Texas senators are wasting no time filling the Public Utility Commission’s vacancies.
On Tuesday, the lawmakers unanimously confirmed Will McAdams by a 31-0 vote. McAdams, a Senate legislative aide for 10 years, was appointed by Gov. Greg Abbott April 1. (See Abbott Taps ABC Texas President McAdams for PUC Seat.)
Thursday morning, the Senate Committee on Nominations asked few questions of Peter Lake, chair of the Texas Water Development Board, who was appointed PUC chair on Monday. Nominations Chair Dawn Buckingham (R) said the panel plans to vote Lake out of the committee on Monday, setting up a confirmation vote before the full Senate.
That would give the commission two members, with a third and final member yet to be named. All three previous regulators resigned in the aftermath of the February winter storms and ensuing long-term blackouts.
Arthur D’Andrea continues to hold the PUC’s chairmanship, which he assumed after former Chair DeAnn Walker’s resignation. D’Andrea resigned in March, shortly after the leak of a phone call in which he told Wall Street investors he was using “the weight of the commission” to avoid repricing $16 billion in D’Andrea Resigns from Texas Commission.)
PUC appointee Peter Lake answers questions before the Senate Nominations Committee. | Texas SenateWill McAdams (Will McAdams via LinkedIn)
Lake told the nominations panel that February’s events were “beyond unacceptable” and that there won’t be “any easy answers or quick fixes.”
“This [position] will require very hard decisions to be made,” he said. “If confirmed, I will find out what went wrong, why it went wrong, and how to fix it. We cannot be hampered by institutional inertia or antiquated mindsets. My focus will be to provide the information you all need to craft policy and will work to implement that policy efficiently and effectively.”
McAdams and Lake must both undergo PUC training before they can begin to serve, the commission said.
A meeting scheduled for April 22 was cancelled to allow new commissioners time to get up to speed. The PUC’s next open meeting is scheduled for May 6.
McAdams’ term expires Sept. 1, 2025 and Lake’s on Sept. 1, 2023.
The California Public Utilities Commission used its new enhanced oversight and enforcement powers for the first time Thursday against Pacific Gas and Electric, citing the utility’s failure to adequately weigh wildfire risks in maintaining its power lines.
Commissioners voted to put PG&E into the first step of a six-step enforcement process that could lead to the utility being placed into receivership or, ultimately, to the revocation of its license to operate as the state’s largest monopoly utility.
“We’ve never had a process like this for any other utility, and I don’t know of any other PUC in the country that has a process like this,” Commissioner Clifford Rechtschaffen said. “Now we shouldn’t congratulate ourselves with that. It’s a process that’s warranted given PG&E’s conduct.”
The draft resolution, approved unanimously Thursday, says PG&E “is not sufficiently prioritizing its enhanced vegetation (EVM) management based on risk.”
“PG&E ranks its power line circuits by wildfire risk, but the work performed in 2020 demonstrates that PG&E is not making risk-driven investments. PG&E is not doing the majority of EVM work — or even a significant portion of work — on the highest risk lines,” it said. “PG&E conducted more work in 2020 on lower risk power lines than high risk lines if one examines the 161 power lines on which PG&E performed EVM. Less than 5% of the EVM work PG&E completed was on the 20 highest risk power lines according to PG&E’s own risk rankings.”
The CPUC’s five commissioners heard from Executive Director Rachel Peterson (bottom center) on the proposed action against PG&E. | CPUC
PG&E agreed to the CPUC’s six-step process as part of its exit from bankruptcy in June 2020. The enhanced oversight and enforcement process was later enacted into law under a bill signed by Gov. Gavin Newsom in July. Senate Bill 350 also authorized the state to seize PG&E through eminent domain, if warranted, and transfer its operations and assets to a nonprofit public benefit corporation. (See Governor Signs PG&E ‘Plan B’ Takeover Bill.)
In November, CPUC President Marybel Batjer wrote to then-acting CEO William Smith saying the commission was considering putting PG&E into the stricter oversight regime because of the utility’s vegetation and line maintenance. (See PG&E Faces ‘Enhanced Oversight’ by CPUC.)
The warning turned to action Thursday.
Step one of the process requires PG&E to submit a corrective plan to CPUC Executive Director Rachel Peterson within 20 days. The plan must describe how the company proposes to mitigate the safety risks that triggered the enhanced oversight process. If PG&E fails to adhere to the plan, the CPUC can move to the second step of its enforcement process, which may include activities such as increased inspections, quarterly reports and spot auditing of the utility’s fire-prevention efforts.
