Numerous East Coast states are counting on offshore wind projects to power tens of millions of homes and to help them transition to cleaner energy.

But putting wind turbines at sea requires the cooperation of a powerful landlord: the federal government. Soon, that government will be led by President-elect Donald Trump, who has frequently disparaged offshore wind and said he will “make sure that ends on Day 1.”

In the eight states that have passed legal mandates to reach certain amounts of offshore wind power, Trump’s second term threatens those timelines.

“This is absolutely going to create problems for how we’re going to meet our emissions goals and the energy needs for the state,” said Massachusetts state Sen. Jamie Eldridge, a Democrat who serves as vice chair on the legislative Joint Committee on Environment and Natural Resources.

For many East Coast states that lack a large land base for extensive onshore development, offshore wind in federal ocean waters is central to their plans for a power supply that doesn’t use fossil fuels. Lawmakers in Connecticut, Maine, Maryland, Massachusetts, New York, North Carolina, Rhode Island and Virginia have established mandates requiring their states to produce certain amounts of offshore wind power in the coming years. Other states have passed laws to allow for offshore wind to be added to their grids or set nonbinding planning targets to prepare for the industry’s development.

State leaders say they will continue to pursue offshore wind but realize there may be delays during the next four years.

In the meantime, some say they will continue to build out the needed electrical grid and ports to get ready for turbines, in hopes of speeding up offshore wind once Trump’s term ends. Others say they may need to consider building more onshore energy projects, including wind and solar, in the next few years to meet near-term climate goals.

“That’s something states will have to take into account,” said Dylan McDowell, executive director with the National Caucus of Environmental Legislators, a collaborative nonpartisan forum for state lawmakers. “Is [offshore wind] still feasible, or do there need to be conversations about solar, [onshore] wind, geothermal, other energy sources that could be put into the mix to help meet those goals? There’s more questions than there are answers right now.”

While a handful of offshore wind projects have already started construction or been completed, many more are in various stages of permitting or awaiting lease auctions held by the federal Bureau of Ocean Energy Management. Industry experts say the Trump administration could deny permits, cancel pending leases and halt further auctions. It could also threaten the industry’s financing by denying clean energy tax credits.

In an extreme scenario, the bureau could even side with opponents who have brought legal challenges against projects that already have been approved and retract permits issued under the Biden administration. Trump’s ability to unwind the moves made under President Joe Biden is “underappreciated,” said Timothy Fox, a vice president at ClearView Energy Partners LLC, an independent research firm.

Trump has repeated claims that offshore wind turbines are a major cause of whale mortality — an assertion that scientists say is false. Many of the groups raising concerns about whales to oppose offshore wind are funded by oil and gas donors.

Trump’s transition team did not respond to an interview request before publication.

Offshore wind also has drawn local opposition from coastal residents who fear it will worsen their views and from fishermen who worry projects could block access to key fishing areas. Meanwhile, some Republicans have pointed to the wind industry’s recent financial struggles to argue that it will increase ratepayers’ bills.

“[T]he business model for these projects has fallen well short of projections to the degree that those wind energy developers are either halting construction or asking the government for additional subsidies to make up for projected cost increases,” four Maryland Republican senators wrote to Democratic Gov. Wes Moore in April, unsuccessfully urging him to veto a financing package to boost offshore wind in that state.

Counting on offshore wind

States’ offshore wind goals were already facing difficulties. Numerous projects were canceled or delayed last year as inflation and supply chain issues raised costs dramatically. Now, political headwinds could cause greater delays.

“Offshore wind might not be a viable option over the next four years,” said Fox, the energy analyst. “Unlike a lot of other resources, offshore wind is reliant on a federal review process because these projects are being deployed in federal waters.”

Offshore wind turbines currently provide only a negligible amount of power to the United States. But a handful of projects currently under construction will soon raise that number to 4 gigawatts (1 gigawatt can power about 750,000 homes). And much more is on the way.

Developers of other projects are working to finalize financing or permits, and wind companies are awaiting federal lease auctions that will open up new areas for development. In total, the project pipeline for offshore wind exceeds 80 gigawatts, according to the National Renewable Energy Laboratory — enough to consistently power more than 60 million homes. The incoming administration could thwart most of that production by denying development permits or leases in federal waters.

