Vineyard Wind 1

Vineyard Wind 1, the first large-scale offshore wind project in the United States, is now providing approximately 68 MW to the New England grid. Once fully operational, Vineyard Wind 1 will deliver 806 MW.

In early January, Vineyard Wind delivered approximately 5 MW of power from one turbine to the grid. Following that milestone, the project has provided power from each of the first five turbines intermittently, as it ramped up its initial operations. Currently, the project has installed nine turbines and is in the process of installing the 10th, with preparations underway to transport the 11th turbine to the offshore project site. Additional power will be delivered to the grid sequentially, with each turbine starting production once it completes the commissioning process.

The power from the project interconnects to the New England grid in Barnstable, transmitted by underground cables that connect to a substation further inland on Cape Cod. Once completed, the project will consist of 62 wind turbines.

Empire Wind 1

With the permitting action by BOEM secured, 810 MW Empire Wind 1 is on track to begin construction in its federal lease area off the southern coast of Long Island later this year and could deliver first power to New Yorkers by 2026. In addition, construction to transform the South Brooklyn Marine Terminal into a hub for offshore wind could begin as early as this spring.

Empire Wind has recently received several federal approvals. Last week, it received its Clean Air Act permit from the Environmental Protection Agency. Earlier this week, it received approval from the NOAA National Marine Fisheries Service in accordance with the Marine Mammal Protection Act. Empire Wind 1 is currently bidding into New York’s fourth offshore wind solicitation.

In January, Equinor and BP decided to terminate the Empire Wind 2 project, citing inflation, interest rates, and supply chain disruptions. The Northeastern U.S. offshore project promised a potential generative capacity of 1,260 MW.

The project was already on the chopping block after the New York State Public Service Commission denied petitions filed by a group of developers and a state renewable energy trade association seeking billions of dollars in additional funding from consumers for four proposed offshore wind projects and 86 land-based renewable projects.

In October, developers who filed the petition, including subsidiaries of Orsted, Equinor, and BP, said that they were reviewing the Commission’s decision before reassessing their offshore projects, like Orsted’s 924 MW Sunrise Wind, Equinor/bp’s 816 MW Empire Wind 1, 1,260 MW Empire Wind 2 and 1,230 MW Beacon Wind.

Originally published by Renewable Energy World.

In 2023, New England had nearly 400 dispatchable generators and about 30,700 MW of generating capability, with 99.3% of electricity provided by natural gas, nuclear, hydropower, and imported electricity (mostly in the form of hydropower from Eastern Canada) and renewables. About 40,000 MW of new capacity is proposed to be built, the report said, and more than 7,000 MW of generation have retired since 2013 or may retire in the next few years, composed of mostly coal-fired, oil-fired and nuclear power plants. The region’s remaining two zero-carbon-emitting nuclear facilities, Millstone and Seabrook, supply a quarter of the electricity New England consumes in a year.

New England also had about 3,800 MW of of demand capacity resources (DCRs) and about 350,000 distributed solar power installations totaling 6,500 MW, with most installed behind the meter.

This number was calculated by adding total electricity generation and price-responsive demand reduction within New England to net imports from and exports to neighboring regions. The energy used to operate pumped storage power plants is then subtracted from that sum. Numbers are preliminary, pending the resettlement process.

Output from solar installations increased by 6% from 2022, rising to 3,851 GWh or 3% of the NEL. Wind power was relatively steady from year to year at 3% of NEL.

Oil-fired resources produced less electricity in 2023 than in 2022, accounting for 322 GWh, or 0.32% of the NEL, compared to the previous year’s 1,844 GWh. Production from coal-fired resources decreased from 320 GWh to 182 GWh, accounting for .16% of NEL for 2023.

All six New England states have renewable portfolio standards, which require electricity suppliers to provide customers with increasing percentages of renewable energy, ISO-NE said. Because large-scale renewable resources typically have higher up-front capital costs and different financing opportunities than more conventional resources, they have had difficulty competing in the wholesale markets. Therefore, the New England states are promoting, at varying levels and speed, the development of specific clean-energy resources to meet their public policy goals.

