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October 30, 2024

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North Carolina Regulators Approve Duke’s 1st Carbon Plan

The North Carolina Utilities Commission on Friday approved Duke Energy’s first “carbon plan” to comply with the state’s law requiring carbon neutrality by 2050.

The plan does not include any major requirements to invest in new resources, but rather calls on the firm to update its modeling and file a plan with actual investments later. The order discusses different ways of achieving the law, from investing in renewables, to keeping existing nuclear plants running another 20 years, expanding batteries, and even building new natural gas plants to replace coal-fired ones.

“The guidance the General Assembly provided to the commission for this task is clear: The commission must find the least-cost path to compliance with the carbon dioxide emissions-reduction requirements while maintaining or improving the reliability of the electric system,” the NCUC said in its order. “Developing the path to least-cost compliance with the carbon dioxide emissions reductions that the law requires is complex and will, necessarily, be an iterative process given the rapid pace of change of the electric industry.”

The law also requires continued reliability of the system, with the NCUC noting that the transformation of the electric system will present new challenges for system operators as resources dependent on weather grow while new demand such as home heating must be met. The outages some customers saw over the holidays during cold weather underscores the vigilance the regulator will have to employ while overseeing that transition, the commission said.

Duke called the decision “constructive,” noting that the plan will be updated every two years going forward under state law.

The commission’s decision “advances our clean energy transition, supporting a diverse, ‘all of the above’ approach that is essential for long-term resource planning,” Duke said. “We’ve already made incredible progress, retiring two-thirds of our aging coal plants in North Carolina and South Carolina and reducing emissions by more than 40% since 2005; we will continue this ongoing work of lowering carbon emissions to reduce risk for our customers while balancing affordability and reliability.”

The utility said it will file an integrated resource plan with South Carolina regulators this August, which will take into account the carbon plan from its neighboring state, recent federal legislation on infrastructure and clean energy, and other factors relevant to clean planning. Customers in both states deserve a clean energy plan that keeps rates as low as possible, Duke said.

The commission drew fire from environmentalists, with climate advocacy group NC WARN calling its decision to allow Duke to build new natural gas plants “tragic.” It noted that in a quantitative analysis of the plan, Duke called for more than doubling its gas generation by building another 11,700 MW, but opponents have argued that the same capacity needs can be met with solar, wind, energy storage and efficiency.

“Duke Energy is required to obtain permits from the NCUC before it actually builds any more gas-fired power plants,” the group said. “NC WARN and others have vowed to vigorously oppose those applications.”

All of Duke’s modeling showed that new combined cycle natural gas plants would be needed as part of a least-cost energy transition and to help retire the utility’s existing coal plants, the NCUC said in its order. Replacing coal with new natural gas would eliminate the need for additional transmission at certain sites.

The delivery of natural gas to new natural gas plants is uncertain with Mountain Valley Pipeline’s construction still under litigation, but the commission said Duke would be able to pivot to an alternate plan if that pipeline does not go forward. The utility will have to use the most up-to-date information on natural gas prices and pipeline capacity into North Carolina to justify the construction of new natural gas plants under its climate plan, it said.

Without new natural gas plants, the utility said it would not be able to speed up the retirement of its dispatchable coal plants, with its plans to retire 8,400 MW of coal by 2035. New combined cycle plants produce 60% less carbon dioxide than the coal plants they would replace, the NCUC said.

The NCUC determined that planning for 1,200 MW of new combined cycle capacity and 800 MW of combustion turbines makes sense, but the utility needs to file a separate application to actually build such assets.

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Feds Charge Two in Wash. Substation Sabotage

The Department of Justice charged two men in attacks on four electric substations that left thousands in Washington state without power on Christmas, saying the incidents were a cover for a burglary plot.

Each of the men — Matthew Greenwood and Jeremy Crahan, both of Puyallup, Wash. — faces a potential prison sentence of 20 years on the vandalism charges. Greenwood was also charged with possessing an unregistered firearm, a potential 10-year sentence.

According to a criminal complaint filed Dec. 31 and unsealed this week, the attacks occurred in Pierce County, beginning early in the morning of Dec. 25. Two of the affected substations were operated by Puget Sound Energy, while the others were controlled by Tacoma Power.

Initial Intrusion in Hemlock Facility

The first sign of a problem came around 2:39 a.m., when PSE crews responded to an alarm from the Hemlock substation. Arriving on the scene, the team discovered that someone had cut the perimeter fence and entered the substation. While the intruders did not steal anything or cut any wires, they did manipulate a bank high side switch, causing a power outage for about 8,000 customers.

While PSE staff were working to restore service at the Hemlock substation, Tacoma Power received a notification around 5:30 a.m. that its Elk Plain substation was offline. Just 30 minutes later, word came that the Graham substation was down as well. Investigators at the Elk Plain facility found the padlocks on the pedestrian gates had been cut and the high side breakers had been handled; at the Graham facility the fence had been cut, similar to Hemlock, and the high side breakers were out.

Tacoma Power said about 7,500 customers lost power because of the two outages. The utility also reported that it would cost about $3 million and take up to 36 months to replace damaged transformers at both facilities. Until the transformers are replaced, Tacoma Power must use mobile transformers at the substations, reducing their combined output from 50 MW to 15 MW.

The final attack occurred around 7:25 p.m. at PSE’s Kapowsin substation. Once again, the chain link fence had been cut and someone had tampered with the bank high side switch. In trying “to pry the linkage open,” the attackers “caused the substation to start arcing and sparking,” according to the complaint. Authorities did not state whether any outages occurred as a result of this attack.

