Vineyard Wind said it has obtained federal approval to resume construction of the wind farm – work that was suspended following the partial collapse of a previously installed turbine blade on July 13.

A press release issued at 7 a.m. Tuesday morning said the Bureau of Safety and Environmental Enforcement had given the developers of the wind farm permission to resume the installation of towers and nacelles (which sit atop the tower and convert wind energy into electricity), but a suspension remains in effect for turbine blades and power generation.

Vineyard Wind is a 62-turbine project and only 24 had been completed at the time of the accident. Work is resuming on the remaining 38 turbines but blades cannot be installed nor power produced under the terms of the revised suspension order. Of the 24 completed turbines, 11 were generating electricity at the time of the incident and 13, including the one that broke, were undergoing testing.

In a joint press release, Vineyard Wind and GE Vernova, the manufacturer of the wind turbines, said a barge departed the New Bedford Marine Commerce Terminal Tuesday morning for the wind farm carrying turbine components, including several tower sections and one nacelle.

“The vessel will also carry a rack of three blades solely for the purpose of ensuring safe and balanced composition for the transport,” the press release said, adding that the blades will not be installed and will be returned to New Bedford later in the week.  

The press release said the Bureau of Safety and Environmental Enforcement revised its suspension order after examining records and a structural load analysis conducted by a third party. The federal agency had no mention of a revised suspension order on its website Tuesday morning.

Vineyard Wind and GE Vernova also said “a substantial amount” of what remained of the damaged blade was cut away on Sunday and Monday.

“During the operations, Vineyard Wind and GE Vernova mobilized maritime crews on multiple vessels nearby to secure as much debris as possible for immediate containment and removal as well as land-based crews managing debris recovery,” the press release said. ”Vineyard Wind and GE Vernova are currently assessing next steps to complete any additional cutting necessary at the earliest opportunity, secure and remove the debris on the turbine platform, remove the blade root, and address the debris on the seabed.”

The blade incident at Vineyard Wind, a joint venture of Avangrid and Vineyard Offshore, has been a major setback for the first industrial scale wind farm in the United States. Foam and fiberglass from the turbine has washed up on Nantucket and other beaches on the Cape and Martha’s Vineyard and raised questions about wind energy at a time when the industry is trying to ramp up production.

A preliminary investigation by GE Vernova has suggested the blade breakdown was caused by a “manufacturing deviation” – specifically insufficient bonding of the blade materials. The company has indicated no problems with the design of the Haliade-X blade, which is 853 feet tall.

It was unclear when Nantucket officials were notified about the resumption of construction of the wind farm. Updates posted on the town website indicated the Select Board was aware of the efforts beginning on Sunday to remove more of the damaged turbine blade.

During an executive session on Thursday, the Select Board met to discuss “strategy with respect to potential litigation in connection with Vineyard Wind,” according to the agenda.

This article first appeared on CommonWealth Beacon and is republished here under a Creative Commons license.

That’s according to the latest reporting from the U.S. Energy Information Administration (EIA). For perspective, the 40.4 GW of generating capacity added in 2023 was the most in a year since 2003.

EIA said 20.2 GW came online during the first half of 2024, 3.6 GW (or 21%) more than the capacity added during the first six months of 2023.

Solar continued to lead all U.S. generating capacity additions in the first half of 2024, representing 12 GW (or 59% of all additions). Texas and Florida made up 38% of U.S. solar additions. The largest new projects included the 690 MW solar and storage Gemini facility in Nevada and the 653 MW Lumina Solar Project in Texas.

Nearly 60% of the planned capacity (25 GW) for the second half of 2024 is from solar. If this planned capacity comes online, solar additions will total 37 GW in 2024, a record in any one year and almost double last year’s 18.8 GW.

Battery storage made up the second-most capacity added so far this year, according to EIA. Battery additions made up 21% of new additions and were concentrated in four states: California, Texas, Arizona and Nevada.

10.8 GW of battery storage is planned for the latter half of 2024. If it all comes online, the 2024 total (15 GW) would be a record. Plans for storage capacity in Texas and California currently account for 81% of new battery storage capacity in the second half.

