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Crews have started work installing the first energy storage battery units at Florida Power & Light’s massive Manatee Energy Storage Center.

The utility says FPL Manatee Energy Storage Center will be the biggest solar power-battery storage facility in the world when operational. The Parrish, Fla., center will have 400 MW of output and 900MWh of capacity, enough to power about 329,000 homes for more than two hours, according to the release.

It is expected to be completed later this year. Irby was awarded the contstruction contract on the project.

“Energy storage is an essential piece of the puzzle when it comes to building on our rapid solar expansion and delivering a brighter, more sustainable energy future that all of us can depend on, including the next generation,” FPL CEO Eric Silagy said. “But the Manatee Energy Storage Center isn’t just bringing the Sunshine State one step closer to around-the-clock solar power, it is also helping turn Florida into a world leader in clean energy and sustainability.”

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The newly installed storage container is the first of 132 units that will ultimately be installed onsite. Each unit weighs approximately 38 tons, is roughly 36 feet long by 11 feet in height and width and will hold roughly 400 battery modules, with each battery module being equivalent to about 2,000 iPhone batteries.

The battery modules will store the extra solar energy produced by the neighboring FPL Manatee Solar Energy Center when the sun’s rays are strongest and send it to the grid when there is a higher demand for electricity.

FPL operates 41 solar energy centers across more than 20 Florida counties. In addition to completing Manatee Energy Storage Center, FPL is also in the midst of constructing nine additional solar energy centers.

By the end of the decade, FPL forecasts that nearly 40% of the company’s power will be generated by zero-emissions energy sources—a 65%-plud increase from 2020.

Energy Storage will be the focus of the December POWERGEN+ online series. Contact us if you have a session idea


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Nel Hydrogen has contracted to supply an electroyzer producing green hydrogen for a steel rolling and milling operation in Sweden.

The collaboration with Ovako, Volvo, Hitachi ABB Power Grids and H2 Green Steel could help the plant reduce carbon dioxide emissions by 50 percent from current levels, according to the release about the project.

Nel CEO Jon André Løkke calls it the first project in the world to heat steel with hydrogen prior to rolling. Green hydrogen is H2 which is created by an electrolyzer powered by carbon-free resources such as wind or solar or nuclear.

”We will work collaboratively together to make this project a success, based on the joint learnings we will standardize the overall solution and ensure that this can be replicated in different locations all across Europe,” Løkke  added.

The carbon-free hydrogen facility would be in Hofors, Sweden.

Nel Hydrogen will be leading a POWERGEN+ session tomorrow on “Green Hydrogen: Enabling Cross Sector Pathways to Decarbonization.

Registration for POWERGEN+ is free and sessions are available on demand.


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The utility which owns and operates one of the nation’s first nuclear power plants to gain 20-year license extensions and utilize digital sensors is seeking to keep that facility running through the 2050s.

Duke Energy has filed an application with the U.S. Nuclear Regulatory Commission to renew the operating licenses at Oconee Nuclear Station for another 20 years. If approved, the South Carolina units would run through 2053 and 2054.

Oconee is Duke’s largest nuclear station, capable of generating more than 2,500 MW of carbon-free electricity. Duke Energy plans to see operating license extensions for 11 reactors it operates at six sites.

“Oconee Nuclear Station has provided safe, reliable, carbon-free energy to customers and our communities for nearly 50 years,” said Oconee Nuclear Station Site Vice President Steve Snider. “Renewing these operating licenses is a significant step toward achieving Duke Energy’s aggressive carbon reduction goals, which cannot be achieved without nuclear power.”

The Duke Energy nuclear fleet plays an important role in reaching the company’s carbon reduction goals. In 2020, operation of the nuclear fleet avoided the release of nearly 50 million tons of carbon dioxide (if that same generation was produced with coal, oil and natural gas) and provided 83% of the company’s carbon-free generation, according to the utility. Duke has set carbon reduction goals of at least 50% by 2030 and net-zero by 2050 from electricity generation.

