Search
`
November 9, 2024

Posted on

Biden 2023 Budget Includes Billions for Clean Energy, GHG Reductions

President Joe Biden’s $5.8 trillion federal budget request for 2023 contains a raft of line items aimed at cutting greenhouse gas emissions, advancing clean energy research and deployments, and propping up the nation’s energy security.

The budget rollout on Monday included announcements from the Department of Energy, the Environmental Protection Agency and the Bureau of Ocean Energy Management detailing the federal dollars for energy and climate projects that are included in their budget requests.

The tax credits and other incentives for clean energy development contained in the failed Build Back Better Bill are not specifically listed in the budget, but, according to a report from Bloomberg, will be included in a placeholder “deficit-neutral reserve fund.”

DOE

The DOE announced a $48.2 billion budget request for 2023 — a $2 billion increase over the $46.2 billion requested in 2022 — with significant clean energy investments but a strong focus on national security. Specifically, close to half of the 2023 budget, $21.4 billion, is earmarked for the National Nuclear Security Administration “to make necessary investments to maintain a safe, secure and effective nuclear weapons stockpile,” according to the DOE’s announcement.

The department is also asking for $202 million for the Office of Cybersecurity, Energy Security and Emergency Response to address cybersecurity risks.

On the energy side, the request focuses heavily on energy efficiency and clean energy research and development. “The investments reflected in this latest budget will cut costs for Americans and secure our energy independence on our path towards a net-zero future,” Energy Secretary Jennifer Granholm said in the announcement.

The budget request includes the following clean energy spending:

  • $502 million to weatherize at least 50,000 homes, including $100 million to retrofit and decarbonize low-income households, installing energy-efficient appliances and systems to cut energy bills. Another $105 million in grants will go to states to help them create “more reliable and affordable clean energy systems.”
  • $200 million “to bolster the U.S. supply chain for solar energy technologies through a new Solar Manufacturing Accelerator.” Another $18 million will go toward building international partnerships to “bolster secure supply chains and expand economic opportunities.”
  • Other supply chain spending includes $5 billion for the Loan Programs Office for investments that will support domestic supply chains for critical minerals.
  • $4 billion “to accelerate research, development, demonstration and deployment of technology and solutions to cut energy costs through low-cost clean energy resources.”
  • Another $7.8 billion is slated to support research at the DOE’s national labs and at universities across the country “to accelerate novel technologies for clean energy solutions to mitigate climate change.”

EPA

EPA Administrator Michael Regan said the budget includes “historic investments” in support of the agency’s FY 2022-2026 Strategic Plan, “including tackling the climate crisis, advancing environmental justice, protecting air quality, upgrading the nation’s aging water infrastructure and rebuilding core functions at the agency.”

“For the first time, EPA’s final [Strategic] Plan includes a strategic goal focused exclusively on addressing climate change, as well as an unprecedented strategic goal to advance environmental justice and civil rights,” EPA said. “At the foundation of the plan is a renewed commitment to the three principles articulated by EPA’s first Administrator, William Ruckelshaus — follow the science, follow the law, and be transparent – while adding an additional fourth principle: advance justice and equity.”

In addition to $4 billion to upgrade drinking water and wastewater infrastructure, the plan includes:

  • $1.1 billion to improve air quality, reduce localized pollution and exposure to radiation, and improve indoor air quality;
  • $100 million in grants to tribes and states to support greenhouse gas reductions and increased resilience;
  • $35 million to implement the American Innovation in Manufacturing Act to phase out hydrofluorocarbons, a greenhouse gas; and
  • $13 million in wildfire prevention and readiness.

In support of Biden’s Justice40 commitment to ensure at least 40% of federal investments in climate and clean energy benefit historically overburdened and underserved communities, EPA would spend $1.45 billion to “create good-paying jobs, clean up pollution, advance racial equity and secure environmental justice,” Regan said. EPA has proposed creation of an environmental justice program office to oversee the effort.

To “rebuild the agency’s capacity” following cuts under the Trump administration, the spending plan would also fund more than 1,900 new full-time equivalents, boosting EPA’s staffing to more than 16,200 FTEs.

BOEM 

The Interior Department’s Bureau of Ocean Energy Management would receive $237.4 million in funding, including $51.7 million for BOEM’s renewable energy program, which is supporting the administration’s goal of deploying 30 GW of offshore wind energy capacity by 2030.

BOEM’s conventional energy program, supporting oil and gas leasing, would receive $63.6 million, while its marine minerals program would get $15.4 million to help procure sand and sediment for coastal restoration.

The budget includes $86.4 million to fund BOEM’s environmental analyses.

BOEM plans to issue nine environmental reviews of offshore wind projects in FY 2023 and to hold up to three lease sales in FY 2022 and up to two lease sales in FY 2023.

