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October 9, 2024

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New York Regulators Deny Astoria, Danskammer Gas Projects’ Air Permits

New York regulators on Wednesday denied air permits for the Astoria and Danskammer Energy Center gas-fired generator projects, saying that the proposed facilities would not comply with the state’s climate law.

The projects “would be inconsistent with or would interfere with the statewide greenhouse gas emissions limits established in the Climate Leadership and Community Protection Act (CLCPA),” New York Department of Environmental Conservation Commissioner Basil Seggos said in a statement. Both developers “failed to demonstrate the need or justification” for their projects “notwithstanding this inconsistency,” he said.

The DEC issued draft air permits for both projects in July but asked for input on potential inconsistencies with the CLCPA.

Gov. Kathy Hochul applauded the decision.

“Climate change is the greatest challenge of our time, and we owe it to future generations to meet our nation-leading climate and emissions-reduction goals,” she said in a statement.

Danskammer Energy’s proposal sought to build a 536-MW natural gas-fired, combined cycle generation facility at the site of the existing 532-MW Danskammer Generating Station in Newburgh, N.Y. NRG Energy’s (NYSE:NRG) Astoria proposal included construction of a 437-MW simple cycle, dual-fuel peaking generator in Queens.

The department determined that the projects would be a new source of a “substantial amount” of direct and upstream GHG emissions, according to notices to Danskammer and NRG. In addition, the DEC said the projects would “constitute a new and long-term utilization of fossil fuels to produce electricity without a specific plan in place to comply with” the CLCPA.

As presented, the department said, the developers’ plans to meet the CLCPA’s requirement to be emission-free by 2040 are “uncertain and speculative in nature.”

NRG “simply assumes that, prior to 2040, the project will be able to utilize hydrogen, renewable natural gas or some other fuel that is considered zero-emissions under the climate act,” the DEC said, while Danskammer has not established the feasibility of using hydrogen or RNG from a supply or GHG emission perspective.

NRG is reviewing the state’s decision, according to Tom Atkins, vice president of development.

“It’s unfortunate that New York is turning down an opportunity to dramatically reduce pollution and strengthen reliable power for millions of New Yorkers at such a critical time,” Atkins said in a statement to NetZero Insider.

The Astoria project would have been fully convertible to green hydrogen in the future, according to Atkins.

“New Yorkers deserve both cleaner air and reliable energy to ensure the lights stay on for our small businesses, homes, schools and hospitals when they need it most,” he said. “That’s what this project would have delivered, and that’s what NRG had been fighting for along with labor leaders, the small business community and local Queens residents. We appreciate their support during this difficult process.”

The company, he said, is “deeply disappointed” in the department’s decision.

“NRG will continue to find ways to help New York achieve its emissions goals,” he said. “In the meantime, our current Astoria plant will continue to operate to help ensure the lights stay on in New York City, as that remains the most important thing.”

Danskammer Energy did not respond to a request for comment on the DEC’s decision.

Reactions

The DEC was “right to reject” the applications, Peter Iwanowicz, executive director of Environmental Advocates NY, said in a statement.

“This is a tremendous decision by DEC and another for the growing list of the Hochul administration’s actions that will provide clean air and a healthful environment for the 20 million people that call New York home,” he said.

The decision to deny the air permits “tees up similar outcomes” for other projects in the permitting process, such as the Gowanus repowering project in Brooklyn, Sierra Club said in a statement.

Astoria Generating, a wholly owned subsidiary of Eastern Generation, filed a plan with the New York Department of Public Service in 2018 to replace 32 oil and gas generating units at the 640-MW Gowanus facility with eight gas-powered units (Case 18-02956). Gowanus is sited on four floating barges moored in Gowanus Bay in Brooklyn.

“Gov. Hochul made clear that fracked gas power plants have no place in New York’s energy future, heeding the call of environmental justice and climate advocates and community members who organized tirelessly for this climate victory,” said Allison Considine, New York campaign representative with Sierra Club.

Given previous remarks by Seggos on the Danskammer project, the DEC’s decision was not surprising, according to a statement from State Sen. James Skoufis (D).

“I stand ready to partner with local communities, buildings trades and environmental stakeholders to put forward a project for the existing Danskammer site that both aligns with New York’s climate laws and serves the needs of our area,” he said.

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MISO Warns of January Emergency Procedures

MISO said an emergency declaration is likely in January if harsh weather collides with unforeseen generation outages.

Senior Director of Operations Planning J.T. Smith said the RTO expects to use load-modifying resources (LMRs), which require a maximum generation declaration, this winter.

“It’s not a one-out-of-50 scenarios. There’s a number of scenarios that put us there,” Smith told stakeholders during a virtual winter readiness workshop Tuesday.

But MISO’s Tim Bachus said the RTO should have enough capacity if the coming winter is in line with historical averages. Under normal circumstances, the grid operator predicts it will have 105 GW of capacity to cover a 94-GW peak in December; 106 GW to handle a 101-GW peak in January; and 108 GW to manage a 95-GW peak in February.

Staff estimates available capacity using average monthly generation outages during peak periods over the last five years.

However, MISO said it could find itself a gigawatt short of non-emergency resources in January if weather conditions drive load to 107 GW. If high generation outages are paired with that load, not even an emergency declaration and 11 GW of LMRs could cover demand, staff said. In a worst-case scenario, MISO could experience 107 GW of demand in January and have just 88 GW in non-emergency resources available.

The grid operator’s all-time winter peak of 109 GW occurred in January 2014.

