The Maine Department of Environmental Protection (DEP) held a hearing Tuesday to determine whether it should revoke Central Maine Power’s (CMP) permit to construct the New England Clean Energy Connect (NECEC) transmission line in the western part of the state.
There is no deadline for the decision in the DEP proceeding, but the agency has the option to suspend the construction permit temporarily or revoke it entirely, forcing CMP to apply for a new one. DEP Commissioner Melanie Loyzim opened the proceeding after a Maine Superior Court ruling in August vacated a 1-mile public land lease to CMP. Loyzim said the court’s decision represented a change in circumstance that could warrant a permit suspension.
CMP argued in the hearing that the decision on the land lease should not hold up or halt construction of the entire 145-mile transmission corridor, presenting two alternative routes the company could take to avoid the lease area.
The company also said it is considering running the transmission line underground, which it argued wouldn’t change recreational use of the state public land or potential alternatives.
If the DEP delays the project until an appeal of the court’s ruling is settled, which likely won’t happen until June 2022, it will cost CMP an extra $67 million, said Thorn Dickinson, CEO and president of NECEC Transmission, the affiliate running the hydropower transmission project already under construction.
The utility also has a December 2023 target date for completion of the line, and delays could put negotiated energy benefits for Maine and Massachusetts residents at risk, he said.
Opponents argued that ongoing construction of the transmission line is causing irreparable damage to the jack pine forests of western Maine, while the project could be halted by the legislature or the state land lawsuit.
“Any trees allowed to regenerate in the cleared corridor will be severely limited and will not achieve the middle and older age height diversity needed by wildlife,” said Roger Merchant of Glenburn, Maine, a licensed forester.
The same impacts would occur in the proposed alternative routes, which could take the 90-foot-wide corridor about 90 years to recover, Merchant said.
One alternative route would run through the Moosehead Conservation Easement Area, but Karin Tilberg, president of the Forest Society of Maine, said in an Oct. 19 email to DEP and Dickinson that a power line would not be permitted in the area.
However, supporters of the line argue the transmission line, which would bring renewable hydroelectric energy from Québec to the New England grid, benefits the health and environment of Maine.
“Climate change is the most serious threat to Maine’s environment,” said Tony Buxton, general counsel to the Industrial Energy Consumer’s Group.
A suspension or revocation of the construction permit for the line would be “contrary to the public interest,” Buxton said.
In a virtual public comment session following the hearing, William Frederic of Starks said if CMP halts construction of the line, he will lose his job and “the chance to make a difference to the future of our planet.”
The hearing comes two weeks before Mainers will vote on ballot referendum Question 1, which, if passed, would put the project before the state legislature, requiring two-thirds majority in both houses for the project to proceed.
“There are no climate change benefits from a project that can’t be completed,” said attorney James Kilbreth, representing the Natural Resources Defense Council of Maine. “Voters could decide to stop the project altogether.”
A plan that will serve as a roadmap for California to reach its 2045 decarbonization goal may be delayed by six months after a state environmental justice committee asked for more time to finish its work.
Members of the Environmental Justice Advisory Committee (EJAC) last week agreed to send a letter to Gov. Gavin Newsom requesting a six-month extension for adopting the plan, moving the deadline to mid-2023 rather than the end of 2022.
The California Air Resources Board (CARB) convened the committee in May to make recommendations on the agency’s 2022 scoping plan, which will serve as a blueprint for the state to reach carbon neutrality by 2045.
Under AB 32, the Global Warming Solutions Act of 2006, CARB must update the scoping plan every five years. The most recent update was in 2017.
But the committee’s letter to Newsom notes that AB 32 allows the governor to adjust scoping plan deadlines “in the event of extraordinary circumstances.”
The extraordinary circumstances in this case include the COVID-19 pandemic as well as extreme weather events such as large wildfires across the state, committee members wrote. These events have made it difficult for EJAC members to conduct outreach on the scoping plan with the communities they represent.
Another extraordinary circumstance, according to the committee, is “the need to allow time for sufficient and meaningful community engagement that was absent from prior scoping plan processes.”
EJAC consists of representatives of communities most heavily impacted by air pollution, including low-income or minority populations. The committee is a requirement of AB 32. CARB appointed some committee members in May and added others in August.
The timeline for EJAC’s work on the 2022 scoping plan was the focus of discussion during the committee’s Oct. 12 meeting.
CARB is asking EJAC to weigh in on scenarios being considered in the scoping plan. In general, the four scenarios being discussed include decarbonization by 2035 or 2045, either with or without a “full suite of technology options,” such as engineered carbon removal.
CARB staff agreed to shift the deadline for the committee to provide input on the scenarios by a month, from the original Oct. 22 deadline to Nov. 24. After that, a consultant will perform modeling on the scenarios in a step that will lead to a final draft scenario.
EJAC member Catherine Garoupa White, executive director of the Central Valley Air Quality Coalition, said during last week’s meeting that she opposed moving ahead with scenario modeling until the community has a chance to weigh in.
She said she was troubled that the strategies presented included continuing cap and trade and carbon capture and sequestration.
“I want to be very clear and on record that I cannot support moving forward with modeling scenarios before we have a public process, because that does not do justice to hearing from the most impacted community members,” Garoupa White said. “What issues they’re experiencing, and how to make sure we’re matching the solutions to that.”
