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April 13, 2026

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Ohio Lawmakers Slow Utility-scale Wind and Solar

Wind and solar developers that want to build utility-scale projects in rural Ohio must first check in with local county commissioners, rather than the state agency that has overseen utility power plant and pipeline projects since 1972, under legislation approved Tuesday during the last minutes of the state’s spring legislative session.

S.B. 52 — introduced in February and amended and revised four times following hundreds of hours of testimony from farmers both for and against, as well as business and manufacturing organizations and growth associations — would create a local voice at the beginning of any future large wind and solar project in the state.

The bill passed the Ohio House of Representatives 52-44, with about 10 Republicans joining all Democrats in opposition. The Ohio Senate approved the newest version of the bill earlier in the day by a vote of 51-12, with four Republicans joining eight Democrats in opposition.

Under the legislation, which Gov. Mike DeWine (R) is expected to sign with an effective date in October, wind and solar developers must contact the boards of county commissioners in counties where the project would be located at least 90 days before filing an application with the Ohio Power Siting Board (OPSB).

The OPSB is an agency created 49 years ago within the Public Utilities Commission to regulate the siting of power plants, transmission lines and pipelines, none of which will be subject to the new hyper local regulation.

Under S.B. 52, the three-member boards would have 90 days either to approve, deny or modify the footprint of a wind or solar farm during a public meeting. That commission decision would be subject to a ballot referendum if at least 8% of those who voted in the most recent election petition the county’s board of elections.

If accepted by the county, project developers would then have up to 300 days to apply to the OPSB, which would begin another round of hearings, including local hearings and adjudicatory hearings in Columbus, which often include negotiations between developers, opponents and the OPSB staff. Applications before the OPSB are usually about 1,500 pages.

The new law would also give county commissioners the right to create “exclusion zones” within unincorporated portions of their county, permanently blocking any wind or solar development, subject again to a referendum vote.

The legislation would also require the OPSB to accept two “ad hoc” voting members when it votes on a wind or solar project. The two would be a county commission and a township trustee from the area impacted by a wind or solar farm. The OPSB includes seven voting members and four nonvoting legislators.

The bill also “grandfathers” a significant number of solar and wind projects already well along in the permitting process before the OPSB.

As originally proposed, the legislation would have required developers to seek permission in each township affected by a proposed development, a provision that prompted some developers testifying before Senate and House utility committee hearings to say they would simply leave Ohio if that became law.

Hundreds of rural residents opposed to an “invasion” of wind and solar projects appeared at Senate and later House committee hearings or sent written testimony in favor of the legislation.

A significant number of their neighbors also turned out to talk about property rights: that is, their right to lease portions of their property for wind or solar projects to create a steady revenue stream buttressing their not-so-steady farming revenue.

Several solar developers meanwhile created an ad hoc group, the Utility Scale Solar Energy Coalition of Ohio (USSEC), initially to oppose S.B. 52, which had quickly reached the Senate and was approved, while the companion legislation, H.B. 118, remained stuck in committee. The two bills were merged in a new version of S.B. 52, which was sent to the House floor this week after five days of hearings and negotiations with committee members who opposed the bill.

Solar developers took on the legislation early, creating an ad hoc group of project developers who testified against the legislation and met with lawmakers in recent weeks in an effort to blunt some the bill’s original provisions.

Following the passage of the legislation, USSEC Executive Director Jason Rafeld was cautiously optimistic about future development under the new law.

“Although the members [of USSEC] remain concerned that S.B. 52 contains numerous vehicles [that] would allow local governments to stop solar development without the benefit of accurate information, we appreciate the willingness of the legislature to engage in discussions and listen to the concerns of the solar development community,” he said in a brief statement Tuesday during an interview. “As a result of countless meetings with the sponsors and legislators, many solar projects will continue, thereby protecting the investment made by companies seeking to build solar energy projects in our state.”

Legislators’ Positions

The debates that began during the first committee hearings continued to the very end, especially on the House floor as one representative, William Seitz (R), tried without success to insert language in the bill allowing township trustees to add their township to “exclusion zones” created by county commissions. The measure, a repeat of what Seitz tried in committee, was soundly defeated.

Before the vote in the House, Rep. Craig Riedel (R), a co-sponsor of the legislation from northwest Ohio where there has been significant wind farm development, said renewable development had become a “quality-of-life issue” for many of his constituents.

“This legislation addresses the pressing issues of what will be done once a project is proposed and how local involvement can be installed in the Ohio Power Siting Board process.

“My constituents, and those throughout the state, are asking for a voice. … The beauty of this legislation is that it gives local control to elected county commissioners for them to decide what is best for their community,” he said.

Opposition among Democrats, most of whom represent suburban and metropolitan areas, never waned during the months of committee hearings. Before the House vote, Rep. Kent Smith (D) said the bill was simply unfair to renewable developers.

“I cannot support substitute Senate Bill 52 because it creates a legislative double standard, as it unfairly singles out wind and solar energy and imposes on only them additional regulatory processes, from which other forms of energy infrastructure are exempt,” he said.

“There is no reasonable justification for requiring that some energy technologies be subject to multiple overlapping forms of local and state control, while others are promoted and protected from local voices. A major concern with [the bill] is its impact on affordability and its subsequent harm that it’ll do to utility prices by erecting barriers to and injecting uncertainty in solar and wind development. It will significantly curtail supply of the most affordably priced generation available and therefore drive up costs.”

One reason for the solid Republican support of the bill may have been the stance of Senate President Matt Huffman (R), who has questioned the value of wind and solar generation and has been strongly opposed to the OPSB process. He vowed to introduce local controls months ago after residents in his district organized resistance to a proposed solar project in his home county.

In a news conference before S.B. 52 had been voted out of committee, Huffman explained in answer to a reporter’s question that the issue over wind and solar projects was “essentially a zoning issue” and should therefore be subject to local control.

“Almost all zoning questions … are always subject to … the question: Why does the government get to tell you what to do on your property?” he said before posing the rhetorical, “Will local jurisdictions have the same kind of control [over a wind or solar project] they would have if you’re going in to build a McDonald’s, if you’re going in to build a manufacturing plant or put in a new landfill? Will [local zoning boards] have the same kind of participation as they do with these projects?”

Huffman also said big wind and solar projects don’t produce enough energy, considering the amount of land they require.

“These projects don’t produce very much energy, and the energy they do produce is very expensive, and most of the projects aren’t financially viable without tax credits; essentially the federal taxpayer is paying for the project to be financially successful. Some wind projects independently are successful and they are built on industrial property. That fits well into our typical zoning,” he said.

Reaction

Reaction to the passage of the legislation from environmental groups was immediate and negative.

