Natural Gas-fired Generation Research Articles

The Impact of Retrofitting Natural Gas-Fired Power Plants on Carbon Footprint: Converting from Open-Cycle Gas Turbine to Combined-Cycle Gas Turbine

Since retrofitting existing natural gas-fired (NGF) power plants is an essential strategy for enhancing their efficiency and controlling greenhouse gas emissions, this paper compares the carbon footprint of natural gas-fired power generation from an NGF power plant in Brazil (BR-NGF) with and without retrofitting. The former scenario entails retrofitting the BR-NGF power plant with combined-cycle gas turbine (CCGT) technology. In contrast, the latter involves continuing the BR-NGF power plant operation with open-cycle gas turbine (OCGT) technology. Our analysis considers the BR-NGF power plant’s life cycle (construction, operation, and decommissioning) and the natural gas’ life cycle (natural gas extraction and processing, liquefaction, liquefied natural gas transportation, regasification, and combustion). Moreover, it is based on data from primary and secondary sources, mainly the Ecoinvent database and the ReCiPe 2016 method. For OCGT, the results showed that the BR-NGF power plant and the natural gas life cycles are responsible for 620.87 gCO2eq./kWh and 178.58 gCO2eq./kWh, respectively. For CCGT, these values are 450.04 gCO2eq./kWh and 129.30 gCO2eq./kWh. Our findings highlight the relevance of the natural gas’ life cycle, signaling additional opportunities for reducing the overall carbon footprint of natural gas-fired power generation.

Operation of coupled power-gas networks with hydrogen refueling stations, responsive demands and storage systems: A novel stochastic framework

Because of factors such as low natural gas prices, low greenhouse gas emission and high efficiency has increased the penetration of natural gas-fired generators in electric power systems. Large gas consumption of gas-fired generators has caused intense interdependence of electricity and gas systems. Most often, the operational planning of power and gas systems is conducted through a co-optimisation model in which the total cost of electricity and gas systems is minimised and the constraints of both systems are considered. On the other hand, due to environmental concerns, the usage of fuel cell vehicles (FCVs) is increasing. Hydrogen refueling stations (HRSs) are needed for refueling FCVs. This paper puts forward a stochastic model for co-optimisation of wind-integrated power and gas systems, hosting HRSs, electric storage systems (ESS's) and responsive electricity and gas demands. The effect of ESS's, responsive demands, contingencies, wind uncertainties and demand response on operation of power-gas nexus is scrutinized. An incentive-based demand response program has been used for both electricity and gas demands. The case study is the Belgian gas network connected to the a 24-bus power system. The findings indicate that responsive electric demands reduce electric system cost by 9.4 %, while responsive gas demands reduce the gas network cost and total operation cost by 1 %. The contingency analysis on the power-gas nexus shows that single line outage contingencies in power system does not result in any demand shed and does not increase the operation cost of either electricity network or gas network.

The effect of PV generation's hourly variations on Israel's solar investment

Limited by sunniness and conversion efficiency, one installed MW of photovoltaic (PV) capacity can only produce ωt MWh of electricity in daytime hour t, where ωt = positive fraction that we call PV's hourly effective capacity (HEC). Based on a sample of commercially operating PV plants in Israel, HEC rises throughout the 08:00–11:00 period, peaks in the 11:00–14:00 period and then declines in the 14:00–18:00 period. Further, HEC values in spring and summer exceed those in autumn and winter, thus motivating our research question: do HEC variations by hour and season adversely affect the plans for and assessment of PV investment in Israel? An affirmative answer would cause concerns regarding Israel's announced policy of relying on increasing market penetration of PV generation transitionally supported by merchant natural-gas-fired generation (NG) to achieve a low-carbon electricity future. Hence, we propose a two-stage model of Israel's forthcoming Cournot wholesale electricity market with independent power producers (IPPs) operating PV and NG power plants. By comparing the model's solutions under alternative HEC scenarios, we find that the level of detail in modelling the HEC variations by hour and season does not materially affect the optimal PV and NG investments, thus lending support to the use of relatively simple models with only two daily non-seasonal HEC values to assess Israel's announced policy of deep decarbonization. Our methodology is general and real-world relevant because it can be readily adapted for applications in other regions with ample sunshine and wholesale electricity market competition (e.g., California, Texas and Australia).