Phone Records Lead to Suspects

The investigation by the FBI’s Joint Terrorism Task Force used surveillance photos from the Elk Plain substation of a man and a vehicle that arrived at the facility at the time of the attack. Investigators also used cell phone records to identify two phones that appeared to have been in the vicinity of each substation around the time the attacks occurred.

Those phones turned out to be connected to Google accounts used by Greenwood and Crahan; in addition, Crahan was identified as the owner of a pickup truck similar to the vehicle seen in the Elk Plain surveillance photos. This connection was enough for the FBI to put both men under “essentially continuous … surveillance” for several days beginning Dec. 27.

Suspect surveillance photos (Tacoma Power) FI.jpgSurveillance photos from Tacoma Power showing the individual who damaged the Elk Plain substation. Matthew Greenwood was later arrested wearing similar clothing. | Tacoma Power

Investigators obtained a search warrant on Dec. 30 for a house in Puyallup where both men were often present. Executing the warrant on Dec. 31, federal agents and local law enforcement officers found Greenwood in a trailer on the property along with a rifle and a shotgun later determined to be unregistered. His clothes “matched, in part, the clothing seen in the” Elk Plain surveillance photos. Crahan was found and arrested a short time later, also in Puyallup.

In a statement to police, Greenwood said he and Crahan committed the power station vandalism as part of a plan to burglarize an unnamed local business. He said he used bolt cutters provided by Crahan to enter the facilities, while Crahan drove their getaway car. According to Greenwood, Crahan only entered one facility, referred to in the court filing as the “South Hill” facility but probably referring to the Hemlock substation, which is located in South Hill.

During the outage, Greenwood said they went to the business where Crahan drilled out the lock, while Greenwood stole from the cash register. It was not clear from the filing when in the day this occurred, or whether it happened before or after the Kapowsin substation attack.

The Washington sabotage came just weeks after unknown attackers damaged two substations in Moore County, N.C. with rifles, causing 45,000 customers to lose power for several days. (See Duke Completes Power Restoration After NC Substation Attack.) Investigators have yet to publicly identify any suspects or motive for those attacks; Duke Energy, Moore County, and the state government have each offered a reward of up to $25,000 to catch those responsible.

In a statement, FBI Special Agent Richard A. Collodi, who heads the bureau’s Seattle field office, said the arrests demonstrate “the commitment by all levels of law enforcement to protect our infrastructure and hold those accountable who put our community in danger.”

Tacoma Power also thanked law enforcement officers, noting that it had “committed significant resources to both cyber and physical security” and that investigators said these efforts “aided in these swift arrests.” During the outages the utility had said that “in accordance with best practices, we do not share the details of our resiliency and security tactics,” but that it “follows federal reliability standards, including assessing physical risks to our critical energy infrastructure and applying recommended mitigation measures.”

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NJ’s Aggressive Clean Energy Plans Face 2023 Challenges

New Jersey’s far-reaching offshore wind plans face a series of challenges in 2023 as the first project undergoes permit scrutiny and the state launches a third coastal wind solicitation amid questions about whether it can handle the rapid development of an industry from scratch.

The advance of OSW projects represents just one facet of the state’s clean energy policy as it works to meet Gov. Phil Murphy’s aggressive goal of zero emissions by 2050. Other key events in the coming months will include the launch of a permanent community solar program and public discussion of how to stimulate the development of heavy-duty electric vehicle chargers, which will be essential for the state’s plan to put more non-fossil fuel heavy trucks on the road.

Transportation is the state’s largest carbon-emitting sector, producing 42% of the state’s greenhouse gases. And the progress of the state’s efforts to cut carbon emissions from the third largest sector — buildings — will likely be a prominent issue this year too, as Murphy’s administration seeks to regain its footing on what turned out to be a controversial policy of replacing fossil fuels with alternatives, mainly electricity.

The state Department of Environmental Protection (DEP) says it is still seeking ways to cut building emissions after the agency — in rules published Jan. 3 — dropped a prohibition on the installation of fossil fuel water and heating boilers after 2025, amid vigorous business and union opposition. (See NJ Backs off Ban on Commercial-size Fossil Fuel Boilers.)

Wind Expansion Planned

OSW will likely represent the most intense of the state’s clean energy efforts, however, as it seeks not only to build its own industry but also to become a regional player. The state’s Board of Public Utilities (BPU) is hoping its first project, the 1,100-MW Ocean Wind 1, will advance rapidly through 2023 and be ready to go online in late 2024.

Construction has not begun on the project, one of three approved by the BPU including the 1,148-MW Ocean Wind 2 and 1,510-MW Atlantic Shores approved in 2019. The BPU’s third solicitation, planned for early 2023, could dramatically accelerate expansion of the wind sector, with the agency planning to approve projects of between 1.2 GW and 4 GW in capacity, and perhaps more.

If that process unfolds as planned, New Jersey could have OSW projects totaling more than 7.5 GW in the pipeline by mid-2023, close to the state’s 2035 target set before Murphy last year increased the goal to 11 GW by 2040.

Some observers, most notably the New Jersey Division of Rate Counsel, and opponents of the projects have suggested that the state move at a slower place so that the success of the early projects can be evaluated before putting more into the pipeline.