“The legislature keeps throwing up roadblocks to renewables, whether it’s through unnecessary, bad policy or, as was the case with H.B. 6, outright corruption, said Neil Waggoner, senior Ohio representative for the Sierra Club’s Beyond Coal Campaign, in a reference to the state’s nuclear and coal power plant bailout legislation approved in June 2019. That legislation led to the indictment on federal racketeering charges of the former House speaker and four others, as well as the firing of top executives at FirstEnergy, which is negotiating a “deferred prosecution” agreement with federal prosecutors.

“The state hasn’t had a real, future-focused energy policy for years,” Waggoner added. “Instead, we’re getting these single issue, haphazard bills like S.B. 52 that are being driven by politics rather than informed debate. We need to be talking about a comprehensive energy policy that reduces carbon, reduces energy waste, saves people money and supports communities impacted by Ohio’s move beyond coal. This legislature just proves over and over that they are not interested in that conversation.”

Daniel Sawmiller, the Natural Resources Defense Council’s director of energy policy in Ohio, said Gov. DeWine should veto the bill. “Solar and wind projects are some of the cleanest, least expensive forms of generating electricity today, and the leases for these projects are one of the greatest investment opportunities for Ohio farmers in a generation. But S.B. 52 gives local officials the ability to ban Ohio farmers from participating, and they don’t even have to give the landowners notice they are taking away those property rights,” he said in a reference to the county’s new authority to created the exclusion zones. “This rushed bill simply goes too far.”

Trish Demeter, chief of staff for the Ohio Environmental Council Action Fund, also urged a gubernatorial veto.

“The process laid out in S.B. 52 singles out solar and wind as the only sources of energy generation subject to local processes and approvals, despite extensive opportunity for public comment and careful, required review by the Ohio Power Siting Board,” she said in a statement.

“This unequal treatment hobbles our state’s ability to harness all the benefits of clean energy. Ohioans overwhelmingly support the transition to a clean, renewable energy future. But today, Ohio lawmakers voted to stifle renewable energy development in the Buckeye State once again. Air pollution will continue to harm Ohio families. We will continue to miss out on new tax revenue for Ohio communities, and we will fail to grow renewable energy careers — among the fastest growing job markets nationally — here in Ohio.”

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King, Mandia Warn of ‘Unlimited’ Cyber Dangers

With nation-state adversaries like China and Russia growing bolder and more experienced at electronic warfare, U.S. cybersecurity tactics need to evolve beyond the defensive, according to participants in a webinar on Tuesday.

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FireEye CEO Kevin Mandia | FireEye

“We’re all playing goalie, in both the public and private sector, trying to keep the ball from going in the goal, and the [adversary’s] getting unlimited penalty shots,” said Kevin Mandia, CEO of cybersecurity firm FireEye, in the Securing Cyberspace webinar hosted by The Washington Post.

The recent ransomware attacks on Colonial Pipeline and JBS USA were a major focus of discussion. Both have been connected to Russia by law enforcement. In the case of Colonial, malware implanted by the DarkSide criminal gang caused the company to shut down the network that delivers nearly 45% of the U.S. East Coast’s supply of fuel products in May. (See Glick Calls for Pipeline Cyber Standards After Colonial Attack.)

As for JBS USA — the U.S. division of the world’s largest meat company JBS, based in Brazil — the FBI confirmed the company was attacked earlier in June by a group using the REvil ransomware. While the Bureau’s original statement did not mention a nation-state affiliation for the hackers, the White House has since acknowledged that the malware “came from Russia.”

King Repeats Calls for Cyber Deterrent 

The ransomware attacks have spurred calls for a re-examination of U.S. critical infrastructure and its vulnerabilities to cyber intrusions. After the Colonial hack, experts suggested to ERO Insider that non-state actors should be considered a threat to national security on par with foreign militaries, and that this stance should be communicated to nation-states that seem to tolerate their presence, if not actively encouraging their activities. (See Experts Call for Cyber Shift in Response to Colonial Hack.)

President Biden seems to have a similar viewpoint. After his meeting with Russian President Vladimir Putin earlier this month, the White House reported that Biden had “laid down some clear markers” with his counterpart on “the capacities that we have should they choose not to take action against criminals who are attacking our critical infrastructure from Russian soil.”

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Senator Angus King (I-Maine) | U.S. Senate

In Tuesday’s webinar, Sen. Angus King (I-Maine) called Biden’s stance “a very important step” for a country that has provided “no real serious response” to years of attacks. Going further, he repeated his previous calls for the U.S. to establish a more active cybersecurity strategy, including a strong deterrent capability that can give pause to potential state and non-state threats before their next attacks.

“They’ve got to feel that they’re at risk. I want somebody in the Kremlin … to say, ‘Gee, boss, I’m not sure we ought to do this because we’re liable to get whacked in some way by those Americans if we follow through,’” King said. “The best cyberattack is the one that doesn’t happen.”

Pressed on whether this means a like-for-like response — paying back a cyberattack with a cyberattack, for instance, or crippling a rival’s infrastructure in retaliation for a similar attack on the U.S. — King clarified that he’s “not prepared to say it should be cyber for cyber.” The goal should be to make clear that the private companies that stand to be harmed the most by attacks on critical infrastructure will not stand alone as before but have the full support of the government, extending to retaliation if necessary.

“We’re really dealing with a new kind of conflict here,” King said. “Traditionally, conflict has been army against army, battleship against battleship. Now we’re really talking about a case where 75-85% of the target space is in the private sector. So we have to figure out a new relationship.”

Pros and Cons of Ransom Payments

The speakers were more ambivalent on the controversial issue of whether ransomware targets should pay attackers in order to unlock their systems and prevent the potential release of confidential information. Both Colonial and JBS admitted they did pay the ransom demanded of them: cryptocurrency valued at $4.4 million and $11 million, respectively.

Colonial CEO Joseph Blount faced tough questions about his decision to pay during a Senate hearing earlier this month where he called the payment “one of the toughest decisions I have had to make in my life.” (See Colonial CEO Welcomes Federal Cyber Assistance.) JBS expressed similar sentiments in a press release regarding its own ransom payment.

King and Mandia avoided blanket condemnation of the companies’ decisions. King called it “a tough call” for companies to make, and Mandia said that banning all ransomware payments “is not fair, nor will it have the desired outcomes.” But both stressed that paying ransoms simply reinforces the idea among bad actors that ransomware works, and will lead to further proliferation of such attacks in the future.

“From my vantage point, there’s so [many] ransomware actors; they’re acting with impunity; they’re acting without risks or repercussions,” Mandia said. “And I just believe wherever money goes, crime follows. So if you can hack and make a lot of money off of it, especially anonymously in safe harbors that are 10,000 miles away from where the crimes are being committed, it’s not going to stop.”