“I think January might be a little challenging,” Bachus said. He added that MISO doesn’t include the 3-9 GW in non-firm imports it usually can access in a pinch.

“We didn’t include that because we want to be conservative,” he said, adding that the RTO’s neighbors are likely to experience emergency conditions when MISO does.

Bachus said MISO is entering this winter with 8 GW additional generation over last winter, mostly from renewable resources. But he said there’s a “significant” 10 GW of capacity that could become trapped in the South region behind the subregional transfer limit because of power-balance challenges.

The National Oceanic and Atmospheric Administration is forecasting an unremarkable winter in terms of temperatures, with a slight increased chance for precipitation in the northern parts of the footprint and a decreased chance for precipitation in MISO South.

“We don’t see any large chances for significant events, at least based on the forecast,” Bachus said.

Preparations stemming from February’s pervasive cold snap that forced MISO to shed load loomed large during the workshop. NERC’s new cold weather standards aren’t set to be effective until April 2023.

Staff said this year’s winterization generation survey indicates that most generation owners are better prepared for winter than in past years.

Smith said MISO will increase efforts this winter to reach out to generation operators to understand their fuel procurement status and weatherization preparedness before harsh weather hits.

He said higher natural gas prices this year will likely force some resource owners to procure coal instead of gas.

“Spot purchases might be difficult this winter,” Smith said. “It’s starting to be a concern, and I think some folks are starting to take action around that.”

This winter, MISO will track whether resources are available during the season’s tightest hours to calculate a new availability-based resource accreditation for its capacity market. Staff plans to file for the new accreditation process, a four-season capacity auction, and a minimum capacity requirement no later than Dec. 1. (See MISO Extends Seasonal Auction Discussions.)

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Ann Arbor Considers ‘Sustainable Energy Utility’; Could Start in 2022

ANN ARBOR, Mich. — Ann Arbor is considering creating Michigan’s first “sustainable energy utility” (SEU) — a nonprofit, publicly owned agency that would promote and help finance energy efficiency, renewable power and microgrids.

The proposal is outlined in a report released earlier this month by Ann Arbor’s Office of Sustainability and Innovations (OSI), which concluded that an SEU would be “more reliable, cheaper, cleaner, more local and more equitable than our current energy system and than a traditional municipal utility.”

SEU vs. Municipal Utility, Community Choice Aggregation

An SEU has elements of a municipal utility, except that it would not own the poles, wires and other infrastructure. It also borrows elements of community choice aggregation (CCA).

Traditional municipal utilities own the electrical distribution infrastructure and sell electricity from third-party generators. Negotiations or court proceedings to determine the purchase price of an investor-owned utility’s assets can take years and cost millions, leaving the city with significant debt.

“A SEU is not about buying the IOU’s substations, circuits, poles and wires. It is not about investing in an outdated utility model with aging infrastructure,” the report said. “Instead, a SEU focuses investments in local energy generation (e.g., solar and geothermal), rigorous energy waste reduction measures, beneficial electrification and energy storage across a given geography (i.e., neighborhood, commercial corridor). The solar and energy storage systems could be installed for a single households or business, or, more ideally, be connected across each household or business through a series of microgrids.

“Over time, the SEU could grow to support additional initiatives such as district geothermal systems or other programs and initiatives desired by the community,” it added.

A-sustainable-energy-utility-(Ann-Arbor-Sustainable-Energy-Utility-report)-Content.jpgA sustainable energy utility — a nonprofit, publicly owned agency focused on providing locally sourced renewable power and microgrids to improve resiliency — has elements of a municipal utility and Community Choice Aggregation. | Ann Arbor Sustainable Energy Utility report

Like SEUs, CCAs do not purchase infrastructure. CCA customers can obtain renewable energy from a third party, paying the existing utility for delivering the power. But unlike SEUs, CCAs don’t have the authority to offer on-bill financing or other powers that are restricted to utilities. On-bill financing allows the cost of the improvements — such as more efficient windows and appliances — to be financed in part through energy savings and to stay with the home, as opposed to the resident. It can fund energy efficiency programs for underserved markets, such as rental housing.

An SEU can also offer financing with longer paybacks, overcoming an obstacle to more extensive retrofits.

Frustration with DTE

The city says the resilience offered by microgrids is central to an SEU’s appeal.

OSI Director Missy Stults said the release of the report was moved up in part because the city saw a number of power outages over the summer months during major storms.

“People are very frustrated with DTE” Energy (NYSE:DTE), the current utility, Ann Arbor City Councilmember Jen Eyer said. “The frequency with which we lose power is unacceptable.”

Asked to respond to the complaints, Brian Calka, director of renewable energy solutions at DTE, said, “DTE and the city of Ann Arbor have been partners with respect to clean energy for a number of years. We are working very extensively with their environmental sustainability office.”

“We continue to have significant dialogue with the city, and we definitely expect we will continue to engage with the city of Ann Arbor to help them achieve their particular carbon-neutrality goals by the end of this particular decade,” Calka said at a press conference DTE held with CMS Energy on community solar projects statewide.

Calka cited the Oct. 4 announcement of a new community solar project, to be built by the city and DTE. Stults said the project, which is expected to begin operations in 2023, may be part of an Ann Arbor SEU.

The city envisions the SEU as a “parallel” to DTE, allowing customers to use solar in the daytime, draw from batteries at night and use DTE’s electricity when local generation and storage can’t meet demand.

