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November 5, 2024

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Experts Talk Carbon Markets at Ontario Energy Conference

Canada has had a price on carbon pollution at the federal, provincial and territorial levels since 2019, but it’s not a perfect system, says Lisa DeMarco, senior partner and CEO of Canadian law firm Resilient.

Carbon pricing in Canada, which reflects the country’s constitutional, federalist structure, is “strange,” DeMarco said during the annual Association of Power Producers of Ontario (APPrO) energy and networking conference on Tuesday.

In what is supposed to be a flexible approach, a province or territory can design its pricing system or choose the federal pricing system. However, the federal government sets benchmark stringency standards that any carbon pricing scheme must meet to ensure it is comparable and effective in reducing emissions. If a province or territory decides not to price pollution or proposes a system that does not meet these standards, the federal system is implemented for consistency and fairness.

The federal price has two parts: a regulatory charge on fossil fuels such as gasoline and natural gas, known as the fuel charge, and a performance-based system for industries, known as the Output-Based Pricing System.

Provinces challenged the constitutionality of the federal system, but Canada’s Supreme Court upheld the government’s ability to set minimum national standards for carbon pricing.

Canada is covered entirely by various forms of carbon pricing. In New England, carbon pricing is a political hot potato. However, its high-profile advocates include ISO-NE CEO Gordon van Welie; U.S. Sen. Sheldon Whitehouse (D-R.I.); and New England Power Generators Association President Dan Dolan, who spoke at an APPrO panel on Monday.

With the looming elimination of the minimum offer price rule and a glut of state-sponsored resources entering the market, Dolan said the question is, “How does the market evolve?” New England has aggressive decarbonization and net-zero targets, driven by Massachusetts and Connecticut, which represent more than 80% of GDP and electricity load, Dolan said. Transportation represents the bulk of emissions in New England, twice the amount of any other sector in the economy and “the only one that has actually gone up,” Dolan said.

Power plant emissions, he added, have “fallen off a cliff” for New England, and now the region has “one of the cleanest fleets” in the country.

“Yet that is continuing to [be] where we see more focus put, in large part, because of political expediency,” Dolan said. “But how we then break that curve on the transportation side and bring in heating is going to be key to the overall foundation of where we can power this economy moving forward.”

Crossing the Border

In July, the Canadian government said its carbon price will increase by $15 per year after 2022 until it reaches $170/ton in 2030. However, that could lead to disparities with international trading partners, including the U.S. As a result, Canada is exploring Border Carbon Adjustments (BCAs), which account for differing carbon costs incurred in producing internationally traded goods.

BCAs could include import charges applied to goods from countries that do not have carbon pricing or use a lower carbon price to ensure that they face similar carbon costs. Export rebates can also be provided so that domestically produced goods compete on equal footing in foreign markets, alongside goods from countries with limited or no carbon pricing.

BCAs are not high on the policy docket at the moment, said Mitchell Davidson, executive director of Canada’s StrategyCorp Institute of Public Policy and Economy. The last thing that Canadian Prime Minister Justin Trudeau wants to do “is make things more expensive, even if it’s already doing that in some capacity with carbon pricing,” Davidson said.

Moreover, he said, the additional level of tariffs that would come with BCAs amid rising prices and supply chain issues make it “a low likelihood” for any immediate action.

“Although in the future it is certainly something that the government could seriously consider,” Davidson said of BCAs.

The better policy, said Scotty Greenwood, managing director of Crestview Strategy in Washington, is to have a “North American approach” for energy pricing and carbon transition.

“I think that is more productive to think about how we do that than trying to look at how we compete on something like carbon,” Greenwood said.

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Stark Choice for Va. Regulators on Shared-solar ‘Minimum Bill’

The Virginia State Corporation Commission faces a stark choice in setting the minimum charge for customers who subscribe to shared solar projects.

Dominion Energy (NYSE:D) has proposed a charge of more than $75/month, saying anything less than that would result in cost shifts to nonparticipating customers. But commission staff, legislators and the Virginia Department of Energy have joined solar advocates in expressing concern that Dominion’s proposed charge is so high it could smother the shared-solar concept in its cradle.

Expected to launch in July 2023, the shared-solar program would allow apartment dwellers and those in homes unsuitable for rooftop solar to offset part of their electric bills by purchasing a share of solar projects remote from their homes. Solar advocates said the “minimum bill” — after accounting for all bill credits — should be 1/10 of what Dominion proposed.

“The high amount proposed by Dominion … may have a significant inhibiting effect on customer acquisition,” the Department of Energy said in filed comments (PUR-2020-00125).