Oconee Units 1-3 all were commissioned in the early 1970s. They run on Babcock & Wilcox pressurized water reactors and boast a lifetime capacity factor of more than 80 percent, 97 percent in recent years.

Ten years ago Oconee was the first U.S. nuclear power station to utilize digitally controlled sensors, according to reports. It is also one of the 20 largest capacity power generation plants in the U.S.

In May, the NRC approved 20-year extensions for Dominion Energy’s Surry nuclear units 1 and 2. This would total 80 years of operation once the lifespan was completed.


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By Ben Emerson and Tim Lieuwen, Georgia Institute of Technology

Bobby Noble and Neva Espinoza, Electric Power Research Institute


Today’s energy system includes three major subsystems: (A) energy sources (oil, solar, etc.), (B) infrastructure and carriers for moving these energy sources, and (C) energy consumers

This article considers issues associated with hydrogen as an energy carrier.  Currently, the energy system is dominated by two largely independent, multi-trillion dollar carrier systems — electricity and  hydrocarbon fuels. In the US today, roughly 40% of energy is carried via electricity and 60% via fuels.  Fuels are chemical-based energy carriers with high energy densities that make long-range transportation possible. Today they are almost completely based on fossil fuels, such as natural gas or crude oil.  These systems leverage millions of miles of pipelines, a significant petrochemical manufacturing base, and serve a global user network, including vehicles, industrial processes, and building heating.   

While many questions remain about the relative roles of electricity and chemical energy carriers in a decarbonized economy, two things seem clear: (1) use of fossil fuels as energy sources and carriers will decrease, although probably not to zero, and (2) use of “manufactured” chemical energy carriers, such as hydrogen that is produced using renewable power, will grow.  These will be used to both move energy from sources to user, as well as to store energy. 

There are three key issues around hydrogen as an energy carrier: (1) generation of hydrogen, (2) logistics, handling, and movement of hydrogen, such as via pipelines, and (3) utilization of hydrogen by a variety of “energy conversion device” – i.e., devices that generate electricity (e.g., fuel cells or gas turbine power plants), or are used to heat water or building spaces.

The primary focus of this article is to address issue (3) –to identify the opportunities and challenges associated with utilizing hydrogen in energy conversion devices. For example, a key opportunity for hydrogen is to store it and then burn it in gas turbines during times of peak demand. This has the benefits of re-purposing existing technology (gas-fired plants and natural gas infrastructure) for combustion-based energy storage with no carbon emissions.  Here we address the following questions:

  1. Is hydrogen viable as a fuel? Can hydrogen be used in retrofitted devices or new systems?
  2. If so, what are the constraints or issues that must be understood by policymakers, users, and the public?

Can Hydrogen be used in Energy Conversion Devices?

The answer to this question is emphatically yes. There is no fundamental reason why hydrogen cannot be combusted in gas turbines, heaters, boilers, or other energy applications such as generating electricity. It can be used in a blend with natural gas, or as pure hydrogen.

In fact, today hydrogen is used as a dominant fuel source for a number of power generating plants, such as the Fusina hydrogen power station in Italy (100% hydrogen), a petrochemical plant in Daesan, South Korea (95% hydrogen), a steel mill in Wuhan, China (60% hydrogen), and several planned facilities converting to 100% hydrogen such as the Magnum plant in Vattenfall, Netherlands, and the Intermountain Power Agency plant in Utah.   It has been flown in specially designed aircraft by Martin, Tupelov, Boeing, and Skyleader, and airframers have pledged future hydrogen aircraft such as the Airbus ZEROe. 

What are the Constraints Associated with Utilizing Hydrogen in Existing Systems?

While hydrogen combustion offers a promising energy storage and conversion pathway, it is not a “drop-in” fuel for much of today’s natural gas fired energy conversion devices.  In other words, alterations are needed in the fuel handling systems, valves and piping, and combustor hardware.  These alterations are needed to address several issues of concern to stakeholders, including pollutant emissions, operability, and cost.  These issues are highly interdependent.