Gas Turbine's Role in Energy Transition

Abstract cycle configuration, with rated efficiencies (at ISO base load) above 60% net LHV, are expected to play a significant role in reducing the carbon footprint of utility scale electricity generation. Even without post-combustion capture, simply switching from coal-fired generation to natural gas-fired generation reduces carbon dioxide emissions by 60% (on a kg per MWh of generation basis). In simple cycle mode, with efficiencies above 40% net LHV and startup times around 20 minutes, 300 to 400+ MW gas turbines can easily serve as peakers to support variable renewable resources, i.e., wind and solar. In this paper, a close quantitative look is taken at the capabilities of gas turbines firing natural gas, hydrogen, or a blend thereof, both in simple and combined cycle configurations. Furthermore, using published data, first-principles calculations, and software simulations, it will be shown that the gas turbine constitutes an efficient and cost-effective technology, with and without carbon capture, as a key player in decarbonization of the electric power sector.

Reserve provision of combined-cycle unit in joint day-ahead energy and reserve markets

With the continuous development of natural gas-fired combined cycle power generation technology, the combined cycle (CC) unit's installed capacity is gradually increasing in the power system because of its flexible operation characteristics. Participating in the energy and reserve markets and taking advantage of flexible mode transfer characteristics, the CC unit can provide the system with energy and sufficient reserve capacity. This paper proposes a bi-level strategic bidding model to study the CC unit’s bidding behavior in the day-ahead energy and reserve markets. The upper-level model is an optimal bidding model for the configuration-based CC unit aiming to maximize its profit. The lower-level model is the joint market clearing model of the energy and reserve markets managed by the independent system operator (ISO). CC unit and ISO in this model influence each other by the locational marginal electricity prices (LMEP) and the locational marginal reserve prices (LMRP) obtained from the lower-level market-clearing model. The CC unit submits the bids to the ISO and arranges the generation plan according to the market clearing results of the lower-level market-clearing model carried out by the ISO. The proposed bi-level optimization model is transformed into a mathematical equilibrium constraint (MPEC) problem by Karush-Kuhn-Tucker (KKT) conditions and duality theory. In this paper, the improved IEEE-6 bus and IEEE-57 bus systems are used as case studies to verify the effectiveness of the proposed bidding strategy for the CC unit. The results show that the proposed bidding strategy can effectively improve the profits of the CC unit in the electricity market. Compared with the case of the CC unit only participating in the energy market, the profits of the CC unit in the market increased by 8.84% and 12.3%.

ЗЕЛЕНЫЕ ТЕХНОЛОГИИ КАК АЛЬТЕРНАТИВА ПРИМЕНЕНИЯ УГЛЕВОДОРОДНЫХ РЕСУРСОВ

The article discusses the prospects for the use of green technologies in the face of an unfavorable geopolitical situation and sanctions announced by Russia, which led to a shortage in the energy market. Renewable energy sources, including solar energy, wind energy, hydropower, biofuels and others, are the main focus of the transition to a less carbon-intensive and more sustainable energy system. Wind and solar PV can reduce the European energy sector's dependence on Russian gas in 2023. Russia supplies about 45 % of the gas imported by the European Union for industry, housing and electricity generation. For electricity generation, natural gas accounts for about 16 % of the group's total electricity demand. Over the past decade, natural gas-fired electricity generation has ranged from 340 to 600 kWh per year, depending on pricing and demand for wind and solar photovoltaic systems. The paper provides an analysis of the average annual energy production on natural gas for individual EU countries. An overview of the change in the price range of biofuels is presented. Uncertainty factors in the construction of economic forecasts are indicators related to fuel, raw materials and the policy of prices for oil and biofuels. Energy and food security, as well as reducing greenhouse gas emissions, are all in constant flux, which also introduces many uncertainties into forecasts. As conclusions on the topic of the work, it was noted that high prices for fossil fuels have increased the competitiveness of electricity generation technologies from renewable sources compared to coal-fired and natural gas power plants. However, despite their potential, accelerating the growth of new renewable energy capacity depends largely on a stable policy environment that provides long-term revenue certainty.