“Now may be the time to be conservative in making larger awards, given the fact that times are uncertain and challenging for all large energy investments,” Brian O. Lipman, director of the division, told a hearing on the third solicitation proposal last month.

Those concerns are partly fueled by rising costs facing all parts of the economy. Cost pressures have been highlighted by developer Ørsted as a potential problem, and Public Service Enterprise Group (NYSE:PEG) CEO Ralph LaRossa in October told investors and analysts that the company is mulling whether to continue its 25% ownership of Ocean Wind 1.

Whether the state can proceed at such a rapid pace will also depend on the progress of Ocean Wind 1 in the coming months, which could smooth the way for succeeding projects.

The BPU in September granted Ørsted an easement that would enable the project to run cables through Ocean City on the Jersey Shore and is now evaluating a second request for an easement through land owned by Cape May County. The board’s decision is expected in the coming months. (See NJ BPU Approves Easement Plan for 1st OSW Project.)

The two easement requests rely on a 2021 state law that allows the BPU to override local government rules if a transmission project is “reasonably necessary” to complete an OSW project. Public hearings on both requests featured vigorous opposition from local residents who say the law disenfranchises local government, whose lawyers have told the BPU they expect the law to be challenged in court.

The project also awaits a DEP decision on the first five of 13 permits needed to advance. The federal government’s permitting dashboard estimates that the federal environmental review and permitting process will be completed in July.

Supporting Infrastructure

New Jersey is also pursuing an aggressive plan to develop a supply chain, manufacturing and service industry to support its own OSW projects and others along the East Coast.

A key element is the development of a wind port in South Jersey, for which the state has committed investments of $478.2 million, the New Jersey Economic Development Authority (EDA) said in November, as it outlined plans to float bonds for additional funding. (See NJ Backs $20 Million Spend on Tx Link for Offshore Wind Port.)

Located in Salem County, the New Jersey Wind Port will include a 30-acre marshalling area for component assembly and staging; a dedicated, overland, heavy-haul transportation corridor; and a heavy-lift wharf with a dedicated delivery berth and an installation berth that can accommodate jack-up vessels. With construction underway, the EDA hopes to complete the first phase by 2024.

The EDA last year also announced plans to hire a consultant to develop a world-class offshore wind research and development testing facility. (See NJ Plans ‘Flagship’ R&D Innovation Center for Wind.)

The BPU in October put in place another major support block for the offshore sector, approving $1.07 billion for transmission upgrades to deliver 6,400 MW of offshore wind generation to the PJM grid. Central to the proposal is the construction of a new substation adjacent to FirstEnergy’s Jersey Central Power and Light’s Larrabee substation in Central Jersey, which is onshore and near the coast. That will be accompanied by a series of smaller upgrades to the transmission system. (See NJ BPU OKs $1.07B OSW Transmission Expansion.)

The BPU picked the projects from among 80 proposals submitted by 13 developers in response to a solicitation issued by PJM that was notable for its use of the State Agreement Approach set out under FERC Order 1000.

Still to be determined, however, is an infrastructure system to bring the offshore energy to the shore. The BPU expects that work to be designed and built as part of the projects picked in the third solicitation.

Grid Worries

Concerns about the ability of New Jersey’s grid to handle the extra load from a dramatic increase in clean energy generation are expected to continue in 2023, reflecting similar discussions about infrastructure weakness across the nation.

“My greatest fear is that one morning, we’re going to wake up and … have no place to plug in our renewable energy,” BPU President Joseph L. Fiordaliso told a Nov. 9 board meeting after the agency approved receipt of a grid modernization study prepared by consultant Guidehouse Inc. Fiordaliso made the same comment on several occasions in 2022.

Solar developers told state legislators in May that the grid is so old and its capacity so limited that new solar projects can’t be connected in certain areas of the state, a weakness that is stifling solar expansion. The developers spoke in support of a bill (S431) that would establish a fixed “grid modernization” fee structure to cover the cost of upgrading the grid. The bill passed the state Senate in June but has not advanced in the Assembly.

A similar concern centered on the PJM Interconnection’s inability to connect new projects, and the lengthy delays in getting it done, which were frequently cited by New Jersey regulators and solar developers looking to build projects in the state.

Solar Advance

Aside from those difficulties, the state solar sector pushed ahead in 2022, reaching 4.2 GW of installed capacity in November, according to the latest BPU figures available. That was driven by the installation of 387,358 kW of capacity in the first 11 months of the year, the fastest addition of new capacity since 2019, the figures show.

The capacity of projects in the pipeline, 709,716 kW, is well below the 1,668,061 KW of 2021, which was inflated by developers rushing to get projects admitted in a soon-to-close incentive program. But the pipeline is stronger than the 532,749 kW reported in 2020, BPU figures show.

The new capacity was driven, in part, by the state’s pilot community solar program, and BPU officials in August celebrated the completion of the first project under the program’s second phase — a 500-kW community solar project covering six roofs in Neptune Township. After developers complained in 2021 about the slow pace to execute the second phase, the BPU announced plans for a permanent program, which will begin in 2023 and is expected to award 150 MW of capacity a year. (See Slow Progress of NJ Community Solar Pilot Draws Fire.)

Still, developers had installed only 20 community solar projects in the state by November, totaling 43,961 kW, less than one-fifth the 240 MW of capacity awarded in the two phases of the program. And while the program has proven popular with developers, the BPU is cautious about making a dramatic increase. In November, a BPU representative urged state legislators not to approve a bill that would triple the size of the planned permanent community solar program to 500 MW a year, expressing concern that the grid and developers would not be able to handle the sudden increase.

