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.

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.

Mill Creek 5 was approved last year by the Kentucky Public Service Commission as part of the utilities’ generation investment plan, which also includes adding new solar and a 125-MW battery energy storage system. At the time, the utilities also received approval to retire Mill Creek Unit 1 by the end of this year and Unit 2 in 2027, as well as several gas peaking units.

“Once complete, Mill Creek 5 will be a hallmark within our generation fleet that’s already among the nation’s best,” said Lonnie Bellar, senior vice president of Engineering and Construction at PPL, parent company of LG&E and KU. “The unit features cutting-edge technologies that maximize its power generation capabilities to help us close the gap toward net-zero carbon emissions by 2050, while preserving reliability and affordability for our 1.3 million customers.”

Mill Creek 5 will be the second natural gas combined-cycle generating unit in LG&E and KU’s generation fleet. In 2015, the utilities began operating Cane Run 7, which was a first-of-its kind in Kentucky.

Major project partners involved in the engineering, manufacturing and commissioning of Mill Creek 5 include GE Vernova; Vogt Power International Inc., a Babcock Power Inc. subsidiary; and TIC–The Industrial Company, which also will provide on-site construction oversight. At the height of construction, LG&E and KU expect to have an additional 500 contract personnel working on site.

Earlier this year, GE Vernova said it secured an order for 7HA.03 combined-cycle plant equipment from LG&E and KU to power the new combined cycle plant at Mill Creek. Mill Creek 5 will feature GE’s 7HA.03 gas turbine, which GE Vernova said will have the ability to use up to 50% hydrogen (by volume) as H2 becomes more available in the future. GE will also provide a STF-D650 steam turbine along with a W86 generator, a Vogt Heat Recovery Steam Generator (HRSG) and its integrated Mark VIe control system for gas turbine performance management. The performance of the new 7HA.03 gas turbine includes a ramp rate of 75MW/min as validated at GE Vernova’s Test Stand 7 in Greenville, South Carolina.

Alongside the groundbreaking, the company also recognized the 50th anniversary of the Gerald Andrus Steam Electric Station, which will be retired when the new plant comes online in 2028.

The project includes more than 300 construction jobs in the area over the next several years and additional tax revenue for Washington County. Entergy will employ about 21 full-time personnel to operate the plant when it comes online.

The new facility will be equipped with a combined-cycle combustion turbine and dual-fuel technology. While natural gas is the primary resource, it will be designed to potentially support blended hydrogen in the future. Once complete, Entergy Mississippi said the Delta Blues Advanced Power Station will be the most efficient power-generating facility in its fleet.

“The groundbreaking of the Delta Blues Advanced Power Station is a significant step in our plan to transform our power generation portfolio for the future,” said Haley Fisackerly, Entergy Mississippi president and CEO. “We’re experiencing historic economic growth in our state. Investing in cleaner, more efficient power generation now will help us keep bills lower for customers than they otherwise would be in the future.”

Earlier this year, Entergy Mississippi announced it was building a new natural gas-fired plant for the first time in 50 years, which will be the first combined-cycle combustion turbine power station the company has built from the ground up.

Entergy Mississippi claims it is producing more electricity from the same amount of fuel while reducing carbon emissions by replacing older power plants with “more advanced and efficient” technology.

Over the past two decades, the utility has bought three natural gas power stations – Attala Plant in Sallis (2006), Hinds Energy Facility in Jackson (2012) and Choctaw Energy Facility in French Camp (2019). In addition to the current natural gas units, the Sunflower Solar Station near Ruleville (built in 2022) and the Grand Gulf Nuclear Station in Port Gibson (built in 1985) are generating electricity and contributing to the company’s power generation mix. Entergy Mississippi purchased the solar facility and owns a portion of the nuclear plant.

Due to an “unprecedented increase” in projected customer demand seen in its fall load growth forecast, Duke Energy provided state regulators with supplemental modeling on Jan. 31, 2024.

