Siemens Energy North America President Rich Voorberg was optimistic and upbeat as he sat down to speak with us at POWERGEN International back in January.

Voorberg has attended POWERGEN for nearly 30 years but still buzzes about walking the show floor or learning the latest technologies.

“It’s about working together,” said Voorberg, “and it’s about learning from each other.”

This kind of collaboration is crucial as the power sector faces the pressures of net-zero carbon goals and unprecedented load growth.

Big changes are happening already. A growing number of utilities and power generation owners have committed to cut carbon emissions 80% by 2030.

The U.S. bulk power system is becoming more renewables-heavy, thanks largely to coal-fired plant retirements and huge growth from utility-scale solar. The U.S. Energy Information Administration (EIA) is projecting that renewables’ share of electricity will increase three percent in just one year, from 22% in 2023 to nearly 25% in 2024.

Demand for power is also exploding. Many utilities are increasing their load forecasts, in no small part from new manufacturing and the rise of energy-intensive data centers using AI. Duke Energy Carolinas, for example, recently told regulators its current projected peak demand growth by 2030 is approximately eight times what it projected in the company’s 2022 Carbon Plan.

Voorberg said an all of the above approach is needed in the face of these challenges. This includes more solar, wind and battery installations, but also advancements in clean firm power technologies like hydrogen and small modular reactors, he said.

Conventional power sources will still be needed “for the foreseeable future,” Voorberg said.

The gas turbine remains the workhorse of power generation, and previous efforts have been aimed at extending time between outages and the life of equipment. Now, the focus turns to burning cleaner fuels like hydrogen, which is no longer simply a hypothetical situation.

Voorberg pointed to a hydrogen-blending test at Constellation’ Hillabee Generating Station, a 753 MW natural gas combined-cycle (NGCC) in central Alabama. Constellation blended 38 percent hydrogen by volume, with the demonstration occurring on a Siemens Energy SGT6-6000G gas turbine.

Researchers said only “minor modifications” were required for the blending test. Constellation said it added an inlet for the hydrogen to be blended, a control valve and calibrated instrument to measure fuel flow.

But Voorberg acknowledged that long-term trial runs are needed to see how parts on the backend are truly affected.

“We’ve theoretically got it,” he said. “But we’ve got to get these machines running and prove it out to ourselves over a longer and longer period of time.”

But at the end of the day, it’s about the business case.

Tax credits and other incentives have been established to support scaling up the production, transportation, storage and end-use of clean hydrogen. Siemens Energy itself opened a gigawatt-scale electrolyzer production facility in Berlin last year.

Establishing a functioning hydrogen economy in the U.S. is not without its headwinds. It’s a microcosm of the greater challenge of getting to net-zero by 2050 and the reality that we might not yet have all the tools commercially available to get there.

That’s why Siemens Energy spends more than $1 billion annually in R&D, aimed at bringing newer, cleaner innovations to market.

“It’s going to be difficult, and it’s going to really push out our engineers,” said Voorberg. “We believe only half of the technology exists today in a commercial mandate to get to 2050.”

All the more reason it takes a village to reach net-zero.

We are more than a month removed from POWERGEN International 2024 in New Orleans, the show’s website has changed color schemes and we are marching toward 2025 in Dallas.

Those who have attended know the show doesn’t come together overnight. Dozens of power sector professionals volunteer their time throughout the year to help plan and curate the POWERGEN technical conference program, which featured more than 200 speakers in 2024.

The POWERGEN International conference program is rich in case studies and technical knowledge – covering all issues related to the construction, maintenance, operation, regulation and chemistry of power generation.

Our show’s content is led by power industry professionals – for power industry professionals – and is committed to helping find a path from where the sector is now to where it’s going.

Educational topics in the POWERGEN program include trends in conventional power, utility-scale renewables, energy storage, onsite power, emerging carbon-free technologies, operations & maintenance (O&M), artificial intelligence, reliability, emission controls and workforce challenges.

Now, as we re-tool our advisory committee for 2025 – we need you!

We are excited to announce that our Call for Committee is now open, and you can apply here. If your background and experience lines up with what we’re looking for, we’ll contact you.