East Coast states don’t have a viable way to meet their clean energy goals without that offshore production, said Maryland state Del. Lorig Charkoudian, a Democrat who authored a law last year that increased the state’s offshore wind targets.

“We’ll continue to support the ongoing development of offshore wind until we have to make other adjustments,” she said.

The Maryland law mandates that the state produce 8.5 gigawatts of offshore wind energy by 2031. Developers of a trio of projects off the state’s coast, totaling 1.7 gigawatts, are working to secure permits and financing, according to the National Renewable Energy Laboratory. And the state is counting on future lease auctions by federal regulators to prompt more development.

Charkoudian acknowledged that Trump could threaten those efforts, but she said the state remains committed to its offshore wind plans. She noted that Maryland is working to improve its electrical grid so that offshore wind projects can “land” their power, an effort that will continue.

“Even if other things do get slowed down, this will make things move faster whenever it can get moving again,” she said.

Nick Guariglia, outreach manager with the New York Offshore Wind Alliance, a network of industry and environmental groups, said that projects take many years to develop, a timeframe exceeding one presidential administration. He also noted that the maturing industry aligns with Trump’s goals of restoring manufacturing jobs and American energy independence. Members of Congress in both parties are seeing economic growth in their districts because of offshore wind, he said.

“This industry has a lot of things to prove about why it’s here to stay,” he said. “Actions are much more important than rhetoric.”

Regardless of what happens at the federal level, offshore wind backers will urge New York lawmakers to continue investing in infrastructure and workforce development to support the buildout of more turbines, he said.

Stateline is part of States Newsroom, a nonprofit news network supported by grants and a coalition of donors as a 501c(3) public charity. Stateline maintains editorial independence. Contact Editor Scott S. Greenberger for questions: info@stateline.org.

The blade tip, which is being developed in ORNL’s carbon fiber technology center, incorporates two layers each of standard glass fiber and a low-cost lab developed carbon fiber, with such customized conductive carbon fiber key to dispersing electrical energy across the blade surface.

The researchers also declare using industry-standard equipment and methods to show that the technology can be easily integrated with established manufacturing processes.

“We don’t have enough data to know the true scope of the challenge [of lightning strike damage], but we know it’s a concern to industry and utilities,” said ORNL researcher Vipin Kumar.

“We know wind energy is a reliable source of electricity that supports energy security, but I believe anything we can do to make it more resilient and reliable is important.”

Lightning strikes to wind turbine blades are known to be frequent but are rarely catastrophic.

Nevertheless, they are believed to be able weaken blades with internal damage that can translate to increased repair costs over time, and they are the second leading cause of blade-related downtime.

In the project an entire 2m turbine blade tip was built using the novel materials. This was then tested against the forces of simulated lightning in a specialized lab at Mississippi State University, where the blade tip emerged pristine after tests that isolated the effects of high voltage.

Separate tests in the same lab found that isolated high current remained destructive.

The cost of carbon fiber has generally limited its use to the wind blade’s load bearing structure, but ORNL’s efforts to lower the cost of carbon fiber may make it economical to replace glass fibers in the blade tip, where the lightning strikes most often.

With the demonstration highlighting the possibilities of a new approach to protecting blades using conductive materials or coatings, further innovations are being investigated.

With resin making up the largest portion of the blade tip, these include the use of a more conductive resin.

Another notable benefit of the hybrid carbon fiber composite blade tip is its weight, about 41% lighter than a pure glass fiber blade tip, opening the way for larger blades of the same weight, with the potential to generate more electricity.

The approach also is considered of potential for preventing lightning damage to the composites used in airplanes.

Originally published by Power Engineering International.

The three facilities are the 200-MW Huck Finn Renewable Energy Center, the 150-MW Boomtown Renewable Energy Center and the 150-MW Cass County Renewable Energy Center.

Both the Cass County and Boomtown facilities will serve Ameren Missouri’s Renewable Solutions program. Organizations from across Missouri signed up to take part in the program, increasing their use of renewable energy and supporting its development in the region. As part of the program, participating organizations will also receive renewable energy credits.

