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November 16, 2024

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Xcel Says Coal Retirements on Track Despite South Dakota PUC’s Plea for Extensions

Xcel Energy insists its plan to retire two Minnesota coal plants won’t mar reliability even though the South Dakota Public Utilities Commission sent a letter urging the utility to hold off on shutting down the units.  

The South Dakota PUC asked Xcel in a letter this month to reconsider its planned closures of the Sherburne County Generating Station (Sherco) and Allen S. King coal plants in Minnesota.  

“Closing these plants will take nearly 3 GW of reliable dispatchable electricity generation off the [MISO] grid precisely at a time when those resources will be needed the most to keep electricity flowing 24/7/365 throughout Xcel and MISO’s footprint,” South Dakota commissioners wrote to Xcel. “Premature closure of these plants adds to the uncertainty of electric generation resource adequacy in the upper Midwest including Xcel’s customers in South Dakota.” 

South Dakota commissioners cited NERC’s finding in its Long-Term Reliability Assessment that the MISO footprint could face a 4.7-GW shortfall through 2028. 

“Evidence is mounting that the premature closure of dispatchable generation will elevate the risk of electricity outages, particularly in tight load hours including hours of extreme cold and extreme heat, as well as those hours when wind generation is low,” the commissioners wrote.  

Commissioners also expressed concern South Dakota ratepayers may bear the costs of closing the plants early. They said Xcel said in a docket that choosing not to operate the two coal plants for the duration of their useful lives paired with a decision against extending the Prairie Island nuclear plant could cost customers $453 million more than keeping the plants open.  

“We do not want Xcel to be part of the impending problem of [a] generation shortage in the MISO footprint. Reliability should be your number one commitment!” commissioners told Xcel leadership.  

Xcel, however, said both the PUC and it are taking threats to reliability seriously and that it appreciates the feedback on plans to decommission its coal plants by 2030.  

“We are in alignment with the commission’s priority to ensure reliability throughout the clean energy transition and ensure South Dakotans have a dependable supply of electricity at all times, including periods of extreme weather and high demand,” Xcel said in an emailed statement to RTO Insider.  

Xcel pointed out that it plans to infuse 2.1 GW of wind and 2.5 GW of solar onto its Upper Midwest grid by 2032 and said it has another 1.1 GW of wind and solar waiting in the wings beyond 2032. It added that its two nuclear plants will be able to complement the variable supply with dispatchable, carbon-free electricity.  

Xcel also said it has plans to include 800 MW of “hydrogen-ready” combustion turbines in its generation portfolio and soon will build 500-700 miles of new transmission lines to further bolster reliability. It said it looks forward to “continuing to meet with the commission” for insight on the “complex task” of ensuring a reliable and affordable clean energy future.  

Xcel remains on track to exit coal generation by the end of the decade. It officially retired the first of its coal units at Sherco on the last day of 2023, with plans to retire the other two in 2026 and 2030.  

Ryan Long, president of Xcel Energy Minnesota, South Dakota and North Dakota, said there’s “tremendous potential for the plant site in the Upper Midwest’s energy future.”  

“Just as we’re taking a phased approach to decommissioning the coal units, we’re building replacement generation in phases to support clean, reliable and affordable energy for our customers,” Long said in a press release at the time.  

Xcel is building the first two phases of the total 710-MW Sherco Solar project adjacent to the Sherco site. It also plans to construct a 10-MW, 100-hour battery storage facility onsite as a pilot project from Massachusetts-based Form Energy. Xcel received a grant of up to $35 million from the U.S. Department of Energy for the battery project. 

Xcel said Sherco Unit 2 is slated to become a synchronous condenser to manage system stability after retirement.  

Finally, Xcel said it’s proposing to build the Minnesota Energy Connection, a 175-mile, 345-kV transmission line in southwest Minnesota that will use existing interconnection at Sherco to connect a minimum 2 GW of wind and solar.  

“There’s a lot of life left at the Sherco site, and our dedicated coworkers will manage the transition over the next decade,” plant director Michelle Neal said in the release.  

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ERCOT Meets Demand, Sets New Winter Peaks

ERCOT set a new winter peak for demand Jan. 16 as it easily met demand during a frigid blast that pushed temperatures 30 to 50 degrees below normal in Texas. 

The grid operator had expected electricity consumption to match the record levels set last summer, projecting demand as high at 86 GW as the winter storm approached. However, demand averaged 78.14 GW during the interval ending at 8 a.m. Jan. 16. 

That broke the previous winter mark set the day before, when demand averaged 76.34 GW during the 9 p.m. interval, surpassing the previous record of 74.53 GW set in December 2022. It also exceeded ERCOT’s earlier all-time peak of 74.53 GW set in 2019. 

The ISO issued conservation appeals for Jan. 15 and the morning of Jan. 16. With a hard freeze expected as far south as Houston, ERCOT is expecting similar conditions the morning of Jan. 17. 

The grid operator thanked Texas residents and businesses on X. 

“Your conservation efforts, along with additional grid reliability tools, helped us get through record-breaking peak times today and yesterday morning,” it posted Jan. 16. 

ERCOT was also boosted by energy storage and solar resources. Batteries peaked at more than 1,200 MW during the early morning hours Jan. 16; solar produced a record 14.21 GW of energy at 10:40 a.m.  