Dominion’s proposal also drew a backlash from the authors of the legislation establishing the shared-solar program, which was enacted last year (HB 1634/SB 629).  

“We believe Dominion’s proposed minimum bill is too high for the program to function as intended,” Sen. Scott Surovell (D) and Del. Jay Jones (D) wrote in an April 29 letter to the commission. “Prior to the passage of this legislation, Dominion Energy attempted to create a community solar pilot program with a minimum bill amount that we understand is similar to the current proposal. The pilot program did not work with a similar amount and we do not believe the program will work this time if the current proposal is enacted.”

Dominion’s April 1 proposal said that a residential customer who consumes 1,000 kWh of power should receive a minimum bill of $74.90 (distribution service charges: $29.45; transmission service charges: $20.29; generation balancing service charges: $25.16), not including administrative overhead costs, which it estimated at $10 to $20/month per customer.

Commission staff warned such administrative costs could push the bill to almost $95/month. It proposed an alternative fee of $10.95/month, which excludes transmission and distribution charges, or $55.10/month, which includes them.

“Staff believes that, ultimately, the determination of the appropriate minimum bill is a policy question for the commission’s determination,” David Dalton, principal utilities analyst with the commission’s Division of Public Utility Regulation, testified in a Nov. 18 hearing on the matter.

Staff said the commission must make a policy decision because the legislation creating the shared-solar program provided “wide statutory discretion.”

The legislation said the minimum bill “shall include the costs of all utility infrastructure and services used to provide electric service and administrative costs of the shared-solar program” and “minimize the costs shifted to customers not in a shared-solar program.” Low-income customers are exempt from the minimum bill.

Points of Disagreement

Dominion and solar advocates disagree over administrative charges, credit calculations for solar generation, and the impact of shared solar on the utility’s generation and transmission expenses.

In an April 30 filing, the Coalition for Community Solar Access (CCSA) and the Chesapeake Solar & Storage Association (CHESSA) recommended a minimum bill of $7.58/month for residential customers: the basic customer charge (currently $6.58/month) plus $1 for incremental administrative costs. The basic customer charge would be different for other rate classes, ranging from as low as $10 for small general service commercial customers to up to $120 for large general service customers.

Based on Dominion’s estimate that a typical 1,000/kWh residential customer would pay about $117/month for electricity service and supply, “this means that Dominion’s minimum bill proposal of about $75/month would be approximately 64% (nearly two-thirds) of the typical residential customer’s bill,” the solar groups said. “Individual customer savings would be reduced if not eliminated.”

CCSA/CHESSA said the additional $67 in Dominion’s proposal “seems to be entirely calculated by Dominion as the sum of the charges a hypothetical customer might have paid, net of avoided energy costs, if the customer had received no bill credit.”

“Dominion’s assertions about cost shifting … are incorrect and premised on a flawed view of its entitlement to effectively eliminate savings customers may realize by participating in the shared-solar program,” said former Texas regulator Karl Rabago, CCSA’s witness at the Nov. 18 hearing. “Dominion’s approach appears specifically designed to make shared-solar subscription unattractive to potential subscribers and, therefore, renders the shared-solar program unworkable.”

Dominion: Seeking to Prevent Cost Shifts

Dominion argued that its proposed charge is an effort “to mitigate cost shifting to nonparticipating customers.” That was a point attorney Jontille Ray, a partner at McGuireWoods, speaking on behalf of the utility, made repeatedly at the SCC hearing. “It is not meant to discourage participation” in the shared-solar program, she said.

Public comments during the hearing weighed heavily the other way. Jay Epstein, president at Health-E Community Enterprises of Virginia, a solar developer, said Dominion’s proposed minimum rate was much too high. Larry Bright, an Arlington resident who said he owns his own solar-powered home and pays $7/month for access to the grid, said $75/month would put shared solar out of reach “for almost everybody who would be interested.”

Likewise, Dr. Samantha Ahdoot, a pediatrician in Alexandria, speaking on behalf of the American Academy of Pediatrics, said Dominion’s proposal would discourage uptake of the shared-solar program. She talked of recently treating a young girl’s first asthma attack, a condition that is aggravated by air pollution of the kind the shared-solar program intended to alleviate.

There was no ruling at the end of the Nov. 18 hearing. Hearing Examiner Matt Roussy directed the parties to file post-hearing briefs by Jan. 13.

The solar groups said the commission should identify and minimize net program costs to nonparticipants by ordering a full benefit-cost analysis, “more transparent and forward-looking” integrated resource planning, including distribution planning, and more effective delivery of energy efficiency and demand response programs for shared-solar customers.