Wind power made up 12% (2.5 GW) of U.S. capacity additions. Canyon Wind (309 MW) and Goodnight (266 MW), both located in Texas, were the largest wind projects that came online in the first half of 2024.

Nuclear power also increased in the U.S. during the first half of 2024, with Vogtle Unit 4 in Georgia coming online in April.

Retirements slow

Retirements of U.S. electric generating capacity has slowed so far in 2024. Operators retired 5.1 GW of generating capacity in the first half of the year, compared to 9.2 GW retired during the same period in 2023.

Natural gas units represented more than half (53%) of the capacity retired in in the first half of 2024, followed by coal (41%).

According to EIA, about 2.4 GW of capacity is scheduled to retire during the second half, including 700 MW of coal and 1.1 GW of natural gas.

Sage has entered into a land use agreement with San Miguel Electric Cooperative Inc. (SMECI) for the 3 MW Geopressured Geothermal System (GGS) energy storage facility. The 3 MW EarthStore system will be in Christine, Texas near the SMECI lignite coal power plant. Sage will operate as a merchant, buying and selling electricity to the ERCOT grid.

Later this year, Sage will launch the EarthStore facility, which it says will utilize the earth’s “natural capacity for energy storage” to produce dispatchable electricity on demand through a power source that works independent of weather conditions.

“Once operational, our EarthStore facility in Christine will be the first geothermal energy storage system to store potential energy deep in the earth and supply electrons to a power grid,” said Cindy Taff, CEO of Sage Geosystems. “Geothermal energy storage is a viable solution for long-duration storage and an alternative for short-duration lithium-ion batteries. Electric utilities and co-ops like SMECI, will be able to use our technology to complement wind and solar, and stabilize the grid.”

The facility will use Sage’s proprietary technology to store energy, targeting 6-to-10-hour storage durations and delivering a round-trip efficiency (RTE) of 70-75%, Sage said. In addition, water losses are targeted to be less than 2%. At scale, this energy storage system will be paired with renewable energy to provide baseload and dispatchable power to the electric grid. When combined with solar power, Sage’s EarthStore facility enables 24/7 electricity generation at a blended Levelized Cost of Energy (LCOE) well under $0.10/kWh, it said.

“Long-duration energy storage is crucial for the ERCOT utility grid, especially with the increasing integration of intermittent wind and solar power generation,” said Craig Courter, CEO, San Miguel Electric Cooperative. “We are excited to be part of this innovative project that showcases the potential of geothermal energy storage.”

Sage will be applying for two drilling permits in Texas. The first permit is in Atascosa County for the EarthStore facility in Christine and the second permit is in Starr County, adjacent to the company’s existing test well.

Geothermal electricity generation taps high-energy-content steam at temperatures of 300-700 degrees Fahrenheit and requires drilling to depths that are as much as tens of thousands of feet below the surface.

The process works by drilling sets of both injection wells and production wells. Cold water is pumped down the injection well and then flows through the geothermal reservoir to the production well. The water returns to the surface at a high enough temperature for the energy to be captured at the surface and enter an electric generation cycle.

GO DEEPER: Fervo Energy co-founder and CEO Tim Latimer joined the Texas Power Podcast with Doug Lewin to discuss a hoped-for resurgence in the geothermal energy industry. Subscribe wherever you get your podcasts.

Compared to older, traditional geothermal energy sites, it’s much more challenging, and expensive, to find heat resources suitable for electricity generation today. That’s why companies like Fervo Energy and Sage are incorporating techniques from the oil and gas industry to give the geothermal industry new life.

Although Texas doesn’t have any geothermal projects of its own yet, several companies headquartered in Houston, including Fervo Energy and Sage, are hoping to change that. Some former oil and gas industry professionals are now championing geothermal as a new resource for reliability, especially given the crossover between equipment and techniques from the oil drilling industry, the Texas Tribune reports.

U.S. wind installations produced 45.9 gigawatt hours (GWh) of electricity in March 2024, eclipsing the 38.4 GWh generated by coal-fired power plants. The following month, coal-fired generation dropped to 37.2 GWh while wind generation blew away its previous high mark, churning out 47.7 GWh.