Posted on

FERC Rebuffs PJM Monitor in Accepting Kestrel Market Power Analysis

FERC on Thursday accepted Kestrel Acquisition’s updated market power analysis as partially compliant with the commission’s standards for market-based rate authority (MBRA), and directed the PJM generation owner to submit a further compliance filing within 30 days (ER18-1106-002).

In doing so, FERC rejected a protest by PJM’s Independent Market Monitor, which said that “current PJM market rules for market power mitigation are insufficient to support [market-based rate] authorizations.”

The commission said the Monitor failed “to submit any specific evidence … demonstrating that Kestrel Acquisition has market power.” Rather, the Monitor’s protest was directed at PJM’s rules and not Kestrel’s analysis itself.

“In granting market-based rate authority, the commission does not certify markets as competitive; it determines whether individual sellers have market power,” FERC said. “Here, IMM makes no attempt to show that PJM’s monitoring and existing market power mitigation provisions would fail to mitigate any market power possessed by Kestrel Acquisition.”

The Monitor argued that Kestrel’s MBRA should be conditioned on offering into the energy and capacity markets at cost-based offers. But FERC said that “many of the allegations in IMM’s protest apply to all sellers in PJM, including those that are not part of the protested proceedings. Such sellers have not been given adequate notice and opportunity to comment on IMM’s proposal.”

FERC noted that the Monitor’s criticism of PJM’s capacity market echo those made in a separate complaint, in which the commission approved its proposal to conduct a unit-specific review of all offers in the capacity market. It is also conducting a review the RTO’s rules on parameter-limited offers. “We believe that proceeding, which will provide all sellers in PJM the opportunity to intervene and participate, is the appropriate forum to consider changes to the relevant PJM mitigation rules,” it said.

Kestrel owns the 810-MW Hunterstown Generating Station combined cycle gas-fired power plant located in Gettysburg, Pa.

Commissioner James Danly concurred in a separate statement to highlight that the Monitor’s “concerns in this case would properly be rejected even if the commission had not recently ordered PJM to adopt” the Monitor’s unit-specific proposal.

“I opposed unit-specific review of all offers because doing so likely will result in over-mitigation,” Danly said. “Unit-specific review is not required to adequately mitigate market power concerns, and today’s order in no way indicates otherwise.”

Posted on

SPP’s Consolidated Tx Planning Just Beginning

Leaders of an SPP task force charged with designing and developing a consolidated transmission planning process and associated cost-sharing mechanism said last week they will wait until the generator interconnection queue’s backlog has been cleared before building the models for the process.

Staff told the Seams Advisory Group Wednesday that they expect it will take two years to get consolidated planning processes approved, with the first study being produced in 2026 at the earliest.

“We want to get queue clear before beginning the consolidated process,” SPP’s Kelsey Allen said. “It’s very hard to coordinate across the various study processes.”

The RTO’s queue backlog dates to 2017 and includes nearly 100 GW of IC requests, as of November. Renewables and storage account for all the potential projects, with a bit more than 6 GW of thermal requests. FERC in January approved SPP’s plan to clean up the backlog by 2024. (See “GI Backlog Plan Approved,” FERC Denies Co-ops’ $79M Complaint vs. SPP.)

The Consolidated Planning Process Task Force, created last year by the SPP board, has held a couple of education sessions and laid out a high-level work plan, said SPP’s Sunny Raheem, who is chairing the task force. Over the next few years, he said, the group plans to write as many policies as it can and build out technical requirements.

The task force will coordinate with and gather input from affected stakeholder groups in proposing methodologies, approaches, assumptions, parameters, criteria, data requirements and/or outcomes for successful consolidated planning design, implementation and approval.

“Sounds like job security to me,” joked American Electric Power’s Jim Jacoby, the SAG’s chair.

The meeting was the first in-person stakeholder meeting at SPP’s corporate campus in Little Rock, Ark., since the onset of the pandemic.

SPP, MISO to Set Joint Stakeholder Meetings

SPP and MISO staff are planning a series of stakeholder meetings over the next four to six months as they work on a cost-allocation methodology for their joint targeted interconnection queue (JTIQ) study.

The final study report is comprised of seven projects at a total cost of about $1.65 billion. If approved, the projects are projected to resolve 48 reliability constraints and deliver about $724 million in adjusted production costs savings to MISO and $247 million to SPP. (See MISO, SPP Finalize JTIQ Results with MISO Tx Duplicates.)

However, MISO has included two of those projects in its first tranche of long-range transmission projects, raising questions about how that affects the JTIQ’s portfolio.

“That’s one of the first things we have to work out in the upcoming stakeholder meetings,” SPP’s Neil Robertson said. “It does change the complexion of how cost allocation will be approached. …That was one of the primary objectives of [the JTIQ study].”

The stakeholder meetings are expected to be scheduled later this week.