“When DTE has a power outage, SEU users still get power from the shared battery and solar systems,” the report said. “Over time, the system could become a closed microgrid loop that has limited to no connection to DTE’s grid.”

Local Generation Capacity

Creating an SEU would also help the city reach carbon-neutrality by 2030, a goal the City Council set in 2019 when it unanimously declared a climate emergency. That proposal called for the city to generate 78 MW through renewable sources on “viable buildings, parcels of land and carports.”

The city estimates rooftop solar could produce 400 MW, “one-third of total electricity consumption for residential, commercial and industrial users, along with the University of Michigan.” It cites Google’s Project Sunroof, which estimates that 71% of the roofs in the city, including residential and commercial buildings, are “solar viable” and that 60% of rooftops can support a system of over 5 kW.

Ann Arbor, a city of about 121,000, needs about 440 MW to meet its needs now, Stults said.

Community-wide-greenhouse-gas-emissions-(Ann-Arbor-Sustainable-Energy-Utility-report)-Content.jpgCommunity-wide greenhouse gas emissions by source | Ann Arbor Sustainable Energy Utility report

The report contends an SEU could offer cheaper rates than DTE because “the SEU would not be concerned about profits to shareholders, maintaining aging assets, paying depreciation for the coal generation facilities that are being retired earlier than planned or upgrading large-scale distribution systems.

“The SEU would be laser-focused on generating energy from the cheapest sources available (energy waste reduction and renewables),” it added. “Our residents’ exposure to anticipated price escalations from fossil fuel generation feeding the grid would be greatly reduced — as would their vulnerability to larger and more prolonged grid outages that climate change is already bringing to Ann Arbor.”

The city said a community-wide rooftop solar installation program could reduce installation costs to $2/W, resulting in a levelized cost of energy of 5 cents/kWh, about one-third of DTE’s retail rate. “Bundling electrification and energy waste reduction upgrades with rooftop solar could reduce the incremental cost of electrification and generate cost savings,” it said.

Next Steps

There are still several steps to take before the city could begin SEU operations. The city’s Energy Commission is expected to propose to the City Council this fall that a feasibility study be done. Stults said residents will also be surveyed on their interest in alternatives to DTE.

There are only a few other SEUs in the U.S., and their focus is on energy efficiency more than generation.

The Delaware Sustainable Energy  Utility and the  D.C. Sustainable Energy Utility provide energy audits, rebates on new heating or cooling systems, programs for low-income households, and low interest loans and grants for solar and geothermal. “These SEUs operate in areas with more flexible legal frameworks than Michigan,” the report says.

Stults said that under Michigan law, a utility has to “sell power. And the only way to sell power [under Michigan law] is to generate power.”

Other SEU initiatives include the Sonoma County (Calif.) Efficiency Financing (SCEF) program, the California Statewide Communities Development Authority and the Pennsylvania Sustainable Energy Finance program.

Because Ann Arbor’s SEU would be the first in Michigan, the city acknowledges it “does not have a precise legal precedent.” But it said it can avoid challenges with the Michigan Legislature and use existing authority to begin work immediately.

Creating a CCA would require state legislation that the report says “would almost certainly face strong opposition from incumbent utilities” and could take years. In contrast, an SEU could be operating by the end of 2022, Stults said.

If CCA legislation is later enacted, the city could use it to procure renewable energy to fill demand not met by the SEU. “Thus, CCA and SEU are not competing strategies — but strategies that can be pursued simultaneously,” the report said.

How to raise startup financing for an SEU has not yet been considered. A referendum is expected in spring 2022 on Mayor Christopher Taylor’s proposed property tax increase to help pay for the city’s net-zero plan. Stults said the SEU could get some initial seed money from the millage, but under state law it would have to repay that because utilities must be self-sufficient.

Other sources for startup funding could include philanthropic donations or selling bonds, she said.

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‘Connected Communities’ Get $61M in DOE Funding

PacifiCorp will receive $6.42 million in Department of Energy funding for a “connected communities” pilot project in Utah that will span apartment buildings, a manufacturing facility, a university laboratory and a mass transit center.

The funding is part of $61 million that DOE has awarded to 10 connected community pilot projects across the U.S. The department announced the funding this month.

Connected communities tie together a group of grid-interactive efficient buildings (GEBs). In addition to improving the energy efficiency of buildings, connected communities use smart controls, sensors and analytics to communicate with the electrical grid.

The goal is to optimize distributed energy resources and reduce the amount of energy needed during periods of peak demand. Utility bills and grid system costs may fall as a result, DOE said.

PacifiCorp’s connected communities project is expected to produce more than 8 MW of flexible load — the highest amount among the 10 pilot projects.

James Campbell, director of innovation and sustainability policy at PacifiCorp subsidiary Rocky Mountain Power, described connected communities as “the grid of the future.”

Smart grids, coupled with increasing amounts of renewable energy, are needed to hit greenhouse gas reduction targets, Campbell said Tuesday during a DOE press conference on the Utah pilot project.

The project includes a diverse group of buildings in the Salt Lake City area. At the Soleil Lofts, an upscale apartment complex in Herriman, rooftop solar and batteries in each unit will run all the appliances and air conditioning, Campbell said.

Soleil Lofts will be connected with a downtown affordable housing project in partnership with the developer, the Giv Group. The connected community will also include a downtown transit station that is a hub for electric trains and where electric buses are being introduced.

Another component of the pilot project is a research lab at Utah State University, which already has a microgrid, as well as an industrial building on the west side of Salt Lake City.