The grid’s staff said in December that there was a 1-in-6 chance of outages this winter if conditions matched those of the 2022 winter storm. While the temperatures have been frigid — Dallas has been below freezing since the afternoon of Jan. 13, with a low of 11 degrees Fahrenheit the morning of Jan. 15 — thermal outages were slightly below average at 7 GW. 

Texas Gov. Greg Abbott (R) took to X to praise ERCOT’s “flawless” performance, a credit, he said, to recent measures to weatherize critical facilities and strengthen the grid. 

Wholesale electricity prices hit $500/MWh during one 15-minute interval the morning of Jan. 16 but have generally stayed below $200/MWh since Jan. 13. 

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NERC Taking Comments as Winter Reliability Standard Deadline Looms

NERC is taking comments on a winter reliability standard for generators that has failed to clear its stakeholder process twice, the ERO announced Jan. 16.  

Comments are due by 8 p.m. EST on Jan. 22. NERC hopes to get one more vote on the rule, which failed to clear the stakeholder process its second time Nov. 30 with only 58% in support, short of the two-thirds required. If stakeholders fail to approve it this time, NERC Board of Trustees Chair Ken DeFontes has said the board might have to move the standard forward on its own. (See Standards Committee Authorizes Shortened Ballots.) 

FERC has required a new reliability standard to be filed by February based on the recommendations from its joint report with NERC on Winter Storm Uri, which led to deadly blackouts in Texas in February 2021. 

The proposed rule (EOP-012-2) would require generators to review their risks for extreme cold weather, which equates to the lowest 0.2 percent of hourly temperatures measured in December, January and February from Jan. 1, 2000, until the date temperatures are calculated. Any generator with extreme temperatures at or below freezing (32 degrees Fahrenheit) will have to comply with the standard. 

The proposal would require generators to develop and implement plans designed to mitigate the reliability impacts of cold weather. If the generators see lower extreme temperatures on their five-year reviews, those plans would have to be reviewed to ensure that they are in compliance with the standard and if they would have to identify additional mitigation measures. 

Generators would have to implement freeze protection measures that protect critical components so they could keep operating at their calculated extreme cold weather temperatures with sustained wind speeds of 20 mph for a period of not less than 12 continuous hours, or the maximum operational duration for intermittent energy resources. 

If a generator cannot meet the proposed standard’s requirements, it would be required to add new or modify existing freeze protection measures to provide the capability to operate at the extreme cold temperatures for its location. 

Generators will have to show that they have followed those cold weather plans and trained their staff to implement them, the proposed standard says. 

NERC plans to hold a nonbinding poll on the associated violation risk factors and violation severity levels through Jan. 22. 

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Congressional Democrats Urge FERC to Complete Transmission Rule

Nearly half the Democrats in Congress sent a pair of identical letters to FERC on Jan. 16 urging the commission to finalize its proposed transmission planning and cost allocation rule.

Sens. Martin Heinrich (D-N.M.) and Ed Markey (D-Mass.) led the group of 21 senators from the party in sending the upper house’s letter, while Rep. Paul Tonko (D-N.Y.) led the group of 113 House members in its version of the letter.

“In recent years, we have witnessed numerous examples of grid resilience issues, which have highlighted the inadequacy of the grid to handle changing load patterns, interconnect new clean energy resources and respond to increasingly frequent and severe extreme weather events,” read both letters, which were addressed to FERC Chair Willie Phillips. “FERC’s final rule should ensure that transmission planners account for these factors by requiring a long-term, forward-looking, 20-year planning horizon that addresses the changing circumstances and the evolution of our energy system.”

Phillips has said since assuming the chair that he wanted to move forward the Notice of Proposed Rulemaking on transmission, which was issued in April 2022. The commission also has to issue an order on rehearing for Order 2023, which updated its minimum standards for interconnection queues around the country. (See FERC Updates Interconnection Queue Process with Order 2023.)

The congressional letters follow some from stakeholders last month urging FERC to complete the rule this year. (See FERC Gets Growing Call to Finish Transmission Rule in 2024.)

The Department of Energy has said improved and increased transmission is needed for reliability, affordability and clean electricity. The department’s National Transmission Needs Study found capacity will need to double in many parts of the country by 2035 to meet the Biden administration’s clean energy goals, assuming just moderate load growth, the members said.

“In order to grow our economy, keep communities safe during extreme weather events, address historic environmental injustices and decrease energy costs for consumers, a robust and well-planned transmission grid is essential,” the letters said. “With a strong final rule, FERC can play a critical role in achieving these goals, fulfilling the promise of the most consequential infrastructure and climate laws in history.”

The Inflation Reduction Act and the Infrastructure Investment and Jobs Act have committed the country to a historic energy transition, they said, but the electric grid needs to be expanded to make that possible.

Americans for a Clean Energy Grid Executive Director Christina Hayes welcomed the support for finalizing the rule from Congress.

“The grid is in need of a 21st-century update, and the reforms currently pending at FERC will go a long way toward increasing the reliability and resiliency of our energy system and ensuring the delivery of cost-effective energy to all Americans,” Hayes said in a statement. “We will continue to work closely with FERC to help finalize a durable rule that advances the development of high-capacity transmission for the benefit of customers throughout the country.”