Several states have established public policies that direct electric power companies to enter into ratepayer-funded, long-term contracts for large-scale carbon-free energy that would cover most, if not all, of the resource’s costs.

About 97% of resources currently proposed for the region are grid-scale wind, solar and battery projects. As of January 2024, about 40,000 MW have been proposed in the ISO New England Interconnection Request Queue.

Energy storage represented 46% of the projects in the Interconnection Request Queue as of January 2024, and solar power accounted for 10%. Most solar power in New England is connected behind the meter directly at retail customer sites. Because such projects do not follow the ISO interconnection process, they aren’t reflected in the Interconnection Request Queue numbers.

The region had a total of about 350,000 distributed solar power installations as of December 2023 with a combined nameplate generating capability of approximately 6,500 MW. 

The utility is seeking wind resources that are within the MISO Local Resource Zone 1 with direct interconnections to the transmission system and the ability to enter commercial production in 2026 or 2027.

Minnesota Power will consider both build-own-transfer and power purchase agreement projects, with a preference for projects between 100 and 200 MW in both categories. An independent third-party evaluator will help Minnesota Power screen and review proposals.

The procurement of wind through this RFP would increase Minnesota Power’s wind portfolio by nearly 50%; it currently has about 870 MW of owned and contracted capacity. The company currently delivers more than 50% renewable energy to its 150,000 retail customers.

This RFP follows Minnesota Power’s 2021 Integrated Resource Plan, approved by the Minnesota Public Utilities Commission, which calls for the company to acquire up to 300 MW of solar energy (which is being evaluated in a separate RFP) and 400 MW of wind generation.

“The carbon-free future must be sustainable for the climate, customers, and communities for everyone to thrive, so we seek projects that will create local jobs, local economic benefits and train people in renewable technologies,” said Minnesota Power COO Josh Skelton. “New wind generation in the Upper Midwest can tap into an excellent wind resource and maximize use of regional transmission assets to deliver renewable energy to our customers and fits well with our portfolio of other energy supply resources to reliably meet customer demands around the clock.”

Proposals will be accepted through April 11, 2024.

The joint funding opportunity between the United States and Denmark aims to advance the global floating offshore wind industry by encouraging collaboration and increasing the impact of research and development in each country.

This proposed funding opportunity will focus on research to improve mooring technologies and methods, which are used to secure floating platforms to the sea floor.

WETO and Innovation Fund Denmark will each contribute approximately $2 million and performing teams must include both U.S. and Danish entities collaborating on each awarded project.

“About two-thirds of U.S. offshore wind energy potential exists over waters too deep for today’s fixed-bottom wind turbine foundations, and instead require floating platforms. This partnership between DOE and Innovation Fund Denmark will advance floating offshore wind R&D to further each nation’s respective climate goals. This effort supports the Floating Offshore Wind Shot, a target to reduce the cost of floating offshore wind in the U.S. 70% by 2035,” said DOE Under Secretary for Science & Innovation Geri Richmond.

“The climate challenge cannot be solved by one good idea or one company—or in one country. It requires many new initiatives and collaborations in different areas that point in the same direction,” said Innovation Fund Denmark chairperson Anders Eldrup.

DOE and Innovation Fund Denmark are seeking proposals addressing five topic areas:

• Compatibility strategies for mooring, cabling, and coexistence
• Mass-producible, high-reliability moorings
• Novel station-keeping systems and components
• Monitoring and inspection technologies for moorings
• Open Topic: Research and development that more broadly support mooring systems for industry-scale deployment of floating offshore wind energy.

This opportunity is expected to be released this spring.

The announcement builds on a previous collaboration between DOE, the Denmark Ministry of Higher Education and Science, the Denmark Ministry of Climate, Energy and Utilities, and Innovation Fund Denmark signed in 2021.

Originally published by Power Engineering International.

This “All-Source” RFP eliminates specific technology requirements, opening the application process for full competition of all non-emitting resources that are widely deployed and consistent with Oregon’s energy policy, PGE said.

