scope of the Real Time Operating Subcommittee.

March 5, 2021January 30, 2025

NY Panel Says Circular Economy Will Cut Waste Emissions

Building end-markets for a circular economy is critical to reducing methane and carbon dioxide emissions from organic waste in the future, according to the New York State Climate Action Council (CAC) Waste Advisory Panel.

The organics diversion and landfills subpanel wants to see materials recovered for their next highest and best use to help meet New York’s climate goals, said Dereth Glance, executive director of the nonprofit Onondaga County Resource Recovery Agency.

“The secret to material management is movement, so we can’t have this stuff stockpiling,” Glance said during a Waste Advisory Panel meeting Wednesday. “We need to keep it moving all the time.”

The New York State Climate Action Council (CAC) Waste Advisory Panel met March 3. Clockwise from top left: New York DEC Deputy Commissioner Martin Brand; Bernadette Kelly, Teamsters Local 210; Michael Cahill, Germano & Cahill; Jane Gajwani, NYC DEP; Lauren Toretta, CH4 Biogas; Dan Egan, Feeding New York State; and Dereth Glance, OCRRA (center). | NYDPS

It is important to have procurement policies at the state and local level for municipalities purchasing recycled content material, buying compost for parks departments, road development, erosion control and other kinds of construction projects, she said.

Dereth Glance, OCRRA | NYDPS

“Not only are we going to be able to move food waste out of landfills and other disposal and into more productive use, but once we create that product, that compost, it has a reliable place to go to be used again,” Glance said.

Routing at least 90% of organics to composting should dramatically reduce organic waste, even in a city as large as New York, said Michelle “Tok” Oyewole, policy and communications organizer at the New York City Environmental Justice Alliance.

Brigitte Vicenty, founder of another recycling group, Inner City Green Team, said she supports imposition of a modest ($2) monthly recycling service fee, on a sliding scale, to be paid by both tenants and property owners to support door-to-door recycling. The fee, she said, would increase participation since people will feel that they already have “skin in the game.”

Brigitte Vicenty, Inner City Green Team | NYDPS

The Waste Advisory Panel is sharpening its recommendations to the full council ahead of a March 19 deadline.

“We are in the last push to get over the finish line and present final recommendations to the council toward the end of March,” said New York Department of Environmental Conservation (DEC) Deputy Commissioner Martin Brand, who chairs the waste advisory panel.

The waste panel received updates from its various subgroups on materials handling; wastewater treatment and recovery; organics diversion and landfills; local scale diversion; and climate justice.

Brand encouraged the subgroups to “keep honing the product down,” promising to get back to the panel members if the DEC arranges “some cross-panel deliberations, particularly on the renewable natural gas, biogas and bioeconomy piece,” because it is still a source of frustration and confusion.

Cash Incentives

The landfills subgroup recommended establishing an energy floor price not less than 10 cents/kWh for power purchase agreement payments for renewable natural gas and non-energy producing compost facilities to stimulate infrastructure upgrades and construction for management of organic wastes at landfills, combustors, digestors and compost facilities.

“We need a new generation of facilities,” said Michael Cahill, partner at the law firm Germano & Cahill. “We don’t have the digestors, we don’t have the compost facilities, we don’t have anything in that gap between generation and landfilling and combustion to fill the need, and we need to get a variety of people on the job to figure out how to make it work.”

The 10 cents/kWh charge would provide an incentive for planners to begin the process of experimentation, innovation and coordination to find a solution in the first five to seven years, according to Cahill.

Keep the Focus

The waste panel also plans to recommend to the full CAC building a distributed energy model that uses local waste and associated emissions/energy recovery to enable communities to be more climate resilient.

Resa Dimino, Resource Recycling Systems | NYDPS

Resa Dimino, senior consultant at Resource Recycling Systems, said it was not clear whether the distributed energy recommendation focuses on development of new waste disposal facilities, or maximizing the efficiency of existing facilities.

“If we want to get real climate benefits, we need to be investing in waste reduction, reuse, recycling and composting,” Dimino said. “Investing in landfills or waste-to-energy facilities that are slightly better than where we are now is not going to get us to the goals we need to reach.”

Eric Goldstein, New York City environment director at the Natural Resources Defense Council, agreed, saying “there is some ambiguity here when we’re talking about financial assistance and investments like encouraging private-public partnership investments through joint funding that values low-emission solid waste infrastructure investments.”

Eric Goldstein, Natural Resources Defense Council | NYDPS

One person’s definition of low-emission might not be another’s, so the focus of the waste advisory panel under the Climate Leadership and Community Protection Act ought to be on reducing emissions, he said.

The distributed energy idea is unique “in that it’s almost equally if not more an adaptation strategy as it is a mitigation strategy,” said Lauren Toretta, president of Greenwich, Conn.-based CH4 Biogas.

She said that extensive work by utilities and NYSERDA to support microgrid infrastructure will help communities benefit from waste-to-energy opportunities.

“We see it as an opportunity if you can leverage the waste resources and associated energy generation to help communities be more independent and more resilient,” Toretta said.