SPP’s M2M Settlements Exceed $250M

SPP accrued almost $7.9 million in market-to-market (M2M) settlements from MISO during January, staff told the SAG, pushing the amount MISO owes its neighbor for congestion to nearly $255 million.

Permanent and temporary flowgates were binding for 1,812 hours during the month. The two grid operators exchange settlements for redispatch based on the non-monitoring RTO’s market flow in relation to firm-flow entitlements.

It was the 11th straight month M2M settlements have accrued in SPP’s favor, and the 26th time in the last 28 months. The grid operators began the process in March 2015.

Posted on

California Auditor Criticizes Wildfire Oversight of IOUs

The two California state entities that oversee investor-owned utility wildfire prevention programs need to exercise their authority more effectively to limit ignitions and public safety power shutoffs, the State Auditor said in a report published Thursday.

The California Public Utilities Commission and the recently formed Office of Energy Infrastructure Safety have fallen short in both regards, Acting State Auditor Michael Tilden said in his report to the state Legislature and Gov. Gavin Newsom.

The CPUC and Energy Safety Office share oversight of the wildfire prevention activities and performance of the state’s IOUs, including Pacific Gas and Electric, Southern California Edison and San Diego Gas & Electric.

The Energy Safety Office accepted utility wildfire mitigation plans despite serious deficiencies and did not ensure proposed improvements were in high-fire threat areas, Tilden wrote.

“The office approved plans despite some utilities’ failure to demonstrate that they are appropriately prioritizing their mitigation activities, and subsequent reviews have found that some utilities failed to focus their efforts in high fire-threat areas,” he said.

The CPUC, which audits utilities to determine if they comply with safety rules, “did not audit all utility service territories on a consistent basis, did not audit several areas that include high fire-threat areas, and has not used its authority to penalize utilities when its audits uncover violations,” he said.

Six of the state’s 20 most catastrophic fires since 2015 were started by utility equipment, Tilden noted. To prevent ignition, IOUs initiated 67 shutoffs from 2013 to 2021, affecting 3.6 million customers, he said.

Utilities have been making improvements, including undergrounding power lines and replacing bare wires with covered conductor, but they have hardened only about 1,500 miles of the estimated 40,000 miles of bare lines in high-threat fire areas, Tilden noted.

“As a result, the state must prioritize the areas utilities need to address first,” he wrote.

Among his recommendations is bolstering a state law that took effect in January requiring utilities to identify line sections that are regularly de-energized to prevent ignitions during dry windy conditions.

“The state could strengthen this law by requiring utilities to identify what is necessary to prevent future power shutoffs if the conditions leading to those shutoffs were to occur again, and to address a type of power outage caused by altering equipment settings [to trigger fast shutoffs] that led to more than 600 unplanned power outages in 2021,” he said.

The CPUC said in a statement that it is “committed to the continuous improvement of its operations. Accordingly, the CPUC will establish a plan and timelines toward implementing the recommendations identified in the California State Auditor’s report.”

Its detailed responses to the audit, along with the responses of the Energy Safety Office, are included with the report.

The commission agreed, for example, that it needs to take a more risk-based approach to its utility audits but disagreed partly with a recommendation for penalizing underperforming utilities.

The Energy Safety Office defended its record, saying the complex process of promoting a safer grid would take time, but agreed that utilities need to “move faster and be smarter” in their fire prevention efforts.

“Utilities will not get ahead of their wildfire risk until they reimagine how they build, operate, and manage their infrastructure,” Director Caroline Thomas Jacobs wrote.

“Energy Safety is committed to driving timely, meaningful and effective changes to the way California’s electrical corporations build, operate and maintain their infrastructure,” she said. “Energy Safety will continue to challenge them, question them and demand continuous improvements to safety.”

Posted on

FERC Partially Grants Challenges to AEP Transmission Rates

FERC last week partially granted four cooperatives’ challenge of American Electric Power (NASDAQ:AEP) companies’ annual update for transmission formula rate charges under the SPP tariff (ER18-194).

The commission agreed with several of the co-ops’ complaints but also rejected others. It ordered AEP to make a compliance filing within 60 days.

The proceeding stems from a formal challenge by East Texas Electric Cooperative, Northeast Texas Electric Cooperative, Arkansas Electric Cooperative Corp. and Golden Spread Electric Cooperative of AEP’s annual informational filings in 2020 on behalf of its Southwestern Electric Power Co. and Public Service Company of Oklahoma (PSO) affiliates. The filing detailed the true-up calculations of charges for the 2019 rate year under the companies’ respective transmission formula rates.

In a settlement approved by FERC in 2019, the AEP rates transitioned from a historical formula rate to a forward-looking formula rate and removed directly assignable transmission costs related to generation.