State officials believe the pace of other types of solar installations will accelerate after the December approval of rules for the Competitive Solar Incentive (CSI) program, which will determine incentive levels for grid-scale solar projects through competitive solicitations. Developing such projects in the state was difficult and rare in the past. (See NJ BPU Approves Rules for Grid Solar Program.)

The CSI program is the second part of the BPU’s Solar Successor Incentive (SuSI) program, which reshaped the state’s incentive system, a response, in part, to criticism that previous programs were too generous. Under the first part of SuSI, the Administratively Determined Incentive (ADI) program, incentives are set by the BPU.

But developers now say the incentives are too low, and although the state has hit its target of 150 MW of net metered residential installations, it is far short of the target for non-residential projects and those installed on brownfield, infill or landfill sites.

That is especially true given the shipping constraints and supply chain issues affecting the industry, which have increased commercial installation costs by 15% since the start of 2021, Scott Elias, director of Mid-Atlantic state affairs for the Solar Energy Industries Association, told the BPU in December.

EV Development

New Jersey also reshaped its strategy in 2022 to accelerate the uptake of EVs. The BPU launched the third phase of its Charge Up New Jersey EV subsidy with a reduction in the maximum incentive from $5,000 to $4,000 after available funds were exhausted in the first two phases. (See NJ Cuts Incentives for New Phase of EV Promotion.)

The state also allocated an extra $46.6 million to expand an incentive program for the purchase of electric trucks and for the first time allowed incentives for Class 7 and Class 8 trucks, the largest on the road and some of the largest polluters. Previously the program funded the purchases of Class 2 to Class 6 trucks only.

Seeking to remove diesel buses from the road, state legislators approved a three-year, $45 million program to test electric buses in 18 school districts, where performance would be evaluated and data on costs, maintenance, fuel and bus speed and movements would be collected and submitted to the DEP.

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NJ Extends Comment Period on 3rd OSW Solicitation

New Jersey has extended by two weeks the comment period on the plan to hold its third — and largest — offshore wind solicitation in early 2023 after speakers at a public hearing into the plan criticized the way the period straddled the holidays and questioned whether the state is ready for such a big expansion.

The New Jersey Board of Public Utilities on Dec. 22 extended the final date by which the public could submit written comments, from Dec. 29 to Jan. 13, after “several stakeholders requested an extension to the comment deadline.”

The concern was raised at a Dec. 13 online hearing into the proposal organized by the BPU to receive stakeholder input. The solicitation guidance document outlines a plan to award project capacity of between 1.2 and 4 GW early next year with the option to go higher, potentially far larger than the 1.1 GW and 2.658 GW awarded in the first and second rounds, respectively. (See NJ Shoots for 4 GW+ in 3rd OSW Solicitation.)

Environmental groups told the BPU that the large size and speed of its third solicitation was essential to combating climate change, which is already disrupting the state and planet. But other speakers, among them local residents, asked the board to slow down, and written opposition to the plan has trickled in since the hearing.

Speaking at the hearing, Kari Martin, advocacy campaign manager for Clean Ocean Action, criticized the BPU for providing insufficient due process for the project by having the public comment period end Dec. 29 and holding a stakeholder hearing two weeks before Christmas.

“This is the largest offshore wind solicitation for New Jersey thus far,” she said. “There is a short time frame for reviewing these documents and providing comments during the height of the holiday season.”

She added that it “it is clear that New Jersey is unprepared for the third solicitation for offshore wind, as well as offshore wind already being fast-tracked in this region,” and she worried about the impact on marine life.

Martin cited a report published by Rutgers University’s Center for Ocean Observing Leadership on strategies for monitoring offshore wind development that stated that the “pace of offshore wind development is faster than the pace of fisheries science.” She noted that the report said that baseline studies should begin at least two to three years prior to construction and added that it is “premature” for the state to move ahead with the solicitation when “current baseline information is deficient and impacts from projects from previous solicitations are unknown.”

Brian O. Lipman, director of the Division of Rate Counsel, also noted that “the comment deadline was placed in between two major holidays when many commenters may be taking a respite from work and may not be available.”

Lipman’s comments, however, focused mainly on concern about the size of the proposed solicitation, and he urged the agency to be “conservative” and ensure that ratepayers don’t bear an unnecessary burden.

Lipman noted the economic turbulence in the U.S. and said the BPU should think about the risk to ratepayers in deciding the size of projects to award in the next round. He said that parts of the economy are suffering wage stagnation, supply chain disruptions, worker scarcity, and higher prices for commodities and equipment.

“It is not unlikely that bids offered in this solicitation may propose to shift some, or a large number, of these risks onto ratepayers,” Lipman told the hearing, adding that his office has “great concern” that developers may try such a move if they get project approval. “Ratepayers simply cannot afford drastically higher electric bills.”

He said one developer is mulling such a move. Danish developer Ørsted, which is developing New Jersey’s first OSW project, Ocean Wind 1, said during a Nov. 3 earnings call that returns on the project are “not where we want to be” and that it is exploring its options, according to a Seeking Alpha transcript of the call.

“This particular solicitation … will represent the largest potential capacity block or range of any solicitation scheduled by the board,” Lipman said. “Rate Counsel suggests that now may be the time to be conservative in making larger awards, given the fact that times are uncertain and challenging for all large energy investments.”