King said that rather than banning the payment of ransoms, the government should focus on “being tough” with companies “about preventing it from happening in the first place.” He was critical of the Transportation Security Administration, which oversees the pipeline system, for failing to enforce strong cyber protections and pointed to FERC’s oversight of electric utilities as a superior regulatory model.

“FERC has a very robust, strong relationship with the utilities; utilities are far ahead of the pipeline companies, [and] pipeline companies are trying to act like they’re not involved in this,” King said. “They are; they’re critical infrastructure. In New England, 60% of our electricity comes from natural gas, and all of it comes through pipelines. If the pipelines go down, the grid goes off. So I think we need to step up dramatically the regulation of these utilities, and I consider the pipelines in that category.”

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IRS Extends ITC, PTC Safe Harbor

An Internal Revenue Service notice issued Wednesday will extend the time that wind and solar developers have to complete their projects and still qualify for either the production tax credit or investment tax credit.

The notice (2021-41) extends the “safe harbor” period for both wind and solar projects to six years for projects that began construction between 2016 and 2019, and to five years for projects that began construction in 2020. For example, a solar project started in 2017 would be eligible for the ITC as long as it went online no later than 2023; one started in 2020 would have to go online by 2025.

To qualify for the credits, a developer must either start and continue work on a project in a specific year (the physical work test) or pay or incur 5% or more of the total cost of the project during that year (the safe harbor test) and then show continual construction or effort on the project.

The “continuity safe harbor” — the time between start and finish of a project — has been reset multiple times, with a previous COVID extension to five years in 2020.

With the new extension, “[t]he Treasury Department and the IRS recognize that regional, national, or global circumstances due to the COVID-19 pandemic have continued to cause delays in the development of certain facilities eligible for the PTC and the ITC. These extraordinary delays have adversely affected the ability of many taxpayers to place facilities in service in time to meet” the tax credit requirements, the notice said.

Developers and energy industry trade groups were quick to praise the extension and the regulatory certainty they said it would provide.

“As with all of American society, the solar industry faced unprecedented challenges during the COVID-19 pandemic,” said Dan Nelson, vice president of tax for California-based developer 8minute Solar Energy. “This additional time to complete projects ensures thousands of megawatts under development will continue and deliver on the jobs and economic value of these projects, while also moving us towards our national clean energy goals.”

Heather Zichal, CEO of the American Clean Power Association, said the safe harbor extension would “ensure additional wind and solar projects have the support they need to move from concepts on paper to steel in the ground. This tax guidance provides the regulatory certainty and predictability to ensure the clean energy projects across the country can be developed to reach the emissions targets we need to achieve.”

“The pandemic disrupted supply chains, shipping and construction operations, permitting processes and financing timelines,” said Abigail Ross Hopper, CEO of the Solar Energy Industries Association. “Without clarity on safe harbor rules from the IRS, some of these solar projects, and the local economic benefits they bring, would not have made it across the finish line.”

Executive Branch Leverage

The notice also offers developers more flexibility for demonstrating continuity of work on a project. Previously, if a project started physical construction, it had to show “continuity of work,” while a project using the 5% safe harbor had to show “continuity of effort,” such as signing contracts for equipment, pursuing permitting or beginning construction.

Now developers can show continuity by use either of two tests, continuity of work or effort, regardless of whether they started actual physical construction or used the 5% safe harbor.

The PTC was originally enacted in 1992, and the ITC, in 2006, to offset the high upfront costs of early wind and solar projects, respectively. The ITC has been particularly critical for the growth of the solar industry, driving tax equity financing for projects and growth rates over 50% per year, according to a SEIA fact sheet.

The ITC currently stands at 26% for residential and commercial solar projects and is scheduled to step down to 22% in 2023. The PTC is $18/MWh through the end of 2021, according to the Energy Information Administration,

Both credits have faced repeated phase-outs, with heavy industry lobbying winning last-minute saves in Congress. The omnibus bill passed in December 2020 extended the PTC one year and the ITC two years. President Biden’s American Jobs Plan proposes a 10-year extension and phase-down of an expanded, direct-pay ITC and PTC. The tax credits were not included in the bipartisan infrastructure package Biden announced on June 24.

Industry analyst ClearView Energy Partners  sees the safe harbor extension “as another example of how the executive branch can leverage its considerable vested regulatory powers to support a green transition even as lawmakers on Capitol Hill wrestle with committing President Joe Biden’s American Jobs Plan to legislative text.”

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BOEM Advances Permitting for Connecticut’s Largest OSW Project

The Bureau of Ocean Energy Management issued a notice of intent to prepare an environmental impact statement (EIS) for the Vineyard Wind South project, which includes the 804-MW Park City Wind facility under development by Avangrid and Copenhagen Infrastructure Partners.

The NOI initiates a 30-day public comment period to define the scope of the EIS, the major permitting study required for project approval.

Park City Wind, selected through a competitive bid process in December 2019 by the Connecticut Department of Energy and Environmental Protection (DEEP), will be built in a federal lease area located approximately 60 miles east of the state and provide roughly 14% of its electricity supply.

“We are eager to participate in this important next step on the Park City Wind project, which is critical to the decarbonization of our regional electric grid and provides a positive boost to Connecticut’s clean energy economy,” DEEP Commissioner Katie Dykes said. “Vineyard Wind has committed to being an engaged partner with environmental and fisheries stakeholders, and we will continue to work with them and all stakeholders to ensure that this crucial project proceeds with appropriate mitigations considered.”

If approved by BOEM, Vineyard Wind would construct and operate a 2,000-2,300 MW wind farm off the coasts of Rhode Island and Massachusetts and develop it in phases. Park City Wind is the first phase and would contribute to Connecticut’s statutory mandate of 2,000 MW of OSW by 2030 through Vineyard Wind’s power purchase agreement with Connecticut’s Public Utilities Regulatory Authority.

Vineyard Wind is actively competing for PPAs for the second phase of Vineyard Wind South, which would provide 1,200 to 1,500 MW of OSW to the Northeast, according to the NOI.

During the 30-day public comment period, BOEM will hold three virtual public scoping meetings and accept comments to inform the preparation of the EIS. BOEM’s scoping process is intended to identify what should be considered in the EIS.

There will be multiple opportunities to help BOEM determine the essential resources and issues, reasonable alternatives, and potential mitigation measures to be analyzed in the EIS throughout the scoping process.

Charles Rothenberger, an attorney for Save the Sound, said the Biden Administration “has come out swinging” with its goal of 30 GW of OSW by 2030 and with progressive agency appointments like BOEM Director Amanda Lefton, which has made “clearing the backlog of these pending projects a priority.” Before working in state and federal government, Lefton was deputy policy director for The Nature Conservancy in New York.

“We recognize that offshore wind is a critical and fairly significant part of what the region needs to do to meet our clean energy goals to reduce our carbon emissions and to ensure that we’re powering the need to transition to electrification of our building and transportation sectors with clean power,” Rothenberger said.