In July this year, prior to the NCUC’s evidentiary hearing on the plan, Duke Energy, the NCUC Public Staff, Walmart and the Carolinas Clean Energy Business Association reached a broad settlement on most topics at issue in the Carolinas long-range plan. The settlement committed Duke Energy to increasing the amount of solar energy and battery storage on its system through 2030, provided the opportunity to upgrade existing small solar facilities that are approaching the end of their contract terms with Duke, and committed Duke Energy to continued reform of its transmission planning process.

Duke Energy originally filed its proposed Carolinas Resource Plan with the North Carolina Utilities Commission (NCUC) On Aug. 17, 2023, two days after filing the same plan with the Public Service Commission of South Carolina (PSCSC). The Carolinas Resource Plan is Duke Energy’s proposed road map for its dual-state system serving North Carolina and South Carolina.

“We believe this is a constructive outcome that allows us to deploy increasingly clean energy resources at a pace that protects affordability and reliability for our customers,” Duke Energy said in a statement. “The order confirms the importance of a diverse, ‘all of the above’ approach that is essential for long-term resource planning and helps us meet the energy needs of our region’s growing economy. We look forward to thoroughly reviewing the NCUC order and incorporating it into our future resource planning.”

After gathering input from public hearings, evaluating Duke’s proposal, modeling, and settlement – along with modeling from Public Staff and targeted recommendations from intervenors – and conducting an extensive evidentiary hearing across two weeks, the NCUC issued its decision late last week. The order accepts the July settlement in its entirety.

Specifically, the order directs Duke Energy to pursue the following:

Near-Term Resources

• Solar: 3,460 megawatts (MW) of new solar generation, beyond the NCUC’s 2022 order – 6,700 MW total by 2031.
• Battery: 1,100 MW of battery energy storage, beyond the NCUC’s 2022 order – 2,700 MW total by 2031.
• Onshore Wind: 1,200 MW of onshore wind in operation by 2033, including at least 300 MW in operation by 2031.
• Combustion Turbines (CTs): Four CTs by 2030 – 900 MW of additional CTs (two units) beyond the 800 MW (two units) in the NCUC’s 2022 order.
• Combined Cycles (CCs): Three CC units by 2031 – 2,720 MW of additional CC capacity (CC2 and CC3) beyond the 1,200 MW (CC1) in the NCUC’s 2022 order.

Long-Term Resources

• Bad Creek II: Approved continued development work, including requested $165 million in early development costs.
• Nuclear: Approved continued development work, including requested $440 million in early development costs, targeting 300 MW of advanced nuclear capacity on line by 2034 and a total of 600 MW by 2035.
• Offshore Wind: Approved continued development work through the Acquisition Request for Information (ARFI) to advance the evaluation of offshore wind’s role in future resource plans, with results filed no later than July 30, 2025, and targeting between 800 and 1,100 MW of offshore wind by 2034 and 2,200 to 2,400 MW by 2035.

Modeling, Reserve Margin, Interim Carbon Reduction Target and Other Key Findings

• Confirmed Duke Energy’s recommended portfolio, P3 Fall Base, as the “reference portfolio.”
• Approved increase in the minimum planning reserve margin to 22% by 2031.
• Waived the requirement to model 70% carbon reduction by 2030, agreed that the evidence in the case supported the decision to extend the date for achieving 70% carbon reduction beyond 2032, and ordered Duke Energy to continue pursuing “all reasonable steps” to achieve 70% carbon reduction by the earliest possible date.
• Confirmed proposed coal retirement dates.
• Noted that “The Commission must be mindful of the impacts to customers when determining the appropriate action to take … to ensure that Duke, and North Carolina, continue this trajectory of rates that are at or below the national average,” highlighting the inflation-adjusted bill impact of the plan as a 0.9% increase by 2038.

The PSCSC continues to deliberate on the resource plan and will issue an order on or before Nov. 26, 2024. Following that order, Duke Energy said it will begin executing the plan while simultaneously developing the modeling required for its 2025 plan update in North Carolina, which must be filed by September 2025. As outlined in North Carolina law, the plan must be checked and adjusted every two years, incorporating technology advances, updated cost forecasts and applicable federal funding that could help customers save money over time.

