The 370 megawatt (MW) Great Plains Power Station is now online near Moose Jaw, Saskatchewan. The plant is powered by Siemens Energy’s SGT6-5000F6.3 gas turbine, SGEN6-1000A generator, SST700-900 steam turbine and SGEN6-100A steam turbine generator.

Construction on the plant began in March of 2021. At the peak of construction in July 2023, there were more than 600 workers on site each day. Now up and running, the plant is operated by 25 full-time employees on site.

Burns & McDonnell was SaskPower’s engineering, procurement, and construction (EPC) partner for the Great Plains project.

We reported back in May that SaskPower planned to invest in new generation as part of a $1.6 billion modernization plan during the 2024-25 fiscal year.

The $710 million in investments includes the construction of the Aspen Power Station Project and the Ermine and Yellowhead expansions.

The Aspen Power Project will be a 370 MW natural gas combined-cycle (NGCC) plant. The project is expected to come online by Spring 2028. Burns & McDonnell was also announced as the EPC.

SaskPower is adding a simple cycle natural gas turbine to the Ermine Power Station. This will be the facility’s third turbine and will produce an additional 46 MW of power. It is expected to be in-service in May 2025.

The utility is also adding 46 MW at the Yellowhead Power Station through the facility’s fourth turbine. The unit is expected to be in service in December 2025.

The $1.6 billion modernization plan also covers grid maintenance and upgrades, growth projects, smart meter deployments and more. The capital investment represents an increase of $433 million over 2023-24.

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

Originally published in Renewable Energy World.

The 1% increase in natural gas consumption in 2023 was driven by a 6.7% (2.2 Bcf/d) increase in consumption in the electric power sector, the largest natural gas consuming sector, EIA said. U.S. consumption of natural gas for power generation averaged 35.4 Bcf/d, or 40% of U.S. natural gas consumed in 2023.

On the other hand, natural gas consumption in the residential sector reached a five-year low at an average 12.4 Bcf/d in 2023, down by 8.9% (1.2 Bcf/d) from 2022, the largest year-over-year decline in the past five years. Natural gas consumption in the commercial sector decreased 4.8% (0.5 Bcf/d).

The summer of 2023 was the hottest recorded in the Northern Hemisphere, increasing consumption of natural gas in the electric power sector to meet demand for air conditioning, EIA said. Additionally, “warmer-than-normal” temperatures in January and February 2023 resulted in less demand for space heating in the residential and commercial sectors than in the past five years and reduced growth in total natural gas consumption in 2023 compared with 2022.

The natural gas consumption trends observed in 2023 largely continued in 2024 through September, EIA said. U.S. natural gas consumption through September 2024 averaged 89.8 Bcf/d, according to EIA’s monthly data, up 1% from the same period in 2023. The increase was driven by a 4% (1.6 Bcf/d) increase in consumption in the electric power sector, which averaged 38.1 Bcf/d, or 42% of U.S. natural gas consumed in 2024 through September.

Earlier this year, EIA predicted a 2% increase (35 BkWh) in natural gas generation in 2024. The increase was driven by low fuel costs and higher overall electricity demand, EIA said. A few new combined-cycle plants have come online in the past year, but the new capacity has been offset by other plants’ retirements, EIA added. Natural gas generation in 2024 is increasing the most in the Midwest (up 11 BkWh) and in the Mid-Atlantic (up 9 BkWh). The agency expects less natural gas generation in California this year (down 6 BkWh) and in the Southwest (down 2 BkWh), in response to large increases in solar generation.

On July 9, 2024, U.S. power plant operators generated 6.9 million MWh of electricity from natural gas on a daily basis in the lower 48 states, EIA said, which was “probably” the most in history, and definitely the most since at least January 1, 2019, when the EIA began to collect hourly data about natural gas generation.

The spike in natural gas-fired generation on July 9 was because of both high temperatures across most of the country and a steep drop in wind generation. According to the National Weather Service, most of the U.S. experienced temperatures well above average on July 9, 2024, with particularly high temperatures on the West Coast and East Coast.

The project is called Mission H2 Power, and will support the decarbonization of SSE’s Keadby 2 Power Station in North Lincolnshire, which is powered by Siemens Energy’s SGT5-9000HL gas turbine.

The multi-million-pound co-investment will see Siemens Energy develop a combustion system for its SGT5-9000HL gas turbine capable of operating on 100% hydrogen, while maintaining the flexibility to operate with natural gas and any blend of the two.

This will see additional facilities constructed at Siemens Energy’s Clean Energy Centre in Berlin to allow testing of the technology for large gas turbines to take place.

Finlay McCutcheon, managing director of SSE Thermal, commented in a statement: “We know hydrogen-fired power stations will be an essential element of the energy mix in a net zero world and Mission H2 Power will help us accelerate their deployment through engineering excellence.