EJAC member Connie Cho, a justice catalyst legal fellow with Communities for a Better Environment, asked whether CARB would support the committee’s request to the governor for a deadline extension.
CARB Executive Officer Richard Corey said that wasn’t possible.
“When it comes to statutory changes, changes to law, it’s the administration that takes positions, agencies don’t take positions,” Corey said. “I can’t weigh in on a proposed change to the law.”
Similarly, CARB Chairwoman Liane Randolph would defer to the administration, he said.
Corey noted that while the scoping plan is important, it’s just one step toward achieving climate goals.
“It is a precursor to rule development, regulation development … all of which take time,” Corey said, adding that later steps would also include opportunities for public involvement.
EJAC members submitted a proposed timeline for the scoping plan that includes extending the period for scenario workshops to the end of November. That would help ensure that committee members understand the material well enough to share it with communities they represent.
Community outreach meetings would be held in December and January. Committee members would then report back on feedback received, which would be used to shape scenarios.
The EJAC would conduct another round of public outreach when CARB releases a draft scoping plan, a step expected in December 2022 or January 2023 under the committee’s timeline.
The CARB board would then meet to approve the scoping plan in June 2023.
New Jersey is looking to jump-start the introduction of electric school buses in the state with millions of dollars in bus purchases — including a proposed $45-million pilot program in 18 school districts — along with guidance from private contractors that successfully introduced EV buses in other states and are saying the state needs to think big.
The proposal, soon to be introduced in the legislature, would offer a more aggressive approach than an existing, $10 million pilot proposal to fund three test projects, A1819, Sen. Patrick J. Diegnan Jr. (D) told an Oct. 13 forum on how to introduce electric buses into New Jersey. The earlier bill passed the Assembly on a 57-14 vote and is now before the state Senate Economic Growth Committee.
The event focused on providing key stakeholders with insights on the experiences of school districts and private bus companies that have introduced electric buses in other parts of the country, and the challenges facing New Jersey as it seeks to follow suit.
Diegnan’s new proposal would create a three-year pilot that would require three of the 18 school districts in the program to be located in environmental justice communities. A primary goal of the program would be to provide data on the use and efficiency of electric buses, which could then be used to promote electrification to other school districts, said Diegnan, who was also a sponsor of the earlier legislation.
“By doing this demonstration project we’re going to know how long does the battery last. Is there a problem with maintenance? What’s going to happen when the air conditioning is on in the summer? Is that going to affect it?” Diegnan said. “So rather than guessing where should we have the charging stations, this program will really put in place reliable information that we can use to move this forward.”
Diegnan said he hopes to get the bill introduced and passed by December, and the pilot program ready to start in the fall of 2022.
New Jersey had 15,703 school buses in 2019, none of them electric, and no electric buses have been registered with the state since, according to information from Atlas Public Policy. Only 1% of the nation’s 480,000 school buses are electric, according to the World Resources Institute (WRI), which helped organize the forum with the Electrification Coalition.
Aiming for Large Scale
Several speakers with experience introducing electric bus programs in other states encouraged New Jersey to move quickly and boldly, saying that the technology already has shown its worth elsewhere in the country. That approach will help overcome challenges to bus electrification, which they said include the difficulty of creating new infrastructure, adjusting to new technology and overcoming the sticker shock of high-priced zero-emission buses.
“What you want to think about are ways to encourage school districts to scale their electrification efforts” and think bigger, said Matt Stanberry, managing director of Highland Electric, a Massachusetts-based provider of turnkey electric fleet solutions, such as electric bus fleet “subscriptions.” “What we really want to be thinking about is creating seeds for electrification at scale.
“If you come in with a mindset of ‘I’m going to start with a single deployment,’ you’re sort of dead before you start,” Stanberry said. “You’ve got to be thinking about how do I set myself up to enable that scale, so I’ve got a plan for it? How do I limit the number of times that I’m breaking ground, busting up concrete, to lay in infrastructure?”
Jim Woods, director of business development for First Student, which provides student transportation to school districts, said that the urgency is so great that companies like his need to think in grander terms. The company has committed to electrifying 20,000 buses, more than half its fleet, over the next 10 years.
“Doing one or two buses here and there, you know, up to five buses, which is becoming more and more easy to do, is a good start,” he said. “But it’s not the way that we’re going to get there. We need to do this on a large scale.”
Grants Totaling $20 Million
Converting to electric buses is one plank of the New Jersey effort to get 330,000 electric vehicles on the road by 2025 and reach 100% clean energy by 2050. The state is mid-way through enacting a rule proposal to encourage the creation of medium- and heavy-duty EV charging stations that would service electric buses and medium- and heavy-duty trucks. (See: NJ’s EV Charger Rules Face Scrutiny.)
Electric school buses are key to the state’s effort not only because they help fight climate change and cut children’s exposure to the pollution generated by diesel engines, but also because they are well suited for the task, said Justin Balik, WRI’s senior manager for state policy for transportation. The limited range of electric vehicles, a primary concern for other types of transportation, is less of a factor on school routes, he said.
“Electric school buses can operate in 90% of the routes that are out there,” Balik said.