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Christie Denounces Tx Incentive Process as FERC Approves More MISO LRTP Project Perks

Commissioner Mark Christie has used FERC’s latest order on transmission incentives to condemn the commission’s process as requests for incentives come in fast and thick from MISO’s long-range transmission projects.

This time, FERC granted Xcel Energy’s ask for construction work in progress (CWIP) incentives and abandoned plant incentives for four 345-kV long-range transmission plan (LRTP) projects in South Dakota, Minnesota and Wisconsin, which allow Xcel to recover incurred costs in rates if the lines are canceled for reasons beyond its control (ER24-409).

The incentives apply to Xcel’s portions of the Big Stone South-Alexandria-Cassie’s Crossing project, the Wilmarth-North Rochester-Tremval project, the Tremval-Eau Claire-Jump River project and the Tremval-Rocky Run-Columbia project.

Xcel said it plans to spend up to $1.2 billion on construction for its portions of the projects. The utility said its Wisconsin- and Minnesota-based Northern States Power subsidiaries “expect to face a negative cash flow position while undergoing extensive levels of capital expenditures over the next several years” to build the LRTP projects.

Xcel said the CWIP incentive will improve cash flow and credit ratings during construction. It also said the projects carry heightened risks of abandonment because multiple utilities over multiple states are working in concert to build the lines. Xcel added that an economic downturn could hurt the chances for the lines, which were planned to serve projected, not existing, generation.

FERC agreed that the CWIP and abandoned plant incentives are “tailored to address the risks and challenges” Xcel’s subsidiaries will face as they undertake the projects.

But in a concurrence, Christie repeated that FERC’s granting of incentives “has become nothing more than a check-the-box exercise.” Christie has become increasingly critical of transmission incentives in FERC orders allowing them for developers. (See FERC Approves Dairyland Incentives for Minn.-Wis. Transmission Line.)

Christie said though FERC followed its protocol to grant Xcel the incentives, it’s time for FERC to revisit its CWIP and abandoned plant incentives, as well as the RTO participation adder, which he called “an involuntary gift from consumers.”

Christie repeated concerns that the CWIP incentive allows utilities to recover costs before a line has been placed into service, effectively forcing customers to serve as a lender for transmission development while they earn zero in interest and even pay utilities a profit through return on equity. He also said the abandoned plant incentive makes ratepayers the “insurer of last resort” as well as the lender on projects.

“Just as consumers receive no interest for the money they effectively loan transmission developers through CWIP, they receive no premiums for the insurance they provide through the abandoned plant incentive if the project is never built,” he wrote. “There is something really wrong with this picture.”

Christie said he supports FERC’s recent proposals contained in notices of proposed rulemaking to limit the RTO participation adder to three years after a utility has joined an RTO and eliminate CWIP incentives. He said those steps, alongside a reconsideration of the abandoned plant incentive, will “ensure that all the costs and risks associated with transmission construction are not unfairly inflicted on consumers while transmission developers and owners stand to gain all the financial reward.”

“In short, revisiting all these incentives is imperative at a time of rapidly rising customer power bills,” Christie said.

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DOE Partners with HVAC Industry on Cold Climate Heat Pumps

With temperatures plunging and home heating bills rising across the country, the Department of Energy recently announced that four companies have developed high-efficiency cold climate heat pumps as part of the department’s Residential Cold Climate Heat Pump (CCHP) Technology Challenge.

The four companies — Bosch, Daikin, Midea and Johnson Controls — have completed laboratory testing for CCHPs that can “deliver 100% heating capacity without the use of auxiliary heat and with significantly higher efficiencies at 5 degrees Fahrenheit,” according to the Jan. 8 announcement.

The next phase of the challenge is “expected to involve the installation and monitoring of … prototypes in various cold-climate locations throughout the U.S. and Canada over the next year,” the announcement says.

Electric heat pumps, which can be used for heating or cooling, extract heat from the air or ground outside the building and then run the heat through a compressor before releasing it inside, according to a DOE factsheet. However, until recently, many of the available models did not perform well in subfreezing temperatures.

Launched in 2021, DOE’s CCHP Technology Challenge is aimed at fostering public-private partnerships “to address the technical challenges and market barriers to adopting next-generation cold-climate heat pumps,” the department says. The initiative has two tracks: one for heat pumps that can operate at 5 F, another optional one for ‑15 F.

The goal is to “ensure that Americans have access to more affordable clean heating and cooling options — no matter where they live,” Energy Secretary Jennifer Granholm said in the announcement.

In addition to the companies announced Jan. 8, four other companies ― Lennox International, Carrier, Trane Technologies and Rheem ― also have produced successful prototypes, according to DOE.

Space heating and cooling across all building types ― homes, offices, schools, hospitals and military bases ― accounts for 35% of U.S. energy consumption, according to DOE. Especially when paired with good building insulation and clean electricity, an electric heat pump may produce about half the GHG emissions of an oil- or gas-fired furnace while saving consumers an estimated $500/year on utility bills.

The Bosch prototype can operate down to a temperature of ‑13 F, according to a company spokesperson.

“The system is equipped with inverter technology, which ramps the compressor up or down to heat (or cool) the home in an efficient way,” the spokesperson said in an email to NetZero Insider. “What enables the cold climate heating is the enhanced vapor injection (EVI) compressor; it essentially borrows additional heat from the hot side of the … cycle and redirects it to help warm up the home on frigid days.”