He added that Save the Sound wants to ensure that projects like Park City Wind are “sited and operated in the most environmentally responsible manner possible.” Rothenberger said DEEP established a Commission on Environmental Standards that convened and released a report in 2019 on minimizing and mitigating impacts from the construction and operation of OSW facilities.

The commission has been on hiatus since the original procurement. However, Rothenberger wants to see it become more active as more projects are solicited and those projects are permitted and developed.

OSW technology is “advancing by leaps and bounds,” Rothenberger said. That helped Vineyard Wind I, which had significant permitting process delays during the Trump administration. Rothenberger said that delay worked to the project’s overall advantage.

“That additional time did allow them to take advantage of some new design features using larger turbine blade sizes, which allowed them to then shrink the number of turbine installations that would be needed and shrink the overall footprint of the project, which is certainly desirable,” Rothenberger said. “We’re certainly hoping moving forward that all of these permitting processes retain the flexibility to allow projects to take advantage of technological advances.”

Gravity-based foundations, as opposed to monopile or jacketed foundations used on the Block Island Wind Farm, are one of the potential technological advancements that could reduce the environmental impact of an OSW project, he said.

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Glick Hypes Biden Admin’s Transmission Promotion

FERC Chairman Richard Glick on Wednesday said that the increasing frequency of extreme weather events like the Pacific Northwest heat wave is making transmission planning an issue of national importance.

“The Biden administration is giving enormous priority to transmission,” Glick said. “Have you ever heard a secretary of energy go around the country talk about electric transmission like Secretary [Jennifer] Granholm is doing? When have you seen legislation, infrastructure legislation for instance, that has billions of dollars proposed for building out additional transmission lines?”

Glick made his remarks at a webinar Wednesday hosted by the Energy Policy Institute at the University of Chicago.

“They know that the clean energy transition that’s underway isn’t going to succeed unless we build out the grid. I think the problem is, of course, we have to get Congress to agree on an infrastructure bill, and they’re working on that right now,” Glick said.

Glick described the process of building grid infrastructure as a three-legged stool consisting of siting, planning and cost allocation.

On siting, some states don’t necessarily have the incentive to approve a transmission line that’s going to cross their state without delivering any power to its residents, he said.

“That is certainly one of the big issues, but there are other issues as well,” Glick said. “For instance, transmission planning. How do we plan for transmission? And that’s something that FERC does have jurisdiction over. And we are not necessarily planning in the best way so far. Essentially, a lot of times we look at local lines to address a local reliability issue.”

The commission isn’t necessarily considering what’s really needed or what the grid is going to look like in the future, he said.

“Probably the biggest impediment in addition to siting is cost allocation,” Glick said. “Everyone wants transmission, but no one wants to pay for it. Courts have told FERC that we are the agency essentially responsible for allocating the cost of interstate transmission; that we have to allocate those costs roughly commensurate with the benefits.”

The commission has been looking at beneficiaries in a very narrow way, defining them as only people who get power from a particular line, he said.

“But the fact is people are benefiting greatly when transmission is built, even if they’re not necessarily accessing directly the power that’s transported along those lines,” Glick said. “For instance, transmission lines certainly enable states and others to achieve their carbon-reduction goals. But transmission lines also reduce congestion on the grid, and that actually increases reliability for consumers and also allows them to access cheaper sources of power elsewhere if congestion on the grid is reduced. So one of the things we need to do is figure out if there is a better approach to how we allocate cost of transmission.”

Reporter Robinson Meyer of The Atlantic asked what role FERC should play in the energy transition or in helping states achieve their carbon-reduction goals.

“We’re not an environmental regulator,” Glick said. “Our role is not saying that you should be reducing emissions, but our role under the Federal Power Act is to get rid of barriers. One thing we do is try to figure out the market barriers out there that are preventing these newer technologies from being developed.”

Rep. Sean Casten (D-Ill.), a member of the Select Committee on the Climate Crisis and the House Science, Space and Technology Committee, had a different take on FERC’s role.

“The single most impactful agency in Washington right now to address CO2 emissions is the Federal Energy Regulatory Commission,” Casten said. “If we are going to electrify everything, and if we are going to get to zero CO2 at the pace that science says we must, then we’re going to have to build probably about at least 1,000 GW of new generation, which is about as much as we already have. We’re going to have to install several hundred billion dollars of transmission, which is huge.”

Any transition to a clean economy is a massive wealth transfer from energy producers to energy consumers, for if homeowners install solar panels, they don’t have to pay for fuel anymore, Casten said.

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BOEM Beginning Environmental Review on Virginia OSW Project

Interior Secretary Deb Haaland announced Thursday that Interior’s Bureau of Ocean Energy Management (BOEM) will begin its environmental review of Dominion Energy’s (NYSE:D) Coastal Virginia Offshore Wind project.

BOEM’s Notice of Intent, which is scheduled to be published in the Federal Register July 2, begins a 30-day public comment period. BOEM will hold virtual public scoping meetings for the environmental impact statement (EIS) on July 12 at 5:00 p.m., July 14 at 1:00 p.m. and July 20 at 5:00 p.m.

Haaland announced BOEM’s review of Dominion’s construction and operations plan (COP), the first major milestone in the federal permitting of the 2.6-GW project, during a tour of The Port of Virginia with U.S. Sen. Tim Kaine (D-Va.) and Gov. Ralph Northam.

The project, with up to 205 turbines, will be located 27 miles from Virginia Beach.

It will require up to 300 miles of “inter-array” cables between turbines and up to nine submarine HVAC offshore export cables. The COP envisions up to three offshore substations and two cable landing locations at the State Military Reservation or Croatan Beach in Virginia Beach, or both.

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Map of the construction and operations plan for Dominion Energy’s Coastal Virginia Offshore Wind project | Dominion Energy

It will connect to the PJM grid at Dominion’s existing Fentress Substation.

BOEM’s EIS will evaluate positive and negative impacts to air quality, water quality, bats, fish habitat, wetlands and commercial and recreational fishing. “Based on a preliminary evaluation … BOEM expects potential impacts to sea turtles and marine mammals from underwater noise caused by construction and from collisions with project-related vessel traffic,” it said.

BOEM expects to make the final EIS public in May 2023, with a record of decision issued at least 30 days later. Based on the EIS and consultations with stakeholders, BOEM will decide whether to approve, approve with modification, or reject the COP.

Last month, BOEM announced the North Atlantic Division of the United States Army Corps of Engineers (USACE) will assist it in planning and reviewing renewable energy projects on the Outer Continental Shelf (OCS), starting with the Dominion project and Avangrid’s (NYSE:AVR) Kitty Hawk project off North Carolina.