We will address pollutant emissions first.  In addition to concerns around CO2 emissions associated with climate change concerns, combustion can generate other pollutants, even zero-CO2 fuels like hydrogen.  Pollutants most commonly associated with fossil fuel combustion are particulates (e.g., soot), carbon monoxide, and NOx. 

Hydrogen combustion emits no particulate or carbon monoxide emissions, since it contains no carbon atoms – another major benefit of it as a fuel.  However, hydrogen combustion can generate nitrogen oxides (NOx) emissions. In essence, NOx is generated when air is heated to high temperatures and the N2 and O2 in air start to react with each other.  NOx is a regulated criteria pollutant because of its potential to cause adverse respiratory health effects and because it contributes to acid rain.

Neva Espinoza of ERPI will joint GTI to talk about hydrogen and other low-carbon resources in next week’s POWERGEN+ series-Online and Free-Register here

Read about Georgia Tech’s new Microgrid project

Hydrogen holds great promise and formidable challenges. Read about H2 and CHP potential

In situations where NOx emissions are not a concern, many options are available to use hydrogen and hydrogen blends, including the ability to use legacy combustor hardware for a range of hydrogen and natural gas blending levels.  In other words, the key challenges associated with using hydrogen are in low NOx combustion systems.  So called “diffusion combustors” are an older technology that leads to high levels of NOx pollutants.  These systems require water or steam injection to comply with the NOx regulations in modern air permits, which may be unattractive due to the cost and complexity of the water management systems.  These systems need large volumes of clean, de-mineralized water, which introduces additional environmental considerations.  In many places, such as the desert, water injection systems are not practical.  Nevertheless, diffusion combustors have good fuel flexibility.  Many of these systems operate today on fuels with very high hydrogen content, fuels that are naturally produced as biproducts of industrial processes in steel mills and petrochemical plants.  Many of these diffusion combustors are 100% hydrogen capable (see specific site examples above) but their deployment is limited to locations and economies where water/steam injection is viable for NOx control.

So called “lean, premixed combustors” are inherently low NOx systems, and can produce compliant emissions without any water or steam injection because they avoid the high temperature regions that produce NOx.  This is illustrated in Figure 1, which shows the differences of lean premixed combustors relative to non-premixed combustors.  Therefore, lean-premixed systems dominate new electric power plant installations and are the predominant technology in the power generating fleet.  However, legacy systems do not have the operational flexibility or fuel flexibility of diffusion combustors. 

Figure 1. Comparison of non-premixed vs lean-premixed combustors

Given these points, we’ll next dig into the details a little further on both operability and emissions in lean, premixed combustors, and what the concerns are and where the issues arise.  Operability refers to the ability to operate the plant reliably without having it shut itself down, damage itself, or have unacceptable performance.  Hydrogen affects operability in several ways.

  • Flashback – this is the most severe concern around high H2 levels in systems designed for natural gas, as the flame can propagate upstream and catastrophically damage hardware.  Hydrogen’s flame speed is an order of magnitude higher than that of natural gas.  Therefore, flashback is the dominant issue for modern lean premixed combustors on hydrogen fuel. 
  • Blowoff – If you’ve ever tried to light a match outside when its windy, you’ll know what this is.  Similarly, combustors have flow velocities that can exceed 100 MPH and so preventing the flame from flying downstream and out of the system is a major challenge.  Because hydrogen propagates so fast, blowoff challenges are alleviated with hydrogen.  However, this issue is compounded for fuel flexible combustors, which must avoid blow out with slower burning natural gas fuel and simultaneously avoid flashback with high hydrogen fuel.  For these reasons, the highest hydrogen capability marketed for any frame engine with lean premixed combustion is 50% hydrogen by volume, and much lower for most systems.
  • Combustion Instabilities- Modern low NOx systems are prone to a variety of damaging oscillations and a great deal of effort is spent on modern systems to develop designs that avoid these issues at the operating conditions of interest.  What this design must look like, however, changes with fuel composition or ambient temperature.  Thus, in cases where the fuel composition can vary widely, it becomes impossible to develop a static design that is stable over all conditions and for all potential fuels.  This has the practical impact of restricting certain operating regimes from operation, depending upon fuel composition.  For example, a plant may not be able to operate at peak power for certain fuel composition ranges.

