Search
`
October 7, 2024

Posted on

Honolulu Rail Project Seeks New Tax to Help Close Budget Gap

The Honolulu Authority for Rapid Transportation (HART) passed a resolution Friday recommending a new tax on tourists to help pay for a $3.5 billion budget shortfall in the city’s 21-mile light-rail project.

The request came two days after HART’s board of directors reviewed a permitted interaction group (PIG) report that explored the value of earmarking a portion of a newly proposed transient accommodation tax (TAT) for the project. Under Hawaii law related to public entities, a PIG is a subgroup of board members assigned to investigate a specific matter related to board business.

Aimed at the tourism industry, the proposed TAT would levy a 3% tax on any accommodation for stays of less than 180 days.

The report recommended that the rail receive one-third of TAT revenues for the first two years after implementation of the tax, and half of TAT revenues thereafter, which would provide a projected $440 million from fiscal years 2023 to 2031. Bill 40, which would enact the TAT, is awaiting its third reading by the Honolulu City Council.

The report also explored other cost-saving methods that could reduce the shortfall to about $2 billion. Triunity, a construction management consultancy approved by the Federal Transportation Administration, determined that HART could reduce the cost of the rail by $749 million. A change in construction plans to avoid relocating high voltage power lines would also save an estimated $150 million.  Use of an unallocated contingency fund within HART’s budget could provide another $222 million.

The report also projected that a “much faster than anticipated” rebound in tourism could produce an additional $539 million from general excise tax revenue by 2030.

The HART project has been plagued with increased costs and budget shortfalls, a fact acknowledged in the report and board resolution. The latter noted that “requesting TAT funding from the Honolulu City Council only makes sense in the context of other measures which, combined, would allow us to complete the rail project. We cannot ask the public for more funding if they perceive that the money would only help extend the system another mile or two.”

The PIG report pointed to “many possible reasons,” for cost overruns, including “significant delays due to lawsuits, rising costs of materials, the pandemic, overly-optimistic cost projections, unanticipated utility relocation costs and operational variables, and leadership decisions.”

The rail project is part of the state’s push for 100% renewable energy by 2045. The trains will be electrically powered and therefore equipped to benefit from the aggressive renewable energy projects the state is building; they will also reduce dependency on imported energy. HART estimates that the rail will cut energy demand by 3%, the equivalent of 5.9 million gallons of gasoline. The rail is projected to take 40,000 cars off the road every day.

Posted on

Veteran Litigator Appointed Head of NJ Rate Counsel

New Jersey Gov. Phil Murphy has appointed Brian O. Lipman, a veteran litigator and senior executive at the state Division of Rate Counsel, to lead the consumer advocacy agency through what is expected to be a period of dramatic and unprecedented evolution in the energy sector.

Lipman joined the division in 2013, spending eight years as its litigation manager before being named acting director after Stefanie Brand retired in September. He also spent 10 years, 2003 to 2013, as a deputy attorney general in the state’s Division of Law where he represented the New Jersey Board of Public Utilities (BPU).

Lipman takes the position of rate counsel as the state reshapes its energy sector in line with Murphy’s Energy Master Plan to reduce New Jersey’s carbon emissions 80% below 2006 levels by 2050. Strategies to achieve that goal include boosting the use of solar with new programs for community solar and grid-scale development, jumpstarting a new offshore wind industry and aggressively promoting the use of electric vehicles. Murphy has particularly focused on cutting emissions from the transportation sector, which accounts for about 40% of the state’s carbon emissions.

Lipman was sworn in as rate counsel on Nov. 8, with Murphy in attendance, as posted on the governor’s official Facebook page. “Under his leadership, we will continue to ensure residents receive safe and affordable utility service,” Murphy said.

In an interview with NetZero Insider, Lipman said it is “hard to say” whether he will take the department in a different direction to the one charted by Brand because “a large portion of what we do is reactive.” While he worked on numerous issues as the division’s litigation manager, market changes mean he will confront others not faced by the agency before, he said.

“We’re entering an era of transformation within the energy industry,” Lipman said. “There’s going to be a lot of things that no one’s ever looked at before that we’re going to have to look at. And that helps set policy.

“It’s a fascinating time,” he said. “It’s a little bit [of a] scary time because of how much everything is going to cost, but it is also a hopeful time. I think that we’ll have a better, safer grid at the end of all this. It’s just a matter of figuring out how we pay for [it].”

Holding the Line on ZECs

Lipman foresees no change in direction to the division’s vigorous opposition to the zero-emission subsidies the BPU awarded to three South Jersey nuclear units in March 2019, and then again on April 27. On both occasions, the BPU awarded $300 million in zero-emissions credits (ZEC) to Public Service Enterprise Group (PSEG) (NYSE:PEG), which owns two of the plants, and Exelon, which co-owns the third plant with PSEG.

State law allows the award of ZECs to nuclear power plants at risk of closure, but the division, under former Rate Counsel Brand, argued that the BPU failed to show that the nuclear plants would lose money without the subsidies. (See NJ Nukes Awarded $300 Million in ZECs.)

The division took the first case to the state Supreme Court, where it was dismissed. On Oct. 12, Lipman, as acting director, appealed the board’s April 27 award to the N.J. Superior Court Appellate Division, again contending that the facts did not support the award. (See NJ Rate Advocate Challenges 2nd Round of Nuclear Subsidies.)