“How do we connect those together, almost in a symphony, to optimize and stabilize the grid?” Campbell said. “So we can actually lower the costs for everybody and also so we can bring on more renewable energy.”

Cybersecurity will be another focus of the project, according to Campbell, who noted the number of components such as solar panels and EV chargers that will be connected directly to the grid.

Rocky Mountain Power will work with the National Association of State Energy Officials (NASEO) and the Edison Electric Institute to evaluate whether the model is one that can be replicated elsewhere.

GEB Interest Growing

The announcement of DOE funding for connected communities projects comes as interest in GEBs is growing. DOE released a report in May laying out a national roadmap for GEBs.

DOE has estimated that GEBs could save up to $18 billion per year in power system costs by 2030 and slash carbon emissions by 80 million tons each year. Buildings account for about 74% of electricity use in the U.S. and 35% of the nation’s energy-related CO2 emissions, the department said.

In California, the state’s Energy Commission held an all-day workshop this month to discuss GEBs. DOE received hundreds of applications for connected communities funding, a department official said during the workshop. (See CEC Explores Grid-interactive Efficient Buildings.)

The 10 projects selected for funding will explore the potential benefits of GEBs across a range of locations, building types and technologies, DOE said in announcing the awards.

“These projects will help universalize technology that can maximize the efficiency and sustainability of America’s nearly 130 million buildings and make significant headway in the fight against climate change,” U.S. Secretary of Energy Jennifer Granholm said in a statement.

Equity Component

In addition, several of the selected projects will bring the economic benefits of GEBs to low-income communities, DOE noted.

One of those is a proposal from the Electric Power Research Institute (EPRI), which will receive $5.27 million for pilot projects in New York City, Seattle and San Diego.

The project will involve retrofitting existing affordable housing complexes in each city into more efficient and connected communities.

As part of the project, EPRI will use data analytics and community energy simulations to help predict the value of energy efficiency, distributed generation and electrification investments, according to Ben Clarin, EPRI’s principal project manager of advanced buildings.

The project will provide technologies such as advanced heat pumps, building envelope systems, water heating systems, and appliances as a way to increase energy efficiency, reduce energy bills, and improve indoor air quality for the communities.

“Finally, the project will look at developing viable business models, knowledge transfer tools, and best practices of how affordable housing providers, community stakeholder groups, and energy companies can work together to develop scalable connected community programs across the country,” Clarin said in an email.

Other Projects

Other connected community pilot projects across the U.S. are receiving DOE funding.

In North Carolina, Ibacos Inc. will test a coordinated control program to optimize the energy use of a variety of distributed energy resources in 1,000 homes in Duke Energy’s service area. The homes are a mix of new and existing buildings, single-family and multifamily homes, and owner-occupied and rental units. The company will receive $6.65 million.

In Oregon, Portland General Electric will receive $6.65 million to renovate more than 500 buildings in North Portland’s historically underserved neighborhoods. The buildings will be upgraded with energy efficiency measures and connected devices.

Ohio State University will receive $4.2 million to see whether its existing on-campus connected community can provide grid services such as frequency regulation, synchronized reserve, and energy and capacity markets participation in a cyber- and data-secure manner.

In California, SunPower Corp. will receive $6.65 million to help develop more than 230 homes in two communities that meet DOE’s zero-energy-ready home qualifications. The project will include solar energy, home energy management systems and community-scale battery storage.

Information on all 10 projects is available here.

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Maryland Looking at New, All-electric Building Code

Maryland’s Climate Change Commission should recommend the General Assembly order the Building Code Administration to adopt an all-electric construction code, according to one of its working groups.

An overhauled code would ensure “that new buildings meet all water and space heating demand without the use of fossil fuels. A cost-effectiveness test would allow building projects to seek variances to code requirements while maintaining electric-ready standards,” the commission’s Greenhouse Gas Mitigation Work Group (MWG) said in a report on building decarbonization it approved Oct. 13 for submission to the full commission.

The MWG advanced the plan following a series of meetings earlier this year in which the consultancy Energy and Environmental Economics (E3) presented several scenarios for building decarbonization. (See Maryland Looks at Pathways to Net Zero Buildings by 2045.)

One was a high-electrification scenario, in which almost all buildings would switch to air-source or ground-source heat pumps; a second involved electrification with gas backup, in which existing buildings would keep using fuels for heating, albeit with heat pump backups, while new buildings would be required to have all-electric heat; and a third involved high decarbonized methane, in which buildings would keep using fuels for heating, but fossil fuels would gradually be replaced by low-carbon renewable fuels.

Least-cost Plan

In the end, however, the MWG’s Buildings Sub-Group adopted its own, least-cost vision, in consultation with E3. It is based on “four core concepts”:

  • “ensure an equitable and just transition, especially for low-income households”;
  • “construct new buildings to meet space and water heating demand without fossil fuels”;
  • “replace almost all fossil fuel heaters with heat pumps in existing homes by 2045”; and
  • “implement a flexible building emissions standard for commercial buildings.”

According to E3, under the plan Maryland would reduce emissions from residential and commercial buildings by 95% by 2045. Gas system investments would be reduced enough to save about $1 billion annually, money that could be reinvested to ramp up electricity system investments. Electricity rates would go up by only 2 cents/kWh, while construction and energy costs would go down for most building types, and gas rates would be lower than all the scenarios E3 modeled.

To get there, the MWG suggested the commission make four core recommendations to the General Assembly, including the proposed all-electric construction code.

