Search
`
November 5, 2024

Posted on

Massachusetts Transportation Bond Bill Seeks to Unlock $4B in IIJA Funds

Massachusetts Gov. Charlie Baker gave testimony Tuesday for a transportation bond bill that would unlock $4.1 billion in funding from the Infrastructure Investment and Jobs Act (IIJA) signed by President Biden in November.

The bill (H.4561) would authorize the state treasurer to issue up to $5.6 billion in bonds to ensure the state can meet federal matching requirements for varying percentages of infrastructure project costs.

“We’ve developed a plan to invest billions of dollars in communities throughout the commonwealth over the next five years using the resources from [the IIJA],” Baker said. “That’s why we filed this legislation to authorize $9.7 billion to prepare for the resources and funding that will come to the commonwealth through this bill.”

Baker signed a $16 billion transportation bond bill in January 2021 that included $4.4 billion in federal funding for the next two years. At that time, Baker said, his administration expected to ask the legislature to authorize additional funding for transportation in the near term, but passage of the IIJA altered their plans.

The IIJA “increases the annual level of federal funding that goes well beyond what we had anticipated for the next five years,” Baker said.

Baker introduced the new bond bill on March 21, declaring it an emergency measure that requires action before the end of the legislative session in July. He acknowledged that the bill creates a lot of work for the legislature in a short time and will attract an “enormous amount of interest.”

Funding in the bill includes $200 million for the Executive Office of Energy and Environmental Affairs (EEA) to implement programs for public alternative fueling and EV charging stations, e-bikes, EVs for hire or sharing, and medium-duty EV trucks.

Of the total allocation for the EEA, Baker said, $150 million is set aside for investments that promote equity and improve public health, such as EV incentives for low-income families or electric school bus purchases. EEA’s remaining $50 million allocation will be used for matching funds to help the state compete for discretionary grants.

A $1.4 billion allocation to the Department of Transportation would support modernization of the transit system, including the Massachusetts Bay Transportation Authority’s (MBTA) plan to electrify its fleet of 1,100 buses by 2040. A bill (S.2292) currently before the Joint Transportation Committee would advance the deadline for MBTA’s fleet electrification to 2030. The committee has until April 29 to report that bill to the legislature.

The DOT would receive another $43.4 million from the bond bill for projects that improve regional transit networks and facilities through, among other things, rehabilitation of facilities to support clean vehicles. Facility upgrades necessary for MBTA’s full bus fleet electrification will cost $4.5 billion, according to the authority.

Additional allocations to the DOT that support the state’s climate laws include $2.8 billion for projects on the interstate and non-interstate federal highway system, including EV charging infrastructure; and $145 million for planning across all transportation modes, including supporting reduction of greenhouse gas emissions from transportation.

To help the state compete for discretionary and grant program funding in the IIJA, the bond bill includes a $3.5 billion authorization, Baker said. While the state awaits grant program guidance, he added, “it’s critical that … we have the authorizations in place so we will be able to move quickly and efficiently to deliver additional federal funding to the commonwealth.”

Posted on

CARB Seeks More Inclusive Clean Cars 4 All

As California prepares for an expansion of the Clean Cars 4 All program, officials are working on strategies to make sure the clean vehicle purchase incentive for low-income residents goes to those who need it most.

The California Air Resources Board (CARB) has proposed a household income limit of 300% of the federal poverty level for drivers to receive the incentive under the expanded program.

But the income limit could be just one piece of a needs-based approach to the incentive, said Aaron Hilliard, manager of the Alternative Strategies Section within the Incentives & Technology Advancement Branch at CARB.

“[We’re] looking at potentially other metrics for determining who is in the greatest need, other than just income,” Hilliard said.

Hilliard’s comments came during a CARB workshop on Monday to discuss the statewide expansion of Clean Cars 4 All. CARB staff described the workshop as a kick-off meeting on program expansion, with many details yet to be ironed out.

CARB’s Anthony Poggi said the agency is looking at how it would prioritize applicants in disadvantaged communities. The strategy will include working with community-based organizations and Access Clean California, a program that helps lower-income residents find clean energy benefits for which they’re eligible.

Program implementation is another variable in the Clean Cars 4 All expansion, according to Hilliard, who said CARB has heard comments about the drawbacks of first-come, first-served vehicle incentive programs.