“We’re going to continue that challenge,” he said. “We’re just not convinced that the amount of ZECs that were paid to PSEG were necessary.”

Lipman said he is comfortable standing up to PSEG, the state’s largest utility. He said he has had numerous interactions with the utility over the years, including as deputy attorney general representing the BPU in an 18-day trial in federal court in 2011. The case involved a lawsuit filed by PSEG against the state’s Long-Term Capacity Agreement Pilot Program that awarded subsidies that the utility disagreed with for the construction of three gas-fired generators in New Jersey that would compete with PSEG.

PSEG won the case, Lipman said, “So, I’ve seen the full weight of the corporation and what they can bring to bear.”

But that case also brought his work to the attention of Brand and eventually brought him to the Division of the Rate Counsel.

“My goal, and I believe we’ve done very well, is [that] while [the relationship with PSEG] may be adversarial, it’s professional,” he said. “And at the end of the day, we can walk away from each other with mutual respect. I’m not going to agree with everything they want to do; they’re not going to agree with everything I say. And we both know that.”

Vying for Fair Cost Allocation

Lipman expects “to see a lot more federal and state transmission issues” than his predecessor, such as the BPU and PJM’s recent solicitation for suggestions on how to modernize the grid to accept energy from the offshore wind developments underway. (See New Jersey Seeks OSW Transmission Ideas.)

“Grid modernization is a big issue now,” he said. “That’s obviously more on the distribution level because the BPU regulates the distribution level,” he said, adding that he expects modernization of transmission infrastructure to be significant as well. “PJM is also looking at grid modernization and what they need to do to upgrade their grid.”

On those issues, and others, his office will monitor how those upgrades are funded to ensure that ratepayers are charged fairly, he said. The rise of the state’s offshore projects will also raise ratepayer and transmission issues that are “much different from anything we’ve ever seen in the state before,” he said.

“Bringing all that power on shore is going to be massive, and making sure that the allocation of those transmission lines is appropriate and that New Jersey is not bearing an unfair weight of that power as it goes into the PJM grid is important,” Lipman said. “And to the extent it goes to New York, to make sure New York is paying its fair share.”

Cost allocation for infrastructure is always an issue, and the rate counsel has been concerned for a while about the allocation of the cost of transmission upgrades in North Jersey, he said.

“Because the lines are in PSEG territory, we are paying for them. We think they should be allocated to New York ratepayers,” he said. “Similarly, lines built in New Jersey for PJM will benefit other states in PJM, and to the extent they benefit, they should pay.”

Advocating for People

As a member of the executive committee of the Consumer Advocates of PJM States, Lipman will likely have a voice in cost allocation discussions.

The new rate counsel graduated from American University with a bachelor’s degree in political science in 1992 and earned his law degree from Rutgers University in 1995.

As an attorney in private practice from 1997 to 2003, he represented private employers and federal employees in in employment litigation matters. He joined the New Jersey Division of Law in 2003, working on a portfolio of cases with periods working at the Division on Civil Rights and Affirmative Litigation Section, both of which are part of the Division of Law.

Lipman said his experience litigating in private practice helped prepare him for the kind of analysis and high-density information absorption he needs as rate counsel.

“I would be lying if I didn’t say I don’t learn something new every day, even now, in the utility world, and you have to be willing to do that — to go out there and just really dig into this stuff to really learn it,” he said.

But Lipman is most motivated in his new role by the opportunity to advocate for those in need.

“I’ve met people out there who have said to me, ‘I have to choose between my medication, my heat and my food. I can’t afford all three. How do I choose?’” he said. “And now I’m advocating on behalf of those people to try and keep their rates down and reasonable.”

Posted on

ACORE Report: Time to Rethink Resource Adequacy

A new report from the American Council on Renewable Energy argues that industry needs to rethink the concept of resource adequacy to get more renewable energy online and decarbonize the U.S. electric power sector by President Biden’s target of 2035.

Creating a level playing field for renewables in capacity markets is one of several recommendations in the report, released Nov. 23 and a joint effort of ACORE, the American Clean Power Association (ACP) and the Solar Energy Industries Association.

“Capacity is not technically a reliability need,” author Rob Gramlich, president of Grid Strategies, said during a webinar launching the report. “What you want is performance at the time and place you need it. It’s getting increasingly hard to rely on a single construct of capacity when there might be multiple products that you actually need.”

The report intends to provide a counternarrative to industry views that inextricably link capacity and reliability to firm, dispatchable power, traditionally provided by fossil fuels.

“Achieving a net-zero emissions grid by 2035 will require a major shift in the resource mix and a reassessment of grid operations and market design to ensure clean power is reliably delivered to consumers,” ACP CEO Heather Zichal said in an ACORE press release announcing the report.

Sean Gallagher, SEIA’s vice president of state and regulatory affairs, called solar and storage “some of the most predictable technologies on the grid.” Following the report’s recommendations could, he said, “unlock new market opportunities for clean energy resources while improving reliability and resilience.”

But even with FERC Order 2222, the 2020 ruling that opened wholesale power markets to aggregated distributed energy resources, longstanding industry biases remain, Gramlich said.