Committee members represent:

• Electric Utilities (Investor-owned, Publicly-owned, Co-op, etc.)
• Independent Power Producers (IPP)
• Commercial and industrial companies with on-site power
• Engineering, Procurement and Construction (EPCs)
• Power generation equipment OEMs
• Trade associations
• Consulting
• Academia

Positions sought for the committee include but aren’t limited to:

• Plant or Site Manager
• Operations Manager
• Project Manager
• Performance Engineer
• Energy Analyst
• Director of O&M
• Director of Operations
• Director of Power Generation
• Emerging Technologies Director
• Chief Engineer
• Health and Safety Manager
• We are especially interested in representatives of technology companies involved in securing power for artificial intelligence, data center or cryptocurrency applications.

As an advisory committee member, you’ll help:

• Serve as a resource to the POWERGEN team to develop ideas for new tracks, topics, and speakers prior to opening call for abstracts.
• Solicit and peer review technical abstracts and case studies that become show presentations.
• Suggest and recruit panelists and keynote speakers from your own networks.
• Act as an ambassador for POWERGEN at other industry events and with peers/professional networks.
• Lead panel discussions and introduce speakers at the show.

Committee members receive one complementary delegate pass to POWERGEN International and their name and company affiliation in official show programming. POWERGEN International takes place February 11-13, 2025, at the Kay Bailey Hutchison Convention Center in Dallas, Texas.

Don’t miss this opportunity to contribute to the power industry’s premier event. Your expertise is crucial in shaping the future of power generation!

POWERGEN International (PGI) has been a beacon of information for over 35 years. Coal was king for the first two-thirds of PGI’s history, and at one point a satellite conference, Coal-Gen, even emerged. Obviously our industry has undergone dramatic changes, and the recently concluded “POWERGEN 2024: Destination 2050” offered many examples of this continuing evolution. 

But every year, this author hears some colleagues exclaim “This is not the POWERGEN that I once knew.” 

Being a former coal-fired power plant steam generation chemist and air pollution control specialist, I can sympathize with these feelings. But we all must face the reality of a rapidly changing industry, where decarbonization is a major driver, and meeting this goal requires many technologies and solutions. Kevin Clark, the content director of Power Engineering and POWERGEN International, emphasized these ideas during an informative conversation we had at the conference. 

This article highlights several of the most important topics from this year’s event. A foundational concept to remember in this discussion is the importance of continued grid stability as the country progresses towards decarbonization. The potential for blackouts and even partial grid collapse from prematurely implemented alternative energy systems could be catastrophic to our economy and personal well-being.

The King is (not quite) dead

Coal-fired power production is not completely dead, and in recent months we have seen some power companies extend deadlines for coal plant retirements due to issues regarding grid stability. In that vein, several tracks at PGI 2024 addressed carbon capture and sequestration (CCS), a contentious issue often defined by one’s side of the political/environmental spectrum. The obvious major benefit of CCS is that the technology might allow some continued use of a plentiful fuel that has a large storage capacity.  Common for coal plants is a 30-day fuel inventory, which vastly exceeds current battery storage capabilities for renewable sources.

However, this benefit is counterbalanced by a number of potentially troublesome issues related to the leading CCS technology at present, CO₂ removal via scrubbing with an amine solution. Some of the most important include:

• The process adds a large and expensive chemical plant to any unit.
• Parasitic power consumption may reach 30%.
• The process consumes a significant amount of water and generates several wastewater streams.
• Concerns continue to grow, some from the general public, about safety issues related to CO₂ transport to injection sites. Pipeline projects have been halted per such concerns.

Another critical issue facing coal plants, retired or still operating, is storage and disposal of bottom ash and fly ash. Of great concern is leachate from these ponds contaminating groundwater and surface water. Much time, effort, and expense will be required to remediate ash storage ponds. The situation has not been helped by several high-profile ash pond failures that have occurred over the last two decades or so.    

Talk continues to swirl about carbon dioxide reduction from the combined-cycle power plants that have served as a bridge technology in the transition from coal to renewables. A requirement to install CO₂ scrubbing technology, at least as it currently exists, on natural gas-fired power units would put those facilities in a huge economic bind.

Renewables: Not yet a straightforward path

Renewable energy, and most notably but certainly not limited to wind and solar, is a primary topic at PGI events. It is hard to argue the foundational concept of wind/solar renewable energy, free and inexhaustible fuel from the sun. However, many clouds still populate the horizon (pardon the pun).  Infrastructure issues can be very challenging. Many wind turbines or solar cells are required to generate the equivalent power of a large coal- or gas-fired plant. Individual wind farms can cover many acres and generate public resistance about their influence on the scenery. Replacement and disposal of aging materials are additional concerns.