The partnership resulted from President Biden’s Executive Order 14008, which directed interagency consultation between Interior and the Department of Defense to increase renewable energy production on public lands and  offshore waters.

Last year, Northam and the Virginia General Assembly set a target of 5.2 GW of offshore wind by 2034.

The state’s Department of Mines, Minerals and Energy (DMME) has created a Division of Offshore Wind to work with stakeholders and coordinate economic development opportunities.

The Port of Virginia, located 30 nautical miles from the Dominion project, is being upgraded to accommodate the heavy loads involved in the construction of offshore wind projects.

A report conducted for DMME found the Port’s Portsmouth and Newport News marine terminals are best prepared for roles in the OSW buildout. “They each have sufficient space to accommodate multiple, co-located offshore wind activities, making them candidates for a future offshore wind manufacturing and deployment hub. The necessary upgrades to meet offshore wind requirements would cost up to $10 million at each port,” it said.

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Minnesota Utilities Struggling to Meet Low-income EE Goals as Legislators Boost Targets

Minnesota’s electric utilities will be required to meet increasing energy efficiency targets under a bill signed by Gov. Tim Walz in May. But a recent report by the state Department of Commerce shows some utilities are not meeting all of the old, lower targets.

The Energy Conservation and Optimization (ECO) Act (HF164) raises the annual energy savings goals for the state’s electric investor-owned utilities from 1.5% to 1.75% and quadruples their low-income spending requirement to 0.4% of gross operating revenues. It also requires utilities to file Conservation Improvement Programs (CIP) with the Minnesota Public Utilities Commission for programs funded by ratepayers but administered by the utilities.

The Department of Commerce’s Energy Policy and Conservation Quadrennial Report 2020, released March 1, says that electric utilities exceeded the original 1.5% goal in both 2017 and 2018, the most recent data available, and that natural gas utilities exceeded the statutory minimum of 1%. The programs saved 15.2 trillion BTU of energy — equal to the annual energy demand of 160,000 Minnesota homes — and reduced CO2 emissions by 1.79 million tons, equivalent to the annual emissions of 350,000 vehicles.

Falling Short on Targets

But the department said a separate dataset for 2019 found that some electric and gas utilities failed to meet their low-income targets.

Xcel Energy (NASDAQ:XEL) met its $2.49 million spending goal on low-income plans, but it saved only 2.39 GWh, a 27% shortfall from the 3.26-GWh goal. Otter Tail Power (NASDAQ:OTTR) and ALLETE’s Minnesota Power (NYSE:ALE), by contrast, spent somewhat less than their goal but exceeded their savings targets.

Of the state’s five natural gas utilities, only one — WEC Energy Group’s Minnesota Energy Resources (NYSE:WEC) — met its low-income savings goals, although three of the five met or exceeded the spending goals.

Low-income programs typically fund energy audits that identify and pay for improvements such as air sealing, weatherization, and replacements of furnaces and other equipment. There also are customer rebates for purchasing and installing energy-efficiency measures in multifamily buildings or nonprofit affordable housing.

“Administering low-income programs can be challenging for utilities and their vendors,” the report acknowledges. “Challenges include finding eligible and interested customers, perceived challenges in meeting U.S. [Department of Energy] WAP [Weatherization Assistance Program] requirements, accommodating the needs of both WAP and CIP, and working with many different Community Action Partnership agencies throughout the utility’s service territory. Commerce continues identifying areas of improvement and working with stakeholders to effectively deliver these programs.”

One challenge, Commerce told NetZero Insider, is that the client needs to be a customer of the utility delivering the program; if the client is a renter, landlord involvement may be necessary. Homes also need to be in a safe condition to weatherize and not in need of major structural repairs.

“CIP contracts are with individual utilities and each service provider, and each utility is unique,” a spokesperson said. “Some combinations are a great match and others are not. All can be affected by changes in funding sources, workforce trends and organizational capacity.”

The ECO Act will boost spending on low-income programs. IOUs’ (defined as “public utilities”) minimum spending increases from 0.1% to 0.4% of its gross operating revenues. “Consumer-owned utilities” (municipal utilities and cooperatives) must spend at least 0.2% of gross operating revenues on such programs, up from 0.1%. Natural gas utilities’ minimum increases from 0.4% to 0.8%.

Consensus Took 6 Years

Government and private clean energy groups across the state hailed ECO as the biggest clean energy win since 2013, when the state enacted several laws boosting solar power. The new bill did not come easily. Bipartisan and diverse special interest consensus required six years of hard work and deep collaboration, according to Mike Bull, director of policy and external relations for the Center for Energy and Environment (CEE), a Minnesota-based clean energy research and implementation nonprofit.

In 2015, the House of Representatives passed a bill that would have repealed the CIP program.

“There was grumbling from some stakeholders that … CIP was not delivering value to Minnesota ratepayers, despite all of the checks and balances in the regulatory system to ensure that value,” Bull said. “Although we were able to stop that 2015 proposal from becoming law, it served as a tremendous wake-up call. We knew we needed to reconnect key stakeholders to the benefits of energy efficiency.

“In developing the bill,” he added, “we painstakingly layered each stakeholder’s ‘gotta-haves’ in alignment with everyone else’s.”

The bill:

      • allows public utilities to recover through energy rates investments in “innovative clean technologies” that are not widely deployed among utilities and that provide net economic benefits to ratepayers if approved by the PUC. Cost recovery is limited to $6 million over three consecutive years for Xcel and CenterPoint Energy and $3 million for other public utilities.
      • increases the state’s annual energy savings goal from 1.5% to 2.5%: electric IOU targets increase from 1.5% to 1.75% of annual retail sales; consumer-owned utilities (municipal utilities and cooperatives) remain at 1.5%; and that for gas utilities is reduced from 1.5% to 1%. The changes were based on the Energy Efficiency Potential Study prepared for the Department of Commerce by CEE and others, which targeted an 11% reduction in gas use between 2020 and 2029.
      • requires public utilities to incorporate programs to improve energy efficiency in public schools.
      • encourages utilities to implement load management programs to shift energy demand from peak times by allowing the companies to obtain financial incentives for programs approved by the PUC. The previous law only allowed for cost recovery. ECO allows utilities to make load management investments utility assets on which a rate of return can be earned.
      • allows utilities to count fuel switching — substituting electricity or natural gas for a customer’s current fuel — in their energy savings and directs the commissioner of Commerce to develop a method for calculating them. Fuel switching is permitted if it reduces the overall amount of energy used, reduces greenhouse gas emissions, is cost-effective and improves the utility’s load factor, an efficiency metric calculated as the ratio of average demand to peak demand. The fuel-switch language prompted the Minnesota Propane Association to oppose the bill, fearing a switch to electric heat pumps. Natural gas heats most Minnesota homes and buildings, but many rural communities rely on propane. The Minnesota Chamber of Commerce also opposed the fuel-switching provision, citing fears of higher energy costs.