Bosch and the seven other companies in the challenge are now field-testing more than 20 heat pumps at locations in 10 states and two Canadian provinces, according to a DOE spokesperson.

The Biden administration has promoted heat pump adoption as part of its drive to decarbonize the electric grid by 2035 and cut U.S. GHG emissions 50 to 52% by 2050, and states are following suit.

The Inflation Reduction Act includes a tax credit of up to $2,000 for the purchase and installation of heat pumps. State incentives in Maine have resulted in the installation of more than 100,000 heat pumps, leading Gov. Janet Mills (D) to set a new target of installing an additional 175,000 by 2027. (See Maine Blows Past Heat Pump Installation Target.)

Maryland’s recently released Climate Pollution Reduction Plan calls for state incentives to cover 100% of heat pump costs for low- and moderate-income households ― although the cash-strapped state will have to come up with extra funding to pay for such initiatives. (See Md. Emission-reduction Plan: High Ambitions, No Funding.)

Beyond cost, cold climate heat pumps will have to prove themselves through field-testing during extreme weather events, such as the current polar vortex blanketing major parts of the U.S. with subfreezing temperatures. The thermometer dropped close to or below zero in North Dakota, Minnesota and Wisconsin on Jan. 16.

Heat pump sales in U.S. surged past gas furnaces in 2022 | Canary Media

According to Canary Media, 2022 saw heat pump sales edge past gas furnace sales for the first time. Business analysts such as Global Market Insights anticipate the CCHP market will grow 10% per year through 2032.

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Mass. Lawmakers Aiming for an Omnibus Climate Bill in 2024

Top legislators in Massachusetts this year hope to pass a major climate and energy bill, which could bring significant permitting and siting reform, and boost transportation and heating electrification.

“The clock is ticking,” Sen. Mike Barrett (D), Senate co-chair of the legislature’s Joint Committee on Telecommunications, Utilities and Energy (TUE), told NetZero Insider. The legislature has until the end of July to reach a consensus.

“It’s my hope that we’ll have something by the springtime on the floor of the House,” said Jeff Roy (D), House co-chair of the TUE committee.

The TUE committee was responsible for a large portion of the omnibus climate bills passed in 2021 and 2022 under the administration of Gov. Charlie Baker (R). These bills contained wide-ranging provisions aimed at expediting the state’s clean energy transition, including setting emissions limits for the major sectors of the state’s economy and directing the procurement of 5,600 MW of offshore wind capacity.

The general template for the bills, which presumably will carry over into 2024, was for the House and Senate to pass distinct legislation compiled from smaller bills introduced earlier in the session. The two chambers then would form a conference committee to reconcile differences between the bills, with the resulting bill eventually passed by both chambers and sent to the governor.

“It’s going to be a really interesting time,” said Kyle Murray, director of state program implementation at the Acadia Center, a climate-focused nonprofit. Murray praised the steps taken in the previous two bills but added that “we’ve got so many areas we still need to cover.”

Permitting and Siting Reform

One major theme emerging for the session is reforming permitting and siting processes for clean energy projects and infrastructure.

“In order to get all this infrastructure built, and to get it built in a timely manner to have an impact on the goals we set, we need to do something about the permitting and siting process,” Roy said.

For most projects today, “it’s going to take you three to five years to get the shovel in the ground because you have to do so many steps in the permitting process,” Roy said. “We’re looking at legislation to revamp the process and bring it down to more like 18 months.”

Roy has introduced a bill that would consolidate the state and local permitting process under a new “electric decarbonization infrastructure permitting office.” The bill also would introduce a roughly six-month process for the office to respond to applications.

S.2113/H.3187, a separate bill aimed at expediting the development of clean energy while protecting environmental justice communities, would introduce significant reforms to the state’s Energy Facilities Siting Board. The bill is a top priority of the Mass Power Forward coalition, a coalition of many of the state’s most influential climate and environmental organizations.

The proposal is intended to prevent new polluting infrastructure in “the same communities that have been dumped on for decades and decades because of systemic racism,” said Claire-Karl Müller, coordinator of Mass Power Forward. The bill simultaneously would speed up the review process for solar, wind and geothermal projects.

“It’s important to do this transition quickly, but we want to make sure it’s done equitably,” Müller said.

The state’s Commission on Clean Energy Infrastructure Siting and Permitting also is due to publish its final legislative and regulatory recommendations at the end of March. (See Massachusetts Announces Permitting And Siting Reform Commission.) Created by Gov. Maura Healey (D) in the fall, the commission is aimed at cutting timelines and barriers for clean energy projects.

Transmission Planning

The state’s Clean Energy Transmission Working Group (CETWG), created in 2022 climate law, released its final report at the end of December, calling for a “more comprehensive, proactive and forward-looking transmission planning processes.”

The CETWG recommended the legislature amend state laws to allow the Department of Energy Resources to “competitively solicit and select proposals for transmission to deliver clean energy generation to help achieve the Commonwealth’s clean energy requirements, beyond existing authority to solicit and select transmission related solely to offshore wind.”

The final recommendations also called for increased efforts to reduce transmission needs through load growth including time-of-use rates, demand response and energy efficiency. The CETWG also advocated for a regional analysis of the potential of alternative transmission technologies (ATTs).