Air District Involvement

In Clean Cars 4 All, an eligible driver agrees to scrap their old car in exchange for an incentive to buy a new or used hybrid, plug-in hybrid or zero-emission vehicle.

The Clean Cars 4 All incentive is currently offered by four California air districts: the Bay Area Air Quality Management District (AQMD); the Sacramento Metropolitan AQMD; the South Coast AQMD, which calls the program Replace Your Ride; and the San Joaquin Valley Air Pollution Control District (APCD), which calls the program Drive Clean in the San Joaquin.

The San Diego County Air Pollution Control District is getting ready to launch the program. CARB provides funding to air districts to administer the program.

A CARB regulation currently limits Clean Cars 4 All participation to air districts with a population of 1 million or more. And drivers receiving an incentive must live in a zip code that contains a disadvantaged community census tract.

But under the statewide expansion, those restrictions would be dropped. Poggi said the statewide expansion would not affect existing programs in the four air districts or the one in San Diego. Instead, the statewide program would be complementary to those programs.

CARB plans to recruit a statewide administrator to run the expansion program. The agency expects to release a solicitation for the position in early June.

Requirements Debated

For the statewide expansion of Clean Cars 4 All, CARB has proposed a household income limit of 300% of the federal poverty limit, which works out to $65,880 for a household of three or $79,500 for a household of four. About 90% of program participants already meet this income requirement.

Beverly DesChaux, president of the Electric Vehicle Association of Central Coast California, suggested targeting the incentive to drivers whose cars are “big, fat polluters.” The size of a car, its age and how much it’s driven could be factored in, she said.

DesChaux also called for restricting the Clean Cars 4 All incentive to plug-in hybrid or zero-emission vehicles and eliminating non-plug-in hybrids from the program.

“A hybrid … is simply a gas car that has a little electric motor that boosts the mileage a little bit,” she said.

Poggi said that hybrids were being included in the statewide program to give participants options on what to buy. He noted that air districts are being given flexibility on whether to include hybrids in their programs.

LaDonna Williams, programs director with All Positives Possible, a non-profit organization promoting disadvantaged communities’ right to a clean environment, said CARB’s proposed changes would make Clean Cars 4 All more inclusive.

Disadvantaged and low-income populations, particularly African-American communities, have fallen through the cracks in the past, she said.

Williams also cautioned against dictating drivers’ choice of car, even if a polluting vehicle might be offensive to some. Not everyone has money to cover the expense of a newer car, she said.

“Because we see someone driving a big vehicle or a gas car, that might be our personal opinion, but we also don’t want to end up being policed,” Williams said. “Because, again, at the end of the day, we know what population is going to be targeted the most for that, so we want to keep these options open.”

Posted on

NERC Director Joins WECC Exec Team

WECC said Tuesday that Steven Noess, NERC‘s director of regulatory programs, will join the West’s regional entity as its new vice president of reliability and security oversight beginning April 29.

Noess will take over a role previously filled by Steve Goodwill, who last fall became WECC’s senior vice president of strategic engagement.

At NERC, Noess leads a working group that supports “the alignment, effectiveness and oversight” of the Compliance Monitoring and Enforcement Program (CMEP) activities within the ERO Enterprise, according to a WECC release.

He recently co-led a team of 50 experts on the FERC-NERC inquiry into the February 2021 cold weather event that caused numerous outages and derates across Texas, leading to the largest manually controlled load-shedding event in U.S. history. (See FERC, NERC Release Final Texas Storm Report.)

In his new position, Noess will oversee development of WECC’s own CMEP and manage teams within the RE’s Oversight department, including Entity Monitoring, Risk Assessment and Registration, and Enforcement and Mitigation.

“Steve [Noess] brings in-depth oversight knowledge to the role, which will enable him to immediately take the lead in this critical position,” WECC CEO Melanie Frye said Tuesday in a statement. “His extensive ERO Enterprise-wide regulatory knowledge, coupled with his ability to successfully collaborate with external stakeholders to achieve reliability goals, will be an additional asset for WECC.”

Noess joined NERC in May 2011 as a standards developer, a position in which he led efforts to complete version 5 of the ERO Enterprise’s Critical Infrastructure Protection program, according to his LinkedIn profile. He was subsequently promoted to the roles of director of standards development and director of compliance assurance and program oversight before taking on his current position.