In it’s 2024 filing to the NCUC, Duke said “new economic development wins, including manufacturing and technology projects across the Carolinas” make up the primary driver of the increased electric demand. The utility said annual demand expects to increase 22% by 2030 and 25% by 2035 from 2022 planning cycles — driven by significant additional economic development activity that took place during 2023. Notably, according to the Census Bureau, South Carolina’s population grew faster than any state’s in 2023.

Duke Energy put forth its original resource plan to regulators in August 2023. The company presented three portfolio scenarios but recommended one that achieves 70% CO2 emission reductions from 2005 levels by 2035. The “Portfolio P3 Fall Base,” introduced almost 6.8 GW of additional resources.

This acquisition secures long-term supply and capacity offtake for Shell in the deregulated Independent System Operator New England (ISO New England) power market, where SENA has held a contract with RISEC under an energy conversion agreement for 100% of the plant’s energy offtake since 2019.

“Shell has had a successful integrated gas and power business in the growing ISO New England market for over 20 years, and this acquisition secures valuable trading opportunities by guaranteeing SENA’s position in the market,” said Huibert Vigeveno, Shell Downstream, Renewables & Energy Solutions Director. “Our strong understanding of this plant’s performance positions Shell to capitalise on its value within our existing trading portfolio.”

RISEC’s combined-cycle gas turbine power plant supplies power to the ISO New England power market, where demand is expected to increase in coming decades due to growing decarbonisation efforts in sectors such as home heating and transportation.

The acquisition will be absorbed within Shell’s cash capital expenditure guidance, which remains unchanged. The transaction is subject to regulatory approvals and is expected to close in Q1 2025.

With RISEC signaling an intent to sell, Shell said this acquisition allows it to continue an energy supply agreement that has been in place since 2019 and secure long-term energy offtake from the plant, maintaining Shell’s position in the ISO New England power market. The acquisition preserves SENA’s current operations and mitigates market risk by ensuring a reliable and stable power generation source.

RISEC’s two-unit combined-cycle gas turbine power plant has a maximum capacity of 609 MW and an average operating capacity of 594 MW. Serving the ISO New England market, the plant is located outside Providence, Rhode Island, and has been in operation since its completion in 2002.

The parent company of RISEC is 51% owned by funds managed by global investment firm Carlyle. The remaining 49% owner of RISEC is EGCO RISEC II, LLC, a subsidiary of Electricity Generating Public Company Limited (EGCO), a Thai public limited company.

The U.S. Department of Energy’s (DOE) Office of Fossil Energy and Carbon Management released the official findings of the GE Vernova-led front-end engineering design (FEED) study, Retrofittable Advanced Combined-Cycle Integration for Flexible Decarbonized Generation.

The study evaluated retrofitting Southern Company subsidiary Alabama Power’s James M. Barry Electric Generating Plant, located in Bucks, Alabama, with technology capable of capturing up to 95% of the plant’s CO₂ emissions. GE Vernova said the study demonstrated that the integration of the company’s EGR system could lead to a reduction of more than 6% of the total cost of the carbon capture facility, as compared to installing carbon capture without the EGR system.

The study was completed in collaboration with Southern Company, Linde, BASF and Kiewit, and explored the benefits of close integration between a natural gas combined-cycle (NGCC) plant and a carbon capture system. GE Vernova’s measures and technologies explored in the study included the use of NGCC steam in the carbon capture system facility, potential gas turbine upgrades, installing NGCC and carbon capture control systems and employing GE Vernova’s EGR system, which reintroduces part of the exhaust gas back into the gas turbine inlet.