Ameren Missouri is also working toward the construction of additional new sources of energy. In 2027, an 800-MW simple-cycle natural gas energy center is expected to be ready to serve as a backup source of energy. The Castle Bluff Energy Center represents an investment of approximately $900 million, and its proposed site previously hosted the coal-fired Meramec Energy Center, which Ameren closed in 2022. The utility owns the property and already has existing infrastructure and transmission line access, reducing the construction costs of the project, Ameren said. Pending regulatory approval, construction would begin in 2026.

Last October, Ameren released its 2023 Integrated Resource Plan, which included investments in natural gas, renewables and battery storage. One of the highlights of the IRP included building an 800 MW simple-cycle plant. Others included:

• Moving back the previously announced addition of a combined-cycle energy center to 2033. This 1,200 MW facility is now scheduled to go in service following the retirement of the Sioux Energy Center in 2032.
• Accelerating Ameren Missouri’s planned renewable energy additions by four years. The company plans to add 4,700 MW of new renewable energy by 2036. This represents a total potential investment of approximately $9.5 billion. The company maintains its goal of 2,800 MW by 2030.
• Adding 800 MW of battery storage, including 400 MW by 2030 – five years earlier than previously planned – with an additional 400 MW of battery storage by 2035. This represents a total potential investment of $1.3 billion through 2035.
• Planning 1,200 MW of clean, on-demand generation to be ready to serve customers in 2040 and an additional 1,200 MW by 2043.

The projects include wind, solar and renewable natural gas facilities (RNG) as well as battery storage capacity.

Solar and wind projects announced this year are a mix of company-built and owned projects and power purchase agreements (PPAs).

Consumers Energy also worked with farmers to announce construction of multiple RNG facilities across the state following expansion of the utility’s MI Clean Air program. In many cases, RNG is considered carbon negative, as it captures and prevents more emissions than it emits.

Consumers Energy’s clean energy goals include bringing 8,000 MW of solar online by 2040 and achieving net-zero carbon emissions from its electric generation and distribution systems.

The Michigan utility’s Clean Energy Plan also calls for eliminating coal as an energy source in 2025 and meeting 90 percent of customers’ energy needs through clean sources.

Today the LPO announced a conditional commitment for a low-interest loan guarantee of up to $15 billion for PG&E’s Project Polaris, which was submitted to the feds for consideration in June 2023. If finalized, the loan guarantee will support a portfolio of projects to expand hydropower generation and battery storage, upgrade transmission capacity through reconductoring and grid-enhancing technologies, and enable virtual power plants throughout PG&E’s service area. The utility, which serves about 16 million customers in Northern and Central California, says the loan will help it meet forecasted load growth, increase electric reliability, and reduce costs for its rate base.

Today’s announcement is the second Energy Infrastructure Reinvestment (EIR) project under LPO’s flexible loan facility and disbursement approach tailored for regulated, investment-grade utilities. The first was for the restoration and repowering of the Holtec Palisades nuclear plant, slated to become the first shut-down nuke plant to be recommissioned in the United States.

Electric utility borrowers for EIR projects must demonstrate that the financial benefits received from the DOE loan guarantee will be passed on to the customers of that utility or the communities it serves. LPO borrowers must develop and implement a comprehensive Community Benefits Plan (CBP), which ensures borrowers meaningfully engage with community and labor stakeholders to create good-paying, high-quality jobs and improve the well-being of the local community and workers. In its CBP, PG&E plans to expand its outreach programs to boost engagement and deliver community benefits in partnership with key stakeholders, including local governments, Native American Tribes, community-based organizations, and low-and-middle-income customers. PG&E has committed to locating many projects in disadvantaged communities, as identified by the Climate and Economic Justice Screening Tool.

LPO’s holiday spending spree

It’s no secret that the LPO is trying to get as much money as possible out the door before the Trump Administration takes office on January 20. In September, Trump pledged to rescind any unspent funds under the Inflation Reduction Act (IRA), the bipartisan infrastructure law that has pumped billions of dollars into the domestic supply chain and clean energy projects from coast to coast.

“To further defeat inflation, my plan will terminate the Green New Deal, which I call the Green New Scam,” Trump promised.

While it’s understandably easier for the President-elect to reign in unspent funding, he will have a tougher time navigating conditional loan guarantees and virtually no chance of recalling funds that have been distributed. According to the Wall Street Journal, the LPO is expected to extend the loan to PG&E via multiple cash installments spread out over several years, and the funding cannot be withdrawn by subsequent administrations. The LPO has closed on more than a dozen loans so far, totaling more than $13 billion.

