CPV Rogue’s Wind would join the CPV Maple Hill Solar and the CPV Fairview Energy Center projects in Cambria County. The project would consist of 19 Vestas V-162 wind turbines.

CPV Rogue’s Wind is expected to come online in 2026. The project is part of the company’s 10 GW pipeline of renewable and dispatchable generation projects, including utility-scale power generation with carbon capture.

CPV Rogue’s Wind is the first project tied to the company’s recent partnership announcement with investment management firm Harrison Street. The partnership, in which Harrison Street acquired one-third of CPV Renewables, will support an accelerated build out of the 4 GW renewable development pipeline.

It represents the end of an era for the massive coal-fired plant, located near Farmington, New Mexico. The plant, which PNM had operated for decades, provided power for much of the state.

The shutdown of San Juan Unit 4 in September 2022 followed the retirement of Unit 1 in June of that year. The coal-fired plant had four units but was reduced to two in 2017, with the closure of Units 2 and 3. The plant first came online in 1973.

The plant’s retirement sent financial ripples through the surrounding communities. Hundreds of employees were impacted. PNM provided $11 million in severance packages to help about 200 displaced workers. About 240 mine workers received severance payments worth $9 million. Another $3 million went to job training.

PNM is the majority owner of San Juan Generation Station, but the city of Farmington has a 5% stake. The city had aimed to keep the plant open, partnering with Enchant Energy for a carbon capture and sequestration (CCS) project.

The San Juan Solar Project, which would have a capacity of 400 MW, is already on the power plant land and could start operating later this year. PNM approved a 20-year power purchase agreement (PPA) for the solar project.

The funding would support technologies that capture CO2 from industrial and power generation or directly from the atmosphere and transport it either for permanent geologic storage or conversion into valuable products such as fuels and chemicals.

The sixth opening of FECM’s Carbon Management funding opportunity announcement (FOA) will support the following areas of interest:

• Reactive carbon capture approaches for point source capture or atmospheric capture with integrated conversion to useful products. Reactive carbon capture is the integration of carbon capture with conversion to a product. This area of interest would focus on conceptual design studies followed by laboratory validation of reactive CO2 capture approaches from exhaust flue gas streams at electric generation and industrial facilities or from the atmosphere, with conversion of the CO2 into environmentally responsible and economically valuable products.
   
• Engineering-scale testing of transformational carbon capture technologies for natural gas combined cycle (NGCC) power plants. Testing under real flue gas conditions aims to achieve 95 percent or greater carbon capture efficiency and 95 percent CO2 purity, while demonstrating significant progress toward a 30 percent reduction in the cost of capture.
   
• Engineering-scale testing of transformational carbon capture technologies in portable systems at industrial plants. Development and testing of portable systems for transformational technologies would be conducted at a variety of sites, including oil refineries and petrochemical, cement and lime, pulp, steel and iron, and glass plants.
   
• Preliminary front-end engineering design (Pre-FEED) studies for carbon capture systems at existing (retrofit) domestic NGCC power plants. Pre-FEED studies of commercial-scale, advanced carbon capture systems at existing NGCC power plants or combined heat and power facilities that employ NGCC power generation.
   
• Pre-FEED studies for carbon capture systems at hydrogen production facilities using coal, mixed coal/biomass or natural gas feedstock. Studies to advance commercial-scale carbon capture systems that separate CO2 with at least 95 percent capture efficiency at new or existing hydrogen production facilities using coal, mixed coal/biomass/municipal solid waste/unrecyclable plastics, or natural gas feedstocks.
   
• Enhancing CO2 transport infrastructure (ECO2 transport): Pre-FEED studies for multimodal CO2 transfer facilities. Studies that support the development of viable and strategically adaptable multimodal transportation infrastructure capable of transferring CO2 across regional and national CO2 transportation networks.

Since the end of 2023, 8 Rivers and Siemens Energy have collaborated on development of direct-fired super critical CO₂ turbines across a range of applications and fuel types. 8 Rivers, a developer of decarbonization technology and projects, said the ongoing turbine development program provides line of sight to future commercial projects. 

Siemens Energy has selected the commercially available generator that will be used with the Allam-Fetvedt Cycle (AFC) turbine. Siemens Energy will also provide related equipment, services, compression and grid technologies.

However, 8 Rivers said it has completed a study with a commercial party which assessed the feasibility of a biomass fueled Allam-Fetvedt Cycle negative emissions power system (Biome). This resulted in the recent signing of an MoU with the aim of commercial deployment, the company said.

8 Rivers argues that biome as a power system allows for the generation of low-cost, reliable, negative emissions power while simultaneously generating large volumes of carbon dioxide removal (CDR).  