The second is to develop a clean heat retrofit program, which would require the legislature to reauthorize the EmPOWER Maryland energy-efficiency program to continue after 2023. It would also have to encourage fuel-switching and beneficial electrification through EmPOWER beginning in 2024, targeting 50% of residential heating and cooling systems and water heater sales to be heat pumps by 2025, rising to 95% by 2030. By that same year, 100% of low-income houses would have to be retrofitted with clean heat.

A third recommendation is to have the Maryland Department of the Environment create a building emissions standard, under which state-owned buildings would have to achieve net-zero emissions by 2035 and commercial and multifamily residential buildings by 2040. An interim goal of a 50% reduction in direct emissions from covered, non-state-owned buildings by 2030 was removed at the Oct. 13 session and will instead be considered for review in the 2022 MWG Work Plan.

“The General Assembly should also provide tax incentives and resources to help owners of covered buildings develop and implement emissions reduction measures,” the report says. “An alternative compliance pathway would be available to allow covered buildings to continue using fossil fuels when emissions reduction measures are unnecessarily expensive.”

Finally, the MWG recommended that the Public Service Commission develop a utility transition plan “whereby the electric and gas utility companies develop plans for achieving a structured and just transition to a near-zero emissions buildings sector in Maryland.”

The Climate Change Commission had not received broader recommendations for greenhouse gas reductions by the official Wednesday deadline for inclusion in its upcoming annual report. Most work group members did not feel ready to vote Tuesday on a sweeping set of recommendations covering everything from water and soil management to the Regional Greenhouse Gas Initiative. Susan Casey, director of communications for the Climate Change Program at the Maryland Department of the Environment, told NetZero Insider in an email that those recommendations need more clarification before a vote.

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Virginia Builds out OSW Supply Chain with Turbine Blade Plant

The buildout of a homegrown U.S. supply chain for offshore wind took a big step forward Monday with the announcement that Siemens Gamesa Renewable Energy (SGRE) will establish a new plant for offshore wind blades at the Portsmouth Marine Terminal in Virginia.

The facility, the first of its kind in the U.S., was announced by Gov. Ralph Northam at a press event on Monday at the terminal, which is located on the southern end of the Virginia coast. The plant will be a “finishing” facility, where blades manufactured elsewhere are painted and assembled prior to installation, according to Steve Dayney, head of offshore wind for Siemens Gamesa North America.

On completion, the plant will be capable of finishing blades for 100 turbines per year, and its initial output will go to Dominion Energy’s 2.6 GW Coastal Virginia Offshore Wind (CVOW) project, Dayney said in an email to NetZero Insider. Dominion selected Siemens Gamesa as turbine supplier for the project in January 2020.

Monday’s announcement also comes two months to the day after Dominion’s parallel commitment to lease 72 acres at the Portsmouth terminal to be used for staging and assembly on CVOW.   (See Dominion Secures 10-Year Va. Port Lease for OSW Staging.)

Northam hailed the two companies’ work on the project as “the most important clean-energy partnership in the United States. This is good news for energy customers, the union workers who will bring this project to life and our business partners.”

SGRE will be investing around $200 million in the plant, which will create 310 permanent positions, according to a company press release. The project timeline and number of temporary jobs to be created during the construction phase of the facility have yet to be determined but will be keyed to progress on CVOW, Dayney said.

Both he and Energy Secretary Jennifer Granholm linked Monday’s announcement to the ongoing negotiations in Congress over the budget reconciliation package, which could still provide funding for major clean energy provisions in President Joe Biden’s Build Back Better agenda.

Supporting the president’s agenda, Granholm said, would show “that the United States is open for clean energy business. Virginia is helping lead the way to strengthen the nation’s domestic supply chains for renewable energy and keep energy prices affordable for American households as we strive for a cleaner future.”

“As Congress considers taking historic action on climate, this facility evidences that offshore wind can create significant new manufacturing activity and quality jobs [for] American communities,” Dayney said. “We are hopeful this commitment will lead to further action by federal and state policy makers to establish policies to provide long-term certainty and help sustain the competitiveness of this facility in the global marketplace for decades to come.”

30 GW by 2030

Certainty — from policy makers and investors — is critical to Europe’s offshore giants like Siemens Gamesa, which is based in Spain, and Ørsted, from Denmark, as they compete for projects in a U.S. market that could accelerate rapidly as it pursues Biden’s goal of deploying 30 GW of offshore wind by 2030.

Both companies are planning facilities on the Atlantic Coast, with Ørsted recently announcing an investment of close to $70 million in Crystal Steel, a company on Maryland’s Eastern Shore. The money will be used to expand Crystal’s plant — and hire 50 new employees — to provide steel for projects to be located off the Maryland and New Jersey coasts.

Similarly, Virginia, New Jersey and other East Coast states are in heated competition to become the supply chain and operations hub for offshore wind on the Atlantic coast.

Speaking before the House Energy and Commerce Committee on Oct. 21, David Hardy, CEO of Ørsted North America, said his company is following a two-pronged approach to building a U.S. supply chain, expanding the capacity of U.S. partners such as Crystal Steel, while also bringing other European companies into the market.

But echoing Dayney, Hardy said building out the U.S. supply chain will take time, regulatory certainty and incentives, noting that Europe’s mature offshore supply chain took decades to build. (See House E&C Hearing Pits Offshore Wind Against High Energy Prices.)