The utility said this is its largest open application process to date and is the first in the company’s recent history to provide a flexible timeline for the start of operations.

This RFP, which accepts proposals for resources with a start date between 2025 and the end of 2027, is meant to be consistent with the objectives described in PGE’s 2023 Integrated Resource Plan (IRP), which was acknowledged by the Oregon Public Utility Commission (OPUC) on January 25, 2024. PGE will accept and evaluate bids throughout the first quarter of 2024 and present a shortlist of top-performing projects for OPUC acknowledgment later in the year.

Last year, PGE released a new Clean Energy Plan in addition to its IRP, which both focus on the addition of more community-based renewable energy (CBRE). In its IRP, PGE forecasts a significant capacity need of 1136 MW in summer, 1004 MW in winter and a significant energy need of 905 MWa (~2,500 MW nameplate) by 2030. To help meet that need, it plans to add up to 155 MW of CBRE resources by 2030 with plans to pursue at least 66 MW by 2026.

At the time, the utility said it also planned to conduct one or more RFPs for an additional 181 MWa (~520 MW nameplate) of non-emitting generation and sufficient capacity to remain resource-adequate each year.

The Clean Energy Plan includes:

• New utility scale renewable projects like wind and solar installations, both in-state and out-of-state.
• Non-emitting capacity such as batteries.
• CBRE resources, small distributed energy resources that include battery storage and solar, which can make customers more resilient and save them money.
• Customer-sited solutions including energy efficiency and demand response programs.
• Upgrades to local transmission lines and new regional transmission solutions to accommodate growth and bring a greater geographic diversity of resources to PGE’s portfolio.

PGE said 2030 emissions targets can be met with technologies and resources that are currently known and commercially available. The utility said to meet 2040 targets, new technologies not yet commercially available that can replicate thermal generation dispatchable capacity, such as advanced nuclear, hydrogen or carbon capture and storage, will be needed to support decarbonization and resource adequacy.

PGE also said its natural gas-fired plants would continue to play a role in meeting resource adequacy needs during the clean energy transition. The utility said it would “continue to invest in the efficiency, safety and emissions controls of those facilities as appropriate.”

The transition to renewable energy—solar, wind, and battery storage—is creating a cleaner generation portfolio but also adding much complexity to generation and dispatching flexibility. This creates increased electric system reliability risk, especially during winter when renewable resources are less available.

Unlike conventional power units, the output of renewable generators may be strongly influenced over a wide geographical area from natural phenomena. Common weather events, such as long winter nights, a string of calm, cloudy days, or even a snowstorm, which may only marginally affect conventional units, if at all, can cause large decreases in intermittent generation output.

This article examines some of the most important aspects of these issues, and it outlines some of the economic concerns as our society moves further from fossil fuels as a means of generating electricity.

Winter wind droughts could become catastrophic

A winter “Wind Drought” over a wide geographic area, such as the one that impacted the 15-state Midcontinent Independent System Operator (MISO) region on January 28-30, 2020, could lead to future capacity shortages. During the 2020 event, wind output was less than one percent of nameplate for 39 consecutive hours (Figure 1).

 At that time, the system had 20.2 GW of nameplate wind capacity but lost nearly all of it during the wind drought. This occurred during what is typically the coldest time of the year. Imagine a night during a future wind drought where there is no solar, little wind and depleted batteries. 

Another example comes from Winter Storm Uri, as shown below.

Reduced renewable capacity, combined with inadequate freeze protection in some locations, caused rolling blackouts and even long-term power outages during a period of extreme cold weather.

Winter brings decreased solar availability

As winter advances each year, the days grow shorter and nights longer with increasing latitude (Figure 3).

The combination of shorter days with widespread cloud cover and fog, as is often experienced during winter, greatly decreases solar output. Furthermore, snow cover, especially in the northern parts of the United States, can impact wide areas, reducing solar output for days or even weeks in some locations.

Combined wind and solar intermittency can bring substantial capacity risks. Below are some general statistics from the mid-latitudes of the United States:

• Wind operates at roughly 40+% capacity factor.
• Solar operates at roughly 20% capacity factor.
• Wind is below 20% capacity ~20% of the time.
• Solar is below 20% capacity ~73% of the time.
• Combined wind and solar is below 20% capacity ~11% of the time.