As an offshoot of their work on the CETWG, Roy and Barrett also introduced bills in the House and Senate that would require utilities to consider ATTs including grid-enhancing technologies, advanced reconductoring and energy storage when planning upgrades to the transmission system.

“We both filed that legislation, which is probably a good sign that it’s something we will agree on this session,” Roy said.

Heating Decarbonization and Electrification

The legislature also is considering a number of bills aimed at supporting heating electrification. Data from the U.S. Energy Information Administration shows that natural gas consumption in Massachusetts increased by about 8% in 2022, and natural gas remains one of the largest sources of carbon emissions in the state.

Legislators so far have submitted a wide range of proposals aimed at cutting gas emissions, from a moratorium on the further expansion of the gas system to bills that would promote blending alternative fuels like renewable natural gas and hydrogen into the network.

For Senate TUE Chair Barrett, one key component is creating “linkage” between the expansion of the electric distribution system and the contraction of the natural gas system.

“Building out the grid — while it’s very important to delivering green juice everywhere it needs to be delivered — is going to make the utilities very wealthy because they make a rate of return on all construction projects,” Barrett said. “What do you ask of the utilities as you deliver vast riches to them? It can’t be zero.”

He noted that approval of increased investments in the grid could be coupled with requiring the utilities to speed up the interconnection of clean energy projects and downsize gas operations.

Barrett also expressed optimism that two programs passed in previous legislation — a new municipal opt-in building code which incentivizes electrification and a 10-town pilot program which allows municipalities to ban fossil fuels in new buildings — will start to make a significant dent in the state’s gas consumption in 2024.

However, both TUE chairs indicated they’re not likely to pass new provisions to directly prohibit the expansion of the state’s gas system, such as an expansion of the 10-town pilot program or a statewide moratorium.

“I think we need time for that pilot project to take place and to get some reporting and data back,” Roy said.

For climate activists pushing for a moratorium on new infrastructure, the verdict on new natural gas infrastructure is clear.

“It is more than beyond obvious that we need to stop building fossil fuels,” said Müller of Mass Power Forward. “We know we can’t be expanding gas.”

The legislature also could consider changes to the state’s Gas System Enhancement Program (GSEP), which is aimed at replacing old pipes to reduce methane leaks. The program has faced criticism for facilitating billions in new gas system investments that could become stranded assets because of the state’s decarbonization efforts. The program ultimately could cost ratepayers over $40 billion, according to a 2021 report.

The 2022 climate bill created a GSEP stakeholder working group, which is tasked with drafting recommendations on changes to the program that would align it with the state’s climate laws. The group released a draft outline of its recommendations in December and likely will publish its final recommendations at some point this session.

The Department of Public Utilities also included legislative recommendations in its recent order on the “Future of Gas” proceeding (DPU 20-80), which requires gas utilities to consider nonpipe alternatives when planning new infrastructure investments and discourages further expansion of the gas system. (See Massachusetts Moves to Limit New Gas Infrastructure.)

The 20-80 ruling also highlighted an apparent contradiction between the state’s required emissions targets and a law passed in 2014 that requires the DPU to “review and approve proposals designed to increase the availability, affordability and feasibility of natural gas service for new customers.”

The DPU recommended the legislature repeal this law to allow the department to “pursue fully its mandate to prioritize reductions in GHG emissions along with safety, security, reliability of service, affordability and equity.”

Speaking at an event in December, DPU Chair Jamie Van Nostrand said the state should reconsider laws that give residential and commercial customers the right to gas service.

“Customers are still going to be provided the essential utility service of heat, but it may be provided in some way other than gas,” Van Nostrand said. (See Clements Outlines Further Steps to Ease Interconnection Woes.)

Transportation

Transportation decarbonization also is likely to be on the docket this session, with the legislature weighing proposals to boost electric vehicle (EV) charging infrastructure and increase ridership on mass transit.

Roy has been especially vocal about the need for more robust charging infrastructure, and he highlighted the state’s ambitious goal to have 900,000 EVs on the road by 2030 (compared to about 70,000 in 2022).

“That’s going to require a huge investment in charging infrastructure,” Roy said. He introduced a bill in early 2023 that would direct state agencies to forecast EV demand and optimal charging locations and require the electric utilities to submit plans for the grid upgrades needed to meet this demand.

Murray of the Acadia Center stressed the importance of securing funding for public transport in the state. According to a recent assessment by the Massachusetts Taxpayers Foundation, the state would need to invest an additional $2 billion annually through 2036 just to make all the necessary repairs for the existing system. This excludes any potential expansion, resilience or modernization efforts to help the state meet its climate goals.

“We need a more stable funding source for the MBTA [Massachusetts Bay Transportation Authority]. I really do think we need to address that at some point in the very near future,” said Murray, while acknowledging the added difficulty of the state’s current financial troubles. Gov. Healey recently proposed a $375 million budget cut to stave off an impending shortfall.

Caitlin Peale Sloan, vice president for Massachusetts at the Conservation Law Foundation, echoed the need to properly fund the MBTA to help reduce total vehicle miles traveled. She added the state also needs to think long term about how to electrify trains and buses, particularly those that operate in environmental justice neighborhoods.

“When it comes to mass transit, it’s a balance,” Peale Sloan said. “We don’t want to make mass transit more difficult and more expensive to users — we want more people using it. But we need to have the big picture plan and start to get that moving.”