EIA included this lovely chart which demonstrates the steady growth of wind generation and the slow decline of our reliance on coal:

Installed wind power generating capacity has grown from 2.4 GW in 2000 to 150.1 GW in April 2024, according to the EIA. By contrast, many coal plants have retired over the past 25 years, and coal capacity has been roughly cut in half, from 315.1 GW in 2000 to 177.1 GW by April 2024. 22.3 GW of U.S. coal-fired electric generating capacity has been retired over the past two years, and operators plan to retire 2.8 GW more in 2024, data from EIA’s July Monthly Energy Review show.

Other sources of electricity generation have also increased as coal-fired generation has declined, notes the EIA. Since 2000, electricity from solar power has increased by 99.1 GWh, and generation from natural gas, which is often more price competitive than coal in electricity market dispatch, has gone up by 287.6 GWh.

And all good things, they say, never last

Wind power typically produces the most electricity in the springtime in the United States, so it’s not likely wind will permanently remain ahead of coal generation (at least not yet). During the first four months of 2024, coal-fired generation was 15% greater than wind generation in the United States.

You may recall something like this happening last year- when U.S. wind generation exceeded coal-fired generation for the first time in April 2023. It took 11 months later for that to happen again. But if you’re searching for silver linings, this spring marks the first time U.S. wind generation has exceeded coal-fired generation for two months in a row.

And there’s more capacity on the way. Operators expect 7.1 GW of wind capacity to come online in the United States in 2024, according to EIA’s July Monthly Energy Review. That’s a substantial amount, albeit a far cry from the 14 GW+ added in both 2020 and 2021, which were record years for growth in the industry.

And finally- a parting gift for those who either didn’t get the headline or understood the reference and now have that Prince slow jam stuck in their heads:

Through the agreement, which kicked off in July, FirstLight will deliver Burlington more than 54 GWh of hydropower and associated VT-1 renewable energy credits through 2025 from FirstLight’s Shepaug Generating Station in Connecticut.

Shepaug is Connecticut’s largest hydroelectric generation station and is also the second largest source of carbon-free electricity in the state, located on the Housatonic River in Newtown and Southbury. Built in 1955, it has a 42.6 MW capacity.

“Our new collaboration with FirstLight serves as another example of Burlington Electric Department’s and the City of Burlington’s commitment to continuing to source 100% of our power from a mix of different types of renewable generation, while maintaining reliability for our customers,” said Darren Springer, BED General Manager.

BED has purchased 100% of its power supply from renewable sources since 2014. As the city transitions away from fossil fuels in the thermal and ground transportation sectors largely through electrification, it expects electricity demand to grow.

To support this increased demand while ensuring its energy mix remains 100% renewable, BED is looking to strategic partnerships like this new PPA with FirstLight to secure additional clean power generation.

“As we electrify more of our heating and transportation needs, BED will continue to look for opportunities to source renewable power to meet demand,” he said.

“We are grateful for thoughtful partners like FirstLight, whose reliable, cost-competitive, clean electricity generation supports our climate goals in Burlington and helps to decarbonize the New England grid.”

FirstLight has a diversified portfolio that includes over 1.65 GW of operating renewable energy and energy storage technologies and a development pipeline with more than 4 GW of solar, battery, hydro, onshore wind and offshore wind projects. FirstLight specializes in hybrid solutions that pair hydroelectric, pumped hydro storage, utility-scale solar, large-scale battery and wind assets. The company’s mission is to accelerate the decarbonization of the electric grid by supporting the development, operation and integration of renewable energy and storage to meet the world’s growing clean energy needs and deliver an electric system that is clean, reliable, affordable and equitable.

“We are pleased to announce this important transaction with LS Power, which is the result of a highly competitive strategic sale process,” said Chris Huskilson, CEO of AQN. “This major milestone, coupled with our previously announced agreement to support the sale of our Atlantica shares, delivers on our plan to transform AQN into a pure play regulated utility, optimize our regulated business activities, strengthen our balance sheet, and enhance our quality of earnings. We are confident that our path towards a pure play regulated utility supports our objective to create long term value for our customers and shareholders.”