Any calm night or calm cloudy day can create a potential capacity shortfall. This may become increasingly critical as we move away from conventional generation resources.

Increased winter load during extremely cold weather

During cold waves, the load curve both increases in magnitude and flattens due to increased heating demand. This is evidenced by the actual MISO load curve during Winter Storm Elliott shown in Figure 4.

Such uniform high load factors leave little room for charging Battery Energy Storage Systems (BESS) or electric vehicle batteries.  The changeover from natural gas to electrical home heating systems, as is advocated by some, will further increase and flatten the winter peak load curve per the energy needed during nighttime hours.

Electrification impacts

Electrification, in the context of this article, is defined as electrifying home, commercial, and industrial building heating systems and providing the energy for automobiles and trucks. Continued conversion to electricity will result in very large increases in both annual energy use and peak demand, especially winter peak demand. 

Three main choices exist for residential and small commercial electric heating systems:

• Resistance heat: Resistance heat is 100% efficient; each kWH provides 3413 BTU of heat.
• Air source heat pump: Air source heat pumps are usually twice as efficient as resistance heat. However, efficiency decreases with decreasing ambient temperature. Backup resistance heating is usually necessary at temperatures below ~20^oF.
• Ground source (geothermal) heat pump: Ground source heat pumps are approximately three times as efficient as resistance heaters. However, they are also the most expensive configuration per the need for subterranean ground loops. Supplemental resistance heat is usually necessary when ambient temperatures reach 0^oF.

During the extreme cold of winter peak days, most electric heating systems will operate in resistance heat mode. This in turn will significantly increase the demand, creating a “needle peak” electric demand. The load curve shown in Figure 4 will become even flatter and grow in magnitude as electric heating systems run nearly continuously. For example, consider the changeover from a common 100,000 BTU, 95% efficient gas furnace to an air source heat pump with 25 kW of backup resistance electric heat. The gas system would have provided 95,000 net BTU of heat per hour to the house. On a winter peak day, the electric-resistance backup would only provide (25 kWH) (3413 BTU/kWH) = 85,325 BTU/H, much less than the 95,000 net BTU of the gas system. Thus, the resistance heat would likely run continuously, increasing the peak-day load and load factor.

Another serious issue with electrical heating is the high cost of electricity relative to the price of natural gas. Consider a natural gas cost of $1.00/therm and electricity cost of 10 cents per kWH, both very reasonable values. The gross cost of gas heat would be $10.00/MMBTU, while the cost of resistance electric heat would be approximately 3 times higher, $29.70/MMBTU. Not to be discounted are the high capital costs of service upgrades, new HVAC systems, new appliances, and wiring upgrades. The utilities’ distribution and transmission systems would also likely need to be upgraded which may result in higher electric rates. These costs may make electrification prohibitively expensive and uneconomical.

Beyond residential and commercial heating issues, the increase in the number of electric vehicles will require added electricity for charging. During cold weather, batteries are less efficient and require additional charging. This issue is greatly exacerbated by electric heaters (mostly resistance type) that rapidly consume EV battery capacity and reduce driving distance between recharging.

Battery energy storage has limitations

A major factor that still limits renewable energy development is electrical storage. For example, a typical lithium-ion battery energy storage system (BESS) has approximately 85% cumulative efficiency. Thus, a standard 100 MW, 4-hour BESS needs 400 MWh to charge but only returns 340 MWh to the grid upon discharging. Furthermore, a BESS requires auxiliary power, even in standby mode, to maintain temperature. Therefore, batteries are a net load on the system.

For comparison of BESS capacity to coal storage, consider a typical 500 MW coal unit burning Illinois coal with 30 days of coal storage. Suppose the unit operates at 70% capacity factor. It would produce (500 MW) (0.70) (720 H) = 252,000 MWh of energy per month. If the unit had a net heat rate of 10,000 BTU/kWh and burned coal with a heating value of 10,000 BTU/lb, the required coal storage becomes 126,000 tons. (252,000 MWh * 10,000 BTU/Kwh * 1000 kWh/MWh * 1 lb/10,000 BTU * 1 ton/2000 lb = 126,000 tons.)  At $50/ton, the inventory value of this coal reserve would be $6.3 million.