Finally, lets dig a little further into NOx emissions.  First, we should correct some common errors that are out there.  Since NOx emissions increase exponentially with temperature, and because hydrogen can burn hotter, its sometimes said that hydrogen combustion will produce more NOx.  However, this point needs to be contextualized as to whether the combustor design is a diffusion flame combustion or lean, premixed combustor.  It is true for diffusion flame combustors, which are inherently high NOx devices.  It is not necessarily true for premixed, low NOx systems.  This is because NOx emissions are a function of temperature in these systems and many energy systems run at a fixed temperature or power settings.  To restate – premixed hydrogen powered systems can be designed for near-zero NOx emissions.

Next, it’s important to understand the connection between efficiency of the engine and its NOx emissions.  An approximate rule of thumb is that higher efficiency machines run at higher temperatures and, therefore, emit higher NOx emissions.  For reference, current EPA regulations on NOx for gas turbines is 30 ppm, while in certain areas such as in California with air quality problems, they can be as low as 3 ppm.  The highest thermal efficiency devices on the planet, combined cycle gas turbines, are now designed to operate with NO emissions between 2-25 ppm.  When operating with various H2 blends, since they are designed to operate at a fixed temperature, hydrogen addition need not adversely impact NOx emissions for premixed, low NOx designs. 

However, H2 also has additional effects on NOx emissions in low NOx, premixed systems associated with subtle differences in the way it burns which causes it to generate trace increases of NO.  For big, high efficiency engines, these effects are very small.  However, for smaller engines, such as microturbine that might emit 1-3 ppm, the effect could be noticeable – for example, a 1 ppm emission level could become 2 ppm.

To summarize, for lean, premixed combustion systems, increasing hydrogen levels can cause small absolute increases in NO levels, which could be large absolute changes (e.g., in the above example it doubled NOx emissions from 1 to 2 ppm).  However, for larger, high efficiency machines hydrogen effects can be minimal. 

A final point – heat transfer coefficients of combustion products fueled with hydrogen are higher than natural gas.  Because the peak temperature in a gas turbine is controlled by heat transfer to the rotating turbine, this could necessitate a reduction in turbine inlet temperature as hydrogen levels increase.  While high hydrogen fuels can actually benefit cycle efficiency, this can be counteracted by the efficiency reduction from a reduction of the turbine inlet temperature.  Figure 2 illustrates this tradeoff.

Figure 2. Simple cycle efficiency as a function of the fuel’s hydrogen content and the firing temperature.  Calculation is based on an F class turbine with methane/hydrogen fuel mixture.  For reference, full firing temperature on 100% methane fuel provides an approximate efficiency of 38.3%.  That value is indicated as a black iso-line.

Key Future Needs

To summarize, this paper  has shown, first, that hydrogen is certainly an acceptable, very clean fuel.  Second, it has shown that it can be used at low levels in existing fielded systems, and some low NOx gas turbines exist in the field today that can operate with H2 levels of up to 50% , cofired with natural gas.  Furthermore, systems have been developed to operate with pure hydrogen.  The key development challenge for the future is low NOx, fuel flexible systems, that can be readily operated with a range of fuel compositions, ranging from pure H2 to pure natural gas.  Figure 3 below summarizes the hydrogen readiness, R&D needs, and NOx compliance of these various technologies.  All of these will enable the combustion technology of the future – low NOx, wide operability range, fuel flexible combustion systems capable of operating up to 100% hydrogen. 