Threat to Shared Solar?

Dominion’s proposal and the two from staff would include a volumetric component that increases with the customer’s energy use. The solar groups said the charge should be a flat fee, arguing “a simple minimum bill will facilitate customer participation while minimizing potential confusion.”

“Higher costs and risks … would likely render projects nonviable,” they added. “Community solar projects are multimillion-dollar projects for which the return on investment takes many years of a project’s multidecade useful life.”

But Dominion said the impact of the minimum charge on the uptake of shared solar is irrelevant. “The appropriate question for this proceeding is not whether the framework of the minimum bill, established by statute, will be conducive to signing up subscriber organizations for the program, but what costs should be included in the minimum bill and how it should be administered to participating customers,” it said in a response to the solar groups’ comments. “The minimum bill as proposed does not interfere with the creation of shared-solar facilities, and the company believes it is too early in the program to reach this conclusion. Significantly more evidence would be needed to support a finding that the minimum bill proposal renders the program inoperable.”

Six Categories of Charges

Commission staff identified six categories of charges that could be included in the minimum bill: the basic customer charge; non-bypassable charges required by the Virginia Clean Economy Act (VCEA) for the renewable portfolio standard; transmission charges; distribution charges; generation balancing services charges; and administrative charges.

Dominion included all but administrative charges in its $75/month proposal.

“Since the shared-solar program is a couple of years away from implementation, it may be premature to set a specific administrative cost to the subscribers at this time, but the company does anticipate that could be in the $10 to $20/month range,” the company said in response to a question from commission staff. “This monthly rate would be independent of subscription size.”

“It is inconceivable that a prudent utility of Dominion’s size would incur incremental fixed costs, independent of subscription size, as large as $120 to $240 per customer per year for shared-solar billing,” Rabago responded.

“Because utility infrastructure and services costs associated with the operation of the shared-solar generator are recovered through upfront and ongoing interconnection costs assessed on shared-solar facilities, the only remaining administrative costs of the shared-solar program that must be reflected in the minimum bill are the costs incurred by Dominion for apportioning, crediting and billing-shared solar subscribers,” CCSA/CHESSA said.

Staff opposed Dominion’s proposal to set the administrative charges when the company files the tariff pages for the shared-solar program. “Staff believes that it is appropriate for the administrative charges to be subject to a formal petition, investigation, litigation and a finding of fact as to their reasonableness rather than proposed and reviewed informally after the commission’s issuance of an order in this case,” the SCC’s Dalton testified.

Dominion said CCSA and CHESSA “appear to use the basic customer charge as a proxy to account for all delivery charges and generation balancing service charges that must be recovered from customers to successfully support the shared-solar program, but the basic customer charge does not account for all costs of supporting the program.”

Commission staff said the CCSA/CHESSA proposal does not include any non-bypassable charges required by the VCEA.

Dalton said staff concluded Dominion’s proposal “appears to include some level of generation in excess of the non-bypassable charges” while leaving it to the commission to determine if recovery of such costs is appropriate.

Staff’s proposed $10.95 monthly fee incorporates the non-bypassable fees and also adopts the solar advocates’ proposed $1/month charge as a placeholder for administrative costs pending an evidentiary proceeding.

Staff’s $55.10/month option includes $49.74/month for transmission and distribution charges — a response to the company’s assertion that shared-solar subscribers will continue using the utility’s transmission and distribution infrastructure in the delivery of their electricity.

Different than Net-metered Solar

Dominion said shared-solar subscribers must be distinguished from net-metering customers who generate power behind their own meter.

“The [shared-solar] generation is not serving any of the customer’s load directly in real time … and, because of the nature of solar generation, does not cover the customer’s load whenever the solar facility is not generating (e.g., night, cloudy days, when the facility is down for repair or maintenance),” Dominion said. “Thus, at all times, the company is providing generation service to the participating customer.”

Rabago and the solar groups counter that Dominion failed to recognize the value of shared solar to Dominion’s system. “Fundamentally, shared-solar subscribers are supporting the construction and operation of clean, distributed solar generation. As such, they supplement and offset costs that the general body of customers would otherwise have to pay to support Virginia’s clean energy transition,” Rabago testified. “Shared-solar subscribers are frontline volunteers, mitigating costs that Dominion would otherwise incur to develop solar to meet the requirements of the Virginia Clean Economy Act and the renewable portfolio standard and which Dominion has not accounted for.”

The utility also ignored the locational value of solar sites, the groups said.