The cooperatives claimed that in the new formula rates, AEP improperly:

    • included regulatory commission fees in one account;
    • accounted for capital lease interest expense;
    • included coal-mining assets;
    • included non-utility railcar facilities;
    • included prepayments for tax credits that were sold;
    • failed to include all unfunded reserves;
    • included accumulated deferred income taxes (ADIT) related to accumulated accruals recovered through rates without including the reserves; and
    • included ADIT related to rate refunds.

FERC disagreed with AEP’s argument that the co-ops’ challenge sought to undermine the settlement process by raising the same issues addressed through the settlement, saying the pertinent issue was whether AEP properly implemented the 2019 rate year formula. The commission agreed with the co-ops that the settlement did not bar future challenges to unfunded reserves and regulatory fees included in the 2019 rate year, finding that they were eligible for inclusion in the challenge, along with whether certain tax credits qualifying as prepayment.

The commission granted the challenge to the proper accounting of regulatory fees, finding they were not taxes. They directed AEP to include in its compliance filing the calculations reflecting the fees’ inclusion and to refund with interest the amounts improperly collected for the 2019 rate year.

FERC also accepted the challenges to capital lease interest expense, the ADIT related to the accumulated reserve accruals for employee benefit costs and the ADIT related to rate refunds.

The commission ordered AEP to refund with interest on all amounts improperly collected for the 2019 rate year and that the refunds be reflected as adjustments in the next rate year’s annual update. It said AEP had not justified why including the ADIT balance in the 2019 rate year’s rate base is appropriate given the ratemaking treatment of the associated accrued reserves. AEP also failed to address whether the ADIT related to rate refunds should be included in rate base when the underlying refund amounts associated with the ADIT are excluded from rate base, FERC said.

The commission, however, denied the challenge to the proper ratemaking treatment for the coal-mining assets and railcar facilities. It found AEP had properly recorded the tax credits at issue, and it also denied the challenge on unfunded reserves associated with contingent liabilities, saying the related employee benefit accounts, except for workers’ compensation, are not considered contingent because PSO knows that it will incur those expenses even if their timing is uncertain.

Posted on

Inslee Partially Vetoes Wash. Siting Council Bill

Washington Gov. Jay Inslee on Friday vetoed a section of a state energy siting council expansion bill that called for a study of the impacts of solar and wind farms on rural areas.

The veto drew criticism from two Republican representatives from rural Eastern Washington, where most of the state’s solar and wind farms have been located. A common complaint from critics of wind and solar farms is that wide-open rural Eastern Washington hosts most of the projects while the electricity produced there goes to heavily populated and forested Western Washington. 

The Democrat-controlled legislature this month passed House Bill 1812, sponsored by Rep Joe Fitzgibbon (D), to take Washington’s Energy Facilities Site Evaluation Council (EFSEC) outside the umbrella of its parent, the Washington Utilities and Transportation Commission, and make it an independent agency. (See Bill to Expand Powers of Wash. Siting Council Passes Senate.)

EFSEC, comprising representatives from several state agencies, makes recommendations to the governor for final decisions on the placement of solar farms, wind turbines and other energy resources.

Under existing regulations, a wind or solar developer opting to seek state approval instead of obtaining county permits can bypass county governments by going through EFSEC. Or a developer can choose to have the appropriate county government handle the permitting, sidestepping EFSEC. 

Besides being an option for wind and solar ventures, the expanded EFSEC will also have jurisdiction over clean energy product manufacturing facilities, renewable natural gas facilities and hydrogen production plants.

The vetoed section of the bill would have required the Washington Department of Commerce to meet with rural stakeholders to prepare cost-benefit reports on renewable projects, including recommendations on how to more equitably distribute costs and benefits of energy projects to rural communities.

In his Friday veto, Inslee wrote that meeting with rural stakeholders is important, but he said that existing studies and meetings are already underway on the issue, including a study on the drawing board by Washington State University. Inslee also wrote that the supplemental budget for fiscal 2023, which begins July 1, 2022, does not include money for the study requested by House Bill 1812. He wrote that the legislature should request such money in its 2023 session. 

On Friday, Reps. Mary Dye (R) and Mark Klicker (R) issued a joint press release condemning the veto. “To say that we are beyond disappointed with the governor’s vetoes is an understatement,” Dye said.

“It is critical for our rural communities and local landowners, especially those in Eastern Washington, to see the big picture of what 30 years of siting utility-scale wind and solar would do to Washington’s rural landscape,” Dye said. “Now that the governor has vetoed these sections, it opens the flood gates for big out-of-state energy corporations to swoop into these small, rural economically-disadvantaged communities and offer leases at a fraction of the value of the agricultural land to struggling farmers and landowners. It’s absolutely devastating to our Eastern Washington farmlands.”