Federal Judge William Alsup, who oversees PG&E’s criminal probation stemming from the 2010 San Bruno gas explosion, has expressed similar concerns about vegetation management and is weighing new probation conditions that could require PG&E to de-energize lines during high-risk fire conditions that have not been cleared of overhanging trees. (See Conflict over Power Shutoffs Grows in California.)
In September, a leaning pine tree struck a PG&E transmission line in rural Shasta County and started the Zogg Fire, which killed four residents and burned 56,000 acres, the California Department of Forestry and Fire Protection determined.
The state’s largest utility was also blamed for catastrophic wildfires from 2017 to 2019, caused by its equipment contacting vegetation. The blazes included the Camp Fire in November 2018, which killed 85 people and destroyed more than 14,000 homes in the town of Paradise. PG&E pleaded guilty to 84 counts of manslaughter and arson in that case.
The California Energy Commission on Wednesday took a step toward making millions of households part of demand response efforts designed to avoid blackouts and bolster the state’s clean-energy goals.
The CEC approved a $16 million grant to the Lawrence Berkeley National Laboratory to establish the California Flexible Load Research and Deployment Hub, nicknamed CalFlexHub. Its four-year mission is to “develop, demonstrate and deploy multiple demand flexible technologies as electric grid resources,” making the technology more user-friendly and available to average homeowners, the CEC said.
“I’m really pleased to support this,” CEC Chair David Hochschild said. “I think that for a long time, electric load, with the exception of a few industrial demand response programs, was just seen as a fixed, rigid thing that we had to ramp up generation to support. I think a more involved understanding of the realities [shows that] there’s a lot about electric load that can be manipulated in ways that support electric reliability and our climate goals, as well.”
“We’re just getting going on this,” he said. “It’s still really early days.”
Lawrence Berkeley National Laboratory will develop the California Flexible Load Research and Deployment Hub. | Roy Kaltschmidt, Berkeley Lab Public Affairs
The CEC’s plan involves making it easier for homeowners to connect smart appliances — thermostats, heat pumps and water heaters — to the grid to receive signals to curtail consumption in response to high demand, high prices and elevated greenhouse gas emissions. Electric vehicle charging is another target. (See CEC Explores Building Design Role in Decarbonization.)
Under the terms of Senate Bill 100, signed by Gov. Jerry Brown in 2018, the state must supply all retail customers with clean energy by 2045. The result is expected to be a huge increase in solar and wind generation and a decrease in natural gas-fired capacity. Demand response should also play a significant role, the CEC, CAISO and the California Public Utilities Commission have said.
In last summer’s energy emergencies, CAISO and the office of Gov. Gavin Newsom called on industrial users and the U.S. Navy to limit usage during the evening net-peak hours, when solar ramped down but demand remained high because of severe Western heat waves. The efforts limited the blackouts of Aug. 14-15 and avoided additional outages over Labor Day weekend, CAISO said. (See CAISO Provides More Details on Blackouts.)
In recent years, researchers at Lawrence Berkeley National Laboratory have been studying the role that flexible load and demand response could play in ensuring grid stability as the nation transitions to renewable resources.
Mary Ann Piette, a senior scientist and director of the Building Technology and Urban Systems Division at Lawrence Berkeley, told the CEC commissioners that CalFlexHub “will help accelerate the development and deployment of technology … to allow buildings to be better integrated with the electric system for … demand management, dealing with renewable overgeneration, ramping and peak demand issues.”
CEC Commissioner Andrew McAllister said Wednesday that California’s efforts would help “create a new regime” nationally.
A 2019 study by the Brattle Group concluded that by 2030, the U.S. would have up to 200 GW of “cost-effective load flexibility potential.”
“This load flexibility potential, which equates to 20% of estimated U.S. peak load in 2030, would more than triple the existing demand response capability and would be worth more than $15 billion annually in avoided system costs,” Brattle said.
McAllister agreed. “I think the rest of the country is waking up to this fact that grid-connected buildings” and load flexibility will help reduce costs, decarbonize and enhance reliability, he said. “That triumvirate of goals is something that is absolutely in line with load flexibility. We’re going to create a significant body of work over the coming years on this and make it practically applicable in the real world, for real people, to benefit Californians.”
“This is a part of our future,” McAllister said. The electricity grid is “a network, not a one-direction system anymore. It’s a web.”
A year after NERC and its regional entities worked to set up human performance training sessions — only to see them cancelled by the COVID-19 pandemic — the Texas Reliability Entity scheduled the training on its own.