“…Our projects will be pivotal in providing flexible backup to renewables and while we still need to see a rapid acceleration in policy and deployment, the need for this technology is beyond question – it is a matter of when not if and this partnership can help us reach that destination as soon as possible.”

Darren Davidson, vice president of Siemens Energy UK&I, added: “We are living in a transformative time for the energy sector. Our HL-class gas turbine has set records for efficiency and power performance. This new collaboration is a significant step in reaching the point where large gas turbines can run on 100% hydrogen.”

Investment in Mission H2 Power aligns with SSE’s commitment to transition away from the use of unabated fossil fuels in electricity generation and accelerate hydrogen projects.

SSE is also working on the Keadby Next Generation Power Station project in partnership with Equinor, to ensure the plant is capable of running on either hydrogen or natural gas, or a blend of the two. This allows for flexibility in the event of delays to the hydrogen infrastructure.

Delivering low-carbon power stations will be essential to providing a clean power system in the UK, with the plants fulfilling a vital role as flexible back-up in a renewables-led system. Analysis from National Energy System Operator shows that around 7GW of low-carbon flexible power will likely be needed on the system by 2035, with around half of that capacity provided by hydrogen-fired power stations.

Originally published in Power Engineering International.

GE Vernova did not disclose any of the customers it had signed reservations for, but Strazik noted they include data center developers. Big tech names are moving to secure generation for their power-hungry campuses, with some facilities eying launch dates as early as 2028, Bloomberg reports.

GE Vernova has generated $4 billion in cash since its split from its parent company GE nine months ago. All of the new orders will be built out of the company’s South Carolina factory. The company expects to see 20 GW of gas turbine orders each year until 2028, with at least half of those orders coming from the U.S..

“We are very well positioned to serve this market,” Strazik told CNBC’s Jim Cramer this week. “We see it every day in both our grid and our gas businesses – a substantial increase in demand.” Strazik also told Cramer the company is poised to upgrade existing nuclear plants “this decade,” while SMRs aren’t expected to become a reality until roughly 2032.

While business is booming on the gas side, GE Vernova also laid out some troubling indicators for the already-struggling U.S. offshore wind industry. “The reality is, the economics of this industry don’t make sense,” Strazik told Bloomberg. The company said it is no longer seeking new sales for its offshore turbines in the U.S., and hasn’t sold one in nearly three years.

Certainly not helping the situation was the incident at Vineyard Wind offshore wind farm, in which a GE Vernova blade broke off of the installation, causing fiberglass and other debris to wash ashore for weeks on Massachusetts beaches. GE Vernova’s offshore wind turbine manufacturing plant in Quebec, Canada fired or suspended several workers in November following a probe into the incident.

In September, GE Vernova said it planned to cut up to 900 offshore wind jobs globally in a move to reduce its offshore wind footprint. The move came not only amid uncertainty and supply chain constraints in the offshore market but also another incident involving a GE Vernova Haliade-X turbine blade – this time at the Dogger Bank Wind Farm off the northeast coast of England. However, in this case, GE Vernova said its analysis showed that the blade event was not caused by an installation or manufacturing issue but instead occurred during the commissioning process, when the turbine was left in a fixed and static position, rendering it vulnerable during a subsequent storm with high winds.

The oil and gas giant is building a massive natural gas-fired plant which is already in early development stages, the New York Times reported. The company said its carbon capture and storage (CCS) system could trap and store over 90% of the plant’s CO2 emissions.

This would be the first time Exxon is developing a power plant that wouldn’t electrify its own operations. The company has developed 5.5 GW of power projects since 2001 in states like Texas and Louisiana.

Exxon believes data centers could account for up to 20 percent of the total addressable market for CCS in 2050, company executives said in a corporate plan update on Wednesday.

This particular gas-fired plant would not be connected to the grid, avoiding grid connection challenges and meaning it could come online faster. Executives said the company has previously developed 800 MW of islanded power generation.

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

Earlier this week NET Power, with the help of several partners, said it plans to develop 1 GW of gas-fired power with its Allam-Fetvedt Cycle CO2 capture system.

Also this week, a new project in the UK was approved to proceed with its plans to create the world’s first gas-fired power station with CCS. NZT Power, a joint venture between bp and Equinor, could produce up to 742 MW of dispatchable low-carbon power. Start-up could be as soon as 2028.

According to a study published by EPRI in May, data centers could consume up to 9% of U.S. electricity generation by 2030 — more than double the amount currently used. Demand for computing power from data centers, fueled by artificial intelligence and other new technologies, requires enormous amounts of power.