A Polyhedral Study on Fuel-Constrained Unit Commitment

The electricity production of a thermal generator is often constrained by the available fuel supply. These fuel constraints impose a maximum bound on the energy output over multiple time periods. Fuel constraints are increasingly important in electricity markets because of two main reasons. First, as more natural gas-fired generators join the deregulated market, there is often competition for natural gas supply from other sectors (e.g., residential and manufacturing heating). Second, as more environmental and emission regulations are being placed on fossil fuel-fired generators, fuel supply is becoming more limited. However, there are few studies that consider the fuel constraints in the unit commitment problem from the perspective of computational analysis. To address the challenge faced by an independent power producer with a limited fuel supply, we study a fuel-constrained self-scheduling unit commitment (FSUC) problem where the production decisions are coupled across multiple time periods. We provide a complexity analysis of the FSUC problem and conduct a comprehensive polyhedral study by deriving strong valid inequalities. We demonstrate the effectiveness of our proposed inequalities as cutting planes in solving various multistage stochastic FSUC problems. History: Accepted by Pascal Van Hentenryck, Area Editor for Computational Modeling: Methods & Analysis. Funding: K. Pan was supported in part by the Research Grants Council of Hong Kong [Grant 15501920]. F. Qiu was supported in part by the U.S. Department of Energy Advanced Grid Modeling Program [Grant DE-OE0000875]. Supplemental Material: The software that supports the findings of this study is available within the paper and its Supplementary Information [ https://pubsonline.informs.org/doi/suppl/10.1287/ijoc.2022.1235 ] or is available from the IJOC GitHub software repository ( https://github.com/INFORMSJoC ) at [ http://dx.doi.org/10.5281/zenodo.6896199 ].

Natural Gas Short-Term Operation Problem With Dynamics: A Rank Minimization Approach

Natural gas-fired generation units can hedge against the volatility in the uncertain renewable generation, which may occur during very short periods. It is crucial to utilize models capable of correctly capturing the natural gas network dynamics induced by the volatile demand of gas-fired units. The Weymouth equation is commonly implemented in literature to avoid dealing with the mathematical complications of solving the original governing differential equations of the natural gas dynamics. However, it is shown in this paper that this approach is not reliable <italic xmlns:mml="http://www.w3.org/1998/Math/MathML" xmlns:xlink="http://www.w3.org/1999/xlink">in the short-term operation problem</i> . Here, the merit of the non-convex transient model is compared with the simplified Weymouth equation, and the drawbacks of employing the Weymouth equation are illustrated. The results demonstrate how changes in the natural gas demand are met by adjustment in the pressure within pipelines rather than the output of natural gas suppliers. This work presents a convex relaxation scheme for the original non-linear and non-convex natural gas flow equations with dynamics, utilizing a rank minimization approach to ensure the tightness. The proposed method renders a computationally efficient framework that can accurately solve the non-convex non-linear gas operation problem and accurately capture its dynamics. Also, the results suggest that the proposed model improves the solution optimality and solution time compared to the original non-linear non-convex model. Finally, the scalability of the proposed approach is verified in the case study.

Possible Scenarios for Reduction of Carbon Dioxide Emissions in Serbia by Generating Electricity from Natural Gas

The main purpose of this paper is to develop possible scenarios for reducing carbon dioxide (CO2) emissions in Serbia by switching from coal-fired to natural gas-fired electricity generation by the end of 2050. Accordingly, the challenges are to establish scenarios and identify measures that are best suited to all Western Balkan countries. In particular, this paper proposes a number of energy mix scenarios that offer some options for reducing CO2 emissions while maintaining an economic way of consumption. Projections of these reduction scenarios are obtained by combining the Kaya identity with the emission factor method. A simplified methodology based on sensitivity analysis is used as a source of data to estimate the nonstatistical uncertainty limits for the projections of the reduction scenarios. The sensitivity analysis is carried out using historical data from Serbia for the period from 1990 to 2019. In addition, a direct verification of the proposed methodology is performed based on historical data for 2020. The developed scenarios 1 and 2 show that CO2 emissions could be reduced by 10.94% and up to 74.44% from baseline in 1990, respectively. The obtained results are also contrasted with the data available for some other countries with similar experiences. Finally, it is found that the developed scenarios are achievable only at significantly decreased levels of coal-fired electricity generation.

Carbon pricing and Alberta’s energy-only electricity market

Alberta operates one of the few energy-only electricity markets. This paper highlights the benefits of Alberta’s market design for the incorporation of a carbon price which efficiently transmits incentives to market participants. Specific attention is paid to how carbon pricing has contributed to the shift away from coal towards natural gas and wind. The incentives created by carbon pricing have resulted in substantial new investment in wind, solar, and natural gas-fired generation capacity.