Prior to joining NERC, Noess was an attorney at the Minnesota legislature, where he managed development of legislation related to economic development, employment law and business and professional codes/licenses. He also helped develop administrative rules for executive branch agencies. He previously served as a captain in the U.S. Army and was deployed to Iraq in 2003, where he was awarded a Bronze Star.

Noess is a graduate of the U.S. Military Academy at West Point and holds a Juris Doctor from the University of Minnesota.

Posted on

SEC Chair, Investors Defend Draft Climate Disclosure Rule

Securities and Exchange Commission Chair Gary Gensler and officials of two large investment funds on Tuesday defended the SEC’s proposed disclosure rule for climate risks, saying it will bring consistency and transparency.

Gensler said the proposed rule, released following a 3-1 vote in March, is consistent with the commission’s “long tradition of disclosures,” which began with reporting of companies’ financial performance and executive pay. (See SEC Seeks Standard Disclosures for Climate-related Business Risks.)

“The core bargain from the 1930s was, and still remains, that investors get to decide which risks to take,” Gensler said during a webinar by Ceres, a nonprofit that promotes corporate sustainability practices. “Risk by definition often involves events that have not yet occurred — the future. So back in 1964, the SEC started to offer guidance about disclosure of risk factors. The agency later adopted disclosure requirements related to management discussion and analysis in the late 70s. Then, they also added environmental-related disclosures. … The same principle applies again and again: Investors get to decide which risks to take, as long as the public companies provide full and fair disclosure and are truthful in the disclosures.”

Gensler urged investors and filing companies to submit comments on the rule before the May 20 deadline. “We’ve already gotten a lot of feedback: some of it for the proposal, some against. That’s what we need to hear,” he said. “And we need to hear the reasons too. We need to hear all sides of this. We consider all of those comments in determining whether and how to adjust the release as we move forward.”

The SEC’s proposal is based on the international Financial Stability Board’s Task Force on Climate-Related Financial Disclosures (TCFD). It would require disclosure of climate-related risks with a “material impact on its business, results of operations or financial condition.”

The rule also would require publicly traded companies to disclose their greenhouse gas emissions, including Scope 1 (company vehicles and facilities) and Scope 2 (purchased electricity, steam, heating and cooling for the company’s own use).

Disclosure of Scope 3 emissions (including indirect emissions from purchased goods and services and the transportation and use of a company’s products) would only be required if they are material or if the company has set a GHG emissions-reduction target that includes Scope 3.

Manchin: ‘Not Necessary’

Earlier this month, Sen. Joe Manchin (D-W.Va.) joined with Republicans in criticizing the rule, saying it undermined “the all-of-the-above energy policy that is critical to our country right now.”

“I cannot help but consider the true need for that mandate when the commission itself reports that ‘nearly two-thirds of companies in the Russell 1000 Index, and 90% of the 500 largest companies in that index,’ already publish sustainability reports that include information about climate risks,” Manchin said in an April 4 letter to Gensler. “In that sense, one could argue that the proposed rule aims to solve a problem that does not exist.”

But Ceres President Mindy Lubber said her organization’s analysis of comments filed with the SEC last year found “overwhelming support” from investors and companies for mandatory standards that are consistent with those used globally.

Lubber said the current voluntary reporting “is not good enough.”

“We want information to be accessible, clear, real and consistent. And right now it’s not. It is inconsistent, at times incomparable, and many cases, not strong enough quality — thus the need for the SEC [rule],” she said. “The investors we’re working with feel like they’re flying blind on investment decisions in their portfolios.”

Anne Simpson, global head of sustainability for Franklin Templeton, which manages $1.5 trillion for investors, also supported the rule, saying it was responsive to the needs of investors. “Risk is a good thing. Risk is where we make the returns. But we have to be able to appraise risk,” she said.

She also said companies that excel in their reporting on sustainability typically have lower costs of capital and that the rule will relieve their “survey fatigue.”

“Typically, a big company will be receiving several hundred surveys a year, most of most of which focus on climate risk, among other issues,” she said. “Having these standardized reporting guidelines will actually make a huge difference for companies.”

Joe Amato, chief investment officer for Neuberger Berman, which manages $500 billion in investments, said investors often have to rely on third-party estimates based on sector or industry averages that “fail to consider important company-specific nuances. And this clearly makes for less efficient capital markets.”

Joe Allanson, Salesforce’s executive vice president for finance ESG (environmental, social and governance), said his company five years ago became one of the first to include ESG reporting in its 10-K filings.