Technip Energies, along with GE Vernova and construction partner Balfour Beatty – and with the support of technology partner Shell Catalysts & Technologies – received a notice to proceed by NZT Power Limited to execute a major contract for the Net Zero Teesside Power (NZT Power) project in the United Kingdom.

NZT Power, a joint venture between bp and Equinor, could produce up to 742 MW of dispatchable low-carbon power. Start-up is expected in 2028, supporting the UK Government’s Clean Power 2030 ambition. The project aims to be the world’s first gas-fired power station with carbon capture and storage. Up to 2 million tons of CO₂ per year could be captured at the plant and transported and permanently stored by the Northern Endurance Partnership, the companies said.

NZT Power has reached financial close and has issued a full notice to proceed to the Technip Energies-led consortium to start the full engineering procurement and construction (EPC) package for the onshore power, capture and compression contract. Financial close follows the UK government’s recent announcement of a £21.7 billion pledge for projects to capture and store carbon emissions from energy, industry and hydrogen production.

A “major” award for Technip Energies is a contract award representing above €1 billion of revenue. The award will be included in backlog in Q4 2024, the company said.

Technip Energies and GE Vernova, with the support of infrastructure group Balfour Beatty, plan to deliver a combined cycle plant and associated carbon capture system. Technip Energies will lead the integration of a carbon capture system using its Canopy by T.EN solution, powered by Shell’s CANSOLV CO₂ Capture System. The plant will be powered by GE Vernova’s 9HA.02 gas turbine, a steam turbine, a generator, a heat recovery steam generator, and an exhaust gas recirculation (EGR) system.

“We believe CCUS technology can be crucial to help decarbonize the planet, and we welcome the commitment from the UK government to invest in its implementation as well as NZT Power’s trust in our technology,” said Maví Zingoni, CEO, Power at GE Vernova. “Flagship projects like Net Zero Teesside Power can give the industry foundations to grow. We look forward to powering the station with our advanced H-Class combined cycle technology, as well as proceeding with the first commercial use of our Exhaust Gas Recirculation system and integration technologies, which aim to support carbon abatement by boosting the efficiency and performance of carbon capture.”

By Joey Mashek, U.S. Sales and Strategy Director, Energy Group, Burns & McDonnell

The evolving regulatory landscape has presented power generation utilities with a complex choice as they consider large-scale gas generation projects and whether to build simple-cycle or combined-cycle power plants. With the U.S. Environmental Protection Agency’s (EPA) updated New Source Performance Standards (NSPS) for greenhouse gas (GHG) emissions, decision-makers must carefully balance operational efficiency, financial feasibility and output needs, while maintaining regulatory compliance. While results of the recent election and new administration may lead to some uncertainty with NSPS, the rule is currently still in effect.

The EPA’s NSPS aim to reduce greenhouse gas emissions from new and modified gas turbine power plants. Originally set at 1,000 pounds of carbon dioxide (CO2) per megawatt-hour (MWh), the standard under 40 Code of Federal Regulations (CFR) 60 Subpart TTTTa is now 800 pounds per MWh, with a further reduction to 100 pounds per MWh beginning January 2032.

These new standards significantly influence the decision between simple-cycle and combined-cycle plants, as they dictate whether plants can operate as baseload units or must operate at a lower imposed capacity factor if the above limits cannot be met. Adding further complexity, the updated standard introduces the concept of intermediate load facilities, with a required limit of 1,170 pounds per MWh and a capacity factor limit of 40%.

Combined-Cycle plants: High-efficiency, higher cost

Combined-cycle gas plants have traditionally been preferred as a baseload technology due to their higher efficiency. These plants utilize both a gas turbine and a steam turbine, significantly improving fuel efficiency compared to simple-cycle setups. While they are more expensive up front, their main advantage is generating more electricity from the same amount of fuel (which also results in a lower CO2 per MWh emissions rate).

However, complying with the upcoming limit of 100 pounds per MWh will require future baseload facilities to incur significant additional costs to mitigate carbon emissions, most likely through CCUS technology. CCUS technology also requires a large amount of auxiliary power, which would offset some of the traditional efficiency advantage of combined-cycle plants. For example, a 1×1 J-class combined-cycle plant with CCUS might generate roughly 750 megawatts (MW) of capacity with duct-firing but the auxiliary power requirements associated with CCUS might reduce the effective output to about 600 MW. While employing CCUS would allow the plant to continue operating as an unrestricted baseload facility, the economic impact of deploying carbon capture must be considered.

Alternately, utilities could forego the investment in CCUS and opt to build combined-cycle plants as intermediate load facilities, which then would be limited to a 40% capacity factor under the current rules. This decision would sacrifice a significant portion of the facilities’ potential energy production each year.