“Those who are living where the green energy is being sited know that the jobs and tax-base impacts have been more salesmanship than substance,” Klicker said. “We asked for a study to show the true costs and benefits, and the governor’s vetoes show we were right to be skeptical. If there was going to be good news about jobs and taxes from these projects, the governor surely would have wanted that documented.”

Dye added: “The governor’s strategy amounts to a hasty build-out of clean energy to serve the Puget Sound without any burden of siting massive wind farms in the Puget Sound view shed. Instead, these facilities will all be sited in our rural counties that have no need for the energy and are already served by clean, affordable hydroelectricity.”

Posted on

Overheard at the NE Electricity Restructuring Roundtable

The New England Electricity Restructuring Roundtable changed gears for its first meeting of the year Friday with a focus on equity.

The roundtable, convened quarterly by Raab Associates, featured discussions on equitably decarbonizing the Northeast, a federal energy update and a case study on a unique partnership north of the border.

How to Decarbonize

A panel of speakers from New England organizations examined greening the region’s energy while ensuring that vulnerable communities are not left behind.

“Whoever has benefited the most in the system as it is should bear the greatest burden as we transition to a new system, and whoever hasn’t received benefits from the system as it is should be at the front of the line,” said Rev. Mariama White-Hammond, chief of environment, energy and open space for the City of Boston.

The panelists tried to define equity, noting that it can have various meanings.

“Equity doesn’t mean equal or the same, and it doesn’t happen by accident,” President of the Northeast Clean Energy Council Joe Curtatone said. “We should all align to a value that leads us with deliberate intention to have impact, especially for those who are impacted the worst.”

Another key to reaching the necessary communities is to ensure funding is available, according to Stephan Roundtree, senior regional director at Vote Solar.

“Part of the challenge I’ve seen in my work is inviting or asking folks with barriers to entry to navigate the really complex world of rebates and program eligibility,” he said, adding that states have an increased responsibility to provide resources and connect people to those resources.

Panelists also addressed the challenge of specific technologies, such as offshore wind, which they said is a valuable decarbonization tool that comes with unique equity challenges.

Raab Roundtable (Raab Associates) Content.jpgA panel of speakers at the virtual Restructuring Roundtable on Friday discussing equitable decarbonization | Raab Associates

“It’s such an important and critical strategy to make a difference for the electricity sector,” said Staci Rubin, vice president for environmental justice at the Conservation Law Foundation.

Offshore wind developers and governments, she said, also need to involve people in the development process who are directly affected by the associated infrastructure.

“I’ve had recent conversations with several tribes who have really not been part of these conversations about offshore wind in a meaningful way,” she said. “We need to make sure that potentially impacted tribes and community organizations are able to have a say in terms of where the infrastructure will go.”

At the federal level, FERC is trying to make sure that it uses its regulatory powers in a way that meets equity goals, powered by the new Office of Public Participation, its director Elin Katz said.

“OPP is designed to provide opportunities for members of the public, and we have a particular focus on landowners, environmental justice communities, citizens of native nations, and consumer advocates and other community organizations,” she said, raising concern about how to bring those voices into FERC.

“We can’t continue to look at policy development as a top-down process that can fairly consider all sides and deliver equitable results if we don’t also include a diversity of voices in the process itself,” she said.

Case in Point

A powerful example of the way conversations around equity are changing came in the form of a case study on a unique agreement between Hydro-Quebec and the Mohawk Council of Kahnawà:ke.

The council is going to be a joint owner of a transmission line bringing energy from the company’s hydropower facilities in Quebec to New York City.

“In the past, there had been expropriations or land takings without consultation or compensation,” said Kahsennenhawe Sky-Deer, grand chief of the Kahnawà:ke Mohawk community.

The new joint agreement is different from what the community has seen in terms of land use, according to Sky-Deer.

“It’s groundbreaking and unprecedented, and something we welcome very much,” she said. “This is an untapped market in terms of partnership and recognition of Indigenous people.”

The partnership goes beyond a financial transaction and will involve jobs and training for Kahnawà:ke youth, Hydro-Quebec CEO Sophie Brochu said.

“We can be very viable business partners,” Sky-Deer said. “We do bring a different perspective and different energy to the table.”

Federal View

Patricia Hoffman, principal deputy assistant secretary for electricity at the Department of Energy, gave a rundown of new programs coming from the Infrastructure Investment and Jobs Act and called for coordination to speed decarbonization.

“Your priorities, the state, community and national priorities, are all critical as we work together to build a safe, reliable and resilient electric grid,” Hoffman said, adding that the infrastructure bill and associated investments are “a real opportunity to make a difference.”

Capitalizing on the investment opportunity that’s available will not be easy, she said. “We are all going to have to roll up our sleeves, but it is definitely worth the time and effort.”