A particular development, which was addressed at POWERGEN and also very recently in Reference 1, is the emergence of winter load vs. generating capacity conflicts. When coal was king, it, along with nuclear energy provided most of the electricity to the country. Plants produced steady power throughout the year, apart from periodic regional severe weather events. So, maximum generating capacity bumping up against load requirements was usually limited to summer operation. With wind and solar, nature has much more of a say regarding generating capacity. In northern locations with short winter days and sometimes frequent snowstorms, solar production may fall to near zero for extended periods. 

Compounding the problem are the not uncommon wind droughts that can cover a wide region.  Wind/solar generating capacity has been known to drop to a very small fraction of nameplate. The kicker is that present battery storage capacity is limited to just a few hours. So, it is very difficult at present to store enough energy to cover load when nature says, “I am taking over.” Obviously, improved battery technology will help alleviate these problems, but how quickly will long-term battery storage arrive? An interesting aspect in this regard are research efforts into more abundant materials than lithium for future battery systems.

A nuclear renaissance?

For years the term “nuclear renaissance” has been tossed around. Nuclear power produces no CO₂ emissions, but public perception of nuclear energy still in large measure remains negative per the enormously high-profile accidents of yesteryear in the U.S., Russia, and Japan. Furthermore, large nuclear plants continue to be enormously expensive. 

Many in the industry are banking on small modular reactor (SMR) technology as the path forward. An argument I hear regularly about the viability of small reactors is that the “U.S. Navy has been using them for years in many of their ships, so the technology is established.” That answer may sound somewhat simplistic, but one argument for continued development of SMR technology is the potential for design standardization to help keep costs low, relatively speaking. Power experts are also looking at small reactors for microgrid applications, where a unit would provide the energy for a local area or perhaps a concentrated group of heavy industries. Managers at refineries, petrochemical plants, steel mills, etc., continue to explore opportunities for replacing some steam-fed heat exchangers with electrical energy. 

Of course, an issue that will remain at the forefront of new nuclear development is spent fuel disposal.  Some argue that breeder reactor technology to convert spent material to new fuel is proven. This discussion will definitely continue, including at future PGI events.

Is hydrogen part of the answer?

Much is being made about projects to produce “green” hydrogen; the generation of H₂ by electrolysis of water with either renewable or nuclear as the energy source. The hydrogen could then serve in multiple applications, including fuel for transportation and as a blended fuel or perhaps even the primary fuel for combined cycle power units. Already in design are combustion turbines to burn blended fuel or even straight hydrogen. 

Some significant speed bumps exist along this path. One is the presence of adequate water supplies for the hydrogen feedstock. I have seen some maps that show potential production facilities in interior portions of the country where water is scarce. This concept seems unrealistic. An alternative is to place production facilities along the coasts with their inexhaustible supply of seawater. However, electrolyzers require high-purity feed water, which would in turn require considerable effort to purify seawater.

Hydrogen distribution also presents challenges. Hydrogen pipeline technology is well established at industries along the “chemical coast” of Texas and Louisiana, but for new energy applications, hydrogen might have to be moved much longer distances. One concept is establishment of “hydrogen hubs” for gathering and distribution of the gas. Of course, hydrogen is extremely combustible, so safety considerations must take top priority. Another concept is to convert the produced nitrogen to ammonia and then transport that product to final locations. Anhydrous ammonia is combustible, but burning it directly produces nitrogen oxides (NO_x), which for years power plants have been removing from flue gas via selective and non-selective catalytic reduction. This is yet another hurdle to consider.

Conclusion

As was mentioned in the introduction, POWERGEN is not the same conference it was in halcyon days of fossil fuel-fired power generation. But this must be expected. The power industry has changed dramatically in the last ten to twenty years, and this change will continue. The conference must keep pace with the industry. Perhaps within a few years we might start seeing papers on fusion-based power production. “Never say never” is a key phrase when it comes to technology advancements, a concept that POWERGEN management well understands.

References

1. K. Kohlrus, “Transition to renewables increases winter reliability risk”; Power Engineering, January 31, 2024.
2. S. Russell, P.E., and E. Eisenbarth, “Carbon Capture Water Requirements and Wastewater Treatment”; from the proceedings of the 2023 International Water Conference, November 12-16, 2023, San Antonio, Texas.