Electric school buses will become increasingly cost-competitive with traditional diesel vehicles over the next decade. | Atlas Public Policy
With transportation accounting for about 42% of carbon emissions in New Jersey, the state has placed a high priority on reducing those emissions via funds from the state’s portion of the Volkswagen Settlement and the Regional Greenhouse Gas Initiative (RGGI). The state awarded $100 million, in large part to transportation, from the two funds in January, including $6.5 million for 17 school buses. (See NJ RGGI Spending Focuses on Transportation.)
Peg Hanna, assistant director of the air monitoring and mobile source programs at New Jersey Department of Environmental Protection (DEP), told the forum that the state will soon announce another $20 million for electric school buses and trucks. Offering a contrast to the widespread perception that electric vehicles of all types are prohibitively expensive, Hanna said that “the projections show that we are expected to reach cost parity — a total cost of ownership parity — by 2025.”
A report released in March by Environment New Jersey and NJPIRG, a public interest advocacy group, said although the $312,000 price of a new electric bus is close to three times more than a new diesel bus, the lower fuel and maintenance costs for an electric vehicle would mean that school districts would save between $80,000 and $130,000 over the 16-year life of each school bus. (See: Environmentalists Call for Faster Transition to Electric Buses in NJ).
The fuel cost per mile for an electric bus will drop from $2.83 in 2020 to about $1.87 in 2030, at which point it will be cheaper than the cost of diesel, about $2.45 per school bus mile, according to information from Atlas Public Policy.
Hanna added that the transition to from diesel to electric school buses must be a collaborative effort.
“Converting to electric school buses and electric vehicles is not something that New Jersey government agencies are going to do solo,” she said. “We really need a combination of stakeholders, and a combination of approaches if we’re going to get there.”
Helping School Districts Jump In
Making it happen requires vigorous community support for school districts and the willingness to make tough decisions that will involve a sizable, upfront investment, said Stanberry of Highland Electric. The company has projects in development in 20 states, including a contract with Maryland’s Montgomery County Public Schools, which will lease 326 electric school buses over four years. (See: Schools’ ‘Budget Neutral’ Bus Deal Could Accelerate BEB Growth).
Financial support from the state is also essential, said Jacqueline Piero, vice president of policy for Nuvve, a San Diego provider of vehicle-to-grid technology that allows EVs to send electricity back onto the grid. One way to make electric buses more financially attractive and acceptable to school districts is to shape the way that support is delivered, she said.
State officials should structure incentive programs around vouchers or rebates, which enable districts to receive reimbursement for investing in electric buses, rather than grants, Piero said
“We found that it’s not just giving schools money; it’s how you give them money that actually can make a huge difference in whether or not they’re able to pull the trigger and electrify,” she said. “We are finding that schools are much more able and willing to engage when they see a more direct process.”
Programs in which the state provides a rebate after the purchase is made are a more direct way to get funds to school districts, but they need to have the money to spend up front, said Piero, who also encouraged the state to produce “step-by-step guides” that explain to school districts how to electrify their fleet and avoid pitfalls. Otherwise, she said, “they can end up with incompatible systems that they’ve cobbled together.”
Woods, of First Student, said school districts and bus companies need to look to the future and ensure that the steps they take early on in an electrification process, especially when it comes to infrastructure, will serve them well as they grow. He noted that to ensure that First Student can secure enough clean electricity to power its buses, the company has partnered with NextEra Energy, which invests in clean energy infrastructure and utilities.
“Infrastructure is one of the biggest challenges,” Woods said. “Putting five buses on a site with a $1,500 charger is not too difficult. Doing 50 buses is entirely a different story.”
He said the company’s purchase of 260 buses from Lion Electric, a California electric bus manufacturer, to put into service in Quebec, Canada, reflects the economies of scale needed to make electric buses viable.
“School districts have limited budgets,” and companies like his need to help them electrify their bus fleets “at a near diesel equivalent cost,” to make the task successful, he said.
“If we don’t have the volume to drive down pricing, then buses are going to continue to be expensive,” he said. “But somehow we’ve got to get beyond the hurdle of that initial expense.”
Two years ago this month, the Connecticut Public Utilities Regulatory Authority approved a sprawling plan to modernize the state’s electric grid.
PURA established four objectives for its Equitable Modern Grid framework centered on Connecticut’s green economy, decarbonization, energy affordability in underserved communities and reliability. It also identified 11 near-term tracks to investigate in three phases.
During a recent webinar to recap progress to date, including three final decisions among the 11 tracks, PURA Chair Marissa Gillett said that while Connecticut’s electric infrastructure continues to age, there is a concurrent reliance on it “to meet our daily needs.”
There is an emphasis on equity that permeates the initiative, including the final decisions on electric storage and zero-emissions vehicles, which contain incentive adders for underserved communities.
“Equity is an important lens that we approach this process with,” Gillett said. “And while I think as an industry, we are starting to do a better job thinking about equitable outcomes, what I think we need to do more of is think about how we inject equity into the process of developing and pursuing those initiatives.”
Gillett added what she said might seem like a commonsense observation: equitable outcomes are borne from fair access to developing them.
For example, PURA was directed through a bill passed by the General Assembly earlier this year to establish a nine-year electric storage program starting next year, which targets deployment of at least 580 MW and supports the state’s goal to reach 1,000 MW by the end of 2030. Storage systems will be compensated through an upfront incentive of $7,500 administered by the Connecticut Green Bank and performance-based incentives provided by Eversource Energy and United Illuminating. There is also a target to deploy 40% of storage in low-to-moderate income communities.