“I still vividly recall the internal debates back then, of how much to report, what to say, what legal exposure we might be taking on. It was quite personal to me, since I was one of the signers of the 10-K,” he said. “But the current proposal helps to alleviate much of the anxiety that I had experienced years ago because I find the proposal quite thoughtful and responsive to preparer concerns.”

Concern over ‘Chilling Effect’

Cynthia Curtis, senior vice president of sustainability for real estate services company Jones Lang LaSalle, said her company also sees the need for increased disclosure and transparency, noting that buildings are responsible for almost 40% of the world’s greenhouse gas emissions.

“That said, we all are also a little … ‘anxious’ is too strong a word. But we just don’t want companies to be backing off of commitments. … If you haven’t made a Scope 3 commitment, will this make you hesitate to lean into establishing a Scope 3?

“You know, quantifying the impacts of climate change, of course, is very hard. And putting it in your SEC filing just raises the bar. … So I just think we do need to pump the brakes a little bit and ensure we get the language right for the level of disclosure and the phase-in of the safe harbor, so that it promotes more disclosure and doesn’t result in some of that chilling effect.”

Posted on

NYISO Business Issues Committee Briefs: April 11, 2022

Manual Updates for GFER Results

The NYISO Business Issues Committee on Monday approved revisions to the Transmission and Dispatch Operations Manual regarding updates required to share Generator Fuel and Emissions Reporting (GFER) survey results with all New York transmission operators (TOPs), effective April 29.

“These changes require that all TOPs [including NYISO] have access to the GFER fuel survey results in order to adequately evaluate energy constraints and develop seasonal operating plans,” said John Stevenson, gas and electric technical specialist.

The revisions are a result of NERC Project 2019-06, which, among other changes, updated standards to require TOPs to include in their data specifications provisions for reporting the cold weather information identified by generator operators in their cold weather plans. (See NERC Board OKs Cold Weather Standards.)

March LBMPs Drop with Milder Weather

NYISO locational-based marginal prices averaged $56.78/MWh in March, down from $94.06/MWh the previous month and nearly double the $28.59/MWh average in March 2021, Rana Mukerji, senior vice president for market structures, said in delivering the monthly operations report, attributing the monthly decrease to lower fuel prices and milder weather.

Day-ahead and real-time load-weighted LBMPs came in lower compared to February. Year-to-date monthly energy prices averaged $100.65/MWh, a 116% increase from $46.57/MWh a year ago.

March’s average sendout was 390 GWh/day, down from 429 GWh/day in February and higher than 381 GWh/day a year earlier.

Transco Z6 hub natural gas prices averaged $4.47/MMBtu for the month, down from $6.17/MMBtu in February and up 99.6% year-over-year.

Distillate prices were up 105.2% year-over-year. Jet Kerosene Gulf Coast averaged $25.68/MMBtu, up from $19.79/MMBtu in February. Ultra Low Sulfur No. 2 Diesel NY Harbor averaged $27.02/MMBtu, up from $20.46/MMBtu in February.

March uplift increased to -9 cents/MWh from -$1.77/MWh the previous month, and total uplift costs, including the ISO’s cost of operations, came in higher than those in February.

The ISO’s local reliability share climbed to 27 cents/MWh in March from 4 cents/MWh the previous month, while the statewide share increased to -36 cents/MWh from -$1.77/MWh in February.

Posted on

ISO-NE Preparing to Move Forward on Day-ahead Ancillary Services

ISO-NE is ramping up its work on incorporating ancillary services in the day-ahead energy market.

In a recent memo and at the NEPOOL Markets Committee meeting Tuesday, officials from the RTO laid out the scope and timing of the project, which is a much anticipated addition to the market.

“Broadly, the day‐ahead ancillary services project seeks to procure and transparently price the ancillary service capabilities needed for a reliable, next‐day operating plan with an evolving generation fleet,” the memo says.

The proposal includes two components. One is an Energy Imbalance Reserve (EIR) feature that would incorporate load forecasting into the day-ahead market and procure energy to cover the gap when physical energy supply awards are below the forecast real‐time load.

The other is Flexible Response Services (FRS), which would procure 10- and 30-minute fast‐start and fast‐ramping capabilities in the day‐ahead market.