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Offshore Wind: NY, NJ Collaborate to Boost Infrastructure, Supply Chain

A.J. Negrelli, Attentive Energy | © RTO Insider LLC

BROOKLYN — Two states with some of the most ambitious offshore wind goals in the nation — and some of the biggest problems in their offshore wind portfolios — brought stakeholders together last week, trying to keep things on track in 2024.

The New York-New Jersey Offshore Wind Supplier Forum on Jan. 11 was part of a growing wind power collaboration by the two states whose coasts form the New York Bight, a stretch of the Outer Continental Shelf that is a prime zone for wind energy development.

In the past few months, they also have shared the frustration of watching thousands of contracted megawatts fall out of their offshore development pipelines.

Some speakers at the forum glossed over the industry’s problems, making only passing reference to the recent cancellation of Ocean Wind 1 and 2 in New Jersey and the offtake contract for Empire Wind 2 in New York. (See Orsted Cancels Ocean Wind, Suspends Skipjack and Empire Wind 2 Cancels OSW Agreement with New York.)

Greg Lampman, New York State Energy Research and Development Authority | © RTO Insider LLC

Officials from the state agencies that organized the event were not so circumspect.

“Hardship brings people together, right?” asked Greg Lampman, director of offshore wind for the New York State Energy Research and Development Authority.

“This is an example of some of the challenges we’re seeing, and how working with New York and New Jersey and the other states in the region, we can help make sure this industry is built, that it’s built sustainably and that it’s robust.”

The U.S. ended 2023 with just 42 MW of installed offshore wind capacity, less than one-one-thousandth of the global total. But it has grand ambitions; New York and New Jersey alone have a combined goal of 20 GW. Combined with the other Eastern states, the target is more than 50 GW, Lampman said.

Jan. 11’s forum reflected the importance of creating an entire industry and support network for this to happen.

Jen Becker, New Jersey Economic Development Authority | © RTO Insider LLC

“Our work is to bring this all together and create the ecosystem that allows the developers to do their work,” Lampman said.

Jen Becker, vice president for offshore wind at the New Jersey Economic Development Authority (NJEDA), listed a few of the collaborative efforts underway by the two states: joint industry training with Oceantic Network, development of a technical assistance program for small businesses and a joint website about training and workforce needs.

The U.S. Bureau of Ocean Energy Management set the stage for this two years ago, issuing a “shared vision” for the two states to collaborate on a supply chain.

Dan Fatton, New Jersey Economic Development Authority | © RTO Insider LLC

Dan Fatton of NJEDA displayed a regional map of the 800-plus businesses that have joined the New Jersey Offshore Wind Supply Chain Registry. The pins spread well beyond New Jersey into New York and southern New England.

He joked about the sense of competition or one-upmanship that can arise when there are ambitious goals and limited resources, but he also pointed to the benefits of the collaboration: “This is a historic moment — we are partnering with New York on this event and on a series of events to come, and we’re really thrilled to have a full room of folks to celebrate this moment with us.”

There were 544 registrants for the event, which filled a sprawling ballroom in a Brooklyn hotel and spilled into adjoining spaces.

Talking Business

An attendee posed a sticky question: Would New York and New Jersey consider regional benefits when reviewing proposals, rather than crediting only those economic benefits that accrue to their state?

David Howard, Community Offshore Wind | © RTO Insider LLC

“We are in conversation about how we could do some cross-crediting, but I think we’re still in an early stage,” Fatton said. “I think we’ll get there with time.”

“Everyone asks, ‘When are you going to share your supply chain?’ and I keep looking for the supply chain,” Lampman said. Allocating the credits and other benefits from that supply chain is secondary to creating the supply chain, he added.

Yvette Mouton, Atlantic Shores Offshore Wind | © RTO Insider LLC

Another asked how the state agencies would hold developers accountable for the local content requirements in their solicitations.

Lampman said accountability is laid out in the project’s contract. Fatton said New Jersey is working toward monthly meetings and quarterly reports with contract holders.

Representatives of the major offshore wind developers in the region offered advice to small business owners who want a piece of the multibillion-dollar pie.

Yvette Mouton of Atlantic Shores Offshore Wind urged companies to produce a good summary of their strengths. “My favorite part of the job is mentoring diverse suppliers and helping people to grow,” she said. “We need to have a starting point, and that starting point is usually a capability statement.” Two pages is good, she added. Twenty-five is not.

A.J. Negrelli of Attentive Energy urged business owners to know who their prospective clients are and what they require. “Make sure you’re qualified with those buyers” as an approved vendor, he said. “Offshore wind has a very strict due-diligence process. A big part of that is also just understanding, what are the differences in offshore wind — do you need to have new certifications?”

Amanda Schoen, Equinor | © RTO Insider LLC

Amanda Schoen of Equinor spoke of the South Brooklyn Marine Terminal, two miles south of the hotel, which her company and bp plan to develop as an offshore wind port starting this year. “There’s not many ports like this one,” she said, noting the lack of bridge-height or channel-depth restrictions. “This is an asset not just for Equinor but for the industry writ large.”

David Howard of Community Offshore Wind challenged his industry peers to collaborate to build the ecosystem they will need. “No developer is going to do this alone — we have to work together. I like to call it cooperative competition. … We have to share assets, we have to amortize together, we have to find a way to bring the costs down.”