About the Contributor: Brad Buecker is president of Buecker & Associates, LLC, consulting and technical writing/marketing. Most recently he served as Senior Technical Publicist with ChemTreat, Inc. He has over four decades of experience in or supporting the power and industrial water treatment industries, much of it in steam generation chemistry, water treatment, air quality control, and results engineering positions with City Water, Light & Power (Springfield, Illinois) and Kansas City Power & Light Company’s (now Evergy) La Cygne, Kansas station. Buecker has a B.S. in chemistry from Iowa State University with additional course work in fluid mechanics, energy and materials balances, and advanced inorganic chemistry. He has authored or co-authored over 250 articles for various technical trade magazines, and has written three books on power plant chemistry and air pollution control. He may be reached at beakertoo@aol.com.               

Hydrogen, as an alternative fuel for gas turbines, will play a role in decarbonizing traditional power generation, however, concerns have been raised by industry leaders about whether there is a sufficient supply of green hydrogen to sustain this green transformation.

“I get into conversations about hydrogen co-firing [and] the thing that comes up almost every time is ‘are we really going to have supply’?”

This was the question posed by Jason Jermark, vice president of Global Services Operations at Siemens Energy, who refers to the hydrogen supply issue as the “elephant in the room”.

Jermark was joined by industry heavy hitters, such as Jeffrey Goldmeer, Emergent Technologies Director – Decarbonization, GE Vernova and Benjamin Thomas, senior manager of Hydrogen Production Engineering of Mitsubishi Power Americas for a panel discussion on the future of gas turbine decarbonization.

Decarbonizing gas assets with hydrogen and ammonia was front and center of the discussion at POWERGEN International, which took a candid turn to explore some of the headwinds facing the sector.

Hydrogen as an alternative

“To be honest, years ago I was skeptical of it,” said Jermark.

“If you think about the scale that’s going to be required, to be able to support the vast amount of [gas] generation that we have, is it going to be possible… and is this really the best use of the hydrogen molecule?”

According to Jermark, there has been a four-fold increase in hydrogen supply projects globally in the last few years. An increase in projects in action and an increase in the speed of production prove the industry is asking for hydrogen to future-proof generation, he suggests.

“Because of the continued interest in the production front, it leads us to believe the supply will happen.

“It may not happen at the scale and speed that some would like, it also may happen in pockets, based on local availability, but it is going to be there.”

Hydrogen as an alternative to gas is not new. Siemens Energy has been using hydrogen in various applications for over four decades, with about 2.5 million operating hours accumulated across that time frame.

The market is maturing, said Jermark, spurred on by the [Inflation Reduction Act] and applicable tax credits in the US, as well as other carbon tax regulations in the EU and Asia.

However, even if supply is available, the panelists questioned whether hydrogen in co-firing is the best use of the molecule.

The role of ammonia

Jermark stated that while the hydrogen gas turbine market is more mature than ammonia, ammonia has a higher energy density and a broader available network to transport it.

“Ammonia is also an interesting application…there’s a lot of discussion about using it as alternative co-firing for gas turbines – our focus is how can we have the infrastructure in place to be able to transport it.”

Benjamin Thomas added that the outlook is quite complex in Japan, where LNG is currently being imported. The country needs products that can work in a variety of situations. There are different grid profiles to respond to in Japan, as wind and solar are developed, which is why there is a big focus on developing ammonia, a big focus for countries without a large hydrogen supply.

Also, in South Korea, a country focused on decarbonizing its gas-fired combined cycle plants, it’s critical to secure the hydrogen required and to transport it effectively. “The best way to do that is with ammonia as the carrier,” added Thomas.

Thomas explained that this drive for decarbonization is opening up opportunities for partnerships and wider developments such as that of zero carbon propulsion systems, providing support for the international maritime organization remit in reducing emissions.

Jeff Goldmeer highlighted that when it comes to ammonia, there is a technology challenge and an economics challenge.

“Study after study has shown that if you want to move hydrogen over long distances, you don’t want to do it as hydrogen, you need to move it as another molecule.

“Ammonia tends to be one of the simplest and cheapest molecules, a lot of people want to talk methanol but then you need to source carbinol. Ammonia just needs nitrogen, which is easily available.”

According to Goldmeer, from an economic perspective, ammonia makes the most sense.

There are technical challenges, however, emphasized Goldmeer. “We acknowledge ammonia does have a toxicity issue,” adding that even small amounts of ammonia will create a NOx problem.

“You need to be 99.9% ammonia-free in your hydrogen to avoid a NOx problem, so face the NOx problem and say I need a new combustor.”

Despite these technical challenges, Goldmeer and the other panelists agreed that there’s a well-established industry in the production and safe use of ammonia.