Feasibility of Replacing Nuclear and Fossil Fuel Energy with Offshore Wind Energy: A Case for Taiwan

Adequate recognition of the offshore wind energy potential may help coastal states frame proper energy policies for replacing nuclear and fossil fuel energy. In this study, we examined the application potential of the offshore wind energy generated by 31 offshore wind farms designated by the Taiwanese government for future exploitation. Our findings indicate that offshore wind energy (through its substantial power generation volume and capacity factor) can play the most pivotal role in future power generation for Taiwan. A total of 59.3 TWh of electricity produced from offshore wind energy and solar photovoltaics (PVs) each year could replace the power generated from nuclear energy by 2025. Coal-fired power generation could be replaced by offshore wind energy and other renewables by 2032. The full exploitation of offshore wind farms as detailed in this study (103.4 TWh/year), together with other renewables, could reduce the share of liquefied natural gas-fired power generation to 5.6% of the total Taiwanese power supply by 2040. Realizing the ultimate target of 100% carbon-neutral power generation would rely mainly on a further decrease in electricity consumption per unit of gross domestic product and the expansion of offshore wind energy and geothermal energy.

Fuelling power plants by natural gas: An analysis of energy efficiency, economical aspects and environmental footprint based on detailed process simulation of the whole carbon capture and storage system

In view of the low-carbon transformation of the power sector, natural gas-fired power generation is the only technology, among fossil resources, that will continue to provide an important source of flexibility for the power system in the coming years. However, the carbon dioxide emissions produced by the operation of such plants call for carbon capture and storage equipment, whose deployment needs to be assessed and compared with the main renewable technologies: wind power and photovoltaics. This work uses process simulation in order to assess two different carbon capture processes: a traditional one, based on monoethanolamine, and an innovative one, based on hot potassium carbonate. Process simulation is also used for the transportation of carbon dioxide to the sequestration site. Mass and energy balances from the simulations are then used for the calculation of the Energy Return on Energy Invested, the Levelized Cost of Energy and as inputs for the Life Cycle Assessments of both alternative designs. The life cycle analyses of the considered power technologies exhibited higher contributions due to fossil-based power plants towards climate-related impact categories, while renewable sources were revealed to be more burdensome for the exploitation of mineral resources. The calculated Energy Return on Energy Invested for gas-fired power plants with carbon capture and storage is between 5.2 and 12.4, comparable with the values of photovoltaics and wind power. On the other hand, their Levelized Cost of Energy is between 10.2 and 20.0 eurocent per kilowatt-hour, much higher than that of renewables. The conclusion is that, at present, the sustainability of gas-fired power stations equipped with carbon capture and storage should be carefully considered and not taken for granted.

A Novel Framework for the Operational Reliability Evaluation of Integrated Electric Power–Gas Networks

This paper proposes a new framework for the operational reliability evaluation of integrated electric power-gas networks (IEPGNs). First, a novel approach for modeling the failure modes of natural gas pipelines is presented. This approach utilizes the concept of virtual nodes and employs a gas release rate model to consider the pinhole, hole, and rupture failure modes of pipelines. Thereafter, a four-state Markov model for natural gas-fired generators (NGFGs) with dual-fuel capabilities is proposed. The area risk method is extended to include the proposed reliability models, and the partial reliability indices of the area risk method are evaluated using a non-sequential Monte Carlo simulation (NSMCS). A nonlinear optimization model is also proposed to calculate electric and gas load curtailments for each system state in NSMCS. This model is linearized to obtain a mixed-integer linear programming (MILP) model for reducing the computational burden. The computational performance of NSMCS is further improved by adopting cross entropy (CE)-based importance sampling (IS). Finally, the efficacy of the proposed framework is demonstrated on three test systems. Case studies validate the importance of considering the proposed reliability models of IEPGNs for operational reliability evaluation. The impacts of operational strategies on the operational reliability indices are also demonstrated.