The turbine blades to be finished in SGRE’s Virginia facility could come from European plants where the company casts the massive blades that could be used for CVOW, pending finalization of the supply contract with Dominion.

Again, Dayney declined to provide details on the kind and size of the blades that will be used for CVOW. But, according to the company website, its offshore blades are made from fiberglass and epoxy resin, cast in one piece. The newest models being rolled out in the next few years will top out at more than 100 meters or close to 330 feet.

Whether Siemens Gamesa will expand the finishing facility to include blade manufacturing will depend on whether the company wins contracts for future projects in Virginia or other East Coast states, Dayney said. While recognizing the benefits of a U.S. supply chain, he said, “the establishment of a blade manufacturing facility, including casting, is a major investment, and SGRE has therefore decided to establish the facility through a phased approach.”

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FERC Accepts PJM BRA Delays

FERC on Monday approved PJM’s request to delay the Base Residual Auction for the 2023/24 delivery year from Dec. 1 to Jan. 25, 2022, in response to the commission’s order in September revising the RTO’s market seller offer cap (MSOC) (ER21-2877).

The commission also granted PJM’s request to delay the BRAs for 2024/25 from June 15, 2022, to Aug. 9, 2022; 2025/26 from Jan. 4, 2023, to Feb. 28, 2023; and 2026/27 from March 17, 2023, to Aug. 29, 2023. The order also delays the third Incremental Auction for delivery year 2023/24 from Feb. 27, 2023, to March 21, 2023.

PJM said in its filing that changing the dates was necessary to maintain the six-and-a-half-month gap between capacity auctions so that market participants “have sufficient time to review the results of each auction before deciding whether to continue offering a resource in the subsequent auction.” (See PJM Proposing 2-month Capacity Auction Delay.)

“We agree with PJM that granting the requested waivers is necessary to ensure orderly auction administration and that, on balance, the benefits outweigh potential harms,” the commission said.

Base-Residual-Auction-(PJM)-Content.jpgCurrent and proposed dates for the 2023/24 Base Residual Auction market seller offer cap-related pre-auction activities. | PJM

PJM is expected to return to the normal, three-year forward schedule in May 2024 with the BRA for the 2027/28 delivery year.

The commission is allowing PJM to use the monthly average day-ahead on-peak and off-peak energy prices that the RTO already calculated for the upcoming auction, rather than having it recalculate them to reflect the new date. PJM said the waiver was necessary to allow the pre-auction deadlines unrelated to the new offer cap rules to remain unchanged.

FERC also accepted PJM’s previously proposed pre-auction deadlines impacted by the revised MSOC that relate to the 2023/24 delivery year auction: Oct. 1 for capacity market sellers to request must-offer exceptions and unit-specific offer caps, Oct. 31 for the Independent Market Monitor to review those requests and Nov. 25 for the RTO to make its final determination.

“We agree with PJM that these dates will allow sellers sufficient time to make their requests and preserve the pre-existing review timelines as much as possible,” the commission said.

PJM’s request was prompted by FERC’s Sept. 2 order adopting the Monitor’s unit-specific avoidable-cost rate proposal and requiring the RTO to revise its tariff (EL19-47, EL19-63, ER21-2444). The Monitor’s proposal followed FERC’s March order requiring PJM to revise the MSOC to prevent sellers from exercising market power in the capacity market. (See FERC Backs PJM IMM on Market Power Claim.)

The Public Utilities Commission of Ohio (PUCO) challenged PJM’s filing, arguing that the proposed delays would harm the state’s auction process for default service. Ohio’s regulated electric distribution utilities “rely on a competitive bid auction process,” which occurs after the BRA for the relevant delivery year, to procure generation service for non-shopping customers that “take service from their default electric service provider,” it said.

FERC disagreed with PUCO’s arguments, saying that the potential harm noted by the state commission was “outweighed by the benefits of ensuring the 2023/24 BRA is run under the new offer cap rules.”

“We disagree with the Ohio commission that this waiver will cause additional uncertainty,” FERC said. “To the contrary, granting additional time now will provide certainty to participants that they will have sufficient time to seek remedy from the commission if necessary.”

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Global Companies Scale Toward 24-7 Clean Energy

U.S. companies with global operations are buying more renewable energy and partnering with international organizations to bring policymakers, regulators and supply chains into the commitment to fully decarbonize their activities by 2030.

Elements of a carbon-free energy system include local procurement, new installations and the creation of supply chains in different parts of the world, but it also includes creating demand, Kanika Chawla, program manager at Sustainable Energy for All, said Monday.

Chawla made her remarks on the first day of the week-long Verge 21 conference hosted by GreenBiz.

Policy and regulation should create a level of certainty for new technologies and act as “a nudge” for both markets and governments, Chawla said.

Even before the world woke up to the existential threat from climate change, “the General Assembly agreed that there needed to be a dialogue on energy … which actually ended up happening in 2021 because of COVID,” Chawla said. (See UN Hosts Energy Dialogue During General Assembly.)

She highlighted the 24/7 Carbon-free Energy (CFE) compact to match every hour of electricity consumption with carbon-free energy resources. The compact, Chawla said, is “a way for government, the private sector, financial institutions, procurers, energy companies as well as distribution companies — really the whole ecosystem — to come together and make a commitment that by 2030 we’re going to have a decarbonization of the electricity system.”

CFE signatories Iron Mountain, Microsoft and Google are demonstrating how to make 24/7 clean energy work, Chawla said. The compact has 20 other signatories;  Chawla said Sustainable Energy for All will announce an additional  20 at the 2021 United Nations Climate Change Conference (COP26).