“We’re trying to give the people what they want. [That’s] Marketing 101,” Matt Barbour, the Texas RE’s training and communications manager, said after the last week’s session.
Jake Mazulewicz | JMA Human Reliability Strategies
The Talk with Texas RE webinar featured Jake Mazulewicz, director of JMA Human Reliability Strategies, who is experienced in working with personnel in “high-hazard” fields who want to improve reliability and safety.
Drawing on his background as an emergency medical technician, firefighter, Army paratrooper, and a human-performance improvement lead for Dominion Energy, Mazulewicz shared tips on how to reduce human error and improve performance.
“To err is human. It doesn’t matter how much education you have, how much experience you have; everybody makes mistakes,” Mazulewicz told his virtual audience. “I don’t know of any exceptions. I don’t know of any organization or team that has been error-free for any length of time.”
Mazulewicz offered “practical techniques for reducing human error, “but also managing it.” He explained the differences between a control-based approach to reducing errors (expect perfection, root out failures, hold individuals responsible) and a learning-based approach (expect humans to be humans, expand successes, focus on systems and teams, not individuals). He also shared examples of how “this stuff works.”
“People doing front-line work … stuff goes wrong,” he said. “Most of the things that go wrong in a high-hazard industry are because of a consolidation of subtleties. Things just don’t work out quite right. If you want to change the game, stop punishing people for making mistakes.”
An impromptu survey of the more than 70 attendees revealed 56% said this was a new approach for them. Mazulewicz said he was only giving a high-level overview, but that more in-depth training was available for anyone willing to pay for the services. He quoted a study that said Fortune 500 companies spend $37 billion a year to reduce errors.
Barbour agreed that while human-performance improvement may not be a normal subject for industry training, surveys of Texas RE’s members indicated that is exactly what they want.
“We’ve tried to broaden [our training] in the last couple of years,” he said, noting that the 70 participants are about par for a Texas RE course. “Our feedback tells us that REs want to hear more from industry experts and other REs.”
On April 15, the Texas RE held another talk, this one with a pair of SERC representatives discussing recent changes to NERC rules triggering certification reviews for operating and certified reliability coordinators, balancing authorities and transmission operators.
At the next Talk with Texas RE, scheduled April 29, FERC’s David DeFalaise and Mark Hegerle will review recent events at the commission.
NERC and WECC submitted the new standard to FERC in 2019 to replace BAL-002-WECC-2a, the regional equivalent of the continent-wide BAL-002-3 (contingency reserve for recovery from a balancing contingency event) and successor to the original standard BAL-002-WECC-2. The organizations argued that the introduction of the BAL-003-1 standard in 2014 had rendered some aspects of BAL-002-WECC-2a redundant.
In particular, NERC and WECC claimed requirement R2 of the regional standard — which mandated that balancing authorities and reserve sharing groups in the WECC region maintain at least half the minimum contingency reserves as operating reserves — was no longer necessary in light of frequency response requirements in the new national standard. A field test performed by WECC between 2017 and 2018 confirmed that retiring the 50% spinning reserve requirement resulted in “no degradation to [disturbance control standard] performance.”
FERC requested additional data in February 2020 from WECC, extending the regional entity’s study from May 2018 to September 2019. In addition, the commission requested NERC’s frequency response records for the Western Interconnection from May 2017 to September 2019. The updated information was submitted in May 2020.
Commission Continues Data Requests
However, while FERC agreed to approve the regional standard last October on the basis of NERC and WECC’s expanded data set, the commission remained concerned “about deliverability of contingency reserves within reserve sharing groups,” specifically the ability of balancing authorities to access hydroelectric resources.
As a result, its order mandated an informational filing 27 months after the implementation of BAL-002-WECC-3, covering the same categories of data from the February 2020 data request for the 24 months following implementation. The commission also mandated that the organizations inform it immediately of “any adverse impacts” observed during the reporting period, as well as any corrective actions that are taken or considered.
WECC and NERC indicated in a December filing that they understood the commission’s desire for additional data and “would, under any circumstances, promptly make the commission aware of” adverse impacts from the new standard. However, while collecting the relevant two years of information would not be a problem, the organizations felt “that three months may not be sufficient to complete the validation and analysis of 24 months’ worth of the requested data.” They suggested six months would be enough time to finish processing the data properly.
In its final approval order, FERC agreed to this modification. The informational filing will be due 30 months after the implementation of the standard.
PacifiCorp has 30 days to convince FERC it should not have to pay a penalty of up to $42 million for alleged violations of NERC reliability standards that may have contributed to the 2012 Wood Hollow wildfire in Utah, the commission ordered Thursday.