PURA also set up a nine-year program for zero-emissions vehicles starting in 2022, which includes a study by the Rocky Mountain Institute to identify how to best address and offer electrified transportation mobility options for low-to-moderate-income communities. Stefanie Keohane, supervisor in PURA’s clean and affordable energy unit, said there is “recognition and acknowledgment” that many in Connecticut may not have personal vehicles or be able to purchase or lease an electric vehicle. Still, there should be equity work that ensures “that the benefits of transportation electrification are shared among all those in Connecticut.”
Despite PURA identifying 11 tracks for the Equitable Modern Grid framework, Gillett said it is not “an exhaustive list.”
“There could have easily been hundreds, if not thousands, of tracks in [grid modernization], and we recognize that we haven’t identified the last of the work,” Gillett said.
Ambitions do not restrict PURA although its current staffing levels offer “constraints,” according to Gillett. Stakeholder engagement in PURA’s public proceedings and constructive feedback through public comments are also critical, though Gillett acknowledged one underreported aspect of that commitment, which is time, especially with non-traditional stakeholders.
“Stakeholder fatigue is a very real challenge that I think is not spoken about enough, and with our desire to emphasize the engagement from non-traditional stakeholders, we want to be cognizant of those limited resources as well,” Gillett said.
WESTBOROUGH, Mass. — Continued discussion of eliminating the minimum offer price rule (MOPR) from ISO-NE’s capacity markets and Order 2222 compliance took up a sizeable portion of the agenda during a two-day, in-person meeting last week of the NEPOOL Markets Committee.
The New England Power Generators Association and Advanced Energy Economy laid out their complaints with the RTO’s proposals at the session, the first in-person meeting of the MC since March 2020 because of the COVID-19 pandemic.
ISO-NE Proposes Review Mechanism
As part of its MOPR elimination, ISO-NE proposes a narrow, buyer-side market power review mechanism where new capacity resources qualified to participate in an upcoming Forward Capacity Auction will follow one of three lanes:
de minimis lane
supported purpose lane
full assessment lane
New resources with a qualified capacity below a de minimis size threshold — yet to be determined — enter that lane and will not be reviewed for buyer-side market power. The RTO’s tariff presently provides de minimis exemptions to certain supply-side market power reviews. The threshold will similarly focus future buyer-side market power reviews on larger new resources. As a result, ISO-NE anticipates that a de minimis threshold will likely exempt most new capacity resources currently subject to review under the MOPR.
All remaining resources — small in number but constituting most of the new qualified capacity offered in the Forward Capacity Market — would need to proceed down the supported purpose or full assessment lanes.
A new capacity resource that can demonstrate that it meets certain criteria — such as the absence of any load-side interest or arrangement or that it is a development to meet a specific state regulatory requirement or policy — would go down the supported purpose lane and will not need further evaluation by the Internal Market Monitor. This will allow resources built to further state decarbonization goals and contribute to the region’s capacity supply to participate in the Forward Capacity Market, which is consistent with the overall objective of the MOPR’s removal, ISO-NE said.
New resources that do not qualify for the de minimis or supported purpose lanes will undergo a more thorough buyer-side market power evaluation by the IMM. In addition, those resources must comply with the new certification requirement, which requires an affidavit stating that they are not participating in the auction to reduce the clearing price. They may be required to provide project-specific confidential information to facilitate an assessment of buyer-side market power and mitigation.
Bruce Anderson, vice president of market and regulatory affairs for the New England Power Generators Association (NEPGA), said in a presentation to the committee that ISO-NE’s MOPR elimination proposal “allows for uncompetitive rates and fails to create a proper balance between consumer and investor interests” in the FCM.
Under the ISO-NE mitigation proposal, new capacity resources may be offered at any price, whether competitive or not, eliminating the critical relationship between competitive offers and competitive rates, NEPGA said.
If the RTO eliminates the MOPR at all, NEPGA said it should be done at the same time as it enacts “capacity accreditation reform and meaningful forward reserve pricing.”
NEPGA said ISO-NE has acknowledged its MOPR elimination proposal would create “a greater risk of inefficient retirements” and “gaps” in the wholesale markets that the generators said must be fixed by the accreditation and forward reserve changes.
“Delaying the remedies for the two existing gaps in the wholesale markets, while creating a third issue to be remedied, is poor planning and should be avoided through the concurrent application of these wholesale market design changes,” NEPGA said.
NEPGA also said that ISO-NE has not explained how the FCA will produce competitive clearing prices when there is no review of new capacity resource offers for competitiveness. Additionally, NEPGA said that the RTO has not determined how it, or the Internal Market Monitor, can testify to the competitiveness of the FCA clearing price without any transparency on new capacity resource offers.
Eliminating the MOPR without “counter-balancing changes” violates the need for wholesale markets to balance consumer and investor interests properly, NEPGA said.
AEE Offers Amendments for Order 2222 Compliance Proposal
ISO-NE’s Order 2222 proposal does not meet FERC’s directive to enable distributed energy resources (DERs) to offer wholesale market services they are technically capable of providing through aggregation, Jeff Dennis, managing director and general counsel for Advanced Energy Economy, said in a presentation.
Without viable participation models for many DERs, New England will forego the option to pursue cost savings, market efficiencies and reliability benefits through wholesale markets, AEE added.