Currently 15-20 million metric tons of ammonia are moved by ship around the world and many ports already have ammonia bunkering capacity, proof of the molecule’s technical and economic viability.

No matter the molecule or path to decarbonization, the industry experts agreed that it’s a complicated journey and requires time and collaboration.

Concluded Jermark: “I don’t think there’s a one-size-fits-all answer [to that] which is why the situation is so complicated.”

Listen to this episode of the Energy Transitions Podcast with Javier Cavada, President and CEO of Mitsubishi Power EMEA, for insights into achieving speed and scale in decarbonizing generation.

2023’s Release of New Regulations was the first Mega Session held at POWERGEN. Regulations highlighted in the 90-minute panel included New Source Performance Standards, the Good Neighbor Rule, Effluent Limitation Guidelines, Coal Combustion Residuals and others.

But a majority of the time was spent talking about proposed carbon emission standards for coal-fired plants and new and existing natural gas-fired plants. The technology-based standards, proposed by EPA in May 2023, lean on hydrogen co-firing and carbon capture and sequestration (CCUS) as strategies for decarbonizing these plants.

Nick Hutson, Energy Strategies Group Lead at EPA and one of the Mega Session panelists, said the agency has heard from various groups and stakeholders during the comment period leading up to the final rule being issued.

The comment period ended December 20, with a finalized rule expected in the Spring.

As we’ve reported, the power industry is fractured over EPA’s proposal. Some utility trade groups say the proposal should not be finalized, while others say improvements are needed. Still other utilities have thrown their support behind it. Opposition to the rule often comes with concerns that its implementation would jeopardize reliability.

While emissions reduction is EPA’s primary objective, Hutson said the agency always wants to “make sure that we’re not adding to the problem unnecessarily.”

“We always do modeling to evaluate what is the projected outcome of our policies,” he said.

As the rule is currently proposed, any coal-fired power plant intending to operate past 2040 would have to install a CCS system that captures 90% of its CO2 emissions by 2030. Any large, frequently operating natural gas-fired power plant would have to either install a 90% capture CCS system by 2035 or operate nearly entirely on clean hydrogen by 2038.

Generators that can’t meet the new standards would be forced to retire.

Jordan Flanagan spoke on the panel representing the Institute of Clean Air Companies (ICAC), a trade association representing technology, equipment and service providers in the power sector.

She said the proposed EPA rules offer both opportunities and challenges for ICAC members.

“Our members have a lot of proven technologies that are available right now to deploy commercially,” said Flanagan, Policy and Programs Associate for ICAC. “But they’re also seeing lots of opportunities and challenges for some of the newer concepts posed by the greenhouse gas power plant rule. There’s a lot of uncertainty around it.”

David Triplett, Sr. Mgr. Environmental Policy & Sustainability at Entergy, offered a utility’s perspective on the proposed rules.

He said while the rules are only proposed and are subject to change before being finalized, they are “important additional inputs” that utilities need to factor into their generation planning processes.

“Our sector really is at an inflection point in terms of change with how we’re meeting resource adequacy requirements,” said Triplett.

Entergy is already taking an “all of the above” approach to resource planning, with a goal of 50% carbon reductions from its fleet by 2030 and to be completely net-zero by 2050.

Triplett said Entergy has signed memorandums of understanding with “a number of partners” to include all potential technologies.

“We’re investigating every possible path to find the one that’s going to be most cost effective and effective feasible for our fleet to get to [net-zero],” he said.

Triplett was asked about what he expects to be the most significant challenges in complying with the proposed power plant emission rules.

“With the with the hydrogen and CCS aspects, there’s significant infrastructure that needs to be built out to support those technologies at our generating facilities that doesn’t exist today or exist in a limited extent,” he said.

Triplett added the caveat that if it does happen, “it will happen here first,” speaking on the existing pipelines in the Gulf Coast region.

Regarding other potential compliance considerations, Triplett noted the importance of timing. With multiple proposed power sector regulations expected to be finalized in 2024, he said thoughtful alignment of compliance requirements is critical to ensuring effective utility resource planning, integration of new generation and continued reliable operation of existing generation resources.

For example, Entergy plans to exit coal by 2030, yet coal compliance dates from the EPA come both before and after Entergy’s anticipated coal retirements.

“Our hope is as EPA takes action to finalize these rules, these various dates will become into closer alignment,” said Triplett. “From our perspective, we don’t want to have to dedicate additional capital to units that are going to deactivate in the near to medium term that could otherwise be deployed more productively for new generation.”