The sale is subject to the satisfaction of customary closing conditions, including the approval of the U.S. Federal Energy Regulatory Commission and approval under applicable competition laws. The Company expects the transaction to close in the fourth quarter of 2024 or the first quarter of 2025 and to receive estimated cash proceeds of approximately $1.6 billion (excluding the earn out) after repaying construction financing, and net of taxes, transaction fees, and other closing adjustments.

Algonquin Power & Utilities isn’t the only company to shed its utility-scale renewables business lately. Last year, Brookfield Renewable announced it would buy Duke Energy’s utility-scale renewable energy business for $2.8 billion.

Duke began shopping its renewables division in September 2022 as it sought to focus on the growth of its regulated businesses. The sale agreement included more than 3,400 MWac of utility-scale solar, wind, and battery storage across the U.S., net of joint venture partners ownership, in addition to operations, new project development, and current projects under construction.

Also last year, RWE AG finalized its $6.8 billion acquisition of all shares in Con Edison Clean Energy Businesses. The transaction made the newly dubbed RWE Clean Energy one of the five largest renewable energy companies in the U.S. and the country’s second-largest solar owner and operator.

The acquisition included a portfolio of 8 GW of renewable energy projects and a development platform of more than 24 GW. Around 60% of the portfolio is onshore wind and 40% solar. Con Edison said it continues to invest in clean energy transmission projects, building electrification, energy efficiency, electric vehicle infrastructure, battery storage, and other technologies. The utility said it also wants to invest in and operate renewable generation in New York.

Originally published in Renewable Energy World.

Georgia Power is celebrating Generation Appreciation Month, a time to recognize the more than 1,100 team members who “work tirelessly in power plants across state to keep reliable energy flowing to the grid on hot summer days, cold winter mornings and every hour in between.”

“In life, as well as with Georgia Power’s power generation facilities, there is no one-size-fits-all option,” said Rick Anderson, senior vice president and senior production officer for Georgia Power. “From the existing facilities that have powered Georgia for decades, to newer sources of generation such as renewable energy, cleaner natural gas and battery storage, Georgia Power’s diverse generation mix continues to evolve to meet the needs of a growing Georgia. To keep the energy flowing, we need a workforce that is just as advanced and diverse.”

Based on available opportunities, a career in power generation offers many possibilities for those who join the team, Georgia Power said. Career paths exist in the areas of operations, maintenance, electrical, instrumentation, engineering and more. Last year, the company hired over 80 team members across generation facilities and expects the hiring trend to continue in the coming years. Strong training programs exist in Operations, along with apprenticeships in Mechanical and Electrical, which develop experienced journeymen who work safely to keep energy flowing to the grid, 24/7.

Georgia Power also highlighted the “continuous learning” it offers, including the Rockmart training facility where electrical, mechanical, and instrumentation and control technicians hone their skills each year. In 2023, this facility conducted nearly 3,000 hours of both hands-on and classroom instruction. Subject matter experts from both Southern Company and external entities visited to assist in this training program.

The total $1.1 billion investment in Indiana’s Pike County would take place from 2024 to 2026.

Petersburg Generating Station Units 3 and 4 would be repowered from coal to natural gas by the end of 2026. AES Indiana anticipates being the first utility in Indiana out of coal, pending approval of the project from state regulators.

The Petersburg Energy Center would add 250 MW of solar and 180 MWh of battery storage to AES Indiana’s portfolio. The project is currently under construction and expected to be operational by the end of 2025.

AES Indiana’s 2022 Integrated Resource Plan (IRP) includes transitioning coal-powered units to natural gas and adding wind, solar and battery storage capacity over the next five years.

Recently, AES Indiana acquired 100 percent interest in Hoosier Wind, a 106 MW wind project in Benton County and announced the commercial operation of the Hardy Hills 195 MW solar project in Clinton County.