North Carolina-based 8 Rivers develops zero-carbon technologies such as hydrogen, carbon capture and biomass carbon removal. It jointly owns NET Power, whose Allam-Fetvedt Cycle combusts natural gas with oxygen (rather than air) to fuel a supercritical CO₂ cycle that generates electricity.

The technology reuses most of the carbon dioxide produced and captures the rest, meaning it emits virtually nothing into the atmosphere. NET Power has said its plants should cost no more to build and operate than a traditional natural gas plant.

In 2018, we reported NET Power successfully achieved first fire of its demonstration plant and test facility in La Porte, Texas. At that time, the company had targeted the global deployment of 300 MW capacity commercial-scale plants beginning as early as 2021.

The Sutter Decarbonization Project would be designed to capture 95% of carbon emissions from Sutter Energy Center. Calpine now plans to begin the first phase of the DOE cooperative agreement, which will support the engineering and design of the project.

Calpine is working with the Sacramento Municipal Utility District (SMUD) to support its 2030 Zero Carbon Plan through the project. Other partners include ION Clean Energy and 1PointFive Sequestration.

Sutter Energy Center is located in Yuba City, California. The 550 MW combined-cycle plant became commercially operable in 2001.

In December 2023, we first reported that the Sutter Decarbonization Project would receive up to $270 million in DOE funding.

The project would use ION’s ICE-21 solvent to capture the CO2 and sequester it permanently more than a half a mile underground in saline geologic formations. It would be the first in the world to deploy an air-cooling system at a carbon capture facility, which would eliminate the use of cooling water and significantly minimize freshwater usage.

Calpine also recently executed the first phase of its cost sharing agreement for the Baytown Decarbonization Project, a similar CCS demo project in Baytown, Texas.

“Calpine is grateful for the DOE’s commitment to working with Calpine to advance this important technology and believes that this is a recognition of the quality and strength of Calpine’s CCS program,” said Alex Makler, Calpine’s Senior Vice President, West Region.

The future adoption of carbon capture and storage likely depends on a variety of factors, like changes in the cost to capture CO2, the availability of pipeline networks and storage capacity for transporting and storing CO2, federal and state regulatory decisions and the development of clean energy technologies that could affect the demand for CCS.

For perspective, AEP’s systemwide peak load at the end of 2023 was 35 GW. The utility serves 5.6 million customers in 11 states through its subsidiaries and has the country’s largest transmission system.

AEP Interim CEO Ben Fowke said the company continues to work with data centers to meet their increased demands for power, while ensuring that new contracts are fair to all of its customers.

“I want to emphasize that it’s critically important that costs associated with these large loads are allocated fairly, and the right investments are made for the long-term success of our grid,” Fowke told investors.

Fowke cited AEP filing new data center tariff proposals in Ohio and large-load tariff modifications in Indiana and West Virginia.

In Ohio, the proposed rate structure would require new data centers with loads greater than 25 MW and cryptomining/mobile data center operations with loads greater than 1 MW to agree to meet certain requirements before infrastructure is constructed to serve them.

Data centers specifically would be required to make a 10-year commitment to pay for a minimum of 90% of the energy they say they need each month – even if they use less.

Along with Exelon, AEP is also protesting a proposal that would result in the co-location of an Amazon Web Services (AWS) data center at Talen Energy’s Susquehanna nuclear plant in northeast Pennsylvania. The utilities claim the proposed interconnection agreement would result in unfair cost burdens on ratepayers and negatively impact market operations and reliability.

According to a study published by EPRI in May, data centers could consume up to 9% of U.S. electricity generation by 2030 — more than double the amount currently used.

The burgeoning of data centers is one reason utilities are planning for the largest increase in natural gas-fired plants in over a decade. Buyers of F-Class, advanced-class and aeroderivative gas turbines are reportedly experiencing lead times not seen since the gas boom of the early 2000s.

AEP’s Public Service Company of Oklahoma (PSO) plans to seek regulatory approval for the purchase of Green Country, a 795 MW natural gas combined-cycle plant in Jenks, Oklahoma. Subject to approval, PSO expects to close on the transaction by June 30, 2025.

On impact of environmental regulations

In the utility’s 10-Q, AEP said federal rules and environmental control requirements would impact the utility’s generation fleet. AEP noted EPA’s suite of measures to crack down on pollution from fossil-fired plants.

Under one of the measures, coal-fired plants which plan to stay open beyond 2039 would have to reduce or capture 90% of their carbon dioxide emissions by 2032. As of June 30, 2024, AEP said approximately 46% of the company’s owned generating capacity was coal-fired.

AEP said it is in the early stages of identifying the best strategy for complying with the rule while ensuring resource adequacy.

The company, along with other utilities, states, companies and trade associations challenged the rule and requested a stay, which was denied by the D.C. Circuit Court of Appeals.