The LPO has been especially this month, announcing a flurry of new loan activity. Yesterday, it announced $9.63 billion for BlueOval SK to finance the construction of three electric vehicle (EV) battery plants in Tennessee and Kentucky. Last week, DOE closed on a $1.25 billion guarantee with EVgo to expand public fast-charging infrastructure nationwide. The week before that was highlighted by a $303.5 million loan guarantee for Eos Energy Enterprises to support two Pennsylvania-based manufacturing facilities developing long-duration batteries. DOE also inked a conditional commitment of up to $7.54 billion with StarPlus Energy, a joint venture between automaker Stellantis and South Korean battery maker Samsung SDI, that will finance two lithium-ion battery cell and module factories in Indiana. According to an analysis by TechCrunch, automakers and battery manufacturers have attracted more than $112 billion via the IRA to build out domestic facilities.

How much more can DOE’s LPO spend?

The LPO has been granted the authority to distribute hundreds of billions of dollars to innovative clean energy and advanced manufacturing projects.

Through September 2024, the office reported financing nearly $44 billion worth to date. As of the EVgo announcement referenced above, that total was closer to $55 billion. Tacking on the billions for BlueOval SK’s battery plants and the PG&E guarantee brings LPO’s total near $90 billion. And there’s more to come.

Through November 2024, DOE’s LPO reports more than 200 active applications accounting for more than $324 billion in requested funding.

As of the start of this month, DOE estimated it had around $397 billion left to play around with, including more than $244 billion for Title 17 Energy Infrastructure Reinvestments, which PG&E just dipped into.

Cause for concern?

Electric utilities are rightfully concerned with the survivability of the LPO once Trump returns to the White House. Entire programs went dormant during his first presidency, and Trump will have the support of a Republican-majority House and Senate this time around.

Earlier this month, Duke Energy Carolinas and Duke Energy Progress paused their consideration of utilizing DOE loans, recognizing the money may not be there under Trump 2.0. According to a recent filing, Duke was about to hire a consultant to review EIR opportunities, but will now wait for the dust to settle.

“It is in the best interest of customers to pause any further efforts or expenditures until February, following the appointment of the new administration to gain clarity on the future of the EIR Program,” Duke Energy said.

PG&E is curious to see how it shakes out too.

“I think the number one thing that we’re interested in learning more about is the approach to the DOE loans,” detailed Shawn Adderly, director of PG&E’s Transmission Performance Center in a recent webinar on POWERGRID.

Adderly notes the application language is currently tied to renewable projects coming online, and he wonders whether the incoming Trump Administration will reframe consideration around something like predictability or grid security.

“We do need to upgrade our infrastructure,” Adderly admitted, referencing transformers operating past their expected lifespan and aging transmission lies. “I’m really hopeful, especially with the incoming administration campaigning on removing some of the bureaucracies, that they would encourage the permitting reforms to continue and to streamline the processes of regional planning and actions siting.”

“The biggest concern is just where the DOE loans land,” he reiterated.

Originally published in Renewable Energy World.

The American Electric Power (AEP) subsidiary has proposed adding a 450-Megawatt (MW) natural gas plant to be located at the previously retired H.W. Pirkey Power Plant site in Hallsville, Texas. The new Hallsville plant is expected to come online in 2027, pending approval from utility regulators in Arkansas, Louisiana and Texas. According to regulatory filings submitted December 17, the facility would feature two GE combustion gas turbine generators and utilize existing water intake structures and site infrastructure to minimize project costs, SWEPCO said.

The utility is also planning a coal-to-gas conversion project at the Welsh Power Plant, located northwest of Cason, Texas. The 1,053 MW project would convert the existing coal-fired boilers of Units 1 and 3 to burn natural gas, with Unit 1 conversion anticipated in 2028 and Unit 3 in 2027.

Natural gas currently accounts for 48% of SWEPCO’s existing power generation portfolio. Due to the evolving reserve requirements set by the Southwest Power Pool, SWEPCO anticipates an increasing capacity need.