COP26 is scheduled to be held in Glasgow, Scotland, between Oct. 31 and Nov. 12.

Small Steps at First

Google is advocating for effective public policies to drive decarbonization of electricity grids across the world, said Devon Swezey, the company’s global energy markets and policy lead.

“We think that policy is really essential to enabling 24/7 carbon-free energy for everyone, and that’s why recently we partnered with Sustainable Energy for All and other partners, including Iron Mountain, to launch the 24/7 CFE compact,” Swezey said.

Google has been carbon neutral since 2007, initially through the purchase of carbon offsets, Swezey said. In 2010, it was one of the first companies to purchase renewable energy directly through a power purchase agreement, and in 2017, it met an earlier goal to match 100% of its global annual electricity consumption with renewable energy purchases, he said.

“First, we are innovating in the way we purchase clean energy, and this includes signing a first-of-its-kind agreement with AES Corp.’s (NYSE: AES) renewable energy development business in PJM, which will combine a portfolio of different clean energy technologies to collectively guarantee that by 2024 we will be operating on 90% hourly carbon-free energy around the clock,” Swezey said.

Second, Google is working to accelerate technology innovation, which includes developing a next-generation geothermal power project with clean energy startup Furbo Energy. The project will deliver around-the-clock clean electricity to the power grid that serves data centers in Nevada.

“We’re also developing a carbon-aware computing platform to make our own electricity demand more flexible and better align it to times of day or places where the grid is cleanest, and we think the planned flexibility can go a long way in helping us achieve the goal,” Swezey said.

People know the environmental and economic costs of climate change, but the business perspective may differ, said panel moderator Bob Keefe, executive director of environmental engineering cooperative E2.

“Tell us why it is important to your companies to do this, either from an efficiency standpoint or bottom-line standpoint,” Keefe said. “How do you bring suppliers along, and what should they be pushing for?”

An important area is the development of data that can add a very granular level to identifying where investments are going to have the greatest grid-scale, society-wide decarbonization impact, said Avi Allison, program manager for energy and sustainability at Microsoft.

“I think 24/7 commitments can be one step in the journey towards decarbonization,” Allison said. “I don’t view them as a sufficient step or even a strictly necessary step, but they are helpful for driving clear procurement for now, and I think we need better tools to help us better target those investments.”

“To kickstart a virtuous cycle,” the three priorities are tracking clean energy production on an hourly basis; identifying the grid-specific emission rate at the time when the production is happening; and developing scalable products that can help others to achieve similar commitments and drive toward grid-scale decarbonization, Allison said.

Business services firm Iron Mountain runs 18 large data centers around the world and sees itself as a critical piece of its clients’ energy supply chain, said Chris Pennington, the company’s director of energy and sustainability.

“We use that scale that we have as a large energy buyer to help make as much of a positive impact from an environmental standpoint as we can, and then pass the benefits of that through to our clients who are using the energy inside our facilities,” Pennington said. “That’s … a bit of the reason why we adopted this 24/7 carbon-free energy commitment, because we think that this is the energy that our clients will be wanting to buy on their own going forward.”

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AEP to Sell Kentucky Operations to Algonquin

American Electric Power (NASDAQ:AEP) said Tuesday it has entered into an agreement to sell its Kentucky operations to Algonquin Power & Utilities (NYSE:AQN) for $2.85 billion.

Kentucky Power serves about 165,000 customers in 20 eastern counties and is easily the smallest of AEP’s seven operating companies. AEP Kentucky Transco is a regulated transmission business operating exclusively in the state.

Algonquin’s regulated utility business, Liberty Utilities, will acquire both subsidiaries. The sale is expected to close in the second quarter of 2022, pending regulatory approvals.

AEP said it expects to net approximately $1.45 billion in cash after taxes and transaction fees. Its CEO, Nick Akins, said the sale strengthens the Columbus, Ohio-based company’s “ability to invest in projects that will support a resilient, cleaner energy system.”

The transaction’s proceeds will be used to eliminate AEP’s forecasted equity needs in 2022 as the company invests in regulated renewables, transmission and other projects, the company said.

Kentucky Power owns 1,075 MW of generation, including Big Sandy, a 295-MW gas-fired facility that burned coal as late as 2015. It also operates and owns 50% of the 1.56-GW coal-fired Mitchell plant.

The sale must be approved by Kentucky regulators and FERC and is also subject to clearance under the Hart-Scott-Rodino Antitrust Improvements Act of 1976 and from the Committee on Foreign Investment in the United States.

AEP said in April it was conducting a strategic review of its Kentucky operations. It held a competitive process as part of the review. (See AEP’s Akins Lambasts FERC’s RTO Adder Proposal in Earnings Call.)

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Michigan Senate OKs Transmission ROFR for Incumbent TOs

LANSING, Mich. — Michigan’s Senate on Tuesday voted 28-6 to grant incumbent transmission owners the right of first refusal (ROFR) to build and operate new transmission lines in the state — legislation that could particularly boost the fortunes of ITC Holdings and American Transmission Co.

There were no comments during the floor vote on the Transmission Infrastructure Planning Act (TIPA) (SB 103). The bill, which was opposed by the most conservative Republican members, now goes to the House of Representatives, which under the state constitution must wait at least five days before acting.