AEP and other utilities have now filed applications with the United States Supreme Court seeking an emergency stay.

The vote green lights Platte River’s recommended “optimal new carbon” portfolio which includes 300 MW of new solar and 460 MW of new wind by 2030. The utility would also add 200 MW of thermal generation in the form of aeroderivative gas turbines by 2028, according to filings presented to the board.

“While some community members question the need for new gas turbines, every portfolio we’ve modeled that meets the requirements of our three foundational pillars adds renewable resources and aeroderivative units,” says Jason Frisbie, general manager and CEO of Platte River.

While PRPA considered five different portfolios, the company said the optimal new carbon plan
“balances cost, reliability and carbon considerations.”

Platte River Power Authority is the utility serving Estes Park, Fort Collins, Longmont and Loveland – communities in Northern Colorado.

In 2020, PRPA had filed an IRP which included the goal of being carbon-free by 2030. However, the utility said supply chain and inflationary pressures caused by the COVID-19 pandemic prompted changes to the plan.

Platte River said the 2024 IRP captures these developments, while reaffirming the need for dispatchable capacity to support a highly renewable energy portfolio.

Platte River said it plans to follow a three-pronged approach to dispatchable capacity:

• Implementing both short and long-duration energy storage when commercially viable. PRPA plans to add 175 MW of battery storage by 2030. The utility acknowledged that long-duration energy storage would not be commercially available at scale until after 2030.
• Using the lowest carbon-emitting combustion turbine technology that is hydrogen capable. It’s worth noting that in all the utility portfolios, it assumes new thermal generation would use a fuel blend containing 50% hydrogen from 2035 on; and 100% hydrogen fuel from 2040 onwards.
• Building out a virtual power plant with the four owner communities. Platte River said though work is already underway to build a virtual power plant, modeling and data from consultants estimate it will take close to a decade to develop a fully functional resource.

In 20 years, the utility plans to add a total of 600 MW of solar and 885 MW of wind. PRPA would also add 275 MW of battery storage and 160 MW of long-duration energy storage during that time.

Platte River noted it could further refine its IRP during implementation, incorporating market conditions, technology evolution, availability and cost and timing of new resources.

WASHINGTON (AP) — In a victory for President Joe Biden’s administration, a federal appeals court on Friday ruled that a new federal regulation aimed at limiting planet-warming pollution from coal-fired power plants can remain in force as legal challenges continue.

Industry groups and some Republican-led states had asked the court to block the Environmental Protection Agency rule on an emergency basis, saying it was unattainable and threatened reliability of the nation’s power grid.

The EPA rule, announced in April, would force many coal-fired power plants to capture 90% of their carbon emissions or shut down within eight years. The rules are a key part of the Democratic president’s pledge to eliminate carbon pollution from the electricity sector by 2035 and economy-wide by 2050.

A three-judge panel of the U.S. Court of Appeals for the District of Columbia Circuit rejected the industry request to block the rule, saying the groups had not shown they are likely to succeed on the merits. Nor did the case invoke a major question under a previous Supreme Court ruling, since the EPA claimed only the power to “set emissions limits … that would reduce pollution by causing the regulated source to operate more cleanly,” the appeals court ruled.

The unanimous ruling also rejected the claim of immediate harm, saying compliance deadlines do not take effect until 2030 or 2032.

The ruling was issued by Judges Patricia Millett, Cornelia Pillard and Neomi Rao. Millett and Pillard were appointed by President Barack Obama, a Democrat, while Rao was named to the court by President Donald Trump, a Republican.

Environmental groups hailed the ruling, saying the court recognized the EPA’s legal responsibility to control harmful pollution, including from greenhouse gas emissions. The power sector is the nation’s second-largest contributor to climate change.

“Americans across the nation are suffering from the intense heat waves, extreme storms and flooding and increased wildfires caused by climate pollution,” said Vickie Patton, general counsel of the Environmental Defense Fund, which filed a friend-of-the court brief in the case. The EDF and other groups “will continue to strongly defend EPA’s cost-effective and achievable carbon pollution standards for power plants,” she said.

Meredith Hankins, a lawyer for the Natural Resources Defense Council, said the EPA rule “set reasonable standards for utilities and states to cut their carbon pollution.” The searing heat wave hitting much of the nation is a sign of how much the rules are needed, she said.

“The idea that power producers need immediate relief from modest standards that start to kick in eight years from now was obviously absurd,” Hankins added. West Virginia and other states that challenged the rule “have plenty of time to begin their planning process” to comply with the rule, she said.

The National Mining Association, which joined the legal challenges, said it would seek an emergency stay from the Supreme Court.