The Order to Show Cause and Notice of Proposed Penalty (IN21-6) cites allegations by FERC’s Office of Enforcement that PacifiCorp violated FAC-009-1 (Establish and communicate facility ratings) and its successor standard FAC-008-3. Specifically, FAC-009-1 requirement R1 and FAC-008-3 requirement R6 both require transmission owners and generator owners to have ratings for their solely and jointly owned facilities that are “consistent with the associated facility ratings methodology [FRM].”
FERC staff claim that PacifiCorp — including its Utah business arm, Rocky Mountain Power — knew in 2009 when it published its FRM that “the clearances on a majority of its bulk electric system transmission lines were incorrect under [National Electric Safety Code] clearance requirements.” Because the clearance data was used to calculate facility ratings, the resulting ratings were inconsistent with the published FRM.
The clearance inaccuracies came to light following the Wood Hollow fire, which caused one death, burned more than 47,000 acres of land and destroyed more than 50 residences or cabins. Utah’s Department of Public Safety determined that the fire was caused by “inadequate clearance between two RMP transmission facilities” near the town of Fountain Green that created an arc in the gusty conditions of June 23, 2012.
Power lines in Fountain Green, Utah, near the origin of 2012’s Wood Hollow wildfire: Inadequate clearance on two PacifiCorp transmission lines is alleged to have sparked the fire. | Ken Lund, CC BY-SA 2.0, via Flickr
FERC’s subsequent investigation found that the Fountain Green facility was just one of the clearance violations on PacifiCorp’s BES transmission lines. Clearance issues were discovered in more than 58% of the lines; 45% of the company’s BES lines had clearance violations so severe that “the transmission lines should have been rated at zero-amperes,” too low to be safely energized. This includes the line involved in the Wood Hollow fire.
PacifiCorp’s engineering department advised management as early as 2007 of the widespread clearance issues and transmission facility misratings, but FERC found that management failed to act on these concerns in a timely manner. For instance, managers delayed until 2009 a 1,200-mile lidar study to determine the extent of the problem; when the study was conducted, the issues were determined to be even worse than thought. Even after this the utility continued to provide incorrect ratings to its reliability coordinator, planning authority, transmission planner and transmission operator, FERC staff said.
“This risk level and various other culpability factors … result in a civil penalty range of $21 [million] to $42 million, and staff recommends assessing a penalty of $42 million in light of the serious nature and scope of PacifiCorp’s violations, as well as their harmful impacts, including the Wood Hollow Fire,” FERC staff said in their report.
In its order, FERC directed PacifiCorp to file, within 30 days, an answer “showing cause why it should not be found to have violated [the Federal Power Act] and … the commission’s regulations by failing to comply with … FAC-009-1 R1 [and] why its alleged violations should not warrant” being assessed the recommended penalty. Enforcement staff may file a reply to the commission within 30 days of PacifiCorp’s filing.
Chatterjee Raises Fairness Concerns
While FERC’s order passed with no dissents — Commissioner James Danly, who served as general counsel before becoming a commissioner last year, recused himself — Commissioner Neil Chatterjee urged his colleagues to consider carefully whether the penalty amount was “appropriate in light of the facts and circumstances presented.”
In a separate concurrence, Chatterjee observed that the previous highest civil penalty assessed by the commission for violations of reliability standards was a $25 million settlement with Florida Power & Light stemming from the 2008 blackout in which millions of customers in south Florida lost power for several hours.
That settlement stemmed from violations of seven groups of reliability standards that “led to the loss of 22 transmission lines, 4,300 MW of generation and 3,650 MW of … load.” By contrast, PacifiCorp is alleged to have violated a single standard, causing “minimal loss of load to customers [and] no loss of BES transmission load.”
“It is difficult to understand how the alleged violations here are substantially more serious than those that warranted the $25 million penalty [for the Florida blackout],” Chatterjee said. “Fairness also requires the commission to consider the fact that, as of August 2016, PacifiCorp had spent in excess of $127 million to conduct lidar surveys of its entire transmission system and to remediate all of the identified clearance conditions. … The commission’s penalty calculations should take into consideration such expenditures, which directly benefit PacifiCorp’s consumers.”
Chatterjee also called the arguments in favor of the penalty amount “confounding,” claiming that FERC staff cited the Wood Hollow fire to justify the $42 million penalty while also saying “the violations alone” warrant the penalty amount.
“The … fire cannot be both relevant and irrelevant. … The commission can and must be more transparent,” Chatterjee wrote.