Posted on

FERC Upholds Denial of NYTOs’ Cost Allocation Complaint

FERC on Thursday upheld its denial of New York Transmission Owners’ (NYTOs) complaint that NYISO’s funding mechanism for transmission upgrades is unjust and unreasonable, refusing a rehearing of the order and rejecting a separate proposal to revise the methodology (EL21-66-001 and ER21-1647-002).

The commission reiterated its previous determinations, concluding that “petitioners’ repetition on rehearing of the evidence and arguments presented in their prior pleadings does not change our assessment.”

The NYTOs, which included all the investor-owned utilities in the state except PSEG Long Island, asserted that the existing funding mechanism does not allow them to recover a reasonable rate of return for the risks and costs of upgrades caused by generator interconnections.

They asked the commission to direct the ISO to amend its tariff to allow them to provide initial funding for such upgrades and charge the interconnection customer to recover a return on this cost.

But the commission said it continued to find its interpretation that costs are distinct from rate-structuring risks “to be appropriate, including the commission’s corollary finding that the regulatory, reliability, cybersecurity, environmental and operational risks that the NYTOs state they face in connection with owning, operating and maintaining system upgrades are not costs under this provision.”

FERC explained that the precedents cited by the NYTOs — Bluefield Water Works v. Public Service Commission, FPC v. Hope Natural Gas and Ameren Services v. FERC — do not require a change to NYISO’s existing funding mechanism and that the NYTOs had not presented sufficient evidence to show that the existing funding mechanism results in the them facing uncompensated risks and costs.

Neither do the other sections of the NYISO-TO Agreement cited by the NYTOs support their preferred reading, the commission said.

Moreover, in alleging that the complaint order was internally inconsistent and that the commission “clearly affirm[ed]” that risks are recovered through authorized returns yet denied recovery in costs because the risks were not costs, the NYTOs misunderstood the commission’s reasoning, FERC said.

“The fact that utilities incur costs to mitigate and manage their risk, and risks therefore increase costs for utilities, does not mean that risks are, themselves, costs. The costs utilities incur to manage and mitigate risks are borne as expenses, which are fundamentally different to the risks themselves,” the commission said.

Commissioner James Danly dissented from the order because the “commission exceeded its authority by impermissibly eliminating rights expressly reserved to the NYTOs … and by rejecting proposed changes to the funding mechanism that were consistent with those reserved rights.”

Posted on

New Jersey Solar Pipeline Surges While Installations Drop

The current state of the New Jersey solar market depends on who you’re talking to.

The Board of Public Utilities (BPU) has been heralding a pipeline of more than 1.6 GW of projects as a healthy surge, while developers caution that the 305 MW of projects completed in 2021 — a 30% drop from 2019 — has left the state lagging on its clean energy goals.

For example, Ariane Benrey, solar policy and program manager for the BPU, said that projects in development have grown more than threefold from 523 MW in January 2021, signaling strong growth ahead.

“This really indicates to us the health of the industry going forward,” Benrey said. “It’s larger by an order of magnitude, by several orders of magnitude, than anything we’ve seen previously. So, we’re actually quite optimistic about the capacity that’s going to be installed later this year, next year, in the following year.”

In a March 2 press release, the BPU called 2021 a “banner year” for solar, adding that the pipeline of projects “provides assurances of continued strong development over the coming year.”

The agency said the dramatic increase in pipeline capacity stems from the convergence of many factors. Project applications slowed with the arrival of the pandemic in 2020 and the closure of many municipal and state offices, which prevented permitting and inspections. The number of applications accelerated in 2021 as vaccines took hold and the economy returned to more normal activity, the BPU said.

But Doug O’Malley, director of Environment New Jersey, says the state’s declining solar subsidies are part of the reason for the drop in installations. State incentives in the form of renewable energy credits were cut in 2020 and again in July 2021.

The state’s “very rich subsidies” in the past helped to offset construction, wage and other project costs, which are high in New Jersey, he said. O’Malley also believes early market growth came from easier projects — “low-hanging fruit” — while developers are now taking on more complicated projects, such as siting solar on landfills and brownfields and may be less keen to pursue them.

The recent decline in installations, in particular, spells bad news for New Jersey’s clean energy goals, O’Malley said. The state’s official Energy Master Plan calls for deploying increasing amounts of solar: 5.2 GW by 2025; 12.2 GW by 2030; and 17.2 GW by 2035.

The state, which had a total of 151,916 installed solar projects at the end of February, hit an annual installation peak in 2016, with 22,289 projects installed, according to figures from the BPU. Since then, new installations have declined each year, slipping to 13,803 projects in 2021.

With 3.84 GW currently online across the state, O’Malley said, “We need to be reaching 750 MW per year of solar to reach the Energy Master Plan goals. We are not there.”

Still another sign of a slowdown in project completions, the recent Solar Market Insight Report, compiled by the Solar Energy Industries Association and Wood Mackenzie, showed New Jersey falling significantly in national rankings based on megawatts installed per year. In 2019, the state took the No. 9 spot, but dropped to 12 in 2020 and to 20 in 2021.