For example, the report notes that “correlated outage risk is now being widely applied to renewable energy sources but not to fossil resources.” While effective load-carrying capability — a prediction of how much power any one resource will be able to deliver at times of high demand — is a metric widely applied to wind and solar, it was originally developed for fossil fuel generation and thus should be applied to all technologies, the report says.

Capacity valuation should also take into account “portfolio effects,” such as the flexibility and backup power available from solar and storage, the report says.

“It’s important to make sure the rules are right,” Gramlich said. “First of all, to achieve reliability; second, to make sure consumers are paying a fair price and not excessive prices, but then also to avoid the situation where resource adequacy regimes are effectively a way to subsidize nonrenewable, nonclean resources in a way that sort of crowds out the clean and renewable sources from the market.”

Michelle Gardner, NextEra Energy’s senior director of regulatory affairs for the Northeast, pointed to ISO-NE’s capacity market as having “a lot of disadvantages for seasonal resources. It’s not dynamic. I don’t think it supports a changing resource mix as we look across summer and winter periods; as we look across the day, and new technologies.”

One of four industry panelists speaking at the webinar, Gardner also questioned whether three-year forward capacity markets — based on “assumed development cycles for gas turbines” — will provide “the right timing going forward.

The industry is often reacting to “the crisis of the moment,” she said. “We don’t often take the time to really step back and say, ‘Is this the right market? What is the product we’re purchasing? Can we define this? Does it still make sense?’”

Seasonal, Granular, Regional

Along with current high energy prices, the 2020 rolling blackouts in California and last February’s unprecedented winter storm and resulting power outages in Texas and the Midwest have intensified the urgency of the power industry’s current discussions on resource adequacy and, by extension, grid planning. Federal and state regulators, utilities, RTOs and ISOs, investors and other stakeholders each have different and sometimes conflicting concerns, and the report acknowledges solutions will likely be regionalized, based on specific market structures that, it says, are not likely to change.

For example, the report recommends ensuring FERC does not have jurisdiction over markets for environmental attributes, invoking the commission’s recent experience extending PJM’s minimum offer price rule (MOPR) to state-subsidized resources. The rule was rolled back in October, but it could have undone state clean energy policies, the report says.

The report cautions that votes on the MOPR fell along party lines, and the balance of power on the commission could easily change if power also shifts in Congress or the White House.

For RTOs and ISOs with capacity markets, the report recommends a more seasonal and “granular” approach to capacity, and a move toward greater reliance on energy and ancillary services markets.

“Seasonal capacity products are incredibly important, especially for offshore wind, where we have significant capacity in the dead of winter, when other renewables are generally not performing well,” said Eric Wilkinson, electric policy market director for Ørsted Offshore North America.

Energy markets also tend to give developers “better information and that allows us to better value the generation … we are building,” said John Brodbeck, senior manager of transmission for EDP Renewables. Better information and valuation also mean “we are likely to make the appropriate investments and convince our investors to do the right thing and give us money to build,” he said.

For states with vertically integrated, “balkanized” utilities, the report pushes for regionalization — similar to the West’s Energy Imbalance Market and, now, the Southeast Energy Exchange Market.

The report’s other recommendations range from a call for competitive procurement for new generation — widely supported by renewable developers and trade groups — to improved preparation for extreme weather events through regional “stress testing” that goes beyond basic resource adequacy.

Along the same lines, new metrics for capacity and reliability will also be needed, Gramlich said. “There probably isn’t a single new future metric,” he said. “There will certainly need to be more focus on all hours of the year, not just the single, peak summer hour. We can find system stress conditions in any season now, depending on generation outages and weather patterns.”

Resistance to Change

While most panelists voiced broad support for the report’s recommendations, Goldman Sachs Vice President Harry Singh had questions about one suggestion: creating buyers with creditworthiness to procure power through long-term contracts that developers need to secure low-cost financing for their projects.

Gramlich said that in many of the states with competitive, restructured power markets, retail providers are not required to be creditworthy and, therefore, may not be able to enter into long-term contracts that can ensure both reliability and low costs for consumers.

Singh did not see an immediate need for any regulatory requirement for such accountability, such as setting up state-level authorities to ensure creditworthiness, even in states with competitive retail markets. The U.S. already has “a very active marketplace of energy contracts,” he said. “You have utility [power purchase agreements]; in parts of the country, you have corporate PPAs, which inherently include environmental attributes, and that’s a very big part of the contracting for clean energy resources today.”

Such contracts can and, especially in the utility sector, already do encompass capacity, Singh said, and contracts are themselves evolving, as the industry looks at new market designs and transaction structures for renewables.

Brodbeck also interjected one subject omitted in the report: interconnection, and the hundreds of gigawatts of renewable projects sitting in queues across the country. “We can have all sorts of desires to reform and rebuild the system, but until we can get something like a smooth interconnection process in any of the RTOs, we’re living in a fantasy,” he said.

Still another core issue the report does not address is how to motivate an industry that recognizes the need for change but remains highly resistant to external recommendations.

Simply put, said NextEra’s Gardner, “there tends to be huge resistance to being told what to do. Each of the RTOs kind of likes their own playground.”

What is needed instead, she said, is a resetting of priorities and “thinking a lot bigger than what each region is dealing with, whatever crisis they’ve created at the moment.”

“Going forward, we may be better off keeping resource adequacy as kind of a peak [demand] product and looking to improve ancillary and reliability products,” Gardner said.

