In their Q3 2024 results, the company announced an improved cash outlook, citing increasing demand for their grid and gas turbine businesses. Gas Services’ orders more than doubled year-over-year.

Specifically, Siemens Energy reports a new record for their order backlog at €120 billion ($131 billion) and revenue growth of 18.5%, with substantial growth in Grid Technologies, Transformation of Industry and Siemens Gamesa.

Commenting in a release, Siemens Energy’s president and CEO Christian Bruch attributed the positive backlog to increases in global energy consumption, which has resulted in demand and growth for their businesses.

Last year, the German government assisted with a counter-guarantee to support the company after their net loss of €4.5 billion ($5 billion) for the 2023 fiscal year, primarily due to the company’s ailing wind division, Siemens Gamesa.

For Q3 this year, the company reported a net loss of €102 million ($111.3 million).

Said Bruch: “The rapidly growing electricity market requires a wide range of our products. Especially our grid and gas turbine businesses are benefiting from this momentum.

“Importantly, with growing our order backlog, we have been able to improve its margin quality as well. Despite all the challenges, we are optimistic about the future and after the first nine months, we are well on track to meet our full-year guidance.”

Looking ahead, the company expects to achieve comparable revenue growth of 10 to 12% and free cash flow pre tax in a range of €1 billion ($1.1 billion) to €1.5 billion ($1.6 billion) for the fiscal year.

Said Bruch during a press conference call: “…quarter by quarter, we’re making headway. It’s not exciting, but it’s what we want to achieve.

“We expect that the global demand for power will continue to grow in addition to population growth and more electrification.”

Additionally, stated Bruch, new markets are opening up with the potential for growth: “New additional markets contribute to this. One topic, which is currently discussed everywhere is the power need for data centers – they make up a considerable part of our inquiries.

“And for the future, this means potential growth.”

Originally published by Power Engineering International.

Atura Power, a subsidiary of Ontario Power Generation, is expanding the power generation capacity at its 900 MW Napanee Generating Station in the Town of Greater Napanee, Ontario. The planned expansion has a targeted completion by 2028.

Atura Power will add an M501JAC combustion turbine from Mitsubishi Power Americas, that will operate in simple cycle and provide up to 430 MW of additional electricity. Mitsubishi Power Americas said its M501JAC is known for its operational flexibility and startup times, and can also operate as a peaker. The turbine will join two M501GAC units already operating in combined cycle at the site. This will be the fifth Mitsubishi Power M501JAC turbine in Canada.

In 2019, Ontario Power Generation acquired the Napanee Generating Station and two other gas-fired plants in a $2.8 billion deal with TC Energy (formerly known as TransCanada). The facilities included the 683 MW Halton Hills power plant, the 900 MW Napanee generating station which was nearing completion at the time, and TC Energy’s 50% interest in the 550 MW Portlands Energy Center.

The deal was subject to a number of closing conditions which included regulatory approvals and Napanee reaching commercial operations as outlined in the agreement.

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.

While electric utilities and developers use terms like “hydrogen-ready” or “hydrogen-capable” in their project plans, IEEFA said this is little more than marketing designed to obscure the challenges of hydrogen co-firing in gas turbines.

The biggest obstacles to hydrogen co-firing in gas turbines include building new infrastructure and ramping up supply, according to the Institute in Hydrogen: Not a solution for gas-fired turbines.

U.S. utilities and developers have announced myriad of “hydrogen-ready” projects over the last several years, ranging from technology demonstrations to large-scale commercial developments. But IEEFA said for at least the next 10 years, any “hydrogen-capable” gas-fired power plants are going to operate almost completely, if not entirely, using natural gas.

The institute said state regulators and potential project investors should scrutinize assertions that hydrogen gas will be widely used in natural gas-fired turbines.

Lack of supply

IEEFA noted the U.S. produces about 10 million tons of hydrogen every year, nearly all of which is consumed in the petrochemical and fertilizer sectors. Any hydrogen co-firing in the power sector would require a lot of new production, the institute said. Just running the 15 largest natural gas combined-cycle (NGCC) plants with hydrogen would require doubling current U.S. production and would replace less than 10% of the electricity now generated annually from natural gas, IEEFA said.

The report cited a 2022 demonstration where Long Ridge Energy tested a 5% hydrogen blend at its newly commercialized 485 MW combined-cycle plant in Ohio. While the demonstration was a success, the company told the U.S. Energy Information Administration (EIA) it burned 325,000 cubic feet of hydrogen during the tests, producing 17 megawatt-hours (MWh) of power.

IEEFA said the example underscores the enormous amount of hydrogen needed for even a small level of blending and the challenges of scaling even larger. According to EIA, the company has not used any hydrogen in the Long Ridge turbine since the 2022 demonstration.

Lack of pipeline infrastructure

The institute noted that no pipeline network exists to distribute the fuel to hydrogen-capable gas turbines being proposed in the U.S. IEEFA also said building such a network would take years and cost billions of dollars, and the time and effort required for this buildout would slow the transition from fossil fuels.