“GE Vernova is grateful for the Department of Energy’s support of this study, the first of its kind to explore EGR technology applied in a gas power carbon capture plant” said Jeremee Wetherby, GE Vernova Carbon Solutions Leader. “We developed a holistic approach considering various integration measures building on our long history and expertise in power plant engineering, operation, upgrades and controls. Carbon capture is a crucial pathway to lowering carbon emissions from power generation to near-zero levels, and we are pleased with the benefits projected by the study – which naturally can vary from site to site but represent a valuable indicator of the possibilities at similar sites.”

The study said the effects of adding a carbon capture system to an NGCC power plant could be reduced through a series of integration measures, including the EGR system. GE Vernova has developed EGR systems for two decades, initially for nitrogen oxide (NO_x) control and part-load efficiency benefits. In addition to this study, GE Vernova has demonstrated the commercial readiness of F- and H-class combustors operating with EGR at GE Vernova’s test facility in Greenville, South Carolina.

This study recognized the potential of an EGR system to deliver the following benefits as compared to a non-EGR system:

• Large reduction of carbon capture facility footprint and cost of absorber
• Lower operating costs due to reduced amine degradation
• Less energy-intensive separation due to higher concentration of CO₂ in flue gas directed to the carbon capture system
• More steam turbine power output because of lower steam consumption

“As a provider of CO₂ capture technology, we commend DOE’s leadership in advancing gas power decarbonization technology towards a clean and reliable energy future. The results of this FEED study underpin Linde’s belief that a collaborative approach between technology providers, end-users, and other stakeholders is essential in driving innovation and cost reduction in CO₂ capture. We are committed to working with DOE and other partners to help decarbonize industry,” said Dominic Cianchetti, Senior Vice President, Region Americas, Linde.

The combined-cycle facility began commercial operations in 2007, and its power is sold to the Electric Reliability Council of Texas (ERCOT).

Calpine has recently been making moves to develop or buy new power generation in multiple regions.

After seeing positive market signals in Texas, Calpine began redevelopment efforts in the Lonestar State last year. The company is reportedly on track to add over 1,000 MW of generation to its Texas fleet over the next few years.

Additionally, in response to skyrocketing energy prices within PJM Interconnection, Calpine plans to explore multiple new locations for generation capacity, particularly in Ohio and Pennsylvania. The company also said it would explore a potential expansion of its existing fleet. Over the last decade, Calpine has brought online 1,600 MW of new gas-fired generation within PJM territory. PJM is the largest grid operator in the U.S.

The company’s fleet is also involved in multiple carbon capture demonstrations.

Earlier this year, Calpine announced that it executed a cost share agreement with the U.S. Department of Energy (DOE) Office of Clean Energy Demonstrations (OCED) for a full-scale carbon capture demonstration project at its Baytown Energy Center near Houston.

The Baytown Decarbonization Project is designed to capture 95% of CO2 emissions from two of the three turbines at the company’s Baytown Energy Facility, enabling the facility to produce electricity as well as steam for collocated industrial use. Calpine began the first phase of the DOE cooperative agreement, with other phases to follow upon successful completion of phase one and finalization of plans for subsequent phases.

In addition to the company’s Baytown project, Calpine continues to advance its similarly sized Sutter Decarbonization Project in California, for which it also recently executed a cost share agreement with OCED. The Sutter Decarbonization Project would be designed to capture 95% of carbon emissions from Sutter Energy Center. Calpine now plans to begin the first phase of the DOE cooperative agreement, which will support the engineering and design of the project. Sutter Energy Center is located in Yuba City, California. The 550 MW combined-cycle plant became commercially operable in 2001.

OCED awarded PPL with the first tranche of funding – $4.9 million – to begin Phase 1 activities. The carbon capture project – developed in partnership with the University of Kentucky and others – represents a total investment of more than $100 million and will be hosted at the Cane Run generating station jointly owned and operated by PPL subsidiaries Kentucky Utilities and Louisville Gas and Electric Company.

“We are proud to take the lead in evaluating and piloting carbon capture technology on natural gas combined-cycle generation, and we’re grateful for the DOE’s support,” said PPL President and Chief Executive Officer Vincent Sorgi. “Ultimately, we believe reliable, dispatchable natural gas units will be essential in the years ahead to ensure there’s sufficient supply to meet electricity demand 24/7. Further, we believe natural gas can be a reliable partner in accelerating the transition to renewables while preserving reliability and affordability.”