At Thursday’s open meeting Chairman Richard Glick emphasized that the staff’s allegations were not the last word in the matter.
“Today’s order is just one step in the process. It does not represent a commission determination that PacifiCorp was in fact in violation or that they should be fined this specific amount,” Glick said. “But today’s order is an indication that the commission takes [its] responsibilities over the reliability of the bulk power system very seriously. There is a reason to believe the company is not in compliance with mandatory reliability standards. We will pursue the matter until it is resolved.”
FERC approved a policy statement Thursday on how it would review carbon pricing proposals in organized wholesale electricity markets, but there’s no indication it will be put to the test anytime soon (AD20-14).
The commission proposed a policy in October for considering market rules suggested by RTOs/ISOs for incorporating state-determined carbon prices. (See FERC: Send Us Your Carbon Pricing Plans.)
Chairman Richard Glick and Commissioner Allison Clements, both Democrats, voted to approve the statement, along with Republican Neil Chatterjee. Republicans James Danly and Mark Christie each concurred in part and dissented in part.
Chatterjee was chairman when the commission proposed the policy in October, just two weeks after holding a technical conference on the issue. Most panelists at the conference urged the commission to support state and RTO efforts to introduce carbon pricing while saying a uniform national price regime authorized by Congress would be preferable. (See FERC Urged to Embrace Carbon Pricing.)
The Analysis Group’s study concluded that New England needs a carbon price of $25 to $35/short ton by 2025, rising to $55 to $70 by 2030, to meet New England states’ carbon emissions goals. | Analysis Group
The commission said that 12 states currently use carbon pricing as a market-based tool to reduce greenhouse gas emissions.
The policy statement, which takes effect immediately, says that wholesale market rules incorporating a carbon price could be within the commission’s jurisdiction under Section 205 of the Federal Power Act (FPA). While the policy statement provides guidance on how FERC would review future proposals, the commission said any rulings would depend on the “facts and circumstances” presented.
“The policy statement serves a useful purpose in discussing how the commission might accommodate a state-determined carbon pricing program [but] the devil is always in the details,” Glick said at FERC’s open meeting. “Until we get a specific request to act, I do not think there’s much benefit to weighing in on further hypotheticals.”
Chatterjee praised the bipartisan vote in support of the statement.
“Carbon pricing has emerged as an important market-based tool that can be deployed to reduce carbon emissions in an efficient and transparent manner — one of those rare policy tools that attracts support from across the political spectrum,” Chatterjee said, noting endorsements of the concept by groups including the Union of Concerned Scientists, the Business Roundtable, the U.S. Chamber of Commerce and, most recently, the American Petroleum Institute.
But Glick acknowledged that New York and the states within ISO-NE and PJM have not taken any steps to implement such programs.
“It’s not entirely clear to me that what we did today is going to have any bearing on the states’ decisions on whether to pursue carbon pricing or not,” he said in a press conference after the meeting.
Danly said although he concurred in the order, “there’s little actual substance behind it. It’s an aspirational goal to be sure. But it doesn’t really amount to very much other than a repetition that people are able to enjoy their [Section] 205 filing rights.”
For his part, Christie said the commission should refer to such proposals as a “carbon tax.”
“Let’s get the labeling right so the public understands what’s going on here. It isn’t just semantics: It helps to clarify the legal and constitutional issues, particularly with regard to FERC’s authority as we consider these proposals,” he said. “Let’s have truth in labeling and not use euphemisms.”
Reaction
Clean energy groups welcomed FERC’s action.
“Today’s policy statement demonstrates an understanding by FERC leadership that the economic design of our nation’s wholesale energy markets is inseparable from our climate reality,” said Gregory Wetstone, CEO of the American Council on Renewable Energy. “Pricing carbon not only sends market signals to emitting resources that they should retire, but also drives investment in new, low-carbon resources by helping them compete. … I encourage electricity market stakeholders to quickly begin assessing their options to develop carbon pricing proposals under this new framework.”
The Ravenswood Generating Station now run by Rise Light & Power, as seen from a neighboring street in Roosevelt Island | Rhododendrites, CC BY-SA 4.0, via Wikimedia Commons
Gene Grace, general counsel for the American Clean Power Association, cited the “overwhelming consensus … that carbon pricing in markets is a powerful and cost-effective tool to drive down emissions and achieve state policy goals while preserving the benefits of competition.”
But ClearView Energy Partners told its clients that the commission’s action is unlikely to open a floodgate of proposals.