Longer-duration ancillary services, like the previously proposed Replacement Energy Reserves, will be deferred while ISO-NE focuses on the former two.

Much of the grid operator’s work to develop the new market features was completed as part of the Energy Security Improvements proposal that was ultimately rejected by FERC. (See FERC Rejects ESI Proposal from ISO-NE.) But ISO-NE is finishing up some calculations and technical work, as well as preparing to redo its impact analysis and market power evaluation for the new proposal.

The RTO is planning to work on the proposed new day-ahead services throughout this year and next, filing it with FERC by the end of 2023 with an implementation date either at the end of 2024 or beginning of 2025.

Still no Go for Proposed FA Changes

The MC again declined to recommend changes to the ISO-NE financial assurance policy that are being proposed by Competitive Power Ventures.

CPV’s Joel Gordon had brought forward more changes to his proposal to, among other things, address concerns with the amount of financial assurance that would be required for solar projects.

The proposal is designed to penalize companies that don’t meet development milestones, a timely topic after the fiasco surrounding Killingly Energy Center earlier this year. But like at the February MC meeting, it failed to get enough support from the committee to recommend advancing it to the Participants Committee.

Posted on

Washington Carbon Offset Program Aims to Preserve Forests

Washington is launching a first-of-its-kind program to auction off carbon offset credits to preserve the state’s forest land.

“We are creating a blueprint that can be used for public lands across the nation,” Washington Lands Commissioner Hilary Franz said Wednesday at press conference.

Franz oversees the state’s Department of Natural Resources (DNR), whose duties include managing the state’s trust lands with the mission of producing revenue from property for various programs such as education. The agency routinely auctions off trees on its lands to be harvested for timber.

The new DNR program will set aside 10,000 acres of forests — with trees that began growing prior to 1900 — that have the potential to be harvested. Offset buyers will bid on carbon credits to keep those carbon-absorbing forests intact. This enables the DNR to achieve its mission of producing revenue from its older forests without having to harvest them for timber, Csenka Favorini-Csorba, a senior policy adviser at DNR, said.

This effort comes after state lawmakers last year approved the nation’s second cap-and-trade program, after California. (See Wash. Becomes 2nd State to Adopt Cap-and-trade.)  Washington officials are still working on the details of that program, which is scheduled to go into effect on Jan. 1, 2023, and raise $500 million annually, with most of the money going to transportation projects.

The DNR project will start out as part of the nation’s voluntary offsets market. Once Washington’s cap-and-trade system is up and running, the offset credits could potentially be applied to offset emissions under the program. Participants in the Western Climate Initiative, which includes California’s cap-and-trade, will be able to buy the initial DNR carbon offset credits from the voluntary market. The agency expects the program to generate more than 900,000 carbon offset credits in its first 10 years.

“This is truly the next generation of carbon offsets,” said Caitlin Guthrie, director of forest carbon origination for Finite Carbon, a developer and supplier of forest carbon offsets. Finite Carbon is participating in the project to ensure it represents durable and verifiable carbon sequestration, she said.

“We hope this becomes a model for other states,” Favorini-Csorba told NetZero Insider.

The new program has identified 2,500 acres on DNR trust lands to be set aside this year in Whatcom, King, Thurston and Grays Harbor counties, stretching from northern to southern Puget Sound. Another 7,500 acres are scheduled to be identified next year.

Many details must still be worked out, including when the credits will be auctioned, what the minimum acceptable bids would be and the overall fundraising targets, Favorini-Csorba said. The state plans to auction off 917,000 carbon credits in the first 10 years of the program.

The DNR created a Carbon Sequestration Advisory Group in 2019 as a climate change measure. The agency has also leased some of its lands to wind farms, now capable of generating more than 200 MW of power.

Posted on

NERC, WECC Repeat Solar Performance Warnings

A series of disturbances involving solar resources last summer in California highlights the ongoing challenges of integrating new generation into the grid, according to a joint report by NERC and WECC released last week.

The report, “Multiple Solar PV Disturbances in CAISO,” concerns four bulk power system disturbances between June and August 2021 in Southern California that led to “widespread reductions of active power output” from solar resources. All of the events triggered the loss of at least 500 MW of generation, qualifying as a Category 1i event under NERC’s event analysis process; two also led to tripping at natural gas plants, and three caused tripping or reduction of distributed energy resources.