Tight Timeline

With the climate crisis looming even larger than when negotiations on the energy-efficiency program began six years ago, all participants realize there can be no pause in implementing ECO, said Anthony Fryer, Commerce’s CIP supervisor, in a June 17 presentation on the law to the Midwest chapter of the Association of Energy Services Professionals.

Commerce has begun stakeholder processes to assist in developing technical guidance on implementing changes under ECO. The timeline:

      • guidelines for multifamily buildings with low-income consumers: Aug. 1.
      • methodology for determining sales for electric vehicle charging: Dec. 31.
      • technical guidelines for fuel-switching programs and calculating energy savings: March 15, 2022.
      • preweatherization measures for low-income consumer programs: March 15, 2022.

The state’s energy-efficiency standards have saved consumers $6 billion in the last 20 years, Fryer said, and that improved efficiency keeps bills low and supports 47,000 jobs in Minnesota.

The ECO Act updates the CIP framework to provide a more holistic approach to efficiency programming and will increase those economic benefits, Fryer said. Because the technical guidelines will be developed by public and private participants, he said there is no overall estimate yet of what the overall savings will be.

“ECO will provide opportunities to leverage energy demand as a more active and significant part of our state’s clean energy transition, opening doors to a greater range of fuel choices and more opportunities to benefit from energy use timed to align with periods of lower demand on our energy grid,” Bull said.

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Researchers in Massachusetts Test Tidal Energy

Researchers from the New England Marine Renewable Energy Collaborative (MRECo) tested how tidal turbines affect the environment around them in the Cape Cod Canal last week.

The team used a camera and acoustic system to assess how a small steel turbine would impact water conditions, as well as fish and other wildlife, in the Bourne Tidal Test site for 48 hours.

A tidal turbine works like a wind turbine, using heavy blades to turn a rotor that powers a generator. They are placed on the sea floor, or at the bottom of an estuary or a river with a strong tidal flow.

The 2-meter turbine prototype was built by Littoral Power Systems, based in New Bedford, Mass.

One of the primary benefits of tidal energy is the predictability of tides, according to John Miller, executive director of MRECo.

“We’ve been predicting tide patterns for centuries,” Miller said.

Additionally, the demonstration on the Cape Cod Canal on the southern coast of Massachusetts found virtually “no environmental impact,” he said. Other studies in Canada and Scotland have had similar results, showing that fish and other ocean wildlife have evolved to avoid the slow-moving blades, Miller added.

The steel turbines need to be fixed to the seabed, which has raised some concern that a large-scale tidal turbine infrastructure could disrupt water flow enough to change sediment flow. Building and maintaining them is a major hurdle to adopting the renewable energy technology, Littoral CEO David Duquette said.

The European Marine Energy Centre is advising Littoral on how to mitigate environmental issues that tidal turbine energy could cause.

Researchers also are investigating how to develop a propulsion mechanism that more closely mimics how animals have evolved to move in water, such as the motion of a whale’s tail going up and down.

Wind turbine blades mimic wings, and “you don’t see wings in the water,” Miller said.

But the cost of testing these technologies is high.

MRECo, which spun off as a nonprofit from the University of Massachusetts research center, established the Bourne Tidal Test Site in 2018 to avoid some of those costs.

Bourne-Tidal-Test-Site-(New-England-Marine-Renewable-Energy-Collaborative)-Alt-FI.jpg
The Bourne Tidal Test Site in the Cape Cod Canal | New England Marine Renewable Energy Collaborative

The demonstration last week was funded by the Massachusetts Seaport Economic Council at a total cost of $400,000. With a designated testing site already at their disposal, the energy collaborative has a much lower testing cost than other researchers. Developing a testing site alone can cost up to $1 million, Miller said.

Previous tidal turbine testing in both the Northeast and Europe went from a university tank to a real-world test of turbine systems 30 to 40 feet in diameter, Miller said. Those large sites typically have a water velocity of 6 knots, equivalent to a 400-mph wind, he added.

“That’s like testing a wind turbine in a hurricane,” he said.

Tidal turbine blades have flown off some tests because the system was not tested at an interim level. The Cape Cod Canal, which runs at about 4 knots, allows researchers to develop the technology at lower speed, increasing the number of places the technology could be deployed, Miller said.

Some of the first large-scale tidal turbines in countries like Canada and Scotland have a diameter of 40 feet and a generating capacity of 1 MW.

But the Ocean Renewable Power Co. is planning to install a utility-scale tidal energy project in the Cook Inlet in Alaska that with a generating capacity of 5 MW. And in Scotland, Simec Atlantic Energy is now planning a tidal power project with a proposed generating capacity of 398 MW.

“We are just getting our toes wet in the U.S.,” Duquette said.

The site in Cape Cod also serves as a place for other companies to test underwater sensors. OpenCape, which provides fiber optics for Cape Cod and southeast Massachusetts, is working with the energy collaborative to install broadband on the test site platform.

Now, the nonprofit is focusing on adding power to the platform, which would also allow the tidal turbines to supply energy to the grid eventually.

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Stakeholders Back PJM MOPR-Ex Replacement

PJM stakeholders voted overwhelmingly Wednesday in support of the RTO’s proposed replacement for the extended minimum offer price rule (MOPR-Ex), handing the recommendation to the Board of Managers.

The RTO’s proposal, which would apply the MOPR only to resources connected to the exercise of buyer-side market power or those receiving state subsidies conditioned on clearing the capacity auction, bested eight other plans in a special Members Committee meeting. It received an 87-18 vote for a sector-weighted score of 4.18/5 (83.6%).

Two other proposals also won majority support but fell short of the two-thirds sector-weighted threshold for a positive recommendation. American Municipal Power’s (AMP) proposal won a 68-30 majority (3.25/5), while the Delaware Division of the Public Advocate’s received a 54-37 vote (2.98/5). Most of the others received less than 20% support.

Dave Anders, PJM’s director of stakeholder affairs, emphasized, however, that the votes were advisory and that the board was not bound by them in proposing tariff changes to FERC under Section 205 of the Federal Power Act. “It does not require a positive, weighted vote,” he said.

“We expect the board will consider all of this in their decision-making,” he said after the vote.

The vote was conducted at a public MC meeting following a closed session with board members in which stakeholders debated the proposals. Proponents were permitted up to three minutes to lobby for their plan in the public session, and several of them used their time to rebut criticism they had heard at the earlier session.

The vote was conducted under the RTO’s critical issue fast path (CIFP) accelerated stakeholder process mechanism, initiated by the board in April. It was the latest development in an 18-month saga that has whipsawed PJM and caused the cancellation of the 2020 Base Residual Auction (BRA).