Microreactors, referred to by some as ‘nuclear batteries,’ are squarely in the spotlight at this year’s POWERGEN International.

Discussions explored the latest technologies, popular applications and the unique business models making them viable.

Four microreactors stood out as trailblazers in the sector:

1 – eVinci Microreactor from Westinghouse Electric Company

It’s a heat pipe reactor that can produce 5MWe with a 13MWth core design. The reactor core is designed to run for eight or more full-power years before refueling.

The reactor is fully factory-assembled and transportable in shipping containers via rail, barge, and truck. Customers will likely be industrial actors and remote communities, with applications ranging from industrial heat and power, military, microgrids, cogeneration and hydrogen production.

The first eVinci microreactor is scheduled to be up and running by 2029.

2 & 3- ZEUS and ODIN from NANO Nuclear Energy

NANO Nuclear Energy is developing ZEUS, a solid core battery reactor, and ODIN, a low-pressure coolant reactor.

The ZEUS microreactor prototype is designed to harness thermal energy for direct heat applications or to convert it into electric power. This allows for diverse applications, ranging from heating to electricity generation.

The ODIN reactor will operate at higher than conventional water-cooled reactor temperatures, which will boost resilience and conversion efficiency in generating electricity.

According to NANO, the ODIN design aims to take advantage of the natural convection of coolant for heat transfer to the power conversion cycle at full power and for decay heat removal during reactor shutdown, operational transients, and off-normal conditions.

Both microreactors use High-Assay, Low-Enriched Uranium (HALEU) fuel, are modular, and are easily transportable.

4 – Micro Modular Reactor (MMR) Energy System from Ultra Safe Nuclear

MMR is a 4th Generation nuclear energy system that is being licensed in Canada and the U.S. and is touted as the first ‘fission battery’ in commercialization.

Ultra Safe Nuclear has established an order book for first users, with demonstration units scheduled for first nuclear power in 2026.

The reactors are being developed for government applications, as well as for use in space and are designed to offer energy security and decarbonization for hard-to-abate sectors, and remote communities.

The reactor is modular and scalable and operates on ceramic-based TRISO fuel.

Big hurdles for micro technology

James Walker, CEO of NANO Nuclear Energy, stated that “nuclear is getting smaller…you could produce potentially thousands of these per year.”

And while this is indeed the case, there are some significant hurdles to overcome before production can increase, said Walker.

These hurdles include:

• Cost – Microreactors mainly compete with diesel generators, a much more cost-effective option. To become more competitive, many more of these solutions need to be sold to create economies of scale and this will take time. To be viable, the industry is targeting 12-14c per KWh.
• New business models are needed: NANO Nuclear is leasing the energy produced to remove capital cost from the customer, and other commercial models are being explored whereby communities can act as developers or part equity owners.
• Skilled workforce required: The question of who will man these reactors on site must be answered, especially as some customers opt to not operate the system themselves.
• A well-functioning, domestic supply chain and secure fuel sources are critical to the success of the industry.

Microreactors have a way to go before they can take their place in the energy mix. However, what is clear is that they aren’t here to compete with big build nuclear. Their value lies in their niche applications, which is where they can make the biggest impact.

Why? “What got us to where we are is not going to get us where we need to be,” said Brian Roth, vice president O&M with PROENERGY. The company is a third-party solutions provider for the energy industry.

How does this connect to remote power plant operations? Divergent thinking, which is a process used to create ideas by exploring many possible solutions, is needed to help address challenges the industry is facing now and will be facing in the future. And yet convergent thinking, which focuses on reaching a single well-defined solution to a problem, often causes us to shut down potential solutions. Roth encouraged a focus on separating convergent thinking from divergent thinking within organizations. Thinking about a challenge without taking into account constraints encourages divergent thinking.

With this encouragement setting the stage, Roth discussed the difference between remote dispatch, which is a subset of remote operations that focuses on start/stop energy monitoring, remote operations (physically controlling a unit) and remote monitoring (and diagnostics) or RM&D. The latter involves looking at data trending, setting more narrow bands to get alarms earlier than the control system and enabling plant personnel to take action.

He was frank when sharing the value of remote operations centers (ROC), including pros and cons. The pros list is substantive: better coordination and resource allocation, safety enhancements, and improved reliability and sustainability. But the cons must also be acknowledged, with Roth highlighting two in particular: technology differences make it more challenging, and the importance of communication without the ability to meet face-to-face can’t be overlooked. In addition, it is easy to overload ROC operators with information.