AEE proposed a series of five individual amendments that are not part of an overall package, including allowing submetered load to participate as demand response and submetering by third parties.
Load reductions from a DER allow customers who cannot participate at the customer meter, because of the cost of metering and/or widely variable load, to participate with a dispatchable device behind the meter, AEE said. It said CAISO uses a FERC-approved DR model that allows submetered EV charging equipment to participate as DR under Order 745.
Allowing third-party metering permits aggregators to meter the injection, withdrawal and load reduction of all DERs within each aggregation without requiring reconstitution by meter readers. Third parties bear costs of additional equipment and do reconstitution when required. The arrangement would facilitate DER aggregation deployment sooner and in the areas with no advanced metering infrastructure, AEE said.
The precedent cited by AEE is the NYISO DER participation model that allows third parties to provide metering and meter data services for wholesale market participation. It defines the roles, responsibilities, equipment and data quality standards while describing the processes for data processing and analysis. It also provides checks and balances to ensure data accuracy.
ISO-NE must make its Order 2222 compliance filing by Feb. 2, 2022.
BOSTON — When Avangrid Renewables (NYSE: AGR) and Copenhagen Infrastructure Partners began talking to banks about financing their Vineyard Wind project back in 2019, more than 60 institutions took the company’s calls.
“We explored all the possibilities, and we saw so much interest,” CFO Álvaro Ortega Sebastián said.
The lenders’ ardor was not dampened when the Trump administration, also in 2019, postponed Vineyard Wind’s final environmental impact statement to conduct an expanded analysis of “cumulative impacts” from the multiple offshore projects proposed for New England.
The 800-MW project, 15 miles off the coast of Martha’s Vineyard, eventually narrowed the group of banks to nine. When Vineyard Wind wanted to close this year, the lineup was intact, Sebastián told the American Clean Power Association’s Offshore WINDPOWER 2021 conference last week.
“We came back in 2021 with the same group just to give them the opportunity to come up to the market with us at the same [interest rates and other terms] that we thought we should go out with, and they were all able to be there,” Sebastián said.
In September, Vineyard Wind I became the first commercial-scale offshore wind project in the U.S. to achieve financial close, having raised approximately $2.3 billion in construction and term loan financing from nine banks.
While developers still face challenges in financing OSW projects, lenders are eager to get involved, Sebastián and other speakers told the conference.
Atlantic Shores is further back in the development cycle than Vineyard Wind I. In July, it was awarded a contract by the New Jersey Board of Public Utilities to develop 1,510 MW in OSW energy. A joint venture between EDF Renewables North America and Shell New Energies US (NYSE:RDS.A), its lease area is located approximately 10-20 miles off the coast of New Jersey between Atlantic City and Barnegat Light.
Joris Veldhoven, the company’s commercial and finance director, told the conference the company would explore equity financing as well as “various forms of debt,” and export credit agencies — which provide loans, loan guarantees and insurance to promote exports — over the next two-plus years.
Given that Vineyard Wind encountered a situation where it had to stop and start again, Sebastián said by beginning the process with the banks in 2019, it was able “to reduce most of the work” as it moved forward this year.
“There’s a lot of back and forth between all the parties involved to negotiate the term price, so the earlier you start, the better,” Sebastián said. “But not too early because things can change over time.”
Mayflower Wind is developing a lease area 30 miles south of Martha’s Vineyard and 20 miles south of Nantucket that it hopes will generate 2,000 MW by the mid-2020s. It is owned by Shell and Ocean Winds, a joint venture by EDP Renewables and ENGIE.
CFO Justin Johns said the companies’ balance sheets and existing banking relationships “gives us a lot of flexibility as to when and how we execute.
“I would expect that we’re going to use non-recourse project financing similar to how we’ve done in Europe, and that will involve working to achieve the most competitive terms in the market,” Johns said. Non-recourse debt, such as a typical home mortgage, is secured by collateral; lenders cannot go after the borrower’s other assets in the event of a default.
OSW projects also currently qualify for an investment tax credit of 30% as long as construction starts by the end of 2025. U.S. Sen. Ed Markey (D-Mass.) introduced a bill in September that would create a 30% investment tax credit for American manufacturers to produce qualified OSW components and dedicated vessels. There would also be production tax credits for select OSW components to “prevent bottlenecks” in the supply chain. (See related story, Offshore WINDPOWER 2021 Conference Briefs: Oct 13-14, 2021.)
Markey’s legislation could get folded into the budget reconciliation bill Democrats are trying to push through Congress. However, Johns said any legislation passed could be a net benefit to the OSW industry if it accounts for all the variables, including the industry’s relative immaturity.
“It depends, but it should be a net benefit if it’s structured right with a view for offshore wind in recognition of where we are with the supply chain,” Johns said. “It needs to recognize U.S. offshore wind is at a much earlier stage. It depends on how that bill is implemented at the agency level. There definitely is potential there, but it needs to be done right.”
FERC has approved the release of up to $2 million from NERC’s financial reserves, allowing the ERO to move ahead with its plans to leave its current office space in Atlanta (RR20-6).
NERC will use the $2 million, to be paid from its Operating Contingency Reserve (OCR), to exercise the early termination clause in the lease for its office in the Atlanta Financial Center. The organization requested FERC’s permission for the expenditure on Sept. 15 because approval is required to spend more than $500,000 from the OCR. (See NERC Seeks FERC Approval to Fund Office Move.)