Simple-Cycle plants: Flexibility at a lower cost with trade-offs

Simple-cycle gas plants offer different advantages and trade-offs. They are generally cheaper to build and operate, with a less complex design and lower initial investment. Simple cycle plants are often used for peaking power, making them an attractive option for utilities needing to respond quickly to fluctuating demand.

From an emissions perspective, modern J-Class combustion turbines can meet the 1,170 pounds per MWh limit on their own. Given their lower output and efficiency, utilities are unlikely to invest in CCUS technology behind simple-cycle engines, which would put them in the intermediate load category.

In the case of simple-cycle plants, decision-makers must evaluate the levelized cost of electricity over the life of the facility. Simple-cycle plants have lower up-front costs, but efficiency would still be less than that of combined-cycle plants (even with CCUS), leading to higher fuel expenses over time. Utilities need to weigh whether the reduced initial investment would offset potentially higher operational costs, especially with fluctuating fuel prices.

A situational decision: Balancing needs and constraints

The choice between simple-cycle and combined-cycle gas plants is situational, depending on several unique factors for each project. For utilities seeking higher efficiency and baseload power, combined-cycle plants with carbon capture may be ideal, despite higher up-front costs. Conversely, utilities prioritizing flexibility and lower initial costs may find simple-cycle plants more advantageous for covering peak demand. Capacity needs are critical to the decision, and under the current rules there are more options to consider than ever before.

As an example, if a utility needs approximately 600 megawatts (or 5,250 gigawatt-hours per year) of replacement generation, a combined-cycle setup could achieve this with fewer units and greater efficiency, while a simple-cycle approach would require multiple smaller units. The decision also depends on the utility’s anticipated emissions profile and willingness to invest in emissions-reducing technologies, like CCUS.

Additionally, utilities must consider other constraints, such as land availability, project timelines and financial resources, when making a decision. As lead times for acquiring equipment increase and regulatory pressures grow, it is essential to begin the decision-making process early and to thoroughly evaluate all variables.

Navigating complex choices

Unfortunately, there is not a clear choice between simple-cycle and combined-cycle gas plants under the updated NSPS. The decision depends on each utility’s specific needs, priorities and constraints. Combined-cycle plants offer higher efficiency and baseload capacity but come with significant costs, especially when incorporating carbon capture. Simple-cycle plants are more economical upfront but may struggle to meet future emissions standards.

Ultimately, utilities must balance efficiency, cost and compliance while staying attuned to regulatory changes. Engaging with peers, staying informed about technological advancements, and starting early are critical steps in successfully navigating these complex decisions.

Comparison chart: Simple-Cycle vs. Combined-Cycle gas plants

Originally published by Burns & McDonnell. See original article here.

Under the terms of the MOU, the parties plan to conduct feasibility studies on locating NET Power’s facilities in proximity to CTV’s underground storage vaults, which the companies say could reduce carbon dioxide (CO₂) transportation costs and midstream investments for CTV’s operations. The parties plan to facilitate the initial deployment of up to 1 gigawatt (GW) of power capacity from NET Power’s new modular plants in Northern California, which could result in up to 3.6 million metric tons per annum (MMTPA) of CO₂ emissions for permanent sequestration in CTV’s nearby reservoirs. Each of NET Power’s utility-scale modular plants is expected to require less than 20 acres, generate up to 250 MW, and be deployable in multi-plant configurations, the company said.

NET Power claims its plants will be designed to eliminate “substantially all” carbon emissions with near-zero air particulate and gaseous pollutants, including nitrogen oxides (NOx) and sulfur oxides (SOx).

This MOU marks NET Power’s initial entry into California’s power market and positions CTV as an early strategic partner in the deployment of NET Power’s power technology. Including this agreement, CTV’s carbon capture and sequestration (CCS) projects under consideration total approximately 7.8 MMTPA of CO₂ emissions and if successful, would enable up to 2.1 GWs of new, low-carbon power capacity in California.

The NET Power capture system utilizes the Allam-Fetvedt Cycle, combusting natural gas with oxygen, as opposed to air, and uses supercritical carbon dioxide as a working fluid to drive a turbine instead of steam. This theoretically eliminates all air emissions, including traditional pollutants and CO2 and inherently produces pipeline-quality CO2 that can be sequestered underground.

In 2021, NET Power claimed a global first when its test facility in Texas generating zero-emission electricity from natural gas delivered electricity onto a power grid. In November 2022 the company announced a plan to develop and build its first utility-scale natural gas-fired plant with carbon capture and sequestration (CCS). NET Power has a “backlog of utility-scale power plant projects,” with initial commercialization expected in 2026.

In June last year, NET Power announced the completion of its previously announced business combination with special purpose acquisition company Rice Acquisition Corp. II.