Discussion of emerging energy conversion technologies is often made more difficult by conflicting terminology, assumptions, and perspectives of researchers who are often in different scientific specialty areas. Furthermore, researchers tend to describe their work in terms of the physical parameters they are able to measure in the laboratory, whereas policy developers and the general public tend to speak in terms of top-level system performance and economics. Consequently, there is often less than effective communication between researchers in different specialty areas, and between researchers and public policy developers. Development of a common framework to discuss all low-carbon energy conversion technologies would facilitate the transfer of ideas and foster more rapid development. Strategic Analysis Inc. (SA) has conducted a variety of techno-economic analyses of emerging low-carbon energy conversion technologies for the Department of Energy covering a range of hydrogen production technologies including electrolysis (Alkaline, Proton Exchange Membrane (PEM), Solid Oxide (SO)), photo-electrochemical (PEC) (electrode and slurry based systems), biological, and solar to hydrogen conversion (STCH). Additionally, SA has examined fuel cell systems (PEM, SO) and fuel-cell/electrolyzer regenerative systems. Examination of these systems grants SA an excellent vantage point to classify the similarities and differences between the systems and their corresponding performance and economic metrics. For instance, all the solar systems utilize sunlight as the primary input energy source. However, performance is typically specified using the full light spectrum energy for photovoltaic (PV) arrays , using only the photosynthetically active radiation (PAR) spectrum for bio systems, and only the energy of direct light (not diffuse) for concentrating PV arrays. Thus all three systems would report a “% efficiency”, where the performance metrics are not directly comparable. The objective of this presentation will be to discuss the common performance and economic metrics that apply to most/all low-carbon energy conversion technologies so as to allow easy and appropriate comparisons of the technologies. An effort will be made to chart a direct path between system level performance and economic parameters that policy makers and the general public find most useful, with the laboratory and scientific metrics that researchers typically use to discuss their work. From this, researchers will have a better holistic understanding of how their particular efforts would translate into system-level performance and a heighted awareness of negative factors that might sabotage the overall economics of the system.

Pacific Northwest National Laboratory (PNNL) is working with industry to independently monitor up to 15 distinct 5 kW-electric (kWe) combined heat and power (CHP) high temperature (HT) proton exchange membrane (PEM) fuel cell systems (FCSs) installed in light commercial buildings. This research paper discusses an evaluation of the first six months of measured performance data acquired at a 1 s sampling rate from real-time monitoring equipment attached to the FCSs at building sites. Engineering performance parameters are independently evaluated. Based on an analysis of the first few months of measured operating data, FCS performance is consistent with manufacturer-stated performance. Initial data indicate that the FCSs have relatively stable performance and a long-term average production of about 4.57 kWe of power. This value is consistent with, but slightly below, the manufacturer's stated rated electric power output of 5 kWe. The measured system net electric efficiency has averaged 33.7%, based on the higher heating value (HHV) of natural gas fuel. This value, also, is consistent with, but slightly below, the manufacturer's stated rated electric efficiency of 36%. The FCSs provide low-grade hot water to the building at a measured average temperature of about 48.4 °C, lower than the manufacturer's stated maximum hot water delivery temperature of 65 °C. The uptime of the systems is also evaluated. System availability can be defined as the quotient of total operating time compared to time since commissioning. The average values for system availability vary between 96.1 and 97.3%, depending on the FCS evaluated in the field. Performance at rated value for electrical efficiency (PRVeff) can be defined as the quotient of the system time operating at or above the rated electric efficiency and the time since commissioning. The PRVeff varies between 5.6% and 31.6%, depending on the FCS field unit evaluated. Performance at rated value for electrical power (PRVp) can be defined as the quotient of the system time operating at or above the rated electric power and the time since commissioning. PRVp varies between 6.5% and 16.2%. Performance at rated value for electrical efficiency and power (PRVt) can be defined as the quotient of the system time operating at or above both the rated electric efficiency and the electric power output compared to the time since commissioning. PRVt varies between 0.2% and 1.4%. Optimization to determine the manufacturer rating required to achieve PRVt greater than 80% has been performed based on the collected data. For example, for FCS Unit 130 to achieve a PRVt of 95%, it would have to be down-rated to an electrical power output of 3.2 kWe and an electrical efficiency of 29%. The use of PRV as an assessment metric for FCSs has been developed and reported for the first time in this paper. For FCS Unit 130, a maximum decline in electric power output of approximately 18% was observed over a 500 h period in Jan. 2012.