PJM adopted the extended MOPR in response to FERC’s 2-1 ruling in December 2019 saying MOPR should apply to all new state-subsidized resources to combat price suppression in the capacity market (EL16-49, EL18-178). Then-Chair Neil Chatterjee and fellow Republican Bernard McNamee formed the majority, with Democrat Richard Glick angrily dissenting, calling it an attack on state decarbonization efforts.

Glick asked PJM to undo the rule after he was named chairman by President Biden in January. (See PJM MOPR in the Crosshairs at FERC Tech Conference.)

Before Wednesday’s vote, board Chair Mark Takahashi thanked stakeholders for their efforts. While noting that members disagreed in their approaches and legal opinions, he said “everything was extremely professional and very helpful to the board.”

‘Maximize Transparency and Market Confidence’

PJM said its approach “will maximize transparency and market confidence while ensuring PJM and the Independent Market Monitor are able to mitigate the exercise of BSMP [buyer-side market power] when it is identified, while also better accommodating state public policies and self-supply business models.”

“Exercises of BSMP require both the ability and incentive to do so. It is the exercise of BSMP that shall be prohibited,” PJM said in a presentation.

Market participants will be asked to sign attestations declaring that they are not exercising market power or receiving state funds tied to clearing in the auction.

The RTO said it and the Monitor will conduct “fact-specific,  case-by-case reviews” if it suspects market power. “Upon that review, should PJM or the IMM have concern that the market seller provided a misrepresentation or otherwise acted fraudulently, PJM or the IMM may make a referral to FERC for investigation,” it said.

With the new rules in place, PJM would eliminate both the expanded MOPR and the prior MOPR, which was limited to new natural gas resources. The board has pledged to have new rules in place for the December BRA for delivery year 2023/24, with a FERC filing expected by the end of July.

Different Approaches

The second-most popular proposal, from AMP, would have determined whether a load-serving entity can exercise market power by determining its ability to influence capacity prices based on its size relative to the rest of its  constrained locational deliverability area. “PJM should not be put in a position of having to determine appropriate versus inappropriate intent,” AMP said.

PJM’s proposed procedure for determining whether a resource is receiving state subsidies conditioned on clearing the capacity auction | PJM

The Delaware Division of the Public Advocate said it combined parts of PJM’s plan and one from Exelon. It would provide an exemption for “emerging technologies,” citing the Bloom Energy fuel cell in Delaware and offshore wind.

The Monitor’s proposal also would exempt emerging technologies such as offshore wind and carbon capture and sequestration that would not otherwise be competitive. “It is not undue discrimination to distinguish between subsidies for uneconomic, emerging technologies and subsidies for mature technologies,” it said.

The IMM also would have PJM exempt self‐supply entities whose net long position did not exceed 15%. All resource types would be subject to review. “Intent is not relevant. Profitability is not relevant,” says the proposal says, rejected by stakeholders 20-81.

Monitor Joe Bowring said it would keep the MOPR in place with “de minimis” impact on auction results. “Contrary to the assertions of some this morning, our proposal is not anti-ZEC,” he said, referring to state zero-emission credits for nuclear plants.

Kicking the Can

Calpine won only 10 votes for its “Sunrise” proposal, which would suspend the MOPR rules through the BRAs in December and June 2022 (delivery year 2024/25) to allow stakeholders to conduct a broader review of capacity market rules.

“Calpine is against just changes in the MOPR,” David “Scarp” Scarpignato said in remarks before the vote. “We think PJM has to take a more holistic approach.”

Among other changes, Calpine wants to increase Capacity Performance penalties and require dispatchable resources to have 16 hours of guaranteed run time for three days through on-site fuel, backup fuel or contracted LNG.

If no agreement could be reached, the existing MOPR rules would become active again — the “sunrise” — for delivery year 2025/26.

Exelon (NASDAQ:EXC) said Calpine’s proposal would “‘kick the can down the road,’ holding MOPR reform hostage to other capacity modifications that will be controversial and are likely to be delayed.”

Instead, Exelon proposed use of an “objective” buyer-side market power test that was effective through 2018. It would use two “bright line” screens: one to address state policies targeted at modifying auction prices, and one to address buyer-side market power.

“Mitigation should only be applied to capacity market offers of new gas-fired units. New gas units are widely acknowledged to be the least expensive incremental capacity resource and therefore the most effective means of successfully exercising buyer-side market power,” Exelon said in its presentation. “Simply put, it makes little economic sense for a buyer to invest in any resource other than a new gas-fired unit if it were attempting to exercise buyer market power.”

Exelon said its proposal is targeted at the Supreme Court’s holding in Hughes v. Talen Energy Marketing, which  outlawed state policies “tethered” to PJM’s federally regulated market.

“State policies that provide value for clean energy attributes that are not conditioned upon clearing in the PJM capacity market are legitimate exercises of state authority; not exercises of market power,” Exelon said. “PJM has every reason to accommodate and respect the state policy. Both the Supreme Court and lower federal courts have acknowledged that nearly every state policy can ‘affect’ PJM capacity market outcomes, without such policies constituting an impermissible intrusion into” federal jurisdiction.

Exelon said the current MOPR rules, which cover ZEC payments, resulted in the transfer of more than $35 million in capacity market revenue from its Illinois nuclear plants to emitting fossil resources in the 2022/23 auction in May. Exelon’s proposal failed 27-66.

Another nuclear operator, Public Service Enterprise Group (NYSE:PEG), also attempted to protect its New Jersey units receiving ZECs with what it called the “Carbon Adjusted Minimum Offer Price Rule.”

It said FERC’s December 2019 ruling on a complaint by Calpine and others “did not take account of the price-distorting impacts of a lack of a price for carbon in the PJM markets.”

PSEG’s proposal would exempt all zero-carbon support programs created by states from the MOPR. PSEG says most zero-carbon programs within the PJM footprint have implied costs of carbon below the federal social cost of carbon and that the two programs with costs above that level — the New Jersey and D.C. solar renewable energy credit programs — are too small to have a material impact on capacity market prices.

It said it would improve the economic efficiency of the market, remove obstacles to states’ carbon-reduction efforts and “establish PJM’s leadership as a change agent in moving towards the establishment of a carbon-free energy economy.”

“Programs designed by states to promote other policies — for example, a state program to help keep coal plants in operation — would not pass this test” and would be subject to the MOPR, PSEG said. Its proposal failed 11-87.

E-Cubed Policy Associates, representing Elwood Energy, proposed testing all new-entry resources and certain existing resources receiving out-of-market revenues through non-bypassable charges. It said it would avoid “the messy and likely costly legal battles of what state policies should or should not be subject to MOPR.” It failed 16-73.