He added that “there are at least four more solicitations of a fixed 1,200-MW target that could be used to make up any lower offshore wind procurement amounts in the third round of bids.”

Reducing Costs, Increasing Competition

The BPU plans to open the third solicitation in the first quarter of 2023 and accept applications through the second quarter. The agency plans to make one or more awards in the third quarter.

“We really want to encourage competition and see reduced overall prices in this third solicitation,” said Andrea Hart, the BPU’s senior program manager of offshore wind, who made the board’s presentation on the solicitation at the public hearing.

Project applications must include the dollar-per-megawatt-hour price at which the developer would execute the project and the impact on ratepayers, which will account for 70% of the evaluation weight, the BPU said in the presentation. Non-price factors such as the economic impact, the strength of guarantees that those benefits will happen, and the impact on the environment and fisheries will account for the remaining 30%.

The Impact of Meeting Climate Goals

About 20 speakers spoke during the hearing, among them local residents that oppose the projects and a nonprofit opposition group, Save Long Beach Island. Supporters of the solicitation included a business group, New Jersey Alliance for Action, several clean energy companies and developers, including a representative of offshore wind developer Atlantic Shores, and environmental groups.

In a Dec. 29 letter to the board, resident Ken Lagana said he understands the importance of renewable energy but that there are “other locations where windmills could be installed.” He expressed concern at the impact of the turbines on fishing in the area.

“The placement of windmills in such close proximity to our waters could potentially disrupt the migration patterns of fish and other marine life,” creating a negative impact on commercial and recreational fishing.

Doug O’Malley, executive director of Environment New Jersey, called the solicitation proposal “a clear plan on how to reach Gov. [Phil] Murphy’s goal of 11 GW of clean renewable energy from offshore wind by 2040.”

“If we are serious about our climate goals, we need to be able to develop offshore wind in an environmentally responsible way,” he said. “Offshore wind is the best source of powering our economy with clean renewable energy.”

David Pringle, representing Clean Water Action, said, “The science says we have eight years to deal with the climate catastrophe unfolding. The state needs not only the third solicitation, but a fourth and a fifth and a sixth, and a heck of a lot more.”

But some speakers at the hearing expressed concern that the state is moving too fast.

Cindy Zipf, executive director of Clean Ocean Action, said there are “too many questions” about OSW to move ahead and urged the BPU to hold off doing so.

“From our view, there is little responsible about the current pace, scope and magnitude, literally paving the ocean in wind power plants,” she said. “The solicitation does not provide evidence of how the clean ocean and that economy can coexist with the industrial economy of the future that is planned.”

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NREL Boosts Development of Distributed Wind Energy

The National Renewable Energy Laboratory last month distributed another round of grants to boost small- to mid-sized wind turbine technology and marketing.

In announcing the funding, NREL said growth in this market sector will boost the development of distributed wind energy, which in turn will support local electrification, grid resilience and reliability, especially when combined with solar and/or storage technology.

NREL said this could support decarbonization in rural communities; support commercial, agricultural and industrial operations in windy regions; and avoid adding load to already strained transmission networks by delivering power directly to users.

The grants are part of the Competitive Improvement Project (CIP) that the U.S. Department of Energy began in 2012.

The sums of money involved are not huge: 11 companies will split $2.9 million in this latest round, bringing the program total to $15.4 million in grants plus $7.9 million in leveraged private-sector funding. But collectively the grants will improve technology, lower costs, encourage innovation and mitigate regulatory barriers, NREL said.

Increasing electrical output without also increasing manufacturing or installation expenses reduces a wind turbine’s levelized cost of electricity (LCOE) and makes it more competitive in more situations with fossil-generated power.

NetZero Insider spoke with three of the recipients. Each has a significantly different niche within the small-to-medium wind market, but all said they see significant benefits from the CIP grants.

Bergey Windpower

In announcing the grants, NREL singled out Bergey Windpower in Oklahoma as a CIP success story, having doubled the power output of its flagship turbine with research and development assisted by several rounds of grants.

CEO Mike Bergey said the company’s Excel 10 became uncompetitive when Chinese solar manufacturers started flooding the U.S. markets with panels that could produce power more cheaply than the 10-KW wind turbine.

So the company followed the example of General Electric and Vestas in squeezing more power out of their megawatt-scale turbines: With CIP help, it lengthened the Excel 10’s rotors and optimized their aerodynamics to create the Excel 15, which produces 15 kW with essentially the same nacelle and tower as the Excel 10.

“The DOE funding has allowed us to develop a whole new design that cuts the LCOE in half,” Bergey said.

He co-founded the company with his father, the late Karl Bergey, in 1977 and has spent his career in the wind industry, with stints as president of the Distributed Wind Energy Association (which he founded) and the American Wind Energy Association (now the American Clean Power Association).

In the distributed energy sector, wind has suffered for years from solar competition, Bergey said.

“There’s so much promotion of solar, we’re kind of stuck in the shadows,” he said. Also, “we don’t have the kind of financing alternatives that the solar industry has.”

This year’s CIP grant to Bergey Windpower is not for technology development: It will help the company set up a financing model that cuts upfront costs for customers. The Excel 15 and a 100-foot self-supporting lattice tower run about $100,000 installed, before incentives.

The events of 2022 are a game-changer, Bergey said: He can direct potential customers to a 30% investment tax credit through the Inflation Reduction Act plus a 10% domestic production adder, because the Excel 15 is made in the U.S. with mostly American parts.