WECC employees have spoken about the events before: In a webinar earlier this year, WECC Reliability Initiatives Director Steve Ashbaker observed that the number of disturbances last year was the same as all those in the previous five years, indicating a significant increase in such issues. (See Texas RE, WECC Call For Coordination on DER Issues.) Other representatives from WECC warned that the accelerating pace of interconnection requests for solar projects points to a growing “reliance” on solar power in the West, making the incidents of last summer more likely.

Four Events in Three Months

NERC and WECC based the report on data from solar facilities that reduced active output by more than 10 MW during the events; the authors held follow-up discussions with plant owners and operators as needed.

In the first event, which began at 3:19 p.m. PT on June 24, a phase-to-phase fault occurred on a 500-kV line near Victorville, leading to a reduction of 765 MW across 27 solar facilities. The second, on July 4, also involved phase-to-phase faults on a 500-kV line, although this time the issue was caused by the Tumbleweed Fire and resulted in a 605-MW reduction of solar across 33 facilities. A combustion turbine at a combined cycle plant also tripped offline while loaded at 125 MW.

In the Windhub disturbance of July 28, a 500-kV line and a 500/230-kV transformer bank both tripped because of a single-line-to-ground fault that occurred while a circuit breaker that faulted was being returned to service after scheduled maintenance; as a result, CAISO recorded 511 MW of reduction across 27 solar facilities. Finally, a fire near the San Bernardino National Forest caused the Lytle Creek disturbance of Aug. 25, with 583 MW of reduction across 30 solar plants. Gas turbines at two nearby plants also tripped, carrying 303 MW of load in all.

Causes of solar PV reduction (NERC) Alt FI.jpgCauses of solar PV reduction in each disturbance. Clockwise from left: June 24, July 4, July 28 and Aug. 25. | NERC

According to the report, a “significant number of solar PV resources responded to the BPS disturbances in a manner that does not support BPS reliability.” In some cases solar facilities as far as 100 miles away from the fault locations were found to have responded abnormally.

Momentary cessation and slow active power recovery were the top two contributors to reduction and provided more than half of the drop in every case, though their shares varied widely: In the Aug. 25 event, momentary cessation accounted for almost three-fourths of the total reduction, while in the July 4 disturbance, it was only 21%. This made the July 4 event the only one in which slow active power recovery was the top cause of reductions, with 33%.

The report noted that the high degree of momentary cessation is “primarily driven from solar PV facilities with legacy inverters that cannot eliminate momentary cessation or modify settings.” Plant controllers may also have contributed to the problem, with the report suggesting their “interactions with the inverters appear to [have elongated] the expected dynamic response from these resources.”

Analysis was made more difficult by a lack of monitoring data from many plants, particularly the legacy facilities installed prior to the publication of NERC reliability guidelines related to the collection of data in BPS-connected inverter-based resources in 2019. This results in “a systemic gap in the capabilities of plant owners to analyze their facilities’ dynamic response to grid disturbances.”

Odessa Recommendations Repeated

In their recommendations, NERC and WECC emphasized that many of the issues highlighted in the report are not new: The Odessa Disturbance Report, published by NERC and Texas Reliability Entity last year, covered a widespread BPS disturbance in Texas involving a total reduction of output of more than 1,300 MW that involved solar, wind and natural gas facilities, and exposed some of the same problems. (See NERC-ERCOT Report Reviews Texas Solar Issues.)

The WECC report identified the root cause of all the issues identified in both reports as “a lack of performance requirements” in the FERC generator interconnection agreements. The report urged that FERC update the agreements to “help ensure there are no gaps in performance for newly interconnecting resources [with] clear requirements for accurate modeling and sufficiently detailed studies during time of interconnection.”

However, the report also called out NERC for shortcomings in its reliability standards that have led to “systemic issues with inverter-based resources.” To address these gaps, it said NERC’s Reliability and Security Technical Committee should help to set standards projects in motion that would result in:

  • a performance validation standard to ensure that reliability coordinators and balancing authorities can seek corrective actions for plants that do not perform up to the requirements of the interconnection agreement;
  • a ride-through standard to ensure solar and wind resources can endure disturbances without causing larger BPS issues;
  • analysis and reporting for abnormal inverter operations; and
  • inverter-specific performance requirements.
Posted on

Advocates Want Climate Metrics in Maine Utility Performance Standards

Recently proposed utility performance standard amendments from the Maine Public Utilities Commission “fail to meet the moment,” Phelps Turner, senior attorney at Conservation Law Foundation, said Thursday.