He added that Community Offshore already is signing up contractors even though it has only a provisional contract award from New York state, no state or federal permits, and three or more years to go before construction. It must do this, he said — the global bottleneck is that bad. “We have to start contracting now to secure CODs. It’s not your traditional procurement where you’re going competitive a year or two prior to delivery, it’s many, many years in advance.”

Kevin Hansen, Ørsted | © RTO Insider LLC

Kevin Hansen of Ørsted offered a neat summation:

“These projects are incredibly reliant on suppliers. If you look at the jobs, if you look at the money that gets spent, it’s not for employees of my company, it’s for employees of your companies. There are tremendous opportunities for local content.”

Hansen also highlighted the interdependent nature of the entire process. Ørsted has a dozen major contractors, each of which has a set of contractors, each of which has their own suppliers and subcontractors, he said.

“So, there’s this incredibly complex collection of people and we all have to work together, because if one party is late, it might impact other parties.”

Representatives of Vestas speak to attendees at the New York-New Jersey Offshore Wind Supplier Forum on Jan. 11 in Brooklyn. | © RTO Insider LLC

Ørsted’s own Ocean Wind projects demonstrated this point to significant effect: Delayed completion of an installation vessel was a primary factor in cancellation of the two wind farms.

But on another Ørsted project, South Fork Wind, the pieces came together well enough that in late 2023, it became the first utility-scale offshore wind farm to send power to the U.S. grid.

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Offshore Wind: Analyst Addresses Industry’s Growing Pains

BROOKLYN, N.Y. — Attendees at the Jan. 11 Offshore Wind Supplier Forum were treated to a precise assessment of what they already knew in varying levels of detail: The young U.S. industry had a difficult time in 2023 and has some growing pains ahead in 2024 and beyond. 

BloombergNEF offshore wind analyst Chelsea Jean-Michel said BNEF has reduced its forecast for 2030 installed U.S. offshore wind capacity by 44% due to soaring costs and other struggles. 

Also, BNEF calculates the levelized cost of electricity for new offshore wind projects at 48% higher in 2023 than in 2021, and that is assuming they qualify for the full 40% investment tax credit, rather than 30%. 

And projects totaling more than 12 GW — more than half the U.S. pipeline — have canceled or sought to renegotiate their contracts. 

BNEF’s analysis shows the levelized cost of electricity produced by new offshore wind plants soaring in 2022 and 2023. | BloombergNEF

“I hope I haven’t depressed you all too much,” she said to laughter from the room, after 15 minutes of doing just that. “There is so much to be excited for in the industry and so much to be optimistic for. At BNEF we really do view these struggles as a bump in the road, as a sign of growing pains.” 

Some of the positives: Only 12% of the pipeline is at the highest risk of cancellation; New York reached provisional contract agreement on three large new offshore proposals even amid all the struggles of 2023; up to 14.8 GW of new contracts could be awarded in five states in 2024; and inflation adjustment mechanisms are being offered in the latest offshore solicitations. 

As the offshore wind industry was setting up in the United States, Jean-Michel said, there were some key departures from practices in Europe: States awarded contracts early on in development, rather than later in the process, and compensation was locked in for the life of the contact, rather than with provisions for regular adjustments to reflect rising costs. 

Two of the first offshore projects contracted in the United States — Vineyard Wind 1 and South Fork Wind 1 — were far enough along when costs began to skyrocket in 2022 that they could continue to construction. But several others were not. Two offshore farms have been canceled outright before construction, four others have canceled their contracts, and at least three others are at risk of canceling their contracts. 

The first monopile foundation complete in New Jersey for the Ocean Wind 1 project is shown in mid-2023. Ørsted canceled Ocean Wind 1 and 2 later in 2023 due to the financial and logistic challenges BNEF analyst Chelsea Jean-Michel laid out in her Jan. 11 presentation. | Ørsted

The levelized cost of electricity for all renewables has risen, Jean-Michel said, not just offshore wind. 

Onshore wind turbines cost 30% more than they did before the pandemic, she said. It is harder to track the price of offshore turbines because there are fewer such projects and they are less transparent, she added, but “There is reason to believe that offshore wind prices have followed a very similar trend.” 

Jean-Michel displayed a chart handicapping 20 nations’ offshore wind goals. 

“What’s very telling here is that we don’t think any of these markets are really going to meet their offshore wind targets, except for Taiwan and Poland,” she said. “The U.S. has been hardest hit by some of these macroeconomic pressures.” 

Jean-Michel was asked if she thought there would be a true “return to normal” and an end to the financial problems plaguing the offshore industry. 

She said it is impossible to predict the future, but governments have adjusted policies to account for financial risk; whether it is enough of an accommodation will start to become apparent soon. 

Government support does remain firm at the state and local level. Both states sponsoring Thursday’s forum are bullish on offshore wind as a source of emissions-free energy as well as jobs.  

New York and New Jersey are attempting rapid turnarounds after losing three major offshore projects from their portfolios in two months. They are stepping up collaboration with each other to improve the chances of success, and they are continuing to support offshore development with money and policymaking. 

Greg Lampman of the New York State Energy Research and Development Authority spoke of the scramble underway.  