In addition to the projects mentioned above, SWEPCO has selected a short-term capacity agreement with a natural gas-fired plant in Texas as part of a competitive bid process. The company said this agreement would serve as a bridge to more permanent resource additions.

SWEPCO continues construction on multiple renewable energy projects. The largest one, the 598 MW Wagon Wheel Wind Facility, spans five counties in Oklahoma and is expected to be operational in December 2025.

The 200 MW Diversion Wind Farm, located in Baylor County, Texas, is scheduled to begin operations this month.

SWEPCO’s first utility-scale solar farm, the 72.5 MW Rocking R Solar Facility, is also nearing completion in Caddo Parish, Louisiana. SWEPCO will not own the facility and will instead purchase the electricity generated via a purchase power agreement.

According to NERC’s 2024 Long-Term Reliability Assessment (LTRA), “well over half” of the continent is at elevated or high risk of energy shortfalls over the next five to 10 years. The assessment highlights critical reliability challenges the power industry will face over the next decade, including satisfying rising energy growth, managing generator requirements, and removing barriers to resource and transmission development.

Generator retirements are slated to continue over the next 10 years, while electricity demand and energy growth are rapidly climbing, NERC pointed out in its LTRA. New data centers are driving a good portion of the demand growth, but electrification in various sectors and other large commercial and industrial loads (like new manufacturing facilities and hydrogen fuel plants) are also playing a part.

“Demand growth is now higher than at any point in the last two decades, and meeting future energy needs in all seasons presents unique challenges in forecasting and planning,” said Mark Olson, NERC’s manager of reliability assessments. “Meanwhile, announced generator retirements over the 10-year period total 115 gigawatts (GW) and are largely being replaced by variable generation. The resulting mix of resources will be able to serve energy needs at most times, but will need to have adequate amounts of dispatchable generators with assured fuel supplies, such as natural gas, to be reliable all the time.”

NERC’s LTRA suggests that the summer peak demand forecast is expected to rise by more than 122 GW for the 10-year period, which is 15.7% higher than the current level. Since last year’s LTRA, the 10-year summer peak demand forecast has grown by more than 50%; the winter peak demand forecast is expected to rise by nearly 14% over the 10-year period.

NERC added that compared to last year’s LTRA, there are indicators this year pointing to greater investment and enhancements in the regional planning process to support grid expansion with more transmission projects reported as either under construction or in planning for construction over the next 10 years.

“While we are encouraged by the significant increase in transmission development, industry and policymakers must address the persistent challenges of siting, permitting, and construction to ensure this growth becomes a reality,” said John Moura, NERC’s director of reliability assessments and planning analysis. “Overcoming these barriers is critical to realizing a more reliable and resilient grid.”

In its Interregional Transfer Capability Study (ITCS), NERC found that an additional 35 GW of transfer capability across the U.S. would strengthen energy adequacy under extreme conditions. Increasing transfer capability between neighboring transmission systems could potentially help alleviate energy shortfalls, and could become one of the solutions that entities put in place to address the resource adequacy issues identified in the LTRA, NERC reckons. While NERC said that multiple areas have been identified as being at “elevated risk” in extreme conditions, the Midcontinent Independent System Operator (MISO) was highlighted as not having the reserves to meet resource adequacy criteria in normal conditions as resource additions are not keeping up with generator requirements and demand growth.

NERC’s assessment offers recommendations for energy policymakers, regulators, and industry to promote actions meant to help meet growing demand and energy needs while the resource mix transitions:

• The pace of generator requirements should be “carefully scrutinized and managed” by industry, regulatory, and policy-setting organizations considering the projected reliability risks;
• Enhance the long-term assessment process by incorporating wide-area energy analysis with modeled interregional transfer capability, as found in the ITCS;
• Support from regulators and policymakers at the federal, state, and provincial levels is “urgently needed” to address siting and permitting challenges to remove barriers to resource and transmission development;
• Collaboration across regulators, electric industry, and gas industry member organizations could help address the operating and planning needs of the interconnected natural gas-electric energy system;
• Ensure essential reliability services are maintained by regional transmission organizations, independent system operators, and regulators

Originally published in Renewable Energy World.

The report, The Future of Geothermal Energy, finds that geothermal energy could meet 15% of global electricity demand growth between now and 2050 if project costs continue to decline.