The lease on NERC’s office in the Atlanta Financial Center is set to expire in 2025. The early termination clause, which must be exercised by Oct. 31, would allow it to exit the lease by October 2022. In its September filing, NERC asked the commission to limit the comment period on its proposal to 14 days, which would allow FERC to deliberate and render a decision by Oct. 15, allowing NERC more time to execute the termination.
NERC also told FERC in September that it has negotiated a lease for a new office space; the location of the new office has not been publicly revealed, but the organization said it expects to save more than $900,000 per year in “budgeted rent and facility expense” after the move. Total out-of-pocket costs for the move to be funded by NERC in 2021 are about $2.7 million, including the early termination fee.
Last month NERC’s Board of Trustees authorized management to execute the lease for the new office and to draw another $773,000 from its reserves in 2022 to fund the move. (See NERC Board Approves Atlanta Office Move.) From that total, $64,000 will be spent from the OCR and the remainder will come from NERC’s Future Obligations Reserve, a fund that CFO Andy Sharp said was set aside by the organization earlier to “subsidize the remaining term of the Atlanta lease.”
NERC’s new landlord has also agreed to pay the majority of the construction, furnishing and move costs, which will allow a “reasonable payback” of the early termination charge, Sharp said.
The use of the reserves means that NERC will not have to change the assessments on regional entities in its 2022 budget. In addition, the ending balance of the OCR in 2022 is projected to be 5.5% of the revised budget, even considering the new expenditures; this is well within the policy target range of 3.5 to 7.5%.
In addition to the financial benefits, the new office space is 40% smaller than the current space. Because NERC plans to allow more employees to work remotely in the future, building on its experience with the COVID-19 pandemic, a smaller footprint will ensure its space does not sit empty. The new space also offers free parking to NERC employees — another benefit to the ERO’s budget — more transportation options, including nearby rail and bus stops, and an adjacent hotel and conference center.
Hydrogen-powered fuel cell maker Plug Power (NASDAQ:PLUG) sees green hydrogen made from water as the fuel of the future and has announced its plans to become the nation’s largest producer of hydrogen, as well as a builder of fuel cells for cars, trucks and stationery power.
Sanjay Shrestha, Plug Power | Plug Power
“We’re starting construction of three [hydrogen] plants this year: two with the nameplate capacity of 15 tons per day [and] and one with 45 tons per day,” Sanjay Shrestha, Plug Power chief strategy officer, told about 5,000 people who tuned in to the company’s third annual symposium held virtually Thursday.
The company plans to have 70 tons/day of capacity by the end of 2022, 200 by 2023 and “well on our way” to 500 by 2025, produced by 13 plants located across the U.S. on sites close to wind and solar installations, Shrestha said.
Currently less than 2% of the hydrogen used in the U.S. is made through the electrolysis of water and is very expensive. Most hydrogen used in industrial process and oil refining is made from “steam methane reforming,” a high-pressure, high-temperature process that also produces carbon dioxide.
Plug expects demand for green hydrogen to soar as governments and corporations chart new courses to lessen carbon dioxide emissions in efforts to avoid accelerating global climate change. The company thus sees opportunities in transportation and heavy industry, including refineries, where most of the hydrogen made from methane is used today. And it believes its hydrogen-powered fuel cells can serve as clean and quiet backup generators at huge data centers that are already trying to replace diesel generators with massive battery systems.
Shrestha said Plug envisions hydrogen being transported long distance via pipelines. “When we build this first-of-a-kind green hydrogen generation network, this will also help accelerate demand for many new fuel cell applications … because this will actually ensure that hydrogen is going to be available all the time.”
Plug’s planned rise as a major player in hydrogen and fuel cell generation will involve a number of mergers and acquisitions, moves that can make investors nervous. In just the past two weeks, the company announced mergers with or acquisitions of key companies crucial to transforming itself from a maker of small fuel cells for warehouse fork lifts into a global conglomerate producing both hydrogen and much larger fuel cells.
Just hours before the symposium began, the company announced it had signed a “definitive agreement” with Applied Cryo Technologies, a Houston-based maker of technology to transport, store and distribute liquefied hydrogen, as well as other industrial gases, at cryogenic temperatures.
During the symposium, the company unveiled a hydrogen fueled delivery van with a 300-mile range that Renault will begin manufacturing in 2022, using a Plug fuel cell.
Also Thursday, the company announced it had signed a letter of intent for a 50-50 joint venture with Fortescue Future Industries (FFI) to build a large factory in Queensland, Australia, that will “produce large-scale proton exchange membrane (PEM) electrolyzers, with the ability to expand into fuel cell systems and other hydrogen-related refueling and storage infrastructure in the future.
“Plug Power will supply the electrolyzer and fuel cell technology, and FFI will contribute advanced manufacturing capabilities. FFI will be the primary customer of the products manufactured by the joint venture, enabling its ambitions in decarbonizing its operations with stationary power and mobility applications running on green hydrogen,” Plug said in a press release.
On Wednesday, the day before the symposium, Plug announced deals with European aircraft contractor Airbus to study the use of the company’s fuel cells in aviation. Also, it announced that it had signed a “memorandum of understanding” with Phillips 66 “to collaborate on the development of low-carbon hydrogen business opportunities.”