“Ahead of any such filing, stakeholders must develop and endorse them, and such debates have been contentious and slow-moving,” ClearView said. “Outside of California, which has already implemented a carbon price into its wholesale market, New York — as a single-state market — appears to represent the next best opportunity to test `integrating’ state policies into a regional market via carbon pricing policies.
“We think it also illustrates the difficulty of finding consensus even among a state’s own policymakers. It appears that Gov. Andrew Cuomo’s (D-NY) unwillingness to endorse the proposal has caused it to stall.”
NYISO locational-based marginal prices averaged $28.59/MWh in March, down sharply from February’s average of $63.70/MWh but well above the $17.11/MWh average in March 2020, the Business Issues Committee heard Wednesday.
Day-ahead and real-time load-weighted LBMPs came in lower compared with February, Rana Mukerji, the ISO’s senior vice president for market structures, said in delivering the monthly operations report.
NYISO Monthly Average Internal LBMPs (2020-2021) | NYISO
Year-to-date monthly energy costs averaged $46.47/MWh, up 98% from a year ago. March’s average sendout was 381 GWh/day, down from 434 GWh/day in February and higher than 375 GWh/day a year earlier.
Transco Z6 hub natural gas prices averaged $2.24/MMBtu for the month, down from $5.22/MMBtu in February but up 50% year-over-year.
Distillate prices rose compared to the previous month and were up 65% year-over-year. Jet Kerosene Gulf Coast averaged $12.38/MMBtu, up from $11.79/MMBtu in February. Ultra Low Sulfur No. 2 Diesel NY Harbor averaged $13.31/MMBtu, up from $12.71/MMBtu in February.
Uplift increased to 11 cents/MWh from -15 cents/MWh in February, while total uplift costs, excluding the ISO’s cost of operations, came in higher than February.
The ISO’s local reliability share dropped to 11 cents/MWh in March from 15 cents/MWh the previous month, while the statewide share climbed to 0 cents/MWh from -30 cents/MWh.
The Thunderstorm Alert cost in New York City remained unchanged at $0/MWh.
A draft study on carbon pricing in Hawaii suggests that an appropriately structured carbon tax and monetary redistribution program would lower GHG emissions, provide households with a dividend and not overly hamper the state’s economy.
The University of Hawaii Economic Research Organization (UHERO) prepared the report for the Hawaii State Energy Office. Entitled Carbon Pricing Assessment for Hawaii: Economic and Greenhouse Gas Impacts, the state’s first comprehensive carbon pricing study examines four scenarios for taxing carbon in Hawaii.
Under the first scenario, the state would tax polluters $70/metric ton (MT) for carbon dioxide emissions, the social cost of carbon (SCC) calculated by the Obama administration’s Interagency Working Group on the Social Cost of Greenhouse Gases in 2016.
A second scenario would see the state charge $1,000/MT based on the state’s 2045 carbon neutral goal.
Graph shows the projected change in Hawaii’s total economic output under four different carbon tax scenarios. | University of Hawaii
The third and fourth scenarios repeat the first and second scenarios but include a carbon tax revenue dividend to be paid to households.
Both taxes would be introduced gradually, reaching their full levels by 2045. The $70/MT plan is projected to result in a long-term GHG reduction of 25 MMT (million metric tons) by 2045, while the $1,000/MT plan would reduce emissions by 150 MMT.
All four tax schemes would cause a dip in economic activity over the long term relative to a baseline scenario with no carbon tax. “These declines are relative to a baseline of growing [Gross State Product] … Thus it is not a decline from the 2019 economy, but rather represents a slower growth pathway,” the study said.
The $70 plan would reduce the “total output” of the economy by 0.6% by 2045, falling to 0.5% with the inclusion of a dividend program. The $1,000 plan would cut economic output by 4.7%, or 4.2% with the dividend.
While imports and visitor spending would see modest downturns, Hawaii’s exports would take a roughly 5% hit under the $70 plan, rising to 30% under the $1,000 plan. “There is an overall loss of competitiveness for Hawaii goods and services” under either plan, the study said.
Energy prices would also be impacted, with the $70 plan raising gasoline prices by 63 cents/gallon and natural gas prices by 35 cents/therm, while electricity prices would remain unaffected. The $1,000 plan would drive up gasoline prices by a whopping $9/gallon, natural gas by $4.90/therm and electricity by 3 cents/kWh.
The electric vehicle sector would reap benefits because of increased gasoline prices. By 2045, EV vehicle miles travelled would increase by 20% under the $70 plan and more than double under the $1,000 plan when compared to the baseline projection of no carbon tax.