A coordinated scheme of electricity-gas systems and impacts of a gas system FDI attacks on electricity system

The increased penetration of natural gas-fired generation units in electricity systems calls for coordination of natural gas and electricity systems. Moreover, concerns over security of coordinated gas-electricity systems are spreading in recent years. Notably, both energy systems are vulnerable to malicious cyber-attacks. Within this context, this article (1) proposes a coordination scheme for the day-ahead schedule of natural gas and electricity systems; (2) defines a new class of false data injection (FDI) cyber-attacks on the gas demand and scheduling information of the natural gas system; and (3) investigates the impacts of such attacks on the operation of both energy systems. The coordination mechanism consists of three nested optimization problems. The natural gas system scheduling step in the mechanism is modeled as a bi-level max–min optimization problem with consideration of attacks. We use a column and constraint generation (C&CG) algorithm to solve this bi-level problem. The coordination mechanism and bi-level attack problem are examined using a case study based on the IEEE 24-node test system and a 9-node gas system, as well as a case study based on the IEEE 118-node test system and a 25-node gas system.

Fault diagnosis of gas turbines with thermodynamic analysis restraining the interference of boundary conditions based on STN

Gas turbines are widely used in natural gas-fired power generation and long-distance natural gas pipelines. The complexity and diversity of boundary conditions usually have a great influence on the measurement parameters, which makes them difficult to reflect the actual health status of gas turbines and leads to lower diagnostic accuracy. In the gas path analysis of gas turbines, traditional mechanism and data-driven methods are difficult to consider the interference of boundary conditions. A novel fault diagnostic method deriving from the spatial transformer network (STN) is proposed to restrain the influences of boundary conditions on fault diagnostic results. It can realize fault detection with higher accuracy by converting different boundary conditions to a designed one.The established STN is then combined with the typical small deviation (SD) theory and a classification network to complete the gas path analyses.The proposed two methods are verified and compared with traditional methodsthrough simulation experiments and field data. Compared with the traditional SD method, the fault detection accuracy is increased by 2.92% in the STN-SD method, and the STN-MLP method improves the diagnostic accuracy by 5.24%. The proposed two methods also have good performance in the field data analysis and realize fast fault detection and early warning.This work provides a reliable way to detect faults subjecting tothe influence of complex boundary conditions and provides reference and support for the fault diagnosis of other thermodynamic systems.

Valuing intra-day coordination of electric power and natural gas system operations

Increasing renewable energy penetrations and low natural gas prices have increased the reliance of U.S. power systems on natural gas-fired generation. Increased reliance has sparked concerns over and resulted in natural gas deliverability constraints. To mitigate these constraints, research and regulatory reform have tried to improve coordination between power and gas systems. The U.S. Federal Energy Regulatory Commission (FERC) issued Order 809 in 2015 to improve day-ahead and intra-day coordination of power and gas systems. Given little research on intra-day coordination and FERC's recent action, we quantify the value of improved intra-day coordination between gas and electric power systems. To do so, we co-simulate coordinated day-ahead, intra-day, and real-time operations of an interconnected power and natural gas test system using a dynamic natural gas simulation model and a power system optimization model. We find intra-day coordination reduces total power system production costs and natural gas deliverability constraints, yielding cost and reliability benefits. Sensitivity analysis indicates improved intra-day renewable energy forecasts and higher renewable energy capacities increase intra-day coordination benefits for gas network congestion. Our results indicate FERC Order 809 and other policies aimed at enhancing intra-day coordination between power and gas systems will likely yield cost and reliability benefits.

Texas's operating reserve demand curve's generation investment incentive

Faced with reserve margin projections well below the adopted target of 13.75% of the system peak forecast, the Public Utility Commission of Texas on 01/17/2019 ordered the state's grid operator, the Electric Reliability Council of Texas, to “right shift” the operating reserve demand curve (ORDC) to increase generators' revenue from energy sales in ERCOT's real-time market (RTM). Using a large sample of 15-min data for the backcast period of 01/01/2015 through 12/31/2018, we calculate the ORDC shift's impact on RTM prices and investment incentives for natural-gas-fired generation (NGFG). Had the ORDC shift been in effect in the backcast period, the resulting RTM price increases in 2018 could suffice to justify NGFG investment, though not in the prior years of 2015, 2016 and 2017. While the actual ORDC shift occurred on 03/01/2019 had a large impact on RTM prices in the ensuing six-month period of March–August 2019, Texas's planned renewable generation is expected to erode NGFG's operating profit, thus diminishing the ORDC's investment incentive over time. Hence, Texas's energy-only market design will likely need further refinements to solve the missing money problem of inadequate NGFG investment incentive.