Phillips operates 16 refineries in the U.S. and Europe and uses hydrogen in those operations. It also supplies gasoline to retail and wholesale markets.
Earlier in October, Plug announced it had formed a joint venture with SK E&S, part of South Korea’s SK Group, “designed to accelerate the use of hydrogen as an alternative energy source in Asian markets.”
“The two companies will collaborate to provide hydrogen fuel cell systems, hydrogen fueling stations, electrolyzers and green hydrogen to the Korean and other Asian markets,” Plug said in a release.
Plug Power CEO Andy Marsh | Plug Power
In what appeared to be a videotaped conversation with Plug CEO Andy Marsh, Ji Young Li, a senior vice president with SK, said the company was planning to spend $16.5 billion “to build a hydrogen eco system in South Korea by 2025.”
The company is investing $1.6 billion in the deal with Plug, she said. “And we thought that with [your] capability of integrating things, we thought that there would [a need for] new technologies going forward. We like the flexibility. That’s why we reached out to you.
“And I think the combination of our skill sets will position us in a unique manner. We’ll have all the technology available throughout the value chain starting with electrolyzers and fuel cells and refueling station solutions, and potentially liquid hydrogen as well,” she said.
Marsh concluded the symposium by asserting that “this company is building the green hydrogen highway. … And no one has made as many fuel cells that have to really work.”
Sheep grazing on solar array lands has been a successful approach in agrivoltaics, but the possibilities are growing for pairing solar with beekeeping, crops and even cattle.
Co-developing agricultural practices and solar has an “incredible amount of potential,” Lexie Hain, executive director of the American Solar Grazing Association (ASGA), said Tuesday at the annual Renewable Energy Vermont conference.
“Sheep and solar are absolutely the most predominant agrivoltaic integration in the U.S. and surely globally,” she said, adding that the practice is “straightforward.” The herd’s vegetation maintenance prevents crops from creating shade on solar panels, and the array infrastructure doesn’t need to be modified to accommodate sheep.
Studies show that the sheep that graze at solar sites don’t have to compete for shade, so they drink less water and have lower stress levels, according to Hain. Their grazing activity also benefits local plant species, with one new study pointing to the biodiversity at grazed arrays being higher than mowed arrays, she said.
In the U.S., there are about 12,000 acres of grazed solar, according to Hain, but she said there are other “big, forward thinking” opportunities for agrivoltaics.
The University of Minnesota studied the effects of grazing cattle in the shade of solar PV systems, Hain said. That study concluded that, while more research is needed, agrivoltaics may reduce the stress from heat on dairy cows and increase their wellbeing.
Solar developer Silicon Ranch, which is a Royal Dutch Shell (NYSE:RDS.A) company, received a U.S. Department of Energy grant this year to study cattle and poultry at the company’s arrays, according to Hain.
In particular, she said, the company is studying the necessary modifications of solar panel racking systems to accommodate cattle.
Another area of “meaningful” agrivoltaics research that Hain sees growing is pairing vegetable crops with solar. The University of Arizona (UA), University of Massachusetts and Oregon State University are all engaged in solar and crops research, she said.
A group of universities that includes UA will work on a project funded by a $10 million, four-year U.S. Department of Agriculture grant announced Oct. 6. The “Sustainably Co-locating Agriculture and Photovoltaic Electricity Systems” project will focus on increasing crop yields, productivity and farmer profits with row, specialty and forage crops.
Putting bee colonies on solar array sites has grown from the level of hobbyists to large-scale beekeepers, according to Hain.
“There are a number of commercial beekeepers in the U.S. and one in Canada who have worked to formalize the process by which beekeeping can be a viable practice to produce a value-added solar honey, and in so doing, gain lands that are accessible 24/7 to them that typically are managed with low or no herbicide use,” she said.
ASGA recently worked with the American Beekeeping Federation to create a solar beekeeping contract.
“We wanted to understand the agricultural viability of this for our solar beekeepers, and we wanted to provide a structure and framework for our solar companies and hosts to understand what the financial expectation and obligation is,” she said.
The contract sets out the basis for which a solar landowner might pay a beekeeper for maintaining an apiary on the solar site. In some cases, co-locating the apiary and solar array would allow the site to qualify as land used in agricultural production under state regulations. The Solar Massachusetts Renewable Target program, for example, offers an additional incentive to solar developers for productive agricultural activity at their projects.
“Most of the states in the Northeast are importers of honey, and this could be another opportunity for value-added production at solar arrays,” Hain said.
Nordic Farm
Vermont entrepreneur Will Raap is using his vision for solar to help Vermont’s ever-shrinking dairy farms. He wants to make his latest project, Nordic Farm, “the most carbon-negative farm in Vermont.”
Part of that vision includes using agrivoltaics to create a profit stream for the dairy farm, which went through bankruptcy four years ago. Raap purchased the farm earlier this year and is planning to build up to 5 MW of ground-mounted solar on marginal, abandoned pastureland and grow berries on the site.
“We’re working with a beverage company, called Shrubbly, to grow aronia, currents and elderberries between the solar panels, which we could harvest for their product,” he said during the conference.
Hinesburg-based Shrubbly produces a sparkling water drink flavored with organic fruit, herbs and spices.
The project team also plans to study the ecosystem benefits of the site, including, for example, carbon sequestration, water retention and pollination.