Household Impacts
“One of the things we were particularly interested in here is understanding how a carbon price would affect different kinds of households by income level,” Makena Coffman, the study’s principal investigator, said during an April 7 presentation of the study to the Hawaii Climate Change Mitigation and Adaptation Commission.
In examining energy use based on household income, the study’s authors found that the top 20% of earners consume 32% of Hawaii’s gasoline, 31% of its natural gas and 26% of its electricity, whereas the bottom quintile consumes 9.6%, 12% and 14%, respectively. The study concluded that a flat dividend rate for households would be progressive because, as Coffman said, “It would be high-income households who pay into the tax more.”
The study also found that by 2045 the $70 plan would provide the state with $610 million in annual revenue, compared with $2.8 billion under the $1,000 plan. Distributed equally, that would provide about $1,000 and $3,000 annually per household, respectively.
Without dividends, both plans would see net spending power drop by a few percentage points depending on household quintile. With dividends, the $70 plan yields a marginal increase in net spending power, while the $1,000 plan results in a marginal decrease. The dividend under the $1,000 plan “is not enough to offset the impacts of the shrinking economy,” the study said.
The study makes a case for implementing a direct carbon tax instead of pursuing other policies to mitigate GHGs, contending that the economy-wide approach “lowers the cost of reducing GHGs because it captures a range of GHG reduction opportunities while harmonizing sectoral interactions.”
“Often regulatory policies are less effective because they fail to address total emissions directly and instead target a proxy for emissions (e.g., vehicle miles traveled) or the rate of emissions (e.g., emissions per unit of electricity generated),” the study said. “Carbon pricing also addresses both new technologies and the ongoing use of fossil fuels … Carbon pricing can be implemented economy-wide, serving to capture GHG reduction opportunities in multiple sectors and harmonize the marginal cost of abatement among sectors.”
If implemented, the $70 plan would lower GHGs by 13% and the $1,000 plan by 70% when compared to the no carbon tax baseline. But the study notes that “[a]s the carbon price approaches $300-$400/MT CO2 [equivalent] … the effectiveness of the carbon tax declines as fewer GHGs are reduced per dollar of tax.”
“There is little economic argument for Hawaii, or any other state, to unilaterally adopt a very high carbon price,” the study concludes. “Hawaii’s per capita emissions are double the global average — motivating a responsibility to play a role in global GHG mitigation.”
The authors contend that a carbon price in line with the Obama administration’s SCC assessment would encourage renewable development and “dissuade fossil fuel burning in power plants and vehicles,” going “a long way” in reducing Hawaii’s contributions to global GHGs.
“At the federal SCC price, returning revenues in equal shares to households would benefit lower-income households relatively more as well as make all of Hawaii’s households economically better-off,” the study said.
Reaction
After the April 7 presentation, the commissioners offered little comment on the study other than expressing satisfaction with the scope. State Rep. Nicole Lowen (D) said that the study’s energy use estimates represented statewide averages that might obscure regional differences.
“Can you speak to what the difference might be between residents in more rural areas who have to spend significantly more on gasoline, for example?” Lowen said. “I feel like it’s important to think about how we look at an average, but it doesn’t account for the differences between islands or between rural and urban.”
“That was totally out of scope to [this study], but I think it’s really important,” Coffman said. “That is the next step. How do you take this information and make it spatial.”
Hawaii Sierra Club Director Marti Townsend pointed to another area of potential inequity.
“It is a little unfair to me to set a price on carbon and have the general public pay for it when we have large corporations that disproportionately benefited from the use of carbon and actually delayed the transition to clean economies,” Townsend said. “The state of Hawaii is facing very expensive climate mitigation measures, and there is no reason why the fossil fuel companies cannot also participate in helping us address this.”
Coffman agreed, explaining that the specifics of implementation were beyond the study’s focus but were important for the success of either plan.
Two Michigan local distribution utilities have squared off with Michigan Electric Transmission Co. (METC) over the transmission company’s request to spend $15 million on a pilot project to build charging facilities for long-haul medium- and heavy-duty commercial vehicles.
In November, METC filed a request with FERC to recover its costs to build three charging stations along the state’s interstate highways (ER21-424). It also sought assurance that FERC would grant it 100% of its costs if the project is abandoned for reasons beyond METC’s control, in accordance with the commission’s 2009 Smart Grid Policy Statement.