This article details analysis of hydrogen (H-2) production based on polymer electrolyte membrane (PEM) electrolysis. This work identifies primary constraints to the success of this production pathway, primary cost drivers, and remaining Research and Development (R&D) challenges. This research assesses the potential to meet U.S. Department of Energy (DOE) H-2 electrolyzer production and delivery (P&D) cost goals of $2 to $4/gasoline gallon equivalent (dispensed, untaxed) by 2020. Pathway analysis is performed using the DOE's main H2A modeling tool, namely, the H2A Production model, which encapsulates the standard methods of energy, emissions, and cost analysis developed by DOE's H-2 and fuel cell technology teams. PEM electrolysis production pathways are analyzed for a distributed, forecourt H-2 production system of 1,500 kilograms (kg) of H-2 per day, and for a central, large, plant size H-2 production system of 50,000 kg H-2/day, for both current and future cases. The analysis is based in part on data from a technical and economic survey completed by four different PEM electrolyzer companies.Model results indicate that, for PEM electrolysis, the primary cost drivers are the electricity expenditures to run the electrolyzer and the capital cost of the electrolyzer. In the future within the electrolyzer system, the balance of plant is expected to be a greater source of cost than the electrolyzer stack due to stack reductions facilitated by operation at higher current densities whereas the balance of plant remains similarly sized for the given flow. This balance between size and cost of the stack versus balance of plant could also increase difficulties in meeting efficiency improvements in the future. The H-2 cost reduction is estimated to be greater moving from a Current case to a Future case, compared with moving from a Forecourt case to a Central case.

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This article presents a design for manufacturing and assembly (DFMA) methodology for estimating the capital costs of new, emerging energy technologies built at varying rates of mass-production. The methodology consists of four major steps: (1) System Conceptual Design, (2) System Physical Design, (3) Cost Modeling, and (4) Continuous Improvement to Reduce Cost. The article describes the application of this methodology to a specific case study of automotive fuel cell systems (FCSs). Because any alternative automotive technology must compete with the very mature and widespread gasoline internal combustion engine, it is vitally important to identify the performance, design, and manufacturing conditions needed to reduce automotive FCS costs. Thus, a DFMA-style analysis is applied to the cost to manufacture a polymer electrolyte membrane (PEM) FCS for cars, at varying rates of production (between 1,000 and 500,000 vehicles per year). The results of this kind of DFMA-style analysis can be used to elucidate key cost drivers at varying levels of production for new energy technologies.

A total cost of ownership model is described for low temperature proton exchange membrane stationary fuel cell systems for combined heat and power (CHP) applications from 1-250kW and backup power applications from 1-50kW. System designs and functional specifications for these two applications were developed across the range of system power levels. Bottom-up cost estimates were made for balance of plant costs, and detailed direct cost estimates for key fuel cell stack components were derived using design-for-manufacturing-and-assembly techniques. The development of high throughput, automated processes achieving high yield are projected to reduce the cost for fuel cell stacks to the $300/kW level at an annual production volume of 100 MW. Several promising combinations of building types and geographical location in the U.S. were identified for installation of fuel cell CHP systems based on the LBNL modelling tool DER CAM. Life-cycle modelling and externality assessment were done for hotels and hospitals. Reduced electricity demand charges, heating credits and carbon credits can reduce the effective cost of electricity ($/kWhe) by 26-44percent in locations such as Minneapolis, where high carbon intensity electricity from the grid is displaces by a fuel cell system operating on reformate fuel. This project extends the scope of existing cost studies to include externalities and ancillary financial benefits and thus provides a more comprehensive picture of fuel cell system benefits, consistent with a policy and incentive environment that increasingly values these ancillary benefits. The project provides a critical, new modelling capacity and should aid a broad range of policy makers in assessing the integrated costs and benefits of fuel cell systems versus other distributed generation technologies.