The system planned for Cane Run is designed to capture a portion of the CO₂ from the natural gas plant’s flue gas using a heat-integrated CO₂ capture technology. PPL said the system is expected to capture more than 95% of the carbon emissions from up to 20 megawatts (MW) of the plant’s 691 MW generating capacity, or up to 67,000 metric tons of CO₂ per year.

PPL maintains that the demonstration project is an important step in assessing the future viability of utility-scale carbon capture technology on natural gas units. Current plans include the captured CO₂ being purified and reused in its entirety by a nearby industrial customer.

In addition to the University of Kentucky, collaborators on the project include the Electric Power Research Institute (EPRI); Kentucky State University; Visage Energy; and American Welding & Gas. Vogt Power International Inc., a Babcock Power Inc. subsidiary, and Siemens Energy, manufacturers of the Cane Run 7 Generating Station, are contributing technical support as part of the project team on integrating the new CO₂ capture system. Koch Modular Process Systems and others will support the design, fabrication and construction of the carbon capture unit.

PPL subsidiaries LG&E and KU have partnered with the University of Kentucky for nearly two decades on various carbon capture research projects and were founders of the university’s carbon capture research program in 2006. Together with EPRI, the company and university deployed a pilot-scale carbon capture facility in 2014 at the KU E.W. Brown coal-fired generating station.

“Significant” capacity expansions are driving the increase in solar generation, EIA said, with solar accounting for 59% of U.S. generating capacity additions in the first half of 2024. The increase in solar capacity was also supported by the development of new battery storage capacity, EIA said.

Perhaps not a surprise, Texas and California are expected to receive the largest gains in solar generation this year: 16 billion kilowatthours (BkWh) for the former, and 9 BkWh for the latter, per EIA.

The EIA credits part of the increase in generation to a hot start to the summer, which resulted in higher air conditioning demand. Next year, EIA predicts an additional 1% (60 BkWh) increase in generation, largely due to ongoing growth in electricity demand, primarily from the industrial sector.

Nationwide, EIA predicts a 37% increase in solar power (60 BkWh) this year, followed by a a 2% increase (35 BkWh) in natural gas, followed by smaller increases in wind (up 6%, or 27 BkWh) and nuclear (up 1%, or 11 BkWh).

Utility-scale solar generation is growing across all regions of the country, EIA said, and is expected to increase 34% nationwide this year through “rapid” installation of solar projects. Solar generating capacity grew in the first half of 2024 by 12 GW, which accounted for 59% of all capacity additions across all types of energy sources.

The increase in natural gas generation 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. Forecast natural gas generation in 2024 is increasing the most in the Midwest (up 11 BkWh) and in the Mid-Atlantic (up 9 BkWh). EIA 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.

Coal-fired generation is down in most regions as it’s displaced by natural gas, renewables, and plant closures, per EIA. Coal-to-natural gas switching is most evident in the Central/SPP region, where the EIA forecast 9 BkWh less coal generation this year than in 2023.

Regarding emissions, EIA expects energy-related carbon dioxide (CO2) emissions to remain flat between 2023 and 2025. EIA maintains that in 2024, the stability of total CO2 emissions is a result of rising natural gas consumption across sectors, offset by less generation from coal. Additionally, EIA expects emissions in 2025 to remain unchanged, as a less than 1% decrease in natural gas emissions, caused by a decrease in naturual-gas fired electricity generation, is offset by a 1% increase in petroleum emissions associated with increased diesel consumption.

EIA also expects the carbon intensity of energy (the total energy-related CO2 emissions per unity of energy consumed) to decline by 1% both this year and next. This reduction can be attributed to renewable energy sources supplying an increasing share of U.S. energy, EIA said. Primary energy consumption is expected to grow by about 1% in both years, with more than 50% of the growth met by solar, wind, and hydropower.