Brodbeck also stressed the role of stakeholders in RTO decision-making and resistance to learning new ways to address resource adequacy.

“Every stakeholder has a different set of goals, and there are many stakeholders whose main goal is to reduce costs,” he said. “They don’t like the idea of building additional transmission … and that all goes against a fast and smooth transition” to clean energy.

Ørsted’s Wilkinson sees an incremental process going forward. Capacity markets may not be a primary revenue stream for renewables, he said, but will still provide significant value for technologies, such as offshore wind, which require high, upfront capital expenditures.

“The good thing is, as grid operators become more knowledgeable and gain experience operating a grid that has a lot of renewables on it, we can take steps in the future to adjust how capacity is valued and exactly who gets credit for what capacity and when.”

Posted on

NM Draft Bill Would Encourage Hydrogen Buildout

The state of New Mexico has released a “stakeholder discussion draft” of a bill that would offer tax breaks as an incentive for developing hydrogen infrastructure.

The bill, known as the Hydrogen Hub Act, will be introduced during the state’s 2022 legislative session, which runs from Jan. 18 to Feb. 17. Comments on the discussion draft will be accepted through 5 p.m. on Dec. 12 and may be sent to hydrogen.feedback@state.nm.us.

As proposed, the bill would set a carbon intensity limit for hydrogen that qualifies under the act. The carbon intensity limit would start at 9 kilograms of CO2 equivalent per kilogram of hydrogen produced and decrease every two years: to 7 kg of CO2 equivalent in 2024; 5 kg in 2026; and 3 kg in 2028.

The bill would offer a variety of tax incentives. An entity with an interest in a qualified hydrogen electric generating plant or a hydrogen production facility would be able to claim a state tax credit for up to 5% of the costs for developing and building the facility.

Companies would be able to deduct from their gross receipts some or all their revenue from equipment or construction services used to build hydrogen infrastructure. That would include pipelines, hydrogen production facilities, hydrogen electric generating plants, or hydrogen fueling stations.

A gross receipts deduction would also be available for revenue from selling hydrogen.

The tax incentives would not be available for hydrogen made from fresh water.

The New Mexico Environment Department sent out the draft bill via email this month. A one-page overview accompanying the bill said hydrogen could be part of the state’s clean energy portfolio, along with solar, wind and geothermal energy.

In particular, hydrogen can reduce emissions from the industrial and transportation sectors, including cement manufacturing, petroleum refining, and aviation, the overview said.

“The Act will drive technological innovation, create clean energy jobs, and diversify our economy — all while accelerating New Mexico’s efforts to reach net-zero carbon emissions by no later than 2050,” the overview stated.

The Hydrogen Hub Act would help New Mexico jump-start a clean hydrogen economy, according to a release from Gov. Michelle Lujan Grisham’s office. The release was issued this month in response to the signing of the federal Infrastructure Investment and Jobs Act. It noted that the bill includes $8 billion for clean hydrogen hubs across the U.S.

Environmental groups are criticizing New Mexico’s proposed Hydrogen Hub Act.

Erik Schlenker-Goodrich, executive director of the Western Environmental Law Center, said the bill’s carbon-intensity “guardrails,” which would determine eligibility for tax breaks, are weak and would condone hydrogen production from fossil gas.

In addition, he said, the guardrails exclude upstream emissions from the oil and gas production process.

Hydrogen can be produced from methane, releasing hydrogen, carbon monoxide and CO2 in the process. In some cases, the CO2 may be captured and stored. Hydrogen can also come from the electrolysis of water, in which hydrogen and oxygen are produced.

Schlenker-Goodrich said there’s nothing in the bill to target hydrogen to hard-to-decarbonize industrial sectors. Instead, the bill tries to push hydrogen into end-uses where it can’t compete with other energy sources, he said.

“The draft Hydrogen Hub Act is nothing more than a move to provide the fossil fuels industry with yet more subsidies, paid for by taxpayers, that benefits politically well-connected fossil fuel CEOs and investors,” Schlenker-Goodrich told NetZero Insider.

The Western Environmental Law Center and a long list of other groups sent a letter last month to Lujan Grisham and lawmakers expressing concern that the state’s focus on a hydrogen hub would “prove a counterproductive distraction from urgently needed climate action.”

The letter urges the state to create a comprehensive climate policy framework and then determine whether hydrogen fits into it.

“In New Mexico, we need statutory carbon emissions limits, methane emissions standards, transportation emissions standards, state investment to power a transition to 100% electric vehicles, and support for New Mexican families who are making their homes more safe, resilient and efficient,” the letter said.

Posted on

Maine Eyes $284M OSW Hub at Port of Searsport

Maine Gov. Janet Mills last week released the first of a two-part seaport study and directed her administration to assess the state’s port infrastructure and the investments needed in them to enable offshore wind activity.

The new Offshore Wind Port Infrastructure Feasibility Study released Nov. 23 evaluated the ability of the Port of Searsport to support a potential floating OSW industry.

“The goal was to develop a viable offshore wind port concept that could proceed to the permitting and design phase,” said Matt Burns, director of ports and marine transportation at the Maine Department of Transportation (DOT).