This paper evaluates the potential for electrochemical hydrogen compression systems (EHCs) regarding their engineering performance, manufacturability, and capital costs. EHCs could enhance or replace mechanical hydrogen compressors. The physical embodiment of EHCs is similar to that of low temperature (LT) proton exchange membrane (PEM) fuel cell systems (FCSs). They also share common operating principles with LT PEM FCS and with PEM electrolysis systems. Design for Manufacturing and Assembly (DFMA (TM)) analysis is applied to EHCs to identify manufactured designs, manufacturing methods, projected capital costs under mass-production, and cost drivers for both the EHC stack and the balance of plant (BOP). DFMA (TM) analysis reveals that EHC stack costs are expected to be roughly equal to EHC BOP costs, under a variety of scenarios. (Total EHC system costs are the sum of stack and BOP costs.) Within the BOP, the primary cost driver is the electrical power supply. Within the stack, the primary cost drivers include the membrane electrode assembly (MEA), the stamped bipolar plates, and the expanded titanium (Ti) cell supports, particularly at lower hydrogen outlet pressures. As outlet pressure rises, capital costs escalate nonlinearly for several reasons. Higher pressure EHCs experience higher mechanical loads, which necessitate using a greater number of smaller diameter cells and a greater tie rod mass. Higher pressure EHCs also exhibit a higher degree of back-diffusion, which necessitates using more cells per system.

A design for manufacture and assembly (DFMA (TM)) analysis is applied to future bus and automotive fuel cell vehicle (FCV) system designs. This DFMA (TM) analysis is used to identify (1) optimal fuel cell system (FCS) operating parameters for system cost minimization, (2) FCV designs appropriate for volume manufacture, (3) FCV manufacturing supply chain designs, (4) projected future capital costs of FCVs at varying manufacturing rates, and (5) primary cost drivers. This DFMA (TM) analysis focuses on the FCS drive train. It excludes fuel storage, the electric drive drain, and all other parts of the vehicle (chassis, exterior, etc.). These FCSs are envisioned to use low temperature proton exchange membrane (LT PEM) stacks to convert hydrogen fuel into electric power. Models are developed to minimize LT PEM fuel cell system costs by finding the cost optimal combination of (1) stack operating pressure, (2) cell voltage, (3) platinum (Pt) catalyst loading, (4) stoichiometric ratio of oxygen, and (5) coolant stack exit temperature. A multi-variable Monte Carlo sensitivity analysis indicates, with 90% confidence, that a FCS producing peak net 160 kilowatt-electric (kWe) for a bus application and produced at a rate of 1,000 FCS/year (yr) is expected to cost between $251/kWe and $334/kWe. Similarly, a peak net 80 kWe automotive FCS manufactured at a rate of 500,000 FCSs/year is estimated to cost between $51/kWe and $65/kWe, with 90% confidence. Total FCS costs are the sum of PEM stack and balance of plant (BOP) costs. The BOP components represent 32% of the bus FCS costs and 48% of the automotive system cost.

This report documents the development of four DOE Hydrogen Analysis (H2A) case studies for polymer electrolyte membrane (PEM) electrolysis. The four cases characterize PEM electrolyzer technology for two hydrogen production plant sizes (Forecourt and Central) and for two technology development time horizons (Current and Future).

The widespread use of combined heat and power (CHP) distributed generation (DG) for buildings could significantly increase energy efficiency and reduce greenhouse gas and air pollution emissions. By displacing both electricity from conventional centralized power plants and heat from decentralized boilers, CHP DG could reduce primary feedstock fuel consumption in the U.S. by approximately 20%, or 6,000 terawatt hours. However, optimally integrating CHP DG within buildings is challenging. This work aims to elucidate optimal system sizing and design of micro-CHP fuel cell systems (FCSs) integrated with commercial buildings. This modeling effort compares and contrasts the performance of high temperature polymer electrolyte membrane (PEM) fuel cell systems (HTPEM FCSs) and solid oxide fuel cell (SOFC) systems for commercial buildings. A parallel research effort is independently analyzing measured data from HTPEM FCSs installed in commercial buildings. Measured