Because of the charging demands of commercial trucks, METC said, their DC fast charging (DCFC) stations “may be best served by interconnections to the transmission system depending on the local system configuration and the availability and proximity of robust distribution infrastructure.” The proposal received support from Michigan officials, including the Public Service Commission, along with General Motors, Ford and several clean energy groups.
But Consumers Energy and DTE Electric Co. have asked the commission to reject METC’s petition until the company can provide more details, saying it could conflict with the distribution planning process and infrastructure development already underway in the state. They say METC’s proposal belongs in MISO’s Transmission Expansion Plan process.
FERC is expected to issue a ruling in the dispute on Thursday.
Corey Proctor, manager of transmission design at METC parent ITC Holdings Corp., told FERC in testimony that the DCFC charging stations will be sited based on criteria including proximity to interstate highways and existing transmission, available properties with willing partners, and location of ancillary services such as convenience stores, restrooms and existing petroleum fueling locations.
METC said it is only requesting cost-recovery of transmission-related infrastructure such as transmission lines of 138-kV and above and associated substations and technology to convert AC power into DC power.
“Power will be supplied by local distribution companies, and the charging stations will be owned and operated by third parties,” Proctor said. “Consequently, the pilot project will depend on the applicant’s successful collaboration with its customers and unaffiliated vendors that provide DCFC services.”
Proctor said although the pilot locations could recharge light-duty EVs, they will be designed to serve medium- and heavy-duty long-haul trucks with charging ports that can charge batteries with that have a demand of 1-3 MWh. Each charging station will have six charging ports.
METC would like to begin the pilot project next year.
Policy Statement
FERC’s 2009 policy statement, issued in response to the Energy Independence and Security Act (EISA), provides “guidance regarding the development of a smart grid for the nation’s electric transmission system, focusing on the development of key standards to achieve interoperability and functionality of smart grid systems and devices.” It set an interim rate policy to apply until the commission adopts interoperability standards.
METC said its proposal meets the policy statement’s requirements for rate recovery: it will advance the policy and goals of Section 1301 of EISA; will not adversely affect the reliability and cybersecurity of the bulk electric system; minimizes the possibility of stranded investment; and will include information-sharing with the Department of Energy’s Smart Grid Clearinghouse.
“Additionally, the pilot project will provide information to METC and the commission regarding the important role that transmission can play in facilitating the deployment of medium- and heavy-duty commercial EVs,” Proctor said.
The company said it can implement the project through the MISO and regional distribution system interconnection planning framework and recover its costs through MISO’s tariff.
Consumers Energy, DTE Oppose
METC’s 5,600-circuit mile transmission system (120 kV to 345 kV) is spread over two-thirds of Michigan’s Lower Peninsula. Consumers Energy is a transmission customer of METC whose 67,000 miles of electric distribution largely overlap METC’s service territory.
Both Consumers and DTE, which owns 40,000 miles of distribution in southeastern Michigan, say they have been heavily involved in Michigan’s efforts to encourage EV use.
Consumers’ “limited” protest said FERC should be careful to “preserve the well-established demarcation between transmission and local distribution facilities, both under the Federal Power Act and under a longstanding contractual arrangement between Consumers Energy and METC.”
Consumers also said the proposal shouldn’t circumvent existing regional transmission planning processes and that METC should be required to partner with Consumers and other affected distribution companies.
Consumers said FERC should reject the application without prejudice and require METC “to work with affected stakeholders, including distribution companies and load-serving entities, and return to the commission with a proposal to construct specific facilities that fit within a coordinated framework for encouraging electric vehicle adoption in Michigan.”
Consumers also asked the commission to conduct “stakeholder collaboratives” on the role of transmission facilities in the EV transition.
Consumers and DTE also insisted most distribution facilities can handle truck charging loads.
“METC’s witnesses contemplate charging stations that could individually serve 2.5 MW of load with all chargers in operation — an amount that is normally (and easily) served by local distribution facilities and local distribution companies,” Consumers said. “Even loads ten times larger could readily be served by Consumers Energy’s high-voltage distribution system.”
DTE said that METC’s application falls short of the requirements in FERC’s Smart Grid Policy and “also sows confusion and potential conflict with the distribution planning process and infrastructure development already well underway in Michigan.”
“Moreover, based on the description of the pilot project provided so far, METC appears to be seeking rate incentives for facilities that may well be local distribution facilities and thus outside FERC’s jurisdiction.”
“It is important to highlight that METC is a transmission owner, only,” DTE said. “It does not own any distribution facilities, and therefore METC lacks the requisite insight into the distribution system which is needed in order to be able to ascertain the most appropriate and cost-effective method of service for a new, end-use customer.”