For the study, the DOT evaluated four sites at the Port of Searsport and determined that two — Sears Island and Mack Point — were “clear leaders,” Burns told the Maine Offshore Wind Roadmap’s ports working group during its latest meeting Nov. 19.

A 330-acre, undeveloped transportation and marine development parcel at Sears Island owned by the DOT is the “preferred site,” he said. It has 9,000 linear feet of available water frontage and site access for vessels via Penobscot Bay, according to the study.

Development for the parcel would include construction of a marshalling and fabrication facility with a heavy-lift bulkhead and about 30 acres for a component laydown and staging area. Mack Point, which is across Penobscot Bay on the mainland, also could be available for an additional support facility, Burns said.

The study estimated that a two-phase, six-year development plan for Sears Island would cost $284 million.

“Cost is going to be a huge issue,” Burns said. “These facilities are not cheap, and we would certainly be pursuing federal funding to help assist us with constructing something of this scale.”

A second port study, which is underway now, will examine other sites that can provide a supporting role to a central port hub, such as Searsport, according to Burns.

The DOT is looking at the ports of Portland and Eastport as part of the second study.

“Once we actually have an array that’s being installed or is in play in the Gulf of Maine, we’re going to need a place for” manufacturing and operations and maintenance facilities, Burns said. “We really see this as a statewide effort.”

The study recommends that Sears Island site be evaluated for potential phased development through an environmental assessment, geotechnical study and preliminary design work.

“We look forward to realizing the economic benefits of putting more port into Searsport, while we preserve the ecological and recreational aspects of what makes us special,” Searsport Town Manager James Gillway said in a statement.

Part of Sears Island is protected under a conservation easement, and much of that property is used for recreation and nature conservancy, according to Burns.

“We thought it was appropriate for this study to also explore how a development on the transportation parcel could complement some improvements for education and maintenance on the conservation side of the island,” he said.

The study acknowledged that there will be “many differing viewpoints” on amendments to the conserved property, and it called for discussion between the DOT and concerned parties in developing a final plan.

Posted on

SEEM Members Embrace Market Changes

In a filing with FERC on Wednesday, members of the Southeast Energy Exchange Market (SEEM) confirmed they would implement the “transparency enhancements” to the market that they previously promised, despite the lack of a commission order requiring them to do so (ER22-476).

The SEEM agreement went into effect Oct. 12 after FERC split 2-2 on approval. With the commission unable to form a majority for or against it, the agreement became effective under Section 205 of the Federal Power Act. (See SEEM to Move Ahead, Minus FERC Approval.) FERC has since approved revisions to four of the participating utilities’ tariffs implementing the special transmission service used to deliver the market’s energy transactions. (See FERC Accepts Key Tariff Revisions to SEEM.)

Earlier this year SEEM members — a group of utilities that includes Southern Co. (NYSE:SO), Dominion Energy South Carolina (NYSE:D), LG&E and KU (NYSE:PPL), the Tennessee Valley Authority and Duke Energy (NYSE:DUK) — proposed several modifications to the agreement in response to FERC’s deficiency letter and objections from the market’s detractors. (See SEEM Members Offer Rule Changes.)

Changes Offered in Previous Deficiency Response

Because the agreement entered operation by default rather than via a commission order, it did not include any of those modifications; however, according to the latest filing, SEEM members “have always intended to fulfill the commitments” they made both because “it is the right thing to do and … to do otherwise might raise questions” regarding the market’s legitimacy. The proposed changes include:

  • weekly submissions of confidential market data to FERC and the market auditor, and periodically providing additional information publicly;
  • disclosure of regulators’ questions and answers, as well as market auditor reports, to participants, subject to restrictions on access to confidential information by marketing function employees;
  • clarification that available transfer capacity calculated by participating transmission providers must be provided to the SEEM administrator and must be used in the algorithm for each leg of any contract path to ensure transmission will not exceed available capacity;
  • updating market auditor functions to clarify that the auditor will verify compliance with market constraints;
  • use of randomization to resolve ties or ambiguities between multiple bids or offers;
  • prohibiting market-based rate holders from providing false or misleading information to the SEEM administrator or market auditor; and
  • implementing a posting requirement for complaints submitted to the market auditor.

In addition, members promised to make the “just and reasonable standard” the default for most SEEM rules rather than the lower Mobile-Sierra public interest standard. The use of Mobile-Sierra was a sticking point for FERC Chair Richard Glick, who in a statement explaining his vote against SEEM said the commission’s monitoring capabilities and enforcement authorities would be “hamstrung” by the doctrine’s application. (See FERC’s Christie Accuses Glick, Clements of Prejudice for RTOs.)

Commissioner Allison Clements also cited the use of Mobile-Sierra in her statement against SEEM. Several of the market’s most vocal critics have criticized the doctrine as well, even going so far as to say that proponents’ offer to voluntarily restrict the application of Mobile-Sierra would still unacceptably limit market participants’ negotiating power. (See SEEM Opponents File Rehearing Requests.)

Nov. 25 Effective Date Requested

SEEM members asked that their proposed changes become effective Nov. 25, one day after their filing, and that the commission waive prior notice requirements in order to allow the new revisions to become effective before the incurrence of vendor costs, which could begin as early as next month. Members noted that if prior notice requirements are not waived, the commission is required to act on the filing within 60 days. They also reminded the commission that Section 205 mandates that FERC “not go ‘beyond approval or rejection’” of an amendment proposal.