Today, geothermal meets about 1% of global electricity demand. However, the IEA analysis, conducted in collaboration with Project InnerSpace, shows that next-generation geothermal technologies have the technical potential to meet global electricity and heat demand many times over.

Importantly, geothermal energy can draw upon the expertise of today’s oil and gas industries by using existing drilling techniques and equipment to go deeper under the earth’s surface to tap into vast low-emissions energy resources.

“New technologies are opening new horizons for geothermal energy across the globe, offering the possibility of meeting a significant portion of the world’s rapidly growing demand for electricity securely and cleanly,” said IEA executive director Fatih Birol. “What’s more, geothermal is a major opportunity to draw on the technology and expertise of the oil and gas industry. Our analysis shows that the growth of geothermal could generate investment worth $1 trillion by 2035.”

Conventional geothermal remains a location-specific, niche technology today with most of the installed capacity in countries that have either have volcanic activity or straddle tectonic fault lines, which make resources easier to access.

Current leaders in the space include the United States, Iceland, Indonesia, Türkiye, Kenya and Italy.

But new technologies are making the outlook for geothermal truly global, opening up the potential to benefit from it in nearly all countries.

The report highlights that more than 100 countries have policies in place for solar PV and onshore wind, but only 30 have such policies for geothermal.

Moving geothermal up national energy agendas with specific goals and backed support for innovation and technology development can go a long way to reducing project risk perception and unlocking new investment.

Clear, long-term regulatory visibility for investors will help mitigate risks in early-stage development and provide visibility on investment returns, which in turn will improve the cost competitiveness of geothermal projects.

By doing so, the report finds that costs could fall by 80% by 2035 to around $50 per megawatt hour (MWh). This would make geothermal the cheapest source of dispatchable low-emissions electricity on a par with existing hydropower and nuclear installations.

However, permitting and administrative red-tape are proving a major barrier to geothermal projects, which can take up to a decade to fully commission. The report suggests governments could simplify permitting processes by consolidating and accelerating the administrative steps involved.

They could also consider dedicated geothermal permitting regimes separate from minerals mining. Policies and regulations enforcing robust environmental standards are critical for the sustainable development of geothermal projects.

Originally published in Power Engineering International.

At its November 14 meeting, the council approved the Final Order on the Application for Site Certificate (ASC) for the Sunstone Solar Project, formerly known as Echo Solar, shortly thereafter issuing a site certificate for the construction, operation, and retirement of the facility in Morrow County, Oregon.

If built to its intended capacity, Sunstone Solar will be one of the largest renewable energy projects in the United States. It is planned to have up to 1.2 gigawatts (GW) of generating capacity via nearly 4 million solar panels and up to 7,200 megawatt hours (MWh) of paired battery energy storage. The site is expected to provide clean, renewable power for up to 800,000 homes.

Construction on the project will include building an interconnection substation, up to six collector substations, up to four operations and maintenance (O&M) facilities, and up to 9.5 miles of 230-kilovolt (kV) overhead transmission lines, in addition to other structural work including roads, fencing, and gates.

Farming the sun

Sunstone will take a large chunk of usable farmland out of production. It is authorized to occupy up to approximately 9,442 acres (14.75 sq. miles) of private land zoned for Exclusive Farm Use within an approximately 10,960-acre (17-sq. mile) site, which is about 15 miles northeast of Lexington, OR.

The Oregonian notes the area has been cultivated in dryland winter wheat, and more than half of the site is considered “high-value” farmland. The state cracked down on solar siting in such places five years ago, but large-scale projects have found ways around restrictions by proving a site’s potential economic benefits to the local economy and mitigating the total loss of farmland.

Another project developer, owner, and operator, Doral Renewables, is plenty familiar with the arithmetic necessary to get projects approved while still maintaining critical agriculture. Doral just finished the first 400 MW phase of the colossal Mammoth Solar in Indiana, which will have 1.3 GW of clean capacity by the time it’s finished. Doral president and CEO Nick Cohen approaches the farmland conundrum with a clever line of thinking.

“We’re farming the sun, which is what they’re doing anyhow,” he notes, pointing out that a lot of farmers near Mammoth are using their crops for ethanol production- just another (dirtier) fuel. “I don’t see how it’s different that now it’s just going straight to electricity,” Cohen surmises.