The cost drops even further via tax deductions for depreciation and Department of Agriculture grants, if the buyer qualifies.

The CIP grants, Bergey said, now seem prescient: They allowed the company to have a new product ready when a new financial paradigm created new market opportunities.

“Because we’re in the sixth year of [CIP], it’s really helped fill the pipeline,” he said.

Carter Wind Energy

Carter Wind Energy, another multigeneration family-run company, is based in Texas, which produces more wind power than the next three highest states combined.

But CEO Matt Carter said his company is not producing the megawatt-scale machines that are creating all that electricity.

“We’re focused on what we call a mid-sized market,” he explained — turbines producing 100 to 1,000 kW.

Carter Wind also uses a different technology than most other wind power manufacturers: lightweight towers designed to sway like a palm tree, and lightweight two-blade rotors oriented downwind from the tower, rather than three blades oriented upwind.

Further, the product is portable, can be set up without a crane and can be relocated on a two-wheel dolly. This is attractive for certain agricultural and manufacturing applications and for industries such as water treatment or oil and gas production.

Finally, customers do not have to buy the tower and turbine: Carter Wind (and investors) will own it and sell the power to the customer or lease the equipment to the customer.

This latest CIP grant — Carter Wind’s third — will help it develop a 60-meter tower whose six sections are tapered, allowing them to nest like a telescope for transport.

“From a shipping standpoint, you can make it much more portable,” Carter said.

The economics are lining up now for small-scale distributed and behind-the-meter wind power operations, he said.

Carter Wind has long been able to pitch a significant savings to potential customers who use diesel-burning generators in remote locations, but now it will be easier to sell wind power to customers who burn natural gas, Carter said, as the 10-year window of the IRA incentives firms up the financing picture.

“These industrial projects are now easier to pitch. … The ebbs and flows have been a challenge for our market, [with its] on-again-off-again incentives.”

XFlow Energy

Two previous CIP grants have helped XFlow Energy take its vertical-axis wind turbine from a concept on paper to testing in the field. This third award will help it design a tower and move toward a prototype incorporating the lessons learned from the models tested.

25-KW vertical-access wind turbine (XFlow Energy) Content.jpgA half-scale prototype of the 25-kW vertical-access wind turbine being developed by XFlow Energy is shown in California. | XFlow Energy

The Washington state-based firm hopes to go to market with a 25-kW turbine in two years’ time, CEO Ian Brownstein said.

Vertical-axis wind turbines and the more commonly seen horizontal-axis designs each have their advantages and disadvantages, he said.

A key drawback of the vertical-axis orientation is the cyclical stress exerted on the rotors, which can cause fatigue. Brownstein and XFlow co-founder Ben Strom both focused on eliminating this problem in their doctoral research and in the subsequent R&D for their turbine.

A key advantage of the vertical-axis design, meanwhile, is its relative mechanical simplicity.

XFlow’s task is the classic R&D goal: Boost output and reliability while cutting costs, enhancing strengths and eliminating weaknesses.

“We’re trying to translate that to a true LCOE-competitive product,” Brownstein said.

Continual technical support from NREL has been just as important as the financial assistance in moving XFlow closer to a point where it can go to market, he said.

“We started with them when our design was pretty much on paper,” Brownstein said. “NREL support has been critical along the way.”

Mass production of the 25-kW turbine is a milestone goal for the company, not the destination, Brownstein said: “XFlow is definitely interested in building larger turbines.”

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Biden Appointees Take Majority on TVA Board

President Biden’s appointees control the majority of seats on the Tennessee Valley Authority’s Board of Directors after six new members were sworn in Wednesday.

The U.S. Senate approved all six of Biden’s board nominees through a voice vote just before Christmas. Without the Senate’s approval, the TVA board would have lost quorum and its ability to make business decisions.

The new members are:

      • Beth Geer, chief of staff to former Vice President Al Gore and a participant in the Nashville Sustainability Accountability committee;
      • Bobby Klein, vice president of the International Brotherhood of Electrical Workers after a decades-long career as a lineman and foreman in Chattanooga, Tenn.;
      • Michelle Moore, author of “Rural Renaissance” and CEO of Groundswell, a nonprofit that builds community power to reduce energy burdens and expand economic opportunity;
      • Bill Renick, a former Mississippi state legislator and mayor who chairs the Commission on the Future of Northeast Mississippi;
      • Joe Ritch, an Alabama-based attorney and former TVA board member (2013-2017); and
      • Wade White, a former Kentucky county judge-executive.

They join TVA Board Chair William Kilbride, whose term expires in 2023, and fellow incumbents Beth Harwell and Brian Noland; their terms expire in 2024. The full nine-member board will meet publicly for the first time in February when it holds a quarterly business meeting in Muscle Shoals, Ala.

Kilbride said in a press release that the federal agency was delighted to welcome the newcomers aboard “during this challenging but exciting period.”

“They each bring diverse perspectives and experience to the board that will help guide TVA as it plans for the future while entering its 90th year of service to the region,” he said.

Biden originally nominated Geer, Klein and Moore in the spring of 2021 and re-upped their nominations in January 2022. The trio faced a somewhat combative Senate confirmation hearing last year, with Republican lawmakers expressing worry that adding more progressive board members would lead to abandoning TVA’s fossil fuel fleet. (See TVA Board Nominees Back Renewable Power, Affordability.)

Biden nominated Renick and White in June 2022; Ritch’s nomination followed in July. Renick and Ritch have Democratic affiliations, while White is a Republican.