While the U.S. has a sprawling natural gas pipeline network, with approximately 305,000 miles of inter- and intrastate transmission lines, there are only roughly 1,600 miles of hydrogen-dedicated pipelines in the U.S. Virtually all the existing infrastructure is concentrated in Texas and Louisiana, where there is petrochemical and other industry activity.

Blending hydrogen into existing pipelines has been proposed as a possible alternative, but IEEFA said the latest research has raised more questions than answers about the technical and safety implications of introducing hydrogen into the system. In short, blending hydrogen into pipelines would weaken the steel, IEEFA said, potentially leading to cracks, leaks and complete failure.

Read the full report here.

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.

Following successful permitting, the company plans to build a two-unit, 1,200 MW combined cycle plant in Monroe County. The facility would be on land already owned by Oglethorpe Power and adjacent to the Smarr Energy Facility, another gas-fired plant. Oglethorpe claimed the new addition would be the “highest-performing, lowest-emitting and most efficient natural gas plants in the state.” Total capital investment would be approximately $2 billion, the company reported.

In Talbot County, Oglethorpe would also build a simple-cycle combustion turbine unit at an existing plant. This new approximately 240 MW peaking unit, which would be the seventh at the Talbot Energy Facility, would have dual-fuel capability. The development of this new unit would represent a capital investment of approximately $360 million.

More details on the projects’ construction and timelines would be available after permits are received, Oglethorpe said.

Oglethorpe Power continues activity in Georgia, where it recently acquired Walton County Power, a 465 MW, three-unit combustion turbine generation facility in the city of Monroe. The facility was purchased from Mackinaw Power Holdings, an affiliate of the global investment firm, The Carlyle Group. Financial terms of the transaction were not disclosed.

U.S. natural gas-fired power generation is expected to grow faster than it has in years. Recent Integrated Resource Plans (IRPs) indicate that utilities are planning for the largest increase in gas plants in over a decade, with the years 2028 and 2030 expecting dramatic increases in renewable energy usage to balance and maintain grid reliability.

The Phoenix (Performance Hydrogen Engine for Industrial and X) project, which is funded with almost €5 million ($5.4 million) by the German government, is aimed to generate the same electrical and thermal energy as currently available through natural gas CHP units in the higher power range of up to 2.5 MW.

When fueled by green hydrogen, this next-generation stationary energy plant, expected to be a first of its kind, should be able to run in a completely carbon-neutral manner.

“We are convinced that combustion engines will remain an essential part of the provision of a reliable energy supply during the energy transition,” said Dr Jörg Stratmann, CEO of Rolls-Royce Power Systems.

“We are making them climate-friendly with sustainable fuels. That’s why we at Rolls-Royce are investing in the development of next-generation hydrogen engines.”

The Phoenix project is being undertaken by a consortium including the sustainable mobile propulsion systems group at the Technical University of Munich, MAHLE Konzern, Fuchs Lubricants Germany GmbH, the German Federal Institute for Materials Research and Testing (BAM) and Robert Bosch AG.

The joint project is scheduled to run for three years to develop a technology concept that is sufficiently mature for use in a complete prototype engine.

Rolls-Royce already has developed a gas-powered combustion mtu engine which can use hydrogen as a fuel, but the Phoenix project will develop the technology for an even more efficient next generation hydrogen engine.

New developments from the partners include the injection system, the piston group and the ignition system, as well as a completely new lubricant.

Rolls-Royce reports that the German government as part of its power plant strategy, which includes the expansion of renewable energies, has decided in favor of building more gas-fired power plants to compensate for the variability of renewable resources – in particular, smaller, decentralized gas engine plants that can flexibly compensate for the fluctuating feed-in of wind and solar power to the grid, which varies depending upon weather conditions.

To reduce CO2 emissions, biogas gensets and, in some cases, the first gas engines converted for hydrogen are currently being used. But as soon as the availability of green hydrogen is ensured on a large scale, the technology of the hydrogen cogeneration plants promoted in the Phoenix project should be ready for use.

Originally published by Power Engineering International.

WASHINGTON (AP) — The Supreme Court is putting the Environmental Protection Agency’s air pollution-fighting “good neighbor” plan on hold while legal challenges continue, the conservative-led court’s latest blow to federal regulations.

The justices in a 5-4 vote on Thursday rejected arguments by the Biden administration and Democratic-controlled states that the plan was cutting air pollution and saving lives in 11 states where it was being enforced and that the high court’s intervention was unwarranted.

The rule is intended to restrict smokestack emissions from power plants and other industrial sources that burden downwind areas with smog-causing pollution. It will remain on hold while the federal appeals court in Washington considers a challenge to the plan from industry and Republican-led states.

The Supreme Court, with a 6-3 conservative majority, has increasingly reined in the powers of federal agencies, including the EPA, in recent years. The justices have restricted the EPA’s authority to fight air and water pollution — including a landmark 2022 ruling that limited the EPA’s authority to regulate carbon dioxide emissions from power plants that contribute to global warming. The court also shot down a vaccine mandate and blocked President Joe Biden’s student loan forgiveness program.