The bill would apply to “regionally cost-shared” transmission projects, such as those resulting from MISO’s Transmission Expansion Plan. It takes advantage of the exception under FERC Order 1000 that allows states to create a ROFR. The order prohibited such rights in tariffs filed with the commission in a bid to create competition, although some incumbents have recently urged FERC to reverse the prohibition in the commission’s Advance Notice of Proposed Rulemaking proceeding. (See FERC Tx Inquiry: Consensus on Need for Change, Discord over Solutions.)

ITC-Michigan-at-a-Glance-(ITC-Holdings)-Content.jpgITC Holdings

Sen. Wayne Schmidt (R), who co-sponsored the bill with Sen. Curtis Hertel (D), told RTO Insider that Michigan “will need more transmission, with growing electrification, especially with electric vehicles.” The legislation would give the state “a more organized way” to develop additional transmission, he said.

Schmidt also said it could assure a more orderly system in building transmission lines, avoiding a “patchwork system.”  It can take five to 10 years to get transmission lines built and operating, he said.

The bill was reported from the Senate Energy and Technology Committee on an 8-2 vote Oct. 6, with all of the panel’s Democrats and all but two Republicans in support. The opponents did not explain their opposition and have not responded to several requests for comment.

The minutes of the committee’s Sept. 21 meeting show the bill was supported by the state’s three biggest transmission operators: ITC, ATC and Xcel Energy (NASDAQ:XEL). ITC CEO Linda Apsey and ITC Michigan President Simon Whitelocke testified on behalf of the bill.

Whitelocke told RTO Insider the bill was supported by “over a dozen entities across Michigan,” including General Motors; Johnson Controls; the Michigan Forest Products Council; IBEW locals 876, 17 and 223; Utility Line Contractors; and the Michigan Chamber of Commerce, in addition to ATC and Xcel.

“SB 103 will ensure that utilities with a proven track record in the state are allowed to construct any future high-voltage transmission projects,” Whitelocke said in a statement. “Adopting a TIPA provision preserves Michigan’s right to decide who builds, owns and operates these systems and where they should be built. This provides benefits in terms of efficiency, planning, development, operation and maintenance of the grid, while protecting landowner interests and meeting the needs of energy consumers.”

ITC-Michigan-Tx-Map-(ITC-Holdings)-Content.jpgITC Holdings’ ITC Transmission and Michigan Electric Transmission Co. serve most of Michigan’s Lower Peninsula through a network of about 8,700 circuit miles. The companies have made $5.5 billion in capital investments in the state since 2003. | ITC Holdings

ITC Transmission and Michigan Electric Transmission Co. serve most of the state’s Lower Peninsula with a network of about 8,700 circuit miles. The companies have made $5.5 billion in capital investments in the state since 2003. ITC is a unit of Fortis (NYSE:FTS).

ATC, which provides transmission in the Upper Peninsula, and Xcel, which has about 110 miles of transmission line in the state serving about 9,000 electric customers, did not respond to requests for comment.

The Michigan Chemistry Council and the conservative Mackinac Center for Public Policy testified against the bill.

The Chemistry Council acknowledges “there remain barriers to transmission planning and development and particularly with the implementation of FERC Order 1000,” Executive Director John Dulmes told RTO Insider. “But our members have long advocated for greater energy competition, and we don’t believe the answer is a state ROFR law that eliminates the benefits of competitive transmission development. We are hopeful that the FERC ANOPR will yield constructive reforms for the benefit of ratepayers across Michigan and the nation.”

The council said it supports House Bills 4806 and 4807, which it said would allow any MISO-qualified transmission developer to exercise eminent domain for competitive transmission projects. “We believe it only makes sense to open up this authority for all qualified developers, as was done in 2004 when the new independent transmission companies (like ITC and ATC) were spun off of the incumbent utilities,” the council said in its written testimony.

Transmission lines built and operated under the legislation would remain subject to the state Public Service Commission’s rules on cost accountability. If the PSC successfully files a complaint against a line or a line owner with FERC, the bill stipulates the company will need reimburse the state commission for up to $25,000 in legal costs.

PSC spokesman Matt Helms said the commission is neutral on the bill.

At one of the first Senate committee meetings on the bill, Mike Byrne, COO of the commission, said the state would need additional generation and therefore transmission as the economy becomes more electrified. He also said more transmission would provide resilience in the grid during extreme weather events such as the massive rainstorms that caused outages in the state in August.

Several other Midwestern states, including Iowa and Minnesota, have similar legislation, Sen. Schmidt said. However, Iowa’s law is the subject of a legal challenge filed in November 2020 by LS Power Midcontinent and Southwest Transmission, based in St. Louis. LS Power is challenging the law on procedural grounds, saying the ROFR provisions were improperly included in an omnibus budget bill. ITC’s Iowa-based Midwest unit and Des Moines-based Mid-American Energy have filed to intervene to protect their ROFR rights.

In 2020, the 8th U.S. Circuit Court of Appeals upheld Minnesota’s ROFR law, affirming a lower court’s 2018 decision. (See Courts Uphold Minn. ROFR, MISO Cost Allocation.)

CMS Energy, Michigan’s largest utility, is neutral on the bill, spokeswoman Katie Carey said. DTE Energy did not respond to a request for comment. The two utilities sold their transmission assets to ITC and no longer own transmission in the state.

According to the Michigan Campaign Finance Database, Schmidt has received $6,500 in campaign contributions from ITC Holdings PAC, and Hertel received $2,500 since 2018, the year of their last elections. Both senators are term-limited and cannot seek re-election next year.