The least popular proposal was LS Power’s “repricing” plan, in which PJM would clear the auction with the MOPR to establish the total cost to load. Then it would have a second run including resources subject to the rule that did not clear and divide the total cost to load by the total megawatts. Resources could withdraw from consideration if prices were lower than it needed as expressed in its bid.

LS Power’s Tom Hoatson used his time to dispute “this notion that all we’re interested in is high capacity prices.

“What we’re interested in is a competitive outcome,” he said. The proposal failed 7-82.

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NJ Awards Two Offshore Wind Projects

New Jersey awarded its second offshore wind solicitation to two projects with a combined capacity of 2,658 MW Wednesday, giving developer Ørsted its second project in the state, and the other to a joint venture between EDF Renewables North America and Shell New Energies US.

The New Jersey Board of Public Utilities (BPU) said it concluded that it could create a more competitive wind sector and accelerate efforts to create an industry hub by assigning two projects.

The two projects will generate electricity equivalent to the amount needed to power 1.15 million homes. Ørsted’s Ocean Wind II, located about 14 miles from the New Jersey shoreline, will generate 1,148 MW and is expected to be completed in three phases in 2028 and 2029. Ørsted is also developing Ocean Wind, an 1,100-MW project off the state’s coastline. Atlantic Shores, by the EDF/Shell partnership, will generate 1,510 MW of electricity in a wind field between 10 and 20 miles off the Jersey Shore near Atlantic City, with completion expected in two phases, in 2027 and 2028.

New Jersey plans another four solicitations, scheduled every two years, to reach its goal of deploying 7,500 MW of capacity by 2035. The first and second awards, if completed, would account for about half the targeted capacity.  

State officials said the award was the largest offshore wind project award in the nation and described it as a major step forward in the state’s effort to reach the target of generating 50% of its electricity through renewables by 2030, and 100% clean energy by 2050. They also sought to cast it as a sign of the state’s strength in the East Coast’s rapidly growing offshore wind sector.

“Today’s award further solidifies New Jersey as an offshore wind supply chain hub,” Gov. Phil Murphy said in a release. “This award ensures that our investment in clean energy is also an investment in our communities and will generate good-paying, union jobs and bring valuable investments to New Jersey.”

Rapidly Growing Sector

The first commercial scale offshore wind energy project in the U.S., Vineyard Wind off the coast of Massachusetts, gained final permit approval from the Bureau of Ocean Energy Management (BOEM) on May 11.

The Biden administration has pledged to build 30 GW of offshore wind in the U.S. by 2030, and in March announced that it would open a new area, New York Bight, to offshore wind development between Long Island and New Jersey. New York has set a goal of generating 9 GW of offshore wind capacity by 2035 and has five projects in the works totaling 4.4 GW.

Before the board’s 5-0 vote on the two projects, BPU Commissioner Bob Gordon said the decision not only showed the state is serious about combating climate change, but also is “making a long-term commitment to offshore wind.”

“We want to build the regional supply chain here in New Jersey,” he said. ”We want to foster innovation and competition. We want to build a whole new industry and the jobs and the economic opportunity that come with it.”

In outlining their recommendation that the board back the two projects, BPU staffers said both will use the New Jersey Wind Port, a manufacturing and logistics hub for the offshore wind sector in Lower Alloways Creek in Salem County, and a monopile manufacturing plant under construction in the Port of Paulsboro.

Ørsted said it would build a nacelle manufacturing plant at the wind port with GE. David Hardy, CEO of Ørsted Offshore North America said the award of the latest project would strengthen the company’s ties to the state.

“We’re thrilled to grow this global industry alongside the state of New Jersey, as well as help all communities in the state benefit from the offshore wind industry,” he said.

Ørsted has financed and has equity interests in 24 offshore wind partnership worldwide, including the Block Island Wind Farm, the first commercial offshore wind project in the U.S.

The Atlantic Shores project, which has agreed to use union labor, will create a nacelle assembly facility at the state’s wind port. The developer will also collaborate on a project to research, monitor and analyze the deployment of hydrogen technology and natural gas blending.

“As offshore wind prepares to take off in the United States, this is a critical moment to lay the groundwork for workforce training and supply chain development,” said Joris Veldhoven, commercial and finance director at Atlantic Shores. “Our robust project includes a number of essential initiatives to train local workers and bring manufacturing jobs to the state.”

Both project developers will also contribute $10,000 per MW to a fund that is expected to accumulate $26 million for use on research initiatives and wildlife and fishery monitoring in the region, the BPU said.

Mixed Reception

In June 2019, New Jersey awarded its first offshore wind contract to Ørsted’s Ocean Wind project, which will be built 15 miles from Atlantic City. It is expected to begin operations in 2024, and is now quarter-owned by Public Service Enterprise Group (NYSE:PEG). (See Orsted Wins Record Offshore Wind Bid in NJ.)

The project has faced opposition from the tourism and fishing industries, as well as some residents, who are concerned about the impact. Yet state legislators showed their commitment to ensuring that offshore wind projects move ahead by passing legislation last week that would allow offshore wind developers to override local and state government to site transmission lines and related infrastructure for their projects on public land. The bill now sits on Murphy’s desk. (See NJ’s Offshore Wind Project Faces Criticism, Support and NJ Lawmakers Back Offshore Wind Bills)

The BPU opened the second solicitation last September, releasing a 142-page guidance document that outlined the requirements for companies looking to fulfill the offshore wind renewable energy certificate (OREC). BPU staffers said the two solicitations were evaluated through a variety of criteria laid out in state laws, including the projects’ impact on ratepayers, the economic benefits to the state, the environmental impact and the likelihood that the project would be brought to fruition.

The staff also looked at issues such as how the selection of a particular project would diversify the state’s risk in pursuing offshore wind projects, how they would spread the economic benefits around the state and how they would expand the supply chain for wind energy goods.

The projects will reduce greenhouse gas emissions by 5 million tons a year, equal to about 26% of the current green house gas emissions from electricity generation, the BPU said.

“These projects will go a long way toward helping New Jersey meet its long-term clean energy goals,” said Raymond Cantor, a lobbyist for New Jersey Business & Industry Association (NJBIA), one of the largest trade groups in the state. “We look forward to the creation of this new and dynamic industry.” Still, he added, “as we applaud the award of these projects, we are also mindful that we must still be vigilant to ensure that our electric grid remains reliable and that the energy we produce remains affordable.”  

Environment New Jersey and Sierra Club New Jersey also welcomed the BPU’s move, in part for the economic benefits and job creation it would bring to the state.

“With this procurement, New Jersey has continued to establish itself as a national leader in offshore wind,” said Taylor McFarland, acting director of Sierra Club New Jersey. “The clean energy boom is inevitable, and it is critical that New Jersey regulators are taking proactive measures to expand our offshore wind industry. This is the future, and we can either fall behind or stay ahead. I’m happy we’ve chosen the latter.”