Mixed Messages

These opposing views, New Jersey’s dramatically rising solar pipeline and declining installations, reflect a state and solar sector striving to balance aggressive clean energy targets with the cost to ratepayers of incentives to support the industry.

As in other states, solar installers in New Jersey were initially roiled by the pandemic. But they have also had to contend with two years of mixed messages as the state simultaneously reshaped its incentive programs to curb costs to ratepayers, while also rolling out new programs aimed at boosting the development of both community solar and grid-scale projects. And the impact on future growth is uncertain.

According to the state’s 2019 Master Plan, the state will need to deploy 950 MW of solar per year to reach its 2035 goal. However, since 2016, New Jersey has been averaging about 289 MW per year, less than a third of the capacity needed.

In other words, the full 1.6 GW in the pipeline would need to be built for the state to reach its 2025 target.

The BPU’s Benrey remains optimistic, pointing to pipeline growth as a sign of “a lot of pent-up demand.”

But at least part of that demand may have been triggered by the BPU’s decision to significantly trim solar incentives. The state’s original, more generous incentives ― the Solar Renewable Energy Certificate program ― paid about $250 per MWh of power generated. The program was cut in 2020 and replaced with the temporary, lower incentives of the Transition Incentive Program, which ranged from about $90 to $150 per MWh.

In July, the BPU approved a permanent replacement, dubbed the Successor Solar Incentive (SuSi) program, which offered even lower incentives, from $70 to $100 depending on the project. (See NJ Sees Solar Growth in Reduced Incentives.) A second element of the SuSi program enabled a much broader range of grid supply projects to be built and created a separate, competitive system for those incentives.

As a result, developers rushed to submit projects to qualify for the transition incentive before it closed, helping boost the pipeline, Benrey said.

Fred DeSanti, executive director of the New Jersey Solar Energy Coalition, estimates that the BPU may have seen about 4,000 project applications between June and August, which he called a “huge” number, due to the incentive change. But he is skeptical that the project completion rate will be anywhere close to the pipeline figure because of the difficulty of completing projects in the time allowed. He expects many projects will be cancelled or abandoned.

“I think by the end of this energy year, on May 31, we will probably show a completion rate of projects that will be even lower than last year,” he said.

Differing Views of the Future

However, Benrey points to other drivers of the pipeline surge as cause for confidence.

The launch of the state’s pilot community solar program in 2019 provided a pipeline boost. As of January, 203 MW of community solar were in the pipeline, accounting for 12% of the total. The BPU expects that number to grow with the coming introduction this year of a permanent community solar program.

The state also expects the number of grid-scale projects to increase as a result of a bill, S2605, that Murphy signed in July, authorizing the BPU to approve incentives and permits for a broader range of grid-scale projects than had been allowed in the past, and creating a new competitive bidding system to set incentive levels. Grid supply projects accounted for 7.4 % of the pipeline, or more than 121 MW in January, the BPU figures show. (See NJ Grid-scale Solar Bill Signed by Murphy.)

Getting those and other projects hooked up to the grid could be a major obstacle, DeSanti said. Many distribution lines have reached capacity and are now closed to additional solar projects, he said.

“The cost of interconnection has increased significantly as the higher levels of renewables on the utility system are requiring major upgrades at very significant cost,” he said. Projects are also being hampered by labor and materials shortages, rising inflation and other pandemic-related problems, he said.

If a project is not completed within 12 months of the date of application for BPU approval, it will fall out of the program unless the BPU grants a waiver. Without the waiver, the developer must to re-apply for SuSi incentives, which in some cases would be too small for the project to be financially viable, DeSanti said.

“It’s all about the numbers,” he said. “If that money … goes away, or it’s too small to support the projects, you’re not going to build them. It’s that simple.”

The BPU believes the SuSi program will “pave the way” for 3,750 MW of new solar generation by 2026 — or 750 MW a year — so that solar would provide 10% of the state’s electricity.

Eric Miller, New Jersey energy policy director for the Natural Resources Defense Council, is not worried about the “mismatch” between the surging pipeline figures and the declining installation figures. One reason is the current turbulence in the state sector, partly due to the changing incentive programs and the pandemic, which makes the future difficult to predict, he said.

“We’re at a very strange time in the history of New Jersey solar,” Miller said. One positive factor is that the SuSi program has “flexibility” in the form of a built-in mechanism that requires the BPU to evaluate the program and allows it to change policies that are not meeting the desired targets, he said.

Miller believes that the state “unequivocally” will meet its solar goals, although that may involve importing some clean energy from out of state. He added, however, that it is “unclear at this point,” whether the state can meet its goals of generating all solar energy in state.