Now let us calculate the number of batteries needed to store the same amount of energy. Assume 100 MW, 4-hour lithium-ion batteries with 85% efficiency and two charging/discharging cycles per day. Each battery would produce 680 MWh/day and 20,400 MWh per month.  Thus, it would take 13 batteries (rounded up from 12.353) to store the same energy as available from the coal storage.

It is also important to point out that the battery system does not, in fact, produce the electricity. The production must come from another source. The 252,000 MWh supplied by the batteries would require 296,471 MWh for charging.  The energy losses calculate to 44,471 MWh per month. Assuming a capital cost of $1000/kW for each BESS, the 13-100 MW batteries would cost $1.3 billion. This is 206 times the cost of coal energy! 

So, while retiring fossil fuel plants is a primary goal in the efforts to slow down climate change, the economics are very problematic without significant improvement in energy storage technologies. Also critical, as the discussion below further illustrates, is grid reliability.

Future renewable risks

The combination of lower solar output due to shorter and cloudier days and snow-covered panels in certain locations, limited storage capacity and duration, and the possibility of extended wind droughts over large areas can put the electrical system at great risk during the winter. Conversely, renewable sources tend to create the most energy during low load periods. This leads to excess electricity that must be stored, transmitted, or curtailed.

Possible solutions

1. Build a more robust transmission system including interregional high-voltage direct current (HVDC) ties joining the Eastern Interconnection with the Western interconnection and Texas Interconnection.

–Opens new and diverse markets for sales and purchases.

-Geographic diversity lessens the impacts of winter storms.

2. Dedicate some renewable energy for electrolysis of water into green hydrogen and oxygen.

–Don’t connect these units to the electric grid.

–Solves interconnection queue backlogs.

–Solves congestion problems.

3. What to do with the hydrogen?

–Store it for later or even seasonal use.

–Use it at the point of production (Advanced hydrogen-fueled combined cycle plants, Reciprocating internal combustion engines, Fuel cell power plants, Fusion reactors, Fuel cell EVs)

-Transport it via pipelines.

Conclusions

The transition to renewables still requires a fleet of conventional, dispatchable resources for grid reliability. Keeping some coal plants around with their valuable but inexpensive coal storage reserves may not be a bad idea. Carbon capture and sequestration (CCS) may evolve into a viable method to continue fossil plant operation, but many questions exist regarding CCS technology and long-term influences of carbon sequestration.

References

MISO is the Midcontinent Independent System Operator www.misoenergy.org

Figure 3 comes from daylight hours map – Search Images (bing.com)

About the Author: Karl Kohlrus, P.E. graduated from the University of Illinois at Urbana-Champaign with B.S. degrees in Engineering Physics and Electrical Engineering and a master’s in business administration. Karl worked for 31 years in the Planning Department at City Water, Light and Power in Springfield, Illinois performing generation and transmission planning studies. He has since worked for over 12 years as Planning Engineer at Prairie Power, Inc.

Contact information: 

Email kkohlrus@comcast.net

Phone 217-891-4870

By early 2025, the IEA expects renewables to make up more than a third of total generation, overtaking coal, and nuclear power is on track to reach an all-time high. “Low-emissions” generation, including nuclear, is expected to account for almost half of global electricity generation by 2026, compared to 40% in 2023.

The report, Electricity 2024, is the latest edition of the IEA’s annual analysis of electricity market developments and policies, providing forecasts for demand, supply, and carbon dioxide (CO2) emissions from the sector through 2026.

Nuclear power is expected to reach a new high as France’s output grows, Japan brings plants back online, and new reactors begin commercial operations in areas like China, India, Korea, and Europe. Natural gas-fired generation is also expected to increase slightly over the outlook period. The European Union saw a sharp decline in gas-fired generation in 2023, while the U.S. saw “massive gains” as natural gas increasingly replaces coal, the report said. Global gas-fired output grew less than 1% in 2023, and the IEA forecasts an average annual growth rate of around 1%.