“The stakes couldn’t be higher. The nation’s power supply is already being pushed to the limit, and this rule flies in the face of what the nation’s utilities, grid operators and grid reliability experts tell us is needed to maintain grid reliability,” said Rich Nolan, the group’s president and CEO.

Nolan and other industry leaders said the rule would force the premature closure of power plants that are crucial to maintaining grid reliability even as demand for electricity surges.

Timothy Carroll, a spokesman for the EPA, said the agency was pleased that the court allowed the power plant rule to go into effect while litigation continues.

“EPA’s final standards will significantly reduce emissions of harmful carbon pollution from existing coal-fired power plants, which continue to be the largest source of greenhouse gas emissions from the power sector,” Carroll said.

The EPA projects that the rule will yield up to $370 billion in climate and health net benefits and avoid nearly 1.4 billion metric tons of carbon pollution through 2047, equivalent to preventing annual emissions of 328 million gasoline-powered cars.

The power plant rule marks the first time the federal government has restricted carbon dioxide emissions from existing coal-fired power plants. The rule also would force future electric plants fueled by coal or natural gas to control up to 90% of their carbon pollution.

The OUCC filed testimony last week to the Indiana Utility Regulatory Commission, arguing that the commission should reject Duke’s proposal due to the “speculative nature of the feasibility and affordability of a CCS system.”

Duke Energy’s request would raise annual revenues for its Indiana electric utility by nearly $492 million, the OUCC said, which would be implemented in two phases. The utility’s testimony and exhibits project that an average monthly residential bill for 1,000 kWh would be $170.67 when new rates are fully implemented in March 2025.

“Duke’s proposal would impose extreme rate shock and unfairly burden its residential customer base, which has experienced significant and worsening affordability challenges,” said Ben Inskeep, Citizens Action Coalition program director. “This rate case is inconsistent with the policy of the State of Indiana and the General Assembly’s repeated emphasis that electric utility bill affordability is a priority. Disappointingly, while Duke proposes a destabilizing rate increase that places a disproportionate burden on residential customers, it has not offered material improvements to its programs that would meaningfully help residential customers with their unaffordable electric bills.”

The OUCC argued its analysis shows that an increase of approximately $184.7 million (6.1%) is warranted instead, based on the case’s evidence and applicable law.

Duke was awarded a Department of Energy (DOE) grant to conduct a front-end engineering design (FEED) study on CCS systems at its Edwardsport Generating Station. The estimated cost of the project is more than $17 million, with an estimated offset of roughly $8 million in federal funding.

In his testimony, Brian Wright, a utility analyst in the electric division for Indiana’s OUCC, noted that Duke’s first CCS feasibility study concluded that CCS was not feasible at Edwardsport due to the “lack of geological formations onsite that could act as a good carbon storage medium.” However, more recent studies at the location have shown that dolomite formations in the area could provide carbon storage capacity.

While Duke Energy has claimed it cannot estimate whether any of its out-of-state subsidiaries could benefit from the study, the OUCC said at “at the very least” the study should improve Duke’s knowledge and experience in evaluating the technological and geographical feasibility of CCS at other sites. Therefore, OUCC argued, the benefits of Duke’s study will likely extend beyond Indiana’s borders, and portions of the cost should be allocated to Duke’s other jurisdictions.

In its petition, Duke Energy said it has been nearly five years since it last filed for a general rate increase, and the test year in the company’s last general rate case was a fully forecasted calendar year 2020 – meaning the case establishing its current rates and charges was filed and the record was closed before the COVID-19 pandemic. Since then, Duke Energy said, the economic climate has changed “significantly,” including increased inflation, increased cost of capital, and Duke Energy Indiana’s capital investments to its electric system.

Testing was conducted at the company’s 4.4 MW gas-powered plant in Holyoke, Massachusetts, which serves the local electric grid.

The company called it a “huge milestone” and said it’s possible for any internal combustion engine – big or small – to have no CO2 emissions.

ESG’s carbon capture system consists of a two-step process: first removing the water from the exhaust and then capturing the CO2. Drying the exhaust more than doubles a CO2-adsorbent’s capacity, enabling 100% of the carbon to be captured while simultaneously reducing the size and cost of the system.

ESG’s water removal and carbon capture system is designed for both large and small systems and can be retrofitted onto current operating power plants plus applied to mobile applications, the company said.

ESG’s water removal system consists of an advanced ceramic membrane incorporated into a mechanical cooling system. According to the company, the CO2 capture system uses solid adsorbers that are nontoxic and easy to handle, making the entire system very versatile and energy efficient.

ESG plans on implementing this technology across all its planned facilities. It has also licensed the technology to a subsidiary of Camber Energy.

The company plans to build a second gas-fired plant in Holyoke. The 4.2 MW plant would also be powered by Caterpillar engines.