Posted on

CARB: Calif. Must Double Annual Solar Build to Meet GHG Goals

To reach carbon neutrality by 2045, California must more than double the amount of solar capacity built each year compared to its previous maximum build rate, according to modeling by the state’s Air Resources Board.

The build rate for battery storage would need to increase by more than six-fold to meet the 2045 target, the modeling found.

And reaching carbon neutrality a decade sooner, by 2035, could require the annual build rates for solar capacity and battery storage to increase more than three-fold and 10-fold or more, respectively.

The California Air Resources Board conducted the modeling as part of the process to develop the agency’s 2022 climate change scoping plan, a roadmap to meeting greenhouse gas reduction goals. Results of the modeling, which analyzed four scenarios for reaching carbon neutrality, were presented to the CARB board on Thursday.

The first two alternatives would bring the state to carbon neutrality by 2035; the other two would reach the target in 2045.

Alternative one, the most aggressive of the four scenarios, would nearly eliminate fossil-fuel combustion by 2035. The scenario would require early retirement of gasoline- and diesel-powered vehicles: an estimated 16 million light-duty vehicles and 1.4 million medium- and heavy-duty vehicles by 2035.

Early retirement of natural gas appliances, such as space heaters, water heaters, clothes dryers, and ovens and stoves, would also be needed under the alternative.

The alternative would require “ambitious innovation in electric technology and aggressive consumer adoption trends,” Maureen Hand of CARB’s Industrial Strategies Division said.

Hand noted that a federal “cash for clunkers” program in 2009 cost $3 billion and removed about 690,000 fuel-inefficient vehicles from the roads.

Other alternatives would allow internal combustion vehicles and gas appliances to reach the end of their useful lives before their owners switch to electric models. The natural gas supply would be retained during the transition from gas to electric appliances.

The alternatives vary in their rate of zero-emission vehicle adoption and the extent to which they rely on carbon capture and sequestration (CCS) technology.

“Electrification is a cornerstone of each alternative,” Hand said. “The speed at which we need to expand zero-carbon electricity capacity is unprecedented.”

Hand said the most solar capacity that California has added in one year was 2.7 GW, and the largest annual increase in battery storage was 0.3 GW. Under the four alternatives, solar capacity must grow by 5 to 10 GW annually, and storage must increase by 2 to 5 GW per year, according to CARB’s modeling.

Role of Hydrogen

The alternatives envision an increased reliance on hydrogen as an alternative fuel in the transportation sector.

“The quantity of hydrogen needed in each of the alternatives to supply California’s projected demand is significant,” Hand said. “It will also need to be provided by low-carbon sources.”

One approach is to use electrolysis to split water into hydrogen and oxygen. If all the state’s demand is met by hydrogen produced through solar-powered electrolysis, solar capacity requirements would increase by 31 to 47 GW, according to the modeling. That’s about 40 to 50% of the state’s current electric generation capacity of 83 GW.

CARB board members listened to a presentation on the modeling on Thursday but took no action. One board member said the modeling showed the enormous cost of the 2035 scenarios.

“It would be hugely disruptive, hugely expensive to get to carbon neutrality by 2035,” said board member Daniel Sperling, who is also founding director of the Institute of Transportation Studies at the University of California, Davis. “Any kind of reasonable assessment would say 2040, 2045 is really the soonest we can get there.”

CARB is planning to hold workshops in coming weeks to focus on the economic and air quality modeling for the carbon-neutrality scenarios. The agency expects to present a draft scoping plan to the board in June and to finalize the plan by the end of the year.

Carbon Capture Controversy

All four scenarios analyzed in the modeling require some degree of carbon capture and sequestration for the industrial and refining sectors. Alternative one, in which petroleum refining would cease in 2035, would require less than 1 million metric tons (MMT) of CCS.

In the remaining three alternatives, the need for CCS would range from 8 to 11 MMT in 2035, dropping to 2.4 to 5 MMT in 2045.

Martha Dina Argüello, co-chair of CARB’s Environmental Justice Advisory Committee, urged the board to look at emerging evidence that calls into question the feasibility and viability of CCS strategies. The evidence comes from studies that are not funded directly or indirectly by the fossil fuel industry, she said.

“What happens if this technology doesn’t work?” Arguello said. “What happens if this technology, as [has] happened with others, actually ends up producing more carbon that it takes in?”

Arguello said CCS could also extend the life of the fossil-fuel infrastructure based in low-income communities and communities of color.

Rajinder Sahota, CARB’s deputy executive officer for climate change and research, said 20 years of testing has shown that CCS is safe and reliable.

Sahota said policymakers’ focus has traditionally been on ways to reduce greenhouse gas emissions. But the Intergovernmental Panel on Climate Change is now pointing to the need for CCS in addition to emission reductions to meet climate goals, she said.

“The science now says that has to be part of the solution,” Sahota said.