As onshore and offshore renewable projects cancel unprofitable contracts, NYSERDA is racing to get them (or replacements) back in the pipeline at higher costs through new requests for proposals. “Racing” is not overstating the matter — it is a blistering pace by the standards of the regulatory world. 

“I’ve got to tell you, I didn’t think we could do it,” Lampman said. “This is moving mountains. Our RFP process typically takes about 14 months. We’re doing it in three.” 

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Offshore Wind: Smaller Companies Help Get Steel in the Water off NY

BROOKLYN, N.Y. — Offshore wind development is the sum of many parts, creating many business opportunities beyond the heavy manufacturing and heavy lifting that only a few companies can perform. 

This point was made repeatedly at the New York-New Jersey Offshore Wind Supplier Forum in Brooklyn on Jan. 11. The two states have a combined 20-GW goal and expect those projects to need everything from lighting and security fencing to paving and portable offices to meal delivery and housekeeping. And electrical components, of course. 

“There’s a lot of opportunity for small suppliers, bigger suppliers to come in and deliver goods and services,” said Steffen Bo Clausen of Vestas Wind Systems. 

“It’s an emerging market, but the general approach with Vestas historically, we’ve used the local supply chain in the neighborhood for many things.” 

NetZero Insider spoke to leaders of two very different New York companies that have benefited from offshore wind development. 

The Turnaround

Ljungstrom is one of those success stories that advocates hope offshore wind will nurture in the United States during the transition away from fossil energy. 

The company builds efficiency components for coal-burning power plants at a factory in Wellsville, more than 200 miles from the nearest ocean shoreline.  

And it is located in one of the original U.S. oil patches — legend has it that in 1627, at a spring not far from where the Ljungstrom factory stands today, a French missionary was the first European to see petroleum in North America. 

Ljungstrom’s employee ranks had been shrinking with the coal industry, but that stopped when the company won contracts to build secondary steel components (anode cages, internal platforms, monopile doors) for the South Fork, Revolution and Sunrise offshore wind farms. 

“This has been amazing for our workforce. We’ve hired a hundred people in the last year,” said Nick George, a member of the sales team.  

“Jude’s personal goal here is to never lay off anyone again,” he added, referring to business development manager Jude Auman.  

Ljungstrom had a moment in the spotlight two days earlier, as Gov. Kathy Hochul (D) highlighted its turnaround in the video introduction to her State of the State Address. Auman narrated that segment of the video.  

George and Auman said the transition from coal to marine wind was not difficult. 

“Learning new specs and all that, we’re good at that,” George said. “There’s aches and pains along the way, but for the most part [it’s] an easy transition.” 

Onshore wind has been a harder nut to crack. Ljungstrom could do the work, but it has not been able to get into the supply chain, which is firmly established in the United States. 

The new offshore wind industry has provided an unlikely opportunity for the company and the Allegany County, where the population has been stagnant or shrinking for decades. Census data show a significantly smaller percentage of county residents engaged in the workforce than New Yorkers as a whole and a poverty rate significantly higher in the county than for the state. 

There simply are not very many good jobs. And, not coincidentally, there are not very many skilled workers. 

“I think there’s only 45,000 residents in Allegany County,” George said. “It’s tough to find and keep people.” 

Red Ironworks of Babylon, N.Y., was among the companies that completed the South Fork Wind substation, shown here while work was in progress in 2023. | South Fork Wind

The Growth Curve

Many speakers at the forum emphasized the importance of skilled workers in the equation.  

Red Ironworks CEO Jason Chadee, who spent two months straight at sea helping build the South Fork Wind substation last year, spoke about the importance of having the right people on an installation project. 

“You really have to educate the workforce on what it is to work offshore — you’re not going to have cellphone service, you’re going to be away from your family for some time, those things take a mental toll. These things you have to consider. Some people are on restricted diets. When you go out there, you eat what is supplied.” 

Jason Chadee, CEO of Red Ironworks, is shown at the New York-New Jersey Offshore Wind Supplier Forum in Brooklyn on Jan. 11, 2024. | © RTO Insider LLC

The worst thing for Chadee was not the tight living quarters or lack of cell service, it was the time away from his children when fog and other delaying factors extended his time at sea. 

“I’ll be honest with you, I wasn’t planning to be there for two months, I was planning to be there two weeks,” Chadee said. “I didn’t plan on it, but I did it as a decision for the company.” 

Chadee bought majority ownership of the Long Island company two years ago. It was not specifically a play for the new offshore wind market — he had been following the sector for years as it took shape, but he was focused more on the terrestrial projects that provide the bulk of the company’s work. 

“I used to be a consultant for them. I saw opportunity to grow,” Chadee said. “Since then, we grew about 800%.” 

He thinks experienced onshore ironworkers can transition well to offshore work. As members of the union, they have a minimum of 1,000 hours of classroom training and 6,000 hours of field experience. They can do the tasks involved. The question is whether they want to. 

“I am an ironworker by trade, and all the other ironworkers there, we are accustomed to working very hard and working a lot of overtime for many years,” Chadee said. “The new workforce, that is something they have to consider. I think they need to engage that person, so they know what they are getting into.” 

There will be some attrition, he predicted. 

“Based on the crew they had out there, there’s a couple of them that said they don’t want to do that again. So, there are people I think after their first rotation or two won’t like it. Definitely.”