The IEA found that although global electricity demand growth eased to 2.2% in 2023, it is expected to jump to an average of 3.4% from 2024 to 2026. About 85% of that increase is expected to come from “outside advanced economies” like China, India, and countries in Southeast Asia.

In the U.S., electricity demand fell by 1.6% in 2023 after increasing 2.6% in 2022 but is expected to grow between 2024-2026. The IEA says one major reason for the decline was milder weather in 2023 compared to 2022, in addition to a slowdown in the manufacturing sector. The report projects an increase of 2.5% in U.S. demand in 2024, followed by an average growth of 1% in 2025 to 2026, primarily due to electrification and data centers.

“The power sector currently produces more CO2 emissions than any other in the world economy, so it’s encouraging that the rapid growth of renewables and a steady expansion of nuclear power are together on course to match all the increase in global electricity demand over the next three years,” said IEA Executive Director Fatih Birol. “This is largely thanks to the huge momentum behind renewables, with ever cheaper solar leading the way, and support from the important comeback of nuclear power, whose generation is set to reach a historic high by 2025. While more progress is needed, and fast, these are very promising trends.”

Global emissions from electricity generation are expected to decrease by 2.4% this year, followed by smaller declines in 2025 and 2026, the report said. Growth in coal-fired generation, such as in China and India amid a reduction in hydropower output, was responsible for the global energy sector’s CO2 emissions. Global fossil fuel generation is expected to decline from 61% in 2023 to 54% in 2026.

Electricity consumption from data centers, artificial intelligence, and cryptocurrency could double by 2026, the IEA said, and data centers are “significant” drivers of growth in electricity demand in many regions. After globally consuming an estimated 460 terawatt-hours (TWh) in 2022, data centers’ total electricity consumption could reach more than 1,000 TWh in 2026.

Originally published in Renewable Energy World.

As a result of new solar projects coming online this year, the EIA forecasts that U.S. solar power generation will grow 75% from 163 billion kWh in 2023 to 286 billion kWh in 2025. The administration expects that wind power generation will grow 11% from 430 billion kWh in 2023 to 476 billion kWh in 2025.

In 2023, the U.S. electric power sector produced 4,017 billion kWh of electric power. Renewable sources—wind, solar, hydro, biomass, and geothermal—accounted for 22% of generation, or 874 billion kWh, last year, the EIA said. Annual renewable power generation surpassed nuclear generation for the first time in 2021 and coal generation for the first time in 2022.

In contrast to the growing generation from renewables, the EIA forecasts that coal power generation will decline 18% from 665 billion kWh in 2023 to 548 billion kWh in 2025. Additionally, it forecasts natural gas will continue to be the largest source of U.S. electricity generation, with about 1,700 billion kWh of annual generation in 2024 and 2025, similar to last year. It expects nuclear power generation will stay relatively flat, rising from 776 billion kWh in 2023 to 797 billion kWh in 2025.

The EIA says new installations of generating capacity support the increase in its renewable generation forecast. Wind and solar developers often bring their projects online at the end of the calendar year, and the new capacity tends to affect generation growth trends for the following year.

Solar is the fastest-growing renewable source because of the larger capacity additions and favorable tax credits policies, EIA said. Planned solar projects increase solar capacity operated by the electric power sector 38% from 95 GW at the end of 2023 to 131 GW by the end of 2024. It expects wind capacity to stay relatively flat at 156 GW by the end of 2024, compared with 149 GW in December 2023.

Late last year, the EIA estimated the U.S. energy sector emitted about 4,790 million metric tons of carbon dioxide (CO2) in 2023, a 3% decrease from 2022, with much of the decline resulting from lower electricity generation from coal-fired power plants due to higher generation from renewable sources such as solar power, the EIA said.

The EIA expected this trend to continue into 2024, with CO₂ emissions declining 1% relative to 2023.