If Vermont is to realize the emission-reduction targets set by the 2020 Global Warming Solutions Act, Raap estimates the state needs to build between 150 and 300 MW of new solar every year for the next decade. That capacity would require 1,000 to 2,000 acres of land beyond brownfields and the built environment, Raap said.
One solution, he said, could be to repurpose marginal and abandoned farmland that has low or no economic value, especially if the land is on economically stressed dairies.
If Raap can demonstrate how to build multiple income streams with solar and agriculture at Nordic Farm, the project would be a valuable model for other dairies.
“Farmers [can] de-risk their farming situation with diversification in their agriculture, not only to produce more income from renewable energy but to reduce their energy footprint and make them a more carbon-negative farm,” Raap said.
California needs another 1.1 million electric vehicle chargers in public areas to meet its transportation decarbonization goals, but the process for building EV charging facilities is slow and expensive compared with other states, making reaching the goal more difficult, developers said in a workshop last week.
The joint meeting of the California Energy Commission (CEC), the California Public Utilities Commission (CPUC) and the Governor’s Office of Business and Economic Development addressed the need to greatly accelerate the growth of EV charging infrastructure in the next eight years.
The state requires nearly 1.2 million public EV chargers by 2030 to support light-duty EVs and meet its greenhouse gas (GHG) reduction goal and clean energy mandate, the CEC estimates. But only 75,000 chargers are installed in shared, public locations, it said.
“We need a massive scale-up,” CEC Commissioner Patricia Monahan said, adding that “bottom line, we need to move quickly to [build] zero emission vehicle infrastructure.”
Without adequate charging infrastructure, the state will have trouble meeting the goal set by former Gov. Jerry Brown of having 5 million EVs on the road by 2030, and Gov. Gavin Newsom’s executive order that all new passenger vehicles sold in-state must be emission-free by 2035. (See Can California Meet Its EV Mandates? and California Needs Huge Number of EV Chargers.)
Under Senate Bill 100, signed by Brown in 2018, utilities must provide retail customers with 60% renewable energy by 2030 and 100% zero-emissions energy by 2045. The state’s legislatively mandated GHG targets include reducing emissions 40% below 1990 levels by 2030.
Developers said for adequate charging infrastructure to be built, the process of getting new charging sites approved by local planning authorities and connected by utilities needs to speed up.
“In California, a new-service utility interconnection takes an average of 39 weeks or nine months to complete, in our experience, having built more than 200 stations today,” said Matthew Nelson, director of government affairs for Electrify America, the largest network of fast-charging stations in the U.S.
“The utility process for constructing the interconnection, the line extension and dropping the transformer … takes an average of 27 weeks, or more than six months, to complete,” Nelson said. “As a result, building stations in California costs 34% more for the exact same station than it costs us to build the same station in any other states.”
The state has invested vast sums toward charging infrastructure in its effort to reduce emissions and electrify the transportation sector, which is responsible for 40% of GHGs in California, with passenger vehicles accounting for about three-quarters of the total.
The most recent state budget allocated $1.2 billion over three years to promote consumer adoption of ZEVs, including $300 million to close the projected gap through 2025 in light-duty charging and fueling infrastructure. (See Calif. Earmarks $3.9B for ZEVs Through 2024.)
The CPUC and CEC have approved large sums to develop and accelerate charging infrastructure. The CPUC authorized the state’s investor-owned utilities to recover $1.85 billion in costs related to EV charging efforts. And the CEC has provided grants of $100 million per year since 2008 for zero-emission vehicle charging and fueling through its Clean Transportation Program.
Disadvantaged Communities
Installing charging sites in low-income communities and apartment complexes so that EV adoption spreads beyond wealthier residents has been a significant part of those efforts.
“As we increasingly broaden deployment to all segments of society — which we can do, and which we must do — getting infrastructure in place is critical,” CEC Commissioner Clifford Rechtschaffen said.
“We’ve prioritized having equitable access to transportation electrification by directing very significant portions of utility investment to disadvantaged communities,” Rechtschaffen said. “That has a great benefit of reducing pollution burden in those areas that need it the most, and we’ve also focused on underserved areas of the market, where the private sector hasn’t stepped in and where we need ratepayer-funded utility investment.”
Installing chargers in disadvantaged communities has proven slow and frustrating, said Paul Francis, CEO of charging manufacturer and software developer Keep it Green Tech. The company has worked with churches in South Los Angeles and other areas to install fast chargers in their large parking lots for use by parishioners and neighbors.
“What we’re noticing in frontline communities are that tier 3 level [fast-charging] projects — you’re looking at 1,500 kW or more — are a lot more challenging and a lot more stringent when you’re talking about the permitting and interconnection process, and interconnection has a lot to do with the permitting process for us,” Francis said.
“For example, it’s taken almost two years to get someone to come out to one site just to check if a pole can be put in place where there’s no power,” he said. “And see, often what’s happened in the past is these communities, these frontline communities, their local grid was never designed for uptake of this type of power capacity. And even though some aren’t affluent areas … a community sense of urgency pushes [for EV charging].”
Rebates and incentives could help, but often by the time we “finally get someone to come check out if we can do it,” the rebate funds have been exhausted, he said. The state needs to set aside funds specifically for fast-charging projects in underserved communities “so that they can participate in the future as well,” Francis said.