Figure 3. Hydrogen readiness and R&D needs for various combustor technologies

About the authors:  Tim Lieuwen is Regents’ Professor, the David S. Lewis, Jr. Chair, and the Executive Director of the Strategic Energy Institute at Georgia Tech. In this capacity, he manages Georgia Tech’s energy portfolio, encompassing more than 1000 researchers. He is also founder and CTO of TurbineLogic, an analytics firm working in the energy industry. Prof. Lieuwen is an international authority on clean energy. He has authored 4 books and over 350 other publications. 

Ben Emerson is senior research engineer at Georgia Tech. Prior to that he was owner of Southern Dynamics Consulting LLC.

Neva Espinoza is vice president-energy supply and low carbon resources, at the Electric Power Research Institute. She has worked for EPRI for the past nine years, including roles as director, senior program manager and senior project manager. Espinoza previously has worked in operations at NRG Energy and at the Oyster Creek Nuclear Generating Station.

Bobby Noble is gas turbines programs manager at EPRI and a Fellow of American Society of Mechanical Engineers. Prior to his nearly six years with EPRI, Noble was a consultant and also was senior research engineer at Georgia Tech.


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A new report released by research firm Global Market Insights states that the global microgrid market will record a 27% compound annual growth between 2021 and 2027.

The report highlights trends likely to shape the microgrid market between 2021 and 2027, with the need to integrate renewable energy technologies as one of the main driving forces.

The need to lower greenhouse gas emissions is pushing energy stakeholders to integrate more renewable energy resources hence driving the microgrid market. More and more governments are enacting regulations stipulating reductions in carbon emissions, a driving force for the deployment of microgrid solutions.

In addition, the growing demand for off-grid electricity in developing economies such as Africa and South-East Asia, where governments and multinational utility companies are rallying towards improving energy access to energy-poor households is a huge driver to microgrid deployments.

The lack of effective electric networks, current lags, voltage fluctuations, and grid failure have been primary concerns driving the remote microgrid industry across developing regions.

Ongoing grid modernization coupled with the installation of advanced and sustainable generation sources across the network will propel the industry scenario such that revenue generation within the sector will hit $33 billion by 2027, according to the study.

Technology developers are investing heavily in research and development to launch advanced, stable and resilient infrastructure across the grid. For instance, in North America where grid networks are often affected by harsh weather conditions, advanced microgrid solutions are increasingly becoming an option to power communities and critical facilities such as hospitals, police and rescue service providers such as firefighters.

The market in Canada is expected to grow significantly due to a strong regulatory and community focus on the integration of sustainable electric networks and reliable power supply infrastructure. Environmental concerns, local revenue opportunities or cost management, and increased autonomy are a few factors driving technological adoption across Canada.

At the same time, the rising demand for combined or hybrid integrated grid networks is expected to foster the hybrid-based microgrid network globally.

Despite environmental concerns to increase the use of renewables to mitigate climate change, the report states that the diesel generator-sourced microgrid market will grow to record over $11 billion in revenue by 2027. Rapid industrialisation coupled with the adoption of large-capacity energy generation facilities will propel the demand for diesel generators across the networks. Ongoing demand for heavy-duty power generators across industrial sectors will further sway product adoption. Low installation costs, when compared to its auxiliary sources, will complement the industry statistics.


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Florida Power & Light is imploding its last coal-fired plant while also announcing that more renewables will be developed in its place.

The utility plans to install a future solar energy center near the site of the Indiantown Cogeneration Plant, which was retired at the end of 2020. Indiantown’s 495-foot stack and coal chute were brought down with the controlled use of explosives recently.

FPL plans to use portions of the plant’s existing infrastructure to connect the new solar project to the energy grid and will explore opportunities to use parts of the plant site for future clean energy solutions.   