“Rejection or acceptance of the amendments are the only permissible outcomes of this Section 205 proceeding,” the members said. “The commission cannot, in this proceeding, revisit the justness and reasonableness of the existing provisions of the [SEEM] agreement, except and only to the extent that the members propose … to change such provisions.”

FERC is also considering a rehearing request filed earlier this month by two ad hoc groups of SEEM’s opponents. The fate of both filings may be impacted by the U.S. Senate’s recent confirmation to FERC of D.C. Public Service Commission Chair Willie Phillips, who will join Glick and Clements as the third Democrat on the commission. (See Senate Confirms FERC Nominee Willie Phillips.)

Posted on

Vermont Climate Council Adjusts Course on TCI-P

The Vermont Climate Council is scrambling to update its draft action plan after Connecticut, Massachusetts and Rhode Island said they no longer back the Transportation and Climate Initiative Program (TCI-P).

“It’s unclear whether or not there will be a viable regional marketplace for this program to move forward,” Peter Walke, commissioner of the Department of Environmental Conservation, said Nov. 23.

The council is poised to consider adoption of the state’s first climate action plan Dec. 1, and joining TCI-P had been a keystone strategy to fund transportation emission-reduction programs in that plan.

Now, however, the council will amend the language around TCI-P as it appeared in the draft plan prior to the council’s latest meeting last week.

Connecticut Gov. Ned Lamont on Nov. 16 announced that he would not support TCI-P-enabling legislation next year. On the heels of Lamont’s announcement, Massachusetts Gov. Charlie Baker said he would remove his support for the program given the lack of broad participation among states. And Rhode Island Gov. Dan McKee said on Nov. 19 that his administration would no longer pursue the initiative.

Vermont has been a member of TCI for over a decade, but it never fully signed on as a program participant. Massachusetts, Connecticut, Rhode Island and D.C. agreed last year to launch TCI-P, which would cap regional transportation emissions and create a market for emissions allowances.

Members of the Vermont Public Interest Research Group said in a Nov. 22 statement that they are disappointed by the latest developments in the region, saying it “ignores our state, regional and national climate commitments.”

“It also ignores broad public support across the region for TCI-P, as confirmed by multiple independent polls and the groundswell of support expressed during the TCI public comment period,” they said.

Despite the latest setbacks, Vermont’s action plan will not abandon the potential for participation entirely, Walke, who is co-chair of the Cross-sector Mitigation Subcommittee, told the full council.

“The reality is that without TCI-P in the plan, it leaves a significant hole in the emissions reductions picture,” Walke said. “We are not proposing alternatives at this time because there’s work that needs to be done to validate those alternatives.”

While the council will monitor the fate of TCI-P and evaluate other options, there likely will not be any concrete actions ready for inclusion in the plan that’s set for adoption next week.

“There could be a lack of clarity and certainty around the future of TCI-P for a while, and at some point, we are going to need to have a plan B for one or more primary strategies that can meet the emissions reduction we were counting on TCI to have had by a date certain,” said council member Jared Duval, who is executive director of the Energy Action Network.

Council members will have one more opportunity on Monday to discuss the changes in the plan before they must vote on whether to adopt it.

As it stands, the updated draft plan language says that joining TCI-P is a “critical component” of the transportation sector strategy, and Vermont should “remain at the table” in finding a pathway for the program’s implementation. The update also allows for “additional parallel work” that is necessary to find a comparable cap-and-investment program for transportation fuel or other policies that will have similar outcomes to TCI-P.

Posted on

PJM to Mandate COVID-19 Vaccines

PJM is mandating COVID-19 vaccines for its employees, contractors, vendors and stakeholders working at or attending meetings at the Valley Forge, Pa., campus or to attend RTO events on and off campus beginning Jan. 4.

CEO Manu Asthana made the announcement in a letter sent to stakeholders Nov. 19, laying out a path for the return to in-person meetings on the campus and working procedures for employees.

Stakeholders had argued for months at committee meetings that the RTO should mandate vaccinations for all its employees. They received further updates at the September Operating Committee meeting, with PJM staff saying they were reviewing Occupational Health and Safety Administration (OSHA) rules requiring vaccinations or a weekly negative COVID-19 test for any company with more than 100 employees by consulting the RTO’s legal counsel, its epidemiologist and the executive team. (See “COVID-19 Update,” PJM Operating Committee Briefs: Sept. 10, 2021.)

The 5th U.S. Circuit Court of Appeals, in New Orleans, earlier this month granted an emergency stay prohibiting enforcement of the OSHA rules, with the court saying they raised “grave statutory and constitutional issues.” The 6th Circuit, in Cincinnati, was selected on Nov. 17 to accept legal challenges to the mandate, and the Biden administration filed an emergency court motion on Nov. 23 seeking the reinstatement of the mandate.

Asthana thanked the membership for their cooperation and flexibility in the stakeholder process as the RTO has “navigated our way through the pandemic.”

“At PJM, the safety, security and reliability of the high-voltage electric system and the wellbeing of our employees and stakeholders are paramount,” Asthana said.

Stakeholder Meetings

PJM had said in August that it expected to resume holding in-person stakeholder meetings on the RTO’s campus in the first quarter of 2022, starting with the Members Committee’s and Markets and Reliability Committee’s meetings.