Regulators’ March 3 proposal for measuring Maine transmission and distribution utilities’ performance does not satisfy current climate law and falls “well short of what’s needed to motivate our utilities to provide a cleaner and more affordable and reliable electric grid,” Turner said in testimony for a standards rulemaking proceeding.

The proposed rulemaking (2022-00052) follows a separate commission inquiry started in December 2020 (2020-00344) on whether updates to utility service quality metrics and incentives could help improve performance. Regulators, however, chose not to include metrics in the proposed amendments that would further state clean energy and environmental laws. Without those metrics, Turner said, the proposal does not align with a 2021 law directing the commission to consider climate impacts in its decision-making process.

Under the proposed rule, metrics and reporting requirements for system reliability, call answering, billing and customer satisfaction would be added to the current T&D utility service standards.

Metrics should also be included for distributed energy resource interconnection, grid modernization and environmental policies, according to Turner. CLF has recommended the commission consider metrics for greenhouse gas emission reductions from programs such as advanced metering and annual compliance with Maine’s Renewable Portfolio Standard.

It’s possible, Turner said, that the commission could phase in environmental metrics for the performance standards.

“Other states are looking at a phased approach, where you start with report-only metrics and then move into positive and negative financial incentives,” Turner said.

The Acadia Center also recommended a phased approach in its March 31 comments on the proposed rulemaking.

“While identifying specific performance benchmarks and targets for some performance categories may be premature without further investigation, Acadia Center believes that there is nevertheless value in establishing metrics and, at a minimum, beginning the process of tracking and collecting performance data,” the nonprofit said.

Establishing public reporting for utility performance, even without benchmarks and penalties, could motivate utilities to make positive changes, according to Acadia.

Enforcement

While the commission’s proposal does not directly address financial penalties for failing to satisfy the new metrics, enforcement provisions were a top concern for stakeholders during the hearing.

The rule would direct the commission to impose a financial penalty on a utility if it does not take corrective action when a performance target is not met. But the commission’s rulemaking notice indicates it will consider specific penalty provisions under a separate proceeding.

AARP Maine would like to see the commission provide more details about penalties in the proposal.

“The lack of any indication of how these reliability and customer service metrics will automatically trigger potential violations and adverse consequences for the utility is a significant concern of ours,” Barbara Alexander, a consultant to AARP Maine, said in the hearing.

The Maine Office of the Public Advocate supports penalties for “persistent and substantial failure to satisfy service standards,” according to testimony of Kristina Winther, OPA senior counsel. The office, however, would not support a provision that allows a reward for meeting standards, she said.

In Central Maine Power’s (CMP) (NYSE:AGR) view, the proposal is one-sided.

“To have all stick and no carrot just isn’t good public policy,” attorney Richard Hevey said in testimony. “If the utility has built into rates the ability to meet the metric and goes above and beyond that, it should be able to earn something beyond not being penalized.”

Versant Power suggested in its March 31 comments that utilities should have an opportunity to present evidence that a failure to meet a metric was due to extenuating circumstances, but Alexander said she was not “sympathetic to that argument.”

“These are annual standards,” she said. “Utilities rarely suffer external events that would not allow them to take steps to ensure annual compliance.”

Final written comments on the proposed rulemaking are due April 27.

Performance Bill

A T&D utility performance bill introduced this session by Gov. Janet Mills, if enacted, would overlap with the commission’s proposed rule. (See Maine Governor Revisits Vetoed Plan to Replace IOUs.)

The bill (LD 1959) would require the commission to adopt rules for quantitative planning and operational standards related to reliability, customer service, billing, generator interconnection and emergency response. Although the commission’s current rulemaking proceeding could meet the requirements set out in the bill, the OPA cautioned that passage of LD 1959 may force regulators to reopen the comment period in the docket.

Mills introduced the utility performance bill after vetoing a similar bill (LD 1708) last year that she believed needed more work. LD 1708 would have opened a direct pathway based on performance history for replacing Central Maine Power and Versant with a consumer-owned utility, but Mills’ approach puts the COU on the table based on future performance metrics.

With one week left in the legislative session and a divided report on LD 1959 from the Energy, Utilities and Technology Committee, the outlook for the legislation is uncertain.