Additionally, the EIA forecasts solar power as the fastest-growing generation source and the largest source of new generation in 2023, as noted in a review by the SUN DAY Campaign, a non-profit research and educational organization.

Solar grew by 14.3%, compared to the same period in 2022 – more than any other energy source. This was driven in large part by growth in “estimated” small-scale (e.g., rooftop) solar PV, whose output increased by 19.8% and accounted for nearly a third (30.8%) of total solar production, SUN DAY Campaign said. For the nine-month period, solar was 5.8% of total U.S. electrical generation. A year earlier, solar’s share was 5.0%

The forecast reduction in CO₂ emissions is largely due to lower power generation from coal-fired power plants, the EIA said, which it expects to contribute to an 18% decline in coal-related CO₂ emissions in 2023 and a 5% decline in 2024. The electric power sector has been retiring significant coal-fired generating capacity in response to economic competition from natural gas and new renewable generating capacity.

Originally published in Renewable Energy World.

AlphaGen will oversee the strategic, commercial, and operational activities for ArcLight’s funds’ power infrastructure assets and portfolio. It’s one of the largest in the country and provides critical supply to key demand centers, including the tri-state area of New York, New Jersey, and Connecticut.

“The creation of AlphaGen builds on ArcLight’s leading position as a proven and experienced power infrastructure investor,” said Dan Revers, managing partner of ArcLight. “We believe power infrastructure will play an increasingly critical and necessary long-term role as demand increases on the back of electrification, data center growth, and AI amongst other things. To help support this growth and create value, we have brought together an industry-leading team with a proven track record of strategic, operational, and commercial experience overseeing and operating power generation assets.”

Curt Morgan, a longtime industry executive, has been named Chief Executive Officer and Chairman of AlphaGen, effective May 1, 2024. Morgan was previously CEO of Vistra, an integrated retail electricity and power generation company. Morgan is currently a Senior Advisor to ArcLight, and Mark Sudbey will serve as interim CEO until Morgan joins.

“I am excited to partner with ArcLight, one of the leading domestic infrastructure investors. We believe AlphaGen’s infrastructure is well positioned to deliver safe, reliable, and critical power to meet current and increasing demand,” Morgan said. “I look forward to working with Mark, Mary Anne, and the rest of the leadership team to help drive value, mitigate risk, and capitalize on new investment opportunities which a portfolio such as this is likely to create.”

ArcLight recently acquired Duke Energy’s commercial distributed generation portfolio, which includes REC Solar’s operating assets, development pipeline, and O&M portfolio, as well as distributed fuel cell projects managed by Bloom Energy.

ArcLight said its acquisition of the distributed generation business further expands the firm’s focus on developing strong standalone renewable platforms across the infrastructure sector. Employees of the distributed generation business transitioned to ArcLight to maintain business continuity for its operations and customers.

Originally published in Renewable Energy World.

The order is the largest single onshore wind turbine order ever received by GE, both in terms of number of turbines and gigawatts of power generation.

The over 3.5 GW SunZia Wind project is expected to be the largest wind project in the West. Construction began in late-2023 after more than 17 years of navigating permits and approvals. The project also includes a 550-mile ± 525 kV high-voltage direct current (HVDC) transmission line between central New Mexico and south-central Arizona with the capacity to transport 3,000 MW across Western states.

GE’s 3.6 MW turbine with a 154-meter rotor is what the company refers to as the 3.6-154. GE said its 3.6-154 turbine delivers the highest efficiency in the market and is built on the back of the 2.8-127.

The company said the product is expected to bring recent innovations in turbine and blade design, including the digital blade certificate, an AI-trained blade manufacturing process designed to produce industry leading quality.

GE Vernova and Pattern Energy’s collaboration on SunZia spans the last 18 months and has included collaborative development and supply chain work to optimize site layouts and performance. GE also provided Pattern Energy with consulting and financial services in support of this deal.

The project will be supplied through GE Vernova’s nacelle facility in Pensacola, Florida, as well as tower manufacturing facilities in Belen, New Mexico, Pueblo, Colorado, and Amarillo, Texas.