The U.S. Department of Energy (DOE) conducted supply chain “deep dives” on renewable energy technologies, including hydropower and large power transformers. Since the deep dives were published, the Water Power Technologies Office (WPTO) has focused on improving its understanding of the hydropower supply chain and developing strategies for addressing supply chain challenges. The report, Hydropower Supply Chain Gap Analysis, was prepared by NREL for DOE and WPTO.

Because the challenges outlined in the deep dives are most acute for large systems greater than 100 MW, NREL’s report focuses on large systems but expects that its recommendations will improve the supply chain for all hydro systems regardless of scale. Additionally, since the federal government owns almost 50% of the nameplate capacity for conventional hydropower systems with 40% (18 GW) of these units being at least 100 MW, the federal fleet is used to prime the development of the supply chain for the rest of the industry, NREL said.

State of the supply chain

The analysis focused on the upstream and midstream sectors of the hydropower supply chain, as they have “limited” domestic capacity, NREL said.

Upstream supply chain components include raw material extraction, concentration, and processing into engineered materials. The U.S. has strong iron mining and steel production capabilities, NREL said, but it has limited to no mining of the trace metals used in steel, and it imports more than 40% of its copper. Additionally, there are only two domestic facilities with forging capabilities for large hydropower shafts (50-75 tons) and a single domestic foundry that can cast large turbine runners greater than 10 tons.

In the midstream supply chain, the first stage is composed of the manufacture and assembly of hydropower components like hydrogenerators and turbines. Some U.S. companies manufacture components, but international competition is “intense,” NREL said, and acquiring components for 100-MW or larger systems is difficult to procure domestically — only one foundry is capable of producing castings greater than 10 tons, and no domestic manufacturers exist for hydrogenerators greater than 20 MW.

Gap analysis

Five “major” gaps in the domestic hydropower supply chain were identified in the report.

1. Unpredictable and variable demand signals

The development of a domestic hydropower supply chain is held back by an unpredictable and highly variable demand for materials and components, NREL said. Hydropower systems typically have long lives, so replacements and refurbishment schedules have cycles that last years or decades.

2. ‘Severely’ limited or nonexistent domestic suppliers for hydropower
materials and components

There are no domestic facilities for hydrogenerator manufacturing greater than 20 MW, and a single facility for less than 20 MW.

The following materials and components only have a single domestic facility or supplier:

• Windings greater than 100 MW for large hydrogenerators
• Large forgings (50-75 tons) for large hydropower shafts
• Foundry with casting capabilities greater than 10 tons for large turbine runners
• Grain oriented-electric steel (GOES) for U.S. transformer manufacturers

Additionally, there are two domestic suppliers of non-oriented electric steel (NOES) for U.S. hydrogenerator manufacturers

3. Federal contracting procedures and domestic content laws

The report identified several procurement regulators and/or general practices that NREL says inhibit the development of the domestic hydropower supply chain, including bonding requirements, specifying pre-contract design work, all-inclusive contracts, and focusing exclusively on the initial capital outlay rather than the total project life cycle cost.

4. Foreign competition, foreign subsidies, and ‘ineffective’ trade policies

NREL said discussions with companies in the hydropower industry highlighted “inequitable” competition from foreign companies and “ineffective” trade policies as other issues in the hydropower supply chain.

Several companies noted that other countries subsidize their steel industries, and China develops “pods” of manufacturing capability to shorten the supply chain, making it more cost-effective.

5. Shortage of skilled workers

Hydropower manufacturing and upstream support industries suffer from a “significant” lack of workers with appropriate expertise, the report said. These industries have been offshored over the last 40 years, leaving skilled workers to retire or move to other industries.

NREL’s recommendations

NREL said DOE and the WPTO should consider the following recommendations to address hydropower supply chain concerns:

Lead with the federal fleet to prime the development of an aggregated, consistent demand signal with the largest producers by examining federal procurement processes and developing best practices for the refurbishment of the domestic fleet. Improve federal procurement processes to include multi-entity or multi-project long-term contracts and ensure that small businesses can compete for federal contracts. Develop best practices for refurbishments to ensure a predictable, steady, demand.