Asthana announced that PJM intends to extend an in-person meeting option in the second quarter of 2022 for the RTO’s standing committees, including the Planning, Market Implementation, Operating and Risk Management committees, as well as senior task force meetings.

Stakeholders will still have a virtual attendance option that has been available since PJM started emergency procedures for the pandemic in March 2020. Members wishing to attend in-person meetings will be required to be vaccinated.

Asthana said the RTO has been looking for locations for its Annual Meeting, but it has been unable to “secure an appropriate venue.” Instead, PJM will hold the meeting at its Conference and Training Center in Valley Forge to conduct necessary business in May, including the election of the Board of Managers, and then hold an event in the fall for “social and leisure activities.”

The Annual Meeting will start May 17 with the MC meeting, the board election and the general session. The following day will feature PJM board meetings with the Transmission Owners Agreement-Administrative Committee, the Public Interest and Environmental Organizations User Group, and the Organization of PJM States Inc. board of directors.

PJM Employees

Asthana also said PJM employees could resume business travel, which has been restricted since January 2020, in the first quarter, provided the employee is vaccinated.

In-person operator training will also resume next year with the spring PJM operator seminar running from March 7 to May 13. Asthana said details regarding the start of other in-person training seminars will be announced in the future.

When asked if there will there be any medical or religious exemptions provided to employees who do not take the vaccine, PJM spokeswoman Susan Buehler said the RTO is allowing for medical and “sincerely held religious exemptions” for employees. Buehler said the exemptions will be handled individually on a case-by-case basis.

A “majority” of PJM employees have already been vaccinated, Buehler said, and the RTO is working with unvaccinated employees to “provide flexibility and alternative jobs” if it is possible. She said the vaccine mandate does not apply to PJM employees working remotely 100% of the time.

Buehler said PJM has not been influenced by the federal court cases regarding the OSHA mandates and plans on holding to the Jan. 4 timeline.

“PJM is most concerned about the safety of the grid, the safety of employees and those who come on our campuses,” Buehler said.

Posted on

Conn. Environmental Advocates Urge Continued Commitment to TCI-P

Environmental advocates from across Connecticut have vowed to maintain pressure on Gov. Ned Lamont and the General Assembly to pass legislation that would enable state participation in the Transportation and Climate Initiative Program (TCI-P).

A dozen advocates co-signed a statement urging passage of the program, which would institute a declining cap on allowable carbon emissions from gasoline and diesel fuel sold and require suppliers to purchase carbon allowances at auction.

Those allowances would generate hundreds of millions of dollars during a 10-year period starting in 2023, which the state would reinvest in programs and infrastructure that reduce transportation emissions. The emissions cap would reduce carbon emissions from on-road transportation by at least 26% through 2032.

Lamont’s latest decision to pause the pursuit of TCI-P has affected the region as well. Massachusetts Gov. Charlie Baker and Rhode Island Gov. Dan McKee announced that their states would back away from the program, which all three states and DC signed a memorandum of understanding to join in December 2020. 

Advocates said walking away from TCI-P should not be an option.

“Pulling their support for TCI was a short-sighted move by the Lamont administration, which kicks the can even further down the road on addressing carbon pollution,” said Louis Rosado Burch, Connecticut program director at Citizens Campaign for the Environment. “Connecticut residents want bold leadership from their elected leaders. TCI is a necessity, not a luxury to be put on the shelf for another day.”

Acadia Center and its partners in Connecticut’s Transportation Future coalition maintain that businesses, mayors, community leaders and public health professionals support TCI-P and its economic, public health and climate benefits, said Amy McLean, Acadia Center’s Connecticut director and senior policy advocate. 

“Environmental justice leaders have worked closely with state agencies and the legislature to center equity and transportation justice in Connecticut’s implementation of the TCI,” McLean said. “While Gov. Lamont appears content to press pause on that important work, we are committed to moving it forward.”

Off Target

Another advocate added that Connecticut is at a crossroads. Charles Rothenberger, climate and energy attorney at Save the Sound, said it has been more than two months since the Department of Energy and Environmental Protection (DEEP) announced Connecticut is not on track to meet its statutory 2030 and 2050 economy-wide reduction targets.

The Connecticut Greenhouse Gas Emissions Inventory, which tracks progress on emissions targets, shows that the state emitted 42.2 million metric tons of carbon dioxide equivalent in 2018, the most recent year that data are available. That is 2.9% higher than the state’s 2020 emissions goal and a 2.7% increase from the 2017 inventory. Transportation emissions, at 15.8 million metric tons, exceeded the combined emissions of the electricity and residential sectors and have been rising since 1990 despite improvements in fuel economy. In addition, vehicle miles traveled have increased faster, further increasing emissions. (See Conn. Falls Behind on Mandated Emissions Targets, GHG Inventory Finds.)

The inventory makes two recommendations that would require action from lawmakers in the General Assembly: Adopting California emission standards for buses, light commercial trucks, single-unit short-haul trucks and similar vehicles; and implementing TCI-P. This spring, a bill to enable TCI-P made it out of the General Assembly’s Environment Committee but did not reach a full vote. Calls to include TCI-P in a special session never came to fruition.