Perspective Analysis of Emerging Natural Gas-based Technology Options for Electricity Production

Abstract The growing worldwide interest in low carbon electric generation technologies has renewed interest in natural gas because it is considered a cleaner burning and more flexible alternative to other fossil fuels. Recent shale gas developments have increased natural gas production and availability while lowering cost, allowing a shift to natural gas for electricity production to be a cost-effective option. Natural gas generation in the U.S. electricity sector has grown substantially in recent years (over 31 percent in 2012, up from 17 percent in 1990), while carbon dioxide (CO2) emissions of the sector have generally declined. Natural gas-fired electrical generation offers several advantages over other fossil (e. g. coal, oil) fuel-fired generation. The combination of the lower carbon-to-hydrogen ratio in natural gas (compared to other fossil fuels) and the higher efficiency of natural gas combined cycle (NGCC) power plants (using two thermodynamic cycles) than traditional fossil-fueled electric power generation (using a single cycle) results in less CO2 emissions per unit of electricity produced. Furthermore, natural gas combustion results in considerably fewer emissions of air pollutants such as nitrogen oxides (NOx), sulfur dioxide (SO2), and particulate matter (PM). Natural gas is not the main option for deep de-carbonization. If deep reduction is prioritized, whether of the electricity sector or of the entire economy, there are four primary technologies that would be assumed to play a prominent role: energy efficiency equipment, nuclear power, renewable energy, and carbon capture and storage (CCS). However, natural gas with low carbon generation technologies can be considered a “bridge” to transition to these deep decarbonization options. This paper discusses the economics and environmental impacts, focusing on greenhouse gas (GHG) emissions, associated with alternative electricity production options using natural gas as the fuel source. We also explore pairing NGCC with carbon capture, explicitly examining the costs and emissions of amine absorption, cryogenic carbon capture, carbonate fuel cells, and oxy-combustion.

The South Korean public’s evaluation of the mix of power generation sources: A choice experiment study

The South Korean government is pursuing an energy transition, which means a reduction in nuclear power and coal-fired power generation, and an expansion into renewable energy. This study seeks to evaluate the South Korean public’s preference for a mix of power generation sources. For this purpose, 1000 households throughout the country were randomly selected and a choice experiment survey of them was undertaken in March 2018. We considered four attributes: the ratio of nuclear power, the ratio of coal-fired generation, the ratio of natural gas-fired generation, and the ratio of renewable energy. An increase in the monthly electric bill was also considered as an attribute. The results of applying the choice experiment approach show that households were willing to accept an increase in their monthly electric bill by KRW 192 (USD 0.17) and KRW 165 (USD 0.15) for reducing the proportion of nuclear power and coal, respectively, by 1%p. They were willing to pay KRW 159 (USD 0.14) and KRW 409 (USD 0.38) for raising the ratio of natural gas and renewable energy, respectively, through an increase in the monthly electricity bill. The findings reveal that the government’s energy transition has overall support from the public.

Economic and environmental impact assessments of a stand-alone napier grass-fired combined heat and power generation system in the southeastern US

Napier grass, one of the high yield perennial energy crops can be grown on marginal lands with minimal inputs, but with increased soil carbon sequestration in the southeastern US. The sustainable use of Napier grass for bioenergy applications such as combined heat and power at low cost to mitigate greenhouse gas emissions needs to be investigated. In this study, an integrated life cycle assessment and techno-economic analysis approach were used to estimate the energy use, environmental emissions, and minimum selling price (MSP) of electricity and thermal heat produced from Napier grass and compared with a coal or natural gas-fired combined heat and power generation plant. The use of Napier grass as a feedstock decreased the global warming potential (GWP) of the medium-sized CHP (i.e., 13 MWe) plant by 73–92 % compared to that of a coal and natural gas-fired CHP plants. Other environmental impacts were also reduced by 24–100 %. Eutrophication was the only impact comparable to that of the coal-fired CHP plant. The energy return on investment (EROI) was around 5:1. The minimum selling price of electricity generated from the CHP plant was US$0.05–0.4 MJe−1 (US$0.13–0.18 kWh−1) considering the credits for steam production, renewable electricity production tax credit (PTC), and carbon footprint from the fossil fuel-based electricity generation. Although the pelleting of Napier grass for the CHP plant increased the cost and GHG emissions by 38% and 55% over the non-pelleted system, the pelleting process can ensure consistent quality and uninterrupted supply of the feedstock for heat and power generation.