Develop domestic supply chain and end-user datasets to increase awareness of current and expanding capabilities of the domestic supply chain and installed hydropower fleet. WPTO is funding the development of two databases at Oak Ridge National Laboratory: a comprehensive database of suppliers in the hydropower supply chain, and an expansion of the HydroSource tool to provide unit and component-level information on the existing domestic fleet.

Work with other low-carbon technologies to create a “significant,” steady, and predictable demand signal for common materials.

Continue workforce development, including continuing collegiate competitions like the Hydropower Collegiate Competition and Marine Energy Collegiate Competition; in addition to acting on recommendations from the Hydropower Workforce report.

Originally published in Hydro Review.

With coal plants retiring, the intermittent availability of renewable solar and wind energy, and data centers and artificial intelligence capabilities expanding, it’s clear that the U.S. is in need of reliable energy sources. Utilities face the complex challenge of firming capacity to continue to provide consistent services. 

Dispatchable, reliable power is crucial, but several obstacles complicate the issue, including the limited availability for procurement of gas turbines and gas engine-driven compressors; limitations of regional gas capacity; unpredictability of weather that can affect the availability of renewable energy sources, and the lengths of permitting processes. Understanding where greater energy capability is needed and what solutions might be available is the first step. There are a variety of options available to help firm capacity.

Compressor Stations

Compressor stations are facilities located along natural gas pipelines that compress the gas to maintain pressure and provide for continuous gas flow at the required delivery points. Increasing the number of compressor stations, or upgrading existing ones, can enhance the capacity and reliability of a natural gas network system. This is particularly useful in regions where the gas supply might be constrained.

While new compressor stations and pipelines face many regulatory hurdles, such stations offer a reliable solution to improve natural gas delivery. The increased capacity that comes with using compressor stations can help meet rising power demands without the need for entirely new pipelines.

Dual Fuel

Dual fuel systems allow power plants to switch between natural gas and an alternative fuel, typically diesel or oil. This flexibility can be invaluable during times of gas supply constraints or price spikes. A dual fuel system provides an immediate backup fuel source, allowing for continuous power generation.

Such systems enhance reliability and operational flexibility, reduce the risk of power outages and enable effective management of fuel costs. The systems may also require additional storage and handling facilities for the secondary fuel, which can drive up costs related to implementing the solution.

LNG Peak Shavers

LNG peak shavers are facilities that store liquefied natural gas (LNG) and can quickly vaporize and inject it into a natural gas pipeline during peak demand periods. These facilities produce LNG during periods of low natural gas demand, such as the summer months, allowing utilities to manage the cost of gas and power for customers. LNG peak shavers provide a buffer during periods of high demand, keeping the gas supply steady even when demand spikes unexpectedly.

The benefits that LNG can provide with a continuous gas supply during peak periods and enhanced system stability are hard to ignore. LNG can be stored and vaporized in a stand-alone facility, either connected to a pipeline or directly feeding an existing power generation station. If stored and vaporized in a stand-alone facility, the LNG is delivered via trucks rather than produced on-site.

Hydrogen

Hydrogen can be used as a fuel for power generation, either blended with natural gas or used in dedicated hydrogen turbines. Hydrogen is often a clean energy source that can significantly reduce greenhouse gas emissions. Hydrogen also can come from various sources, including renewable solutions, providing a versatile and sustainable option.

Hydrogen currently has high production costs and requires significant infrastructure development before operations can begin. However, the solution offers the hope for greater energy security through the diversification of fuel sources and the possibility of long-term energy sustainability.

Meeting the Demand

Firming generation in the face of changing power demands and shifting energy landscapes requires innovative solutions and strategic planning. Compressor stations, dual fuel systems, LNG peak shavers and hydrogen each offer unique benefits and challenges. By carefully considering these options, utilities can enhance stability and reliability while meeting the growing energy needs of the future.

Originally published by Burns & McDonnell.

About the Author: Sara O’Dell, PE, is an associate project engineer with nearly 20 years of engineer-procure-construct (EPC) project execution experience, spending the last 15 years working on LNG projects using both liquefaction and regasification processes for onshore and floating installations.