Ritch’s term expires in 2025 and Renick’s and White’s in 2027. The other three terms expire in 2026.

The full board has its work cut out for it. TVA was forced to order rolling blackouts ahead of Christmas day, leading to another FERC–NERC joint inquiry into grid performance during winter storms. (See FERC, NERC Set Probe on Xmas Storm Blackouts.)

The board is also tasked with approving TVA’s resource mix under its next 10-year integrated resource plan, due out in 2024. The federal utility has come under pressure in recent years from renewable power advocates, who say TVA is shortsightedly planning natural gas generation and overlooking renewable resources. (See Nonprofits Urge TVA to Reconsider Gas-fired Options.)

Some conservation groups have said the agency’s goal of reaching net-zero carbon emissions by 2050 is too gradual and out of step with the Biden Administration’s 2035 target for decarbonizing the power sector. TVA responded last year to a letter of inquiry from the U.S. House of Representatives’ Committee on Energy and Commerce that focused on its decarbonization goal and energy affordability. (See TVA Defends Rates, CO2 Reduction Plans in House Inquiry.)

TVA said it will contract this year with a third party to conduct a Valley Decarbonization Study, which will analyze how it can further slash emissions. It also plans to build 10 GW of solar generation by 2035.

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NY Proposes Credit System to Fund 6 GW of Energy Storage

New York is considering a system of credits to help fund what it calls the most ambitious energy storage goal in the nation: 6 GW installed by 2030.

Gov. Kathy Hochul announced the proposed framework in late December; the Public Service Commission is expected to decide on it later this year.

Energy storage is a crucial component of the state’s plan to replace dirty but steady fossil-burning generation with clean but intermittent wind and solar power. About 130 MW of storage was installed statewide as of November, and 1,300 MW was in some stage of development.

The framework developed by the New York State Energy Research and Development Authority and Department of Public Service calls for bringing an additional 4,700 MW of short-duration storage online by 2030, at an estimated cost of $1 billion to $1.7 billion.

The proposed index storage credit would be similar in many ways to the renewable energy certificate structure used across most of NYSERDA’s Clean Energy Standard procurements, with one credit awarded each day for each megawatt-hour available for dispatch.

The credit system would cost residential ratepayers an estimated 34 to 58 cents/month on average for 22 years.

In a news release accompanying the proposal, Hochul said, “Storing clean, renewable energy and delivering it where and when it is needed is one of the most critical challenges we must overcome to reduce statewide emissions, especially from traditional fossil fuel peaker plants. This roadmap will serve as a model for other states to follow by maximizing the use of renewable energy while enabling a reliable and resilient transformation of the power grid.”

The proposed 6-GW framework is, however, only a small step toward the massive storage capacity New York will need in order to keep the lights on, heat running and cars rolling in the decarbonized future envisioned for the state.

Six gigawatts of short-duration energy storage will provide perhaps 2 million of New York’s 7.5 million households with a few hours of power; it is a tool for intraday load balancing, not a replacement power source to maintain resource adequacy during a multiday cold snap.

The framework’s authors acknowledge the need for long-duration storage and suggest large-scale use of hydrogen and 100-hour batteries as a solution. But such technology is highly uncertain at present, the authors write, and it is critical to invest in their development now so they can be field tested before 2030 and deployed at scale after 2030.

State law requires that 70% of New York’s electricity come from renewable sources by 2030 and mandates 100% zero-emission electricity by 2040.

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Entergy Seeks Review of FERC’s Block on MISO Capacity Obligation

Entergy’s operating companies have mounted a campaign at the D.C. Circuit Court of Appeals to override FERC’s rejection of MISO’s minimum capacity obligation.

The company’s Arkansas, Louisiana, Mississippi, New Orleans and Texas subsidiaries maintain that MISO’s unsuccessful bid to require load-serving entities to demonstrate that they have obtained at least 50% of the capacity required to meet peak load obligations before auctions are held can be beneficial and help rectify capacity shortages. Entergy attorney Michael Griffen petitioned the D.C. Circuit Court for reconsideration in a Dec. 28 filing (22-1334).

FERC in late August and again in late October rejected MISO’s request to install a minimum capacity obligation. The commission found that the RTO did not prove that such a rule would address resource adequacy concerns or that it would incent members to construct new generation. (See Regulators, LSEs Ask FERC to Reconsider MISO’s Seasonal Capacity Accreditation.)

The grid operator disagreed. It has said that an obligation would foster sensible planning by its members and regulators and serve as a “guardrail” against reliance on its voluntary capacity auctions for anything more than residual capacity needs.

MISO has claimed that years of inexpensive capacity prices have accelerated generation retirements and held up new investment in generating facilities. It said some LSEs depend on its residual auctions to provide for all their capacity needs.

Entergy has also characterized a minimum capacity obligation as “a practical safeguard to ensure that LSEs engage in reasonable resource planning practices that will maintain reliability in the MISO region and help mitigate a capacity market free rider problem.”

The utility said that without the obligation, the RTO’s current resource adequacy construct allows LSEs to become too attached to auctions. It said the current environment “distort[s] planning, shift[s] substantial costs to other LSEs’ customers and ultimately negatively impact[s] reliability.”

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California Storms Fill Reservoirs, Build Snowpack

A series of Pacific storms are beginning to fill the lakes behind hydroelectric dams and to build snowpack for spring and summer generation, but California will continue to be gripped by drought without far more precipitation, officials said.