Doral is making active efforts to return to traditional farming on small farms, leaning into an agrivoltaics pilot and maintaining close relationships with farmers in Mammoth’s footprint. It is unclear if Pine Gate plans to employ similar tactics at Sunstone Solar.

“There was a time in America when small farms grew food,” Cohen said in a recent chat with Renewable Energy World. “They produced food as a business. And that’s one of the things that our projects do, is we bring the heritage farming back to the small farms.”

Construction on Sunstone Solar is expected to begin in 2026, although the Pine Gate subsidiary has until November 18, 2027, to comply with applicable pre-construction site certificate conditions and start putting steel in the ground. It has up to three years to complete construction once work has begun.

The project will put a sizable dent in Oregon’s state climate goals, which require its two largest electric utilities, Portland General Electric and Pacific Power, to reduce greenhouse gas emissions by 80% by 2030 and be emission-free by 2040. PGE currently operates the region’s largest battery energy storage system, two 200 MW/800MWh BESS commissioned in 2023, which will be dwarfed by the Sunstone BESS once operational.

This fall, Pine Gate Renewables closed on a $288 million preferred equity investment with funds affiliated with Blackstone Credit and Insurance (Blackstone) supporting six solar projects in two states totaling 780 MW of capacity. All six of the projects are backed by corporate offtake agreements. Their locations have not been publicly announced.

Originally published in Renewable Energy World.

Quaise and NGM are exploring additional decarbonization of the latter’s newly commissioned 200-megawatt (MW) solar power plant by using geothermal heat from NGM’s land and subsurface holdings to hybridize on-site power generation.

The TS Solar Power Plant has the capacity to produce 17% of NGM’s annual power demand while realizing an equivalent emissions reduction of 234 Kt of carbon dioxide per year. Barrick president and chief executive Mark Bristow says the solar facility will reduce NGM’s total annual greenhouse gas emissions by 8% against a 2018 baseline.

NGM is currently in the process of converting to co-fire capabilities at the plant, planning to use cleaner-burning natural gas as another fuel source. In its partnership with Quaise, NGM is also investigating deep geothermal energy sources to further reduce the plant’s fossil fuel consumption and greenhouse gas (GHG) emissions. It marks the commercial pilot for retrofitting a fossil fuel power plant to accommodate geothermal heat.

“Nevada Gold Mines is targeting an overall 30% reduction in GHG emissions by 2030,” explained Henri Gonin, managing director of Nevada Gold Mines. “We continue to pursue initiatives that economically reduce our reliance on carbon-based electricity sources. Quaise offers a unique prospective solution to hybridize our on-site power generation with clean geothermal heat.”

Quaise Energy spun out of the MIT Plasma Science and Fusion Center in 2018. The company has raised more than $95 million to date, including a $21M Series A1 financing round led by Prelude Ventures and Safar Partners in March 2024. Mitsubishi Corporation and Standard Investments were among several new participating investors.

The startup says its approach to geothermal is unique by going hotter and deeper to significantly increase power density and worldwide accessibility. Outfitting existing drilling rigs with millimeter wave technology accelerates the development of deep geothermal energy by leveraging the fossil fuel infrastructure of today, it argues.

“Deep geothermal can decarbonize critical industrial processes like mining because of its superior power density,” said Carlos Araque, president and CEO of Quaise Energy. “Our millimeter wave drilling technology is the key to unlocking high-grade geothermal heat, repositioning fossil-fired assets for a clean energy future.”

Quaise Energy bills itself as “terawatt-scale geothermal,” opening access to renewable baseload power for the planet. Deep geothermal uses less than 1% of the land and materials of other renewables, making it the only option for a sustainable clean energy transition, according to its website. Deep geothermal wells can be drilled in more places around the world, even next to existing power plants, and can compete with fossil fuels on cost while eliminating carbon emissions.

According to Quaise, deep geothermal power plants can create 10 times more energy than conventional geothermal can while providing 24/7 baseload power on a relatively small land footprint. The company believes the retrofit of NGM’s TS Power Plant positions Quaise to go from drilling field trials to full commercial deployment of its technology. The ongoing partnership with NGM also invites other industrial use applications worldwide.

Originally published in Renewable Energy World.