“While the sun is setting on coal use in Florida, cleaner energy is rising like never before,” said Eric Silagy, FPL president and CEO. “We have built more than 40 solar energy centers throughout the state and we are well on our way to installing more than 30 million solar panels by 2030.  And, we are not stopping there. With the construction of the world’s largest solar-powered battery facility and an innovative green hydrogen pilot project, we are leading the state and nation in producing energy that is reliable, affordable and better for our environment.”   

FPL purchased the 395-MW Indiantown Cogeneration plant, located in Martin County, in 2017 for the sole purpose of shutting it down because it deemed coal-fired power as uneconomical for its customers. The utility reportedly paid Calypso Energy Holdings $451 million for the plant, according to reports.

The formal retirement marked the end of coal in FPL’s power plant operations.   

In addition, Gulf Power, a part of FPL that serves customers in Northwest Florida, ceased coal-fired power generation at its Plant Crist in Escambia County earlier this year. The plant modernization included converting it to run entirely on American-produced natural gas—cutting the plant’s carbon emissions rate by 40% and marking the end of Gulf Power’s use of coal to generate energy in Florida.    

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 By the end of the decade, FPL forecasts that nearly 40% of the company’s power will be generated by zero-emissions energy sources – a more than 65% increase from 2020.   

The company now has 41 large-scale solar energy centers installed throughout Florida, with nearly 3,000 megawatts (MW) of solar capacity.


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The Texas power grid, which nearly collapsed due to generation outages during historic winter cold, is being stretched tight again.

The culprit is not freezing temperatures which dropped to sub-zero for several days in February, but “tight grid conditions” caused a higher level of generation outage than usual during the pre-summer heat. The system operator Electric Reliability Council of Texas asked customers to reduce electric use “as much as possible” through Friday.

“Generator owners have reported approximately 11,000 MW of generation is on forced outage for repairs; of that, approximately 8,000 MW is thermal and the rest is intermittent resources,” reads the ERCOT news release. “According to the summer Seasonal Assessment of Resource Adequacy, a typical range of thermal generation outages on hot summer days is around 3,600 MW. One MW typically powers around 200 homes on a summer day.”

Wind output on Monday totaled between 3,500 and 6,000 MW during 3 p.m.-9 p.m. peak demand period. This is about 1,500 MW lower than typical for peak demand, which was estimated at 73,000 MW and maybe above.

“The peak demand record for June is 69,123 MW set on June 27, 2018 between 4 and 5 p.m.,” reads the ERCOT statement.

Texans apparently responded to the ERCOT call for conservation even through peak demand hit a new June record. Power generators, meanwhile, completed some repairs which allowed some 1,200 MW back online.

POWERGEN+ online’s June series focuses on the Future of Electricity featuring hydrogen and carbon capture

Registration is free and sessions available on demand

About 52 of generation capacity was offline in February when Winter Storm Uri forced load shedding and power disruptions. Close to 100 people died from the weather exposure, according to reports.

In April, an investor group called Starwood Energy sent ERCOT a letter proposing some $8 billion worth of power infrastructure spending in the state.

Starwood Energy is interested in developing, building and owning 11 new natural gas-fired power plants totaling some 11 GW in capacity.

No decision has been made whether to approve the Starwood proposal.


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An infrastructure development wing of Black & Veatch has gained the financing it needs for a 138-MW solar farm planned in Texas.

Diode Ventures closed funding round for the Grizzly Ridge Solar Project to be located in Hamilton County near Fort Worth. The project was co-developed with RKB Energy LLC.

“Grizzly Ridge is one of the first utility-scale solar projects that Diode developed from the ground up, marking a significant milestone for the company when it comes to pure greenfield development projects,” said Brad Hardin, president of Diode. “In Texas, we are seeing more resilient infrastructure development on the horizon to support large-scale energy generation from both renewable and non-renewable sources.”

See PE’s full coverage of utility-scale solar project development

Diode partnered with RKB – a greenfield, utility-scale solar development company that currently focuses on the West and Southwestern regions of the U.S. – to assist with co-development activities of the project, from origination to sale.