“It’s always great to be above average this early in the season, but we must be resilient and remember what happened last year,” Sean de Guzman, the state Department of Water Resource’s supply forecasting manager, said in a news release. “If January through March of 2023 turn out to be similar to last year, we would still end the water year in severe drought with only half of an average year’s snowpack.

“We still have a long way to go before the critical April 1 total,” de Guzman said. Months of heavy snow and rain will be needed to reach a historical average on that key date, the department said.

The latest storm was forecast to hit the state from Wednesday evening into Thursday, with heavy snow and rain and winds gusting to 60 mph or more.

“A powerful hurricane-force low pressure system located over the eastern Pacific is set to surge a plume of moisture and damaging winds into the West Coast beginning tonight,” the National Weather Service said on its website Wednesday. “The greatest impacts, which include damaging winds, excessive rainfall, and extremely heavy snow, is forecast to occur over much of California and into southern Oregon through Thursday.”

The ground remains saturated from a New Year’s Day deluge with strong winds that caused flash flooding, toppled trees and knocked out power to about 680,000 customers in the territories of Pacific Gas and Electric and the Sacramento Municipal Utility District.

The next storm could fell even more trees, the weather service warned.

“Be prepared for widespread power outages, downed trees and very difficult driving conditions,” it said on Twitter.

Atmospheric river weather systems, which bring large amounts of moisture from the central Pacific, could continue over the next two weeks due to a “persistent mid-level low pressure anchored over the North Pacific,” it said.

While the storms wreak havoc, they also bring much-needed water and snow to California, which has had three dry years in a row. With a Mediterranean climate, the state gets almost all its precipitation from December through February.

On Tuesday, the first snowpack measurement of the year showed it to be far above average in the north-central Sierra Nevada.

The Department of Water Resources (DWR) measured 55.5 inches of snow and a snow water equivalent of 17.5 inches — or 177% of average — at a main survey site in the mountains above Lake Tahoe.

“The snow water equivalent measures the amount of water contained in the snowpack and is a key component of DWR’s water supply forecast,” it said.

Statewide the snowpack was 174% of average for Jan. 3 and 64% of the average total for April, it said.

However, it warned that this year could see a repeat of last winter when a wet December was followed by three dry months.

“Conditions so far this season have proven to be strikingly similar to last year when California saw some early rainstorms and strong December snow totals only to have the driest January through March on record,” DWR said.

The state’s major hydroelectric reservoirs are filling from the rains but some of the biggest lakes remain far below capacity, DWR said. Low water levels have hurt hydropower, adding to the state’s summer resource shortfalls.

Lake Oroville, which ran so dry that generation ceased in July 2021, stood at 39% of capacity on Tuesday and held 74% of its historical average total for this time of year. Lake Shasta was at 34% capacity and 57% of its historical average.

Others had filled past their historical averages. Folsom Lake near Sacramento filled to 141% of its average for the date and was releasing large amounts of water from the New Year’s storm. The reservoir, however, is about one-fifth the size of Lake Oroville and one-fourth the size of Shasta.

If above-normal rainfall continues into spring, it would extend the state’s recent pattern of multiple drought years followed by one year of heavy precipitation. The pattern is a product of climate change, the state’s top water official said in the news release.

“The significant Sierra snowpack is good news, but unfortunately these same storms are bringing flooding to parts of California,” said DWR Director Karla Nemeth. “This is a prime example of the threat of extreme flooding during a prolonged drought as California experiences more swings between wet and dry periods brought on by our changing climate.”

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Massachusetts OKs Sharing Cost of Maine Wind Power

Massachusetts electric distribution companies have been authorized to take on up to 40% of a two-part, $1.7 billion clean energy project in northern Maine.

The Massachusetts Department of Energy Resources, after consulting with the state Attorney General’s Office, notified Maine of the decision Friday.

The Maine Public Utilities Commission in October selected the 1-GW King Pine wind farm proposed by Longroad Energy and a 345-kV power line proposed by LS Power to help move the state closer to its renewable energy goals.

The transmission line is expected to cost ratepayers $2.78 billion, while the wind power is expected to provide a $1.08 billion benefit for a net cost of $1.7 billion over 30 years. But the PUC opted to also look for partnerships with other states that could reduce the cost of the projects to Maine ratepayers.

The DOER determined that the two projects would meet the standards set forth in Section 82 of last year’s Driving Clean Energy and Offshore Wind Act: They would provide cost-effective, clean-energy generation to Massachusetts ratepayers and help the state meet its decarbonization goals while improving energy security and reducing costs during the winter.

The department is additionally requiring that negative impacts be minimized to the extent possible; progress be demonstrated toward permitting and interconnection approvals; and a credible schedule and plans be in place.

It directed the EDCs to begin negotiations with the two projects’ developers for cost-effective long-term contracts that will be reviewed and approved by the Massachusetts Department of Public Utilities.

The Maine PUC has set a Jan. 15 deadline for its staff to report back on potential partnerships and recommend the next step. The Massachusetts DOER set a Feb. 28 deadline for Maine to obtain contract support to demonstrate the project’s viability.

The move comes as Massachusetts’ efforts to foster ocean-based wind power off its coast falter. Construction has begun on an 800-MW wind farm, but developers of two projects that would have a combined 1,600 MW capacity have said the financial terms are no longer viable because of escalating costs. (See related story, Mass. DPU Orders Commonwealth Wind Project to Continue.)