“Even in the near term, shared-solar generation can be injected into the grid at or near distribution load, providing transmission and distribution system savings that Dominion has not accounted for,” Rabago said. “Exported energy from shared-solar facilities does not physically travel to the homes of shared-solar subscribers. That energy will serve the nearest unserved load and will pass through a revenue meter when it does so. That service will generate full retail billings by Dominion, but without incurring the total system costs that drive Dominion’s cost of service.”

Rabago testified that the solar groups’ proposal would add about $25 million in costs to nonparticipants — adding about 35 cents/month for a 1,000-kWh/month user.

“Dominion has not performed and does not possess any research, analysis or other material on distributed generation that would be installed under the shared-solar program as [it] relates to the Virginia Clean Economy Act, the renewable portfolio standard or Virginia’s participation in the Regional Greenhouse Gas Initiative, and has conducted no evaluation of how the shared-solar program would impact its integrated resource planning process and plans,” Rabago said.

Crediting Calculation

Solar advocates also challenged Dominion’s proposal over how to calculate the bill credit that shared-solar subscribers should receive.

CCSA called for use of U.S. Energy Information Administration data, which it said justified a credit of 12.06 cents/kWh. Dominion proposed using data from FERC Form 1, which it said would amount to a credit of 11.765 cents/kWh.

Commission staff agreed, noting that Form 1 is already used by the commission in its multifamily shared-solar program.

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NECEC Halts Tx Line Construction, Regulators Suspend Env. Permit

In a fast-moving series of recent events surrounding the New England Clean Energy Connect (NECEC) transmission line, the project’s developer halted line construction and Maine regulators suspended its environmental permit.

The Maine Department of Environmental Protection issued a suspension order on Nov. 23 for the permit it granted last year authorizing construction of the line.

In the order, the DEP said that “all construction must stop.” NECEC Transmission, however, had announced on Nov. 19 that it is discontinuing construction while it challenges the legal authority of a referendum on transmission development passed by voters earlier in the month.

Gov. Janet Mills certified the referendum vote in a Nov. 19 proclamation and immediately sent a letter to NECEC Transmission CEO Thorn Dickenson asking that the company stop construction.

NECEC’s decision to continue work on the line without further legal clarity, she said, “is disrespectful to Maine people.”

The referendum authorizes a statutory change requiring legislators to approve high-voltage transmission lines greater than 50 miles that are not necessary for reliability purposes.

Suspension

While the DEP’s May 2020 permit allowed NECEC to start building the line, a Maine court in August reversed a Bureau of Parks and Lands decision to lease a 1-mile corridor to the company for the project.

The court’s ruling prompted DEP Commissioner Melanie Loyzim to launch a permit suspension proceeding, saying the ruling represented a “change in circumstance.”

In early November, the facts before the DEP for the suspension proceeding changed after voters approved the transmission-related referendum. The DEP then proceeded to seek additional input from parties to the proceeding regarding the referendum and scheduled a hearing for Nov. 22.

The referendum, NECEC argued during the hearing, does not represent a change in circumstance requiring permit suspension because there will be no environmental impact while work is stopped on the line.

Loyzim, however, determined that because of the statutory changes approved in the referendum, NECEC will not be able to construct the line as permitted, and it will need to find a new project route.

“The law would ban construction of any transmission line defined as a ‘high-impact transmission line’ in the Upper Kennebec Region,” where NECEC is sited now, the order said.

The DEP’s suspension order will remain in effect unless the court grants NECEC’s request to continue construction while it challenges both the referendum and the BPL corridor decision.

Despite DEP’s suspension order, Iberdrola remains committed to developing the line, Dickenson said in a Nov. 23 statement.

Mills reinforced her ongoing support for the project in her Nov. 19 letter to NECEC, saying the line “will usher in substantial environmental and economic benefits for Maine.”

“But more than any single policy or project, I support the rule of law that governs our society and the will of the people that informs it,” she said.

Legislators’ Plea

Members of the Maine State Senate and House of Representatives urged Massachusetts Gov. Charlie Baker in a Nov. 23 letter to terminate the NECEC project.

NECEC would supply hydropower from Hydro-Québec to the New England grid through a 20-year supply agreement with Massachusetts utilities.

“As a bipartisan group of lawmakers representing regions throughout Maine, we discourage Massachusetts from proceeding with this project after the people of Maine delivered a stunning rebuke of the NECEC,” the letter said.

The state’s utilities, the group said, received other bids as part of its clean energy generation request for proposals, and they should “move on” from NECEC.

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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.

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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.”

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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.”

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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.

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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.

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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.)

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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.