“Diode Ventures has been an excellent partner in the Grizzly Ridge Solar project,” said Robert Schleider, president of RKB. “We are excited to see this project enter the build phase of its life cycle and believe it is a great project for Hamilton County and the State of Texas.”

Black & Veatch, one of the nation’s biggest engineering, construction and consulting firms for the energy industry, created Diode Ventures as a spinoff focused on infrastructure for the commercial, industrial and technology sectors. It has played a role in develop solar projects in Texas, Missouri, Taiwan and Japan.

Texas, already home to the largest wind power state in the U.S., could reach 1.6 GW of installed solar capacity by next year, behind only California.


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The coal-fired San Juan Generation Station in New Mexico will not close within two years as expected, but could operate for several years beyond that was its new owners raise funds for a giant carbon-capture facility on the site.

Various news reports indicate that Enchant Energy, which is buying the San Juan coal-fired plant from utility Public Service Co. of New Mexico (PNM), will need more time to convert the facility into a carbon-capture plant. Thus, the carbon emitting facility could run as is through 2025, according to the Albuquerque Journal report.

PNM received state regulatory approval last year to drop its stake in the San Juan facility in Farmington, N.M. The company is now in the midst of a merger deal with Avangrid.

A team including Enchant Energy founders Larry Heller and Jason Selch, and the city of Farmington, stepped in to try and save San Juan from the closures impacting so many of the nation’s coal-fired units. Their solution was to convert San Juan into a CO2 sequestration project, hopefully keeping the plant and jobs going while eliminating carbon emissions.

The news reports, however, indicate that the Enchant team is having trouble raising all the money its need for the conversion project. Some reports have put the price tag at about $1.4 billion.

PNM announced plans to close the San Juan units seven years ago. The coal-fired plant is not part of the PNM-Avangrid deal.

San Juan Units 1 and 4, which produce more than 900 MW at capacity, were completed and commissioned in the mid-1970s and early ‘80s, respectively. Units 2 and 3 were retired four years ago, according to reports.

— — — — —

Carbon capture is part of the discussion happening in two weeks when the June series of the online POWERGEN+ focuses on the Future of Electricity. Panelists include experts from the Global CCS Institute and Southern Co., among others. Registration is free.


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Two new Michigan solar projects are now operational and delivering up to 40 MW of carbon free power to the region.

National Grid Renewables announced work was completed at Bingham Solar and Temperance Solar, both part of the company’s MiSolar Portfolio. National Grid Renewables owns both projects, which will generate under power purchase agreements with utility Consumers Energy.

The developer kept the construction work as local as possible. Michigan-based contractor J. Ranck Electric handled engineering, procurement and construction duties, employing about 160 workers, most of which came from within 100 miles of each site.

“Our company has a long history in Michigan, and we are proud to support the state and local economies through the creation of new tax revenue and jobs that result from these projects,” stated David Reamer, Head of Development, US Onshore Renewables for National Grid Renewables. “Thank you to the residents of Clinton and Monroe Counties for welcoming us into your communities.”

Subcontractors included Michigan-based The Hydaker-Wheatlake Company, based out of Reed City.

“The Hydaker-Wheatlake Company was proud to help construct the MiSolar Portfolio,” stated Neil Wallerstrom, General Foreman, The Hydaker-Wheatlake Company. “Solar projects like the MiSolar Portfolio provide economic benefits for Michigan residents at the local and state level. Throughout the construction process of both project substations, we were able to hire Michigan residents and were pleased to support local hardware stores, hotels, and restaurants.”

Now operational, three full-time operations and maintenance staff work at the MiSolar project sites. During the first 20 years of operation, MiSolar is projected to further benefit the community through the creation of approximately $6 million in new tax revenue, based on current Michigan law.

Throughout that same time period, using the United States Environmental Protection Agency’s (EPA) greenhouse gas equivalencies calculator, the combined projects are estimated to offset carbon dioxide emissions by more than 50,000 metric tons annually.


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