The court is currently weighing whether to overturn its 40-year-old Chevron decision, which has been the basis for upholding a wide range of regulations on public health, workplace safety and consumer protections.

Three energy-producing states — Ohio, Indiana and West Virginia — have challenged the air pollution rule, along with the steel industry and other groups, calling it costly and ineffective. They had asked the high court to put it on hold while their challenge makes it way through the courts.

The challengers pointed to decisions in courts around the country that have paused the rule in a dozen states, arguing that those decisions have undermined the EPA’s aim of providing a national solution to the problem of ozone pollution because the agency relied on the assumption that all 23 states targeted by the rule would participate.

The issue came to the court on an emergency basis, which almost always results in an order from the court without arguments before the justices.

But not this time. The court heard arguments in late February, when a majority of the court seemed skeptical of arguments from the administration and New York, representing Democratic states, that the “good neighbor” rule was important to protect downwind states that receive unwanted air pollution from other states.

The EPA has said power plant emissions dropped by 18% last year in the 10 states where it has been allowed to enforce its rule, which was finalized a year ago. Those states are Illinois, Indiana, Maryland, Michigan, New Jersey, New York, Ohio, Pennsylvania, Virginia and Wisconsin. In California, limits on emissions from industrial sources other than power plants are supposed to take effect in 2026.

The rule is on hold in another dozen states because of separate legal challenges. Those states are Alabama, Arkansas, Kentucky, Louisiana, Minnesota, Mississippi, Missouri, Nevada, Oklahoma, Texas, Utah and West Virginia.

States that contribute to ground-level ozone, or smog, are required to submit plans ensuring that coal-fired power plants and other industrial sites don’t add significantly to air pollution in other states. In cases in which a state has not submitted a “good neighbor” plan — or in which the EPA disapproves a state plan — the federal plan was supposed to ensure that downwind states are protected.

Ground-level ozone, which forms when industrial pollutants chemically react in the presence of sunlight, can cause respiratory problems, including asthma and chronic bronchitis. People with compromised immune systems, the elderly and children playing outdoors are particularly vulnerable.

Natural gas is yet again making headlines for its role in providing reliable power to maintain grid stability.

Amid federal and state mandates driving the sector toward cleaner and more efficient solutions, natural gas has emerged once again as a crucial player in the transition to a more sustainable energy landscape. Recent Integrated Resource Plans (IRPs) indicate that utilities are planning for the largest increase in gas plants in over a decade, with the years 2028 and 2030 expecting dramatic increases in renewable energy usage to balance and maintain grid reliability.

Regulatory drivers aside, the need for energy-dense, dispatchable electricity is fueled by the continuous retirement of coal facilities, the burgeoning of data centers, the rapid development of AI technologies and the onshoring of manufacturing trends. By 2028, the growth of data centers, supercharged by the development of AI, could consume 7.5% of all electricity in the U.S. This calls for an urgent need for the U.S. to enhance its infrastructure to accommodate this significant load growth in addition to what’s currently planned. These factors highlight the challenge that renewable energy sources alone face in supplying the necessary power capacity to meet escalating energy demands. 

The demand for new gas generation builds is back 

Given the prevailing demand, the lifecycle of gas projects is now being significantly prolonged. Essentially, if you haven’t started proactive project planning yet, you may be already running behind.

A reoccurring conversation we’ve been having with customers is about the need to build new gas generation in addition to renewables. With simple-cycle and combined-cycle gas turbines in such high demand, buyers of F-Class, advanced-class and aeroderivative gas turbines are experiencing lead times not seen since the gas boom of the early 2000s.

Historically, the steps for developing a new gas generation project included front-end studies, siting and permitting and interconnecting to the grid before buying the equipment needed for the project. In the current market, securing long-lead equipment and entering the interconnection queue has become the main priority. 

Yes, the gas boom is back. Its resurgence in the market highlights its indispensable role in today’s energy transition. Natural gas facilities can provide the critical path forward to support and solve the challenge of increasing load growth. Nearly half of the coal-generating capacity seen in 2011 is expected to be retired by the end of 2026 as the U.S. continues its sustainable efforts. 

Signs of a booming market for simple-cycle, combined-cycle and recips are prominent across the United States. It may be too early to tell what it will bring and how long it will last, but keep an eye on signs such as lead times for major equipment, craft labor availability and changes in project development processes as indicators of the ongoing longevity of the gas boom. 

About the Author: Joey Mashek is the U.S. sales and strategy director for the Power Group at Burns & McDonnell. With nearly 20 years of experience, he discusses, develops and negotiates generation needs for utilities, independent power producers (IPPs), cooperatives, municipalities and end users across North America.

The proposed site for Castle Bluff previously hosted the coal-fired Meramec Energy Center, which Ameren closed in 2022. The utility owns the property and already has existing infrastructure and transmission line access, reducing the construction costs of the project, Ameren said. Pending regulatory approval, construction would begin in 2026, with the plant coming online the following year.

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

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