The nonprofit Our Power, however, has reinvigorated its campaign to collect signatures for a citizen initiative to force a public vote on LD 1708 in November 2023.

Posted on

California PUC Tells SoCalGas to Return Ratepayer Money

The California Public Utilities Commission on Thursday ordered Southern California Gas Co. to refund ratepayer money it inappropriately used to lobby against regulations that could undermine its business, such as building codes that require electric space and water heaters in new construction instead of gas appliances.

The commission also imposed a $150,000 penalty against SoCalGas after hearing from some parties who argued for no fines and others who urged a $255 million penalty.

The moves were the latest in a long-running dispute between the CPUC and the nation’s largest gas utility, a subsidiary of Sempra Energy (NYSE:SRE), over its advocacy efforts against the California Energy Commission’s building decarbonization requirements, federal efficiency standards, and the state’s 100% clean energy mandate, which would remove natural gas from the generation mix by 2045.

Last month the CPUC fined SoCalGas $9.8 million for contempt of its 2018 order to stop using ratepayer money to lobby against greenhouse gas reduction efforts intended to benefit ratepayers. The company flouted the order and continued to engage in “numerous and substantive” activities that harmed the regulatory process, Administrative Law Judge Valerie Kao wrote in her Feb. 3 decision.

“Such insolence must be accorded a high degree of severity,” Kao said. Her decision took effect last month after SoCalGas did not appeal it in the required 30 days.

The CPUC’s Public Advocates Office (Cal Advocates) had recommended a $124 million fine in the case.

Of the dozens of allegations against it, SoCalGas accepted some in a filing but argued others were outside the scope of the 2018 order. It contended, for example, that lobbying the U.S. Department of Energy was not covered by the order, an argument that Kao flatly rejected.

The case decided Thursday involved SoCalGas’s activities prior to the 2018 order, from 2014 to 2017, when it was prohibited from engaging in “codes and standards advocacy” with ratepayer money because of a prior order but did so anyway, the CPUC said.

Kao issued a proposed decision in the case that ordered SoCalGas to refund ratepayer funds but did not impose a penalty. Commissioner Clifford Rechtschaffen offered an alternative decision that was the same as Kao’s except for proposing a $150,000 fine.

Both decisions ordered SoCalGas to return the ratepayer dollars it misspent and instructed commission staff to perform an audit to determine the amount.

Commissioners adopted Rechtschaffen’s alternative Thursday, voting 3-2 in a rare split decision.

Commissioner Genevieve Shiroma, who was the lead commissioner in the proceeding before Kao, said she thought the judge had “got the outcome right” and voted against Rechtschaffen’s alternative. The previous $9.8 million fine of SoCalGas and the later decision ordering the return of ratepayer money “go together,” she said.

Commissioner Darcie Houck said she agreed with Shiroma and voted against Rechtschaffen’s proposal.

Other commissioners supported Rechtschaffen’s contention that the fine was necessary to deter similar behavior.

Rechtschaffen’s decision applied “deliberate and precise penalties for specific actions that clearly contradict the commission’s direction,” CPUC President Alice Reynolds said. “These carefully crafted additions to [Kao’s proposed decision] are important to ensure the integrity of the regulatory process and deter future unlawful practices.”

Commissioner John Reynolds also voted for Rechtschaffen’s decision, as did Rechtschaffen himself.

Opponents of both proposed decisions said $150,000 would not deter unlawful behavior and proposed a fine of up to $255 million, based on the argument that SoCalGas’s improper actions were “continuing” over time, not 10 distinct actions each meriting a fine of $15,000, as Rechtschaffen concluded.

Rechtschaffen’s alternative decision “errs in considering what it properly identifies as ‘a deliberate and years-long pattern of misconduct’ as constituting 10 single-day violations for the purpose of assessing penalties,” the Sierra Club contended. “Commission precedent strongly supports finding SoCalGas’ conduct as a continuing violation.”

Cal Advocates argued that a $150,000 penalty “falls far short of an amount that could reasonably be expected to deter SoCalGas and other utilities from future misconduct” and said a $255 million fine for SoCalGas’s ongoing violations was more appropriate.

“The commission, consistent with its prior decisions, its established penalty framework, and its obligation to oversee the conduct and rates of the entities it regulates, must impose a fine that is likely to deter SoCalGas from disregarding Commission directives when faced with the choice of either complying with those directives or maximizing shareholder profits,” it said.