“Our leaders need to step up to the plate and show the same urgency in their policies that they’ve shown in their rhetoric,” Rothenberger said. “The cost of inaction is too steep.”

‘Powerful’ Opposition

Last week, Lamont cited rising gas prices as an obstacle to enabling TCI-P legislation, saying the policy would be “a pretty tough rock to push” through the General Assembly. (See Lamont’s TCI-P Reversal Surprises Environmental Advocates, Lawmakers.)

“We are up against the richest and most powerful industries in the world in the fight against climate change,” said Megan Macomber, policy advocate for the Connecticut League of Conservation Voters. “The pushback on TCI shows us how loud these fossil fuel industries can be, but they do not represent the will of the majority.”

Republican lawmakers and gasoline trade associations labeled TCI-P as a “gas tax” in the form of potential pass-down costs from fuel suppliers to consumers.

DEEP analysis shows participation could boost gas prices by 5 cents/gallon beginning in 2023, assuming fuel suppliers will pass down 100% of allowance costs to consumers. Multiple consumer protection safeguards, including a cost-containment reserve, would kick in at 9 cents/gallon.

Opponents said the 5- to 9-cent increase applies to the first year of TCI-P alone, with prices potentially rising by as much as 26 cents.

Macomber added that a poll by Langer Research Associates showed that 78% of respondents ages 18-29 said climate change is a severe problem that needs to be addressed. 

“Major climate programs like TCI must not fall victim to in-party fighting or be used to leverage political agendas,” Macomber said. “With 2022 elections on the horizon, elected officials should double down on their efforts to reduce fossil fuel emissions, not shy away from the fight.” 

Posted on

Interior Greenlights South Fork Wind Project COP

The U.S. Department of the Interior on Wednesday approved the construction and operations plan for the 132-MW South Fork Wind Project being built for the Long Island Power Authority, the second major offshore wind project in the country to move forward following the July permitting of Vineyard Wind.

“We have no time to waste in cultivating and investing in a clean energy economy that can sustain us for generations,” Interior Secretary Deb Haaland said in a statement. “Just one year ago, there were no large-scale offshore wind projects approved in the federal waters of the United States. Today there are two, with several more on the horizon.”

A joint venture between Ørsted and Eversource Energy (NYSE:ES), South Fork will be located approximately 19 miles southeast of Block Island, R.I., and 35 miles east of Montauk Point, N.Y.

“New York state is facing the challenges of climate change head-on, and we thank the Biden-Harris administration for their steadfast support,” Gov. Kathy Hochul said in a statement. “With today’s permitting milestone, South Fork Wind is set to be New York’s historic first offshore wind farm providing clean energy where it is needed most. Our nation-leading climate and offshore wind goals demand bold action, and moving South Fork Wind forward brings us closer to a cleaner and greener future.”

Interior’s approval of South Fork’s plan to install 12 or fewer turbines is conditioned on several measures to avoid, minimize and mitigate potential impacts. Prior to construction, the developer must submit to Interior’s Bureau of Ocean Energy Management a facility design report and a fabrication and installation report.

The Environmental & Energy Law Program at Harvard University forecast that BOEM’s final approval might indicate how the agency “will address the concerns of the fishing industry when considering alternatives, mitigation measures and cumulative impacts under the National Environmental Policy Act.”

Fishermen, environmentalists, labor unions and local residents broadly support the project, but some opponents have filed suits in state courts to have its power purchase agreements nullified. (See BOEM Hears Public Support for South Fork OSW.)

Newsday reported Wednesday that the nonprofit Government Justice Center filed a lawsuit in New York State Supreme Court in Suffolk County on behalf of two Long Island ratepayers alleging that the Long Island Power Authority ignored its own criteria for power production resources in entering into a contract for the South Fork Wind Farm. The suit called the project’s power unreliable “because it depends on an intermittent resource to generate electricity.”

The main point in the September 2021 complaint signed by Wainscott resident Simon V. Kinsella, however, was price, not reliability. The PPA pays 22 cents/kWh versus the 8 cents being paid to the neighboring Sunrise Wind Project, the complaint said.

The request for proposals “was a manipulated, noncompetitive solicitation,” Kinsella argued, in which the company administering the procurement, PSEG Long Island, awarded a contract to its existing business partner, Deepwater Wind, at a rate that exceeded the market rate by 53% at the time. Deepwater Wind was the original developer of the South Fork project.

The complaint also alleges that then-Gov. Andrew Cuomo inappropriately interfered with the procurement process earlier this year by pressuring the LIPA Board of Trustees, the majority of whom were appointed by him, to approve a contract for $1.6 billion, which they did on Jan. 25.

The project’s “gross profit (excluding operations and maintenance) is $885 million, representing 120% of the cost ($740 million),” the complaint said.

LIPA determined that the totality of South Fork’s benefits outweighed the variable nature of wind power, spokesman Andrew Berger told RTO Insider.

“As part of the solicitation for resources, the South Fork Wind project was paired with transmission, battery storage and demand response. Thus, the awarded portfolio of projects produced more benefits to customers than the alternatives,” Berger said. “As with all LIPA contracts, the procurement was also independently reviewed and approved by the New York attorney general’s office and the state comptroller’s office.”

LIPA also pointed out that larger projects such as Sunrise Wind, able to spread fixed costs over greater energy production, have lower per-unit costs than smaller projects.