Roth pointed out that tools don’t solve problems. With RM&D, the aspiration is to detect small anomalies and then do something with that information before there’s a problem. RM&D can empower a utility to reach peak efficiency using predictive technology. RM&D systems can deliver prescriptive alerts to operator, which Roth called alarms with recommendations.

Now, coming back to the concept of divergent thinking: Early in the session, Roth asked attendees: “Can a single operator run 100 units?” The knee-jerk answer to that question might be no, and in that case you would be thinking convergently, not divergently. Putting aside current technology and personnel constraints, your answer should change. Roth said at this time, the company has an ROC where a single operator runs 32 units, so taking today’s constraints out of the equation could perhaps see the aspirational goal of 100 units reached.

Two states — California and Texas — account for the vast majority of installed battery storage capacity in the U.S., which has grown from 1.6 GW in 2020 to more than 14 GW by the end of 2023. The trajectory is only expected to continue.

“There was nothing. Now, we’re chasing our…” said Sai Moorty, principal of market design and development at ERCOT, the Texas grid operator.

Moorty joined a panel of regional grid operators at POWERGEN International 2024 in New Orleans alongside CAISO market design sector manager Danny Johnson and Michael DeSosio, a consultant who previously served as the director of market design at NYISO.

Battery storage growth in ERCOT can be largely attributed to a streamlined permitting and interconnection process, as opposed to procurement mandates in states like California and New York.

And while batteries have captured much of ERCOT’s ancillary services market, sustained growth could be predicated on market adjustments, Moorty said. Price volatility in energy-only ERCOT creates uncertainty for developers, while the surge in predominately 1-hour batteries creates operational challenges for the grid operator.

Moorty said a capacity construct, which is under consideration, may be the key to incentivizing longer-duration battery storage development.

“We have good scarcity pricing, our price gaps are really high, but do they last long enough to justify the additional capital investment?” Moorty said. “Lacking (capacity payments), we’re going to have to wait.”

Other potential pitfalls concern state of charge requirements, which determine the amount of power that must be stored in a battery at a given time.

Moorty acknowledges that a state of charge rule issued by ERCOT last year may be viewed by some battery storage developers as discriminatory to the technology. He said the rule is the product of rapid growth and an imperative to adapt to an evolving grid.

“We just don’t have experience with batteries,” Moorty added. “In ERCOT, we’re playing catch up right now.”

California, the U.S. leader in battery storage deployment with 7.3 GW of nameplate installed capacity, is the country’s most formidable market, thanks to capacity payments, broad participation opportunities, and a sizeable procurement mandate.

There are still “significant” challenges facing grid operators, according to Johnson of CAISO. State of charge management tops the list, he said.

“It’s finding the right balance of flexibility for asset owners to utilize and bid-in their assets as they see fit, while also ensuring that, as a grid operator, those assets will be able to perform as dispatched and we can maintain reliability,” Johnson added.

Another, forward capacity planning for battery storage, still eludes grid operators.

The traditional process of adding up total capacity to meet peak load in the coldest or hottest times of the year doesn’t easily incorporate an asset like battery storage, which has to charge in order to serve the grid.

“The traditional stack analysis goes out the window with storage,” Johnson said. “You have to make sure that they have the ability to discharge the energy. When are you charging? How does that get factored into capacity planning?”

New York State’s 194 MW of installed battery capacity pales in comparison to the totals boasted by California and Texas. But near-term capacity constraints, paired with a 3,000 MW energy storage target, present attractive opportunities for developers.

DeSocio, who now leads the consultancy Luminary Energy, said an indexed energy storage credit construct under consideration in New York is a good start. The program would marry capacity payments with energy arbitrage, which at present isn’t economically attractive enough to incentivize storage deployment in the state.

DeSocio advised developers to avoid New York’s retail market, which treats batteries as native load, triggering demand charges.

“There is a whole lot of pressure to get new resources built,” DeSocio said. “The opportunity for storage is two-fold: maximize wholesale revenues (capacity and ancillary services) and offtakers.”

As carbon emissions and temperatures continue to rise, there is increasing pressure on the power generation sector to decarbonize at pace. Of all the challenges facing the sector to bring about green transformation, it seems cost is causing the biggest headache.

This sentiment was expressed by Kevin Lauzze, Vice President and Project Director at Sargent & Lundy, who spoke at POWERGEN International in New Orleans. When asked what keeps him up at night, his answer was unequivocal, “cost”.

“It’s easy for people to want this until they know their power bill will go up,” he said, adding that results of up-front studies result in shock because of the high costs.

But the cost of doing nothing is more, he agrees, so it’s better to pay more now than to pay a higher price later, referring to the cost of the impact of climate change.

Said Lauzze, “It’s not just [about] do it all and spend infinite amounts of money or spend nothing,” but rather, he suggests, it’s about finding the balance, something in the middle that will offer the best return.

Varied decarbonization pathways – it comes down to the bottom line

Lauzze went into detail about what he referred to as an ‘all of the above approach’.

As electricity demand continues to increase due to market growth and electrification, he recommends a varied energy mix, including hydrogen, renewables and nuclear, together with carbon capture.

However, despite the opportunities offered by each of these pathways to decarbonization, the common theme is clearly how to mitigate the high cost associated with maximizing these opportunities. 

Renewables, for example, is clearly here to stay and when coupled with energy storage, holds great promise for our decarbonization journey, said Lauzze.

However, without the required transmission and distribution infrastructure build out, a costly endeavour indeed, there is a soon-to-be-reached ceiling for renewable deployment.

Hydrogen, a useful zero carbon emission fuel and well-suited for use in peaking applications, is currently without the infrastructure needed for a well-functioning value chain. And not surprising, Lauzze points to the significant investment needed to make this a reality. 

Finally, one of key pathways to decarbonization and arguably one of the most costly, Lauzze, points to carbon capture.

“Fossil-based generation is not going away,” he said. “We will have dispatchable power, but you need to make the power less carbon intensive.”

Proponents say carbon capture is a proven technology that can be deployed now on existing and new fossil assets and industrial sources that are hard to abate. However, despite the production and investment tax credits, and the fact that the Department of Energy is actively funding project development, the biggest hinderance to deployment of carbon capture tech is cost, he said.

According to Lauzze, carbon capture requires double the space and double the investment of a combined-cycle facility.

Despite these concerns, the sentiment overall is optimistic, with Lauzze suggesting we will meet our 2050 decarbonization goals.

However, it seems the next few decades will be filled with some sleepless nights, as the sector works to mitigate the high cost of going green.

In the wake of Hurricane Ida, the newly-minted chief executive of Entergy New Orleans, surveyed the damage. But it was the quiet that struck her most.

Less than 90 days in the role, Rodriguez encountered a fatality, tornado, hurricane, and a public relations storm that swirled around the company’s new peaker power plant.

Rodriguez clearly realized that her charge of leading the utility into a more resilient and cleaner future would not come without costs.

“It’s expensive and requires a lot of communication,” Rodriguez said during the keynote address at POWERGEN International 2024 in New Orleans.

Rodriguez’s role requires her to think about the future. An order from the New Orleans City Council to submit a resiliency plan in response to Hurricane Ida further solidified the imperative.

Seeing into the future, though, can be daunting. Especially without a roadmap.

Brian David Johnson, an applied futurist and professor who headlined the POWERGEN keynote, pushed attendees to embrace the power of “dumb ideas” when planning for the future.

An idea is only “dumb” until someone realizes its genius, he said. The exercise also triggers imaginative collaboration that will be critical as the power industry evolves in the coming decades.

Johnson himself went through the process as an internal futurist at IBM, tasked with predicting consumer behaviors for chip investments that take 10-15 years to materialize.

“You’ll see your team, and yourself, do some crazy stuff,” Johnson said. “You have really important things to solve, and this is a way to actually go through and begin to solve them, and come up with some of those things that people have never thought of before.”

Large corporations, like Microsoft, are dependent on the power industry to evolve and embrace The Next Big Thing, in large part due to ambitious climate and clean energy goals.

Todd Noe, Microsoft’s director of nuclear technologies engineering, told the POWERGEN International keynote audience that nuclear energy stands to play a pivotal role in the company’s carbon-negative efforts. He added that small modular reactors (SMR), hydrogen, and long-duration energy storage technologies could also prove crucial.

“Our vision is we seek to have a decarbonized grid, not just for Microsoft, but our customers around the world,” Noe said. “We don’t see any one carbon-free technology that’s going to be the answer.”

A piece of that puzzle, particularly in the future, is carbon capture and storage.

Brad Crabtree, assistant secretary for the Department of Energy’s Office of Fossil Energy and Carbon Management, said scaling carbon capture retrofits for aging coal fleets will be “critical” to meeting international climate obligations.

“Demonstrating U.S. leadership here at home, scaling up the technology, reducing costs, and building industry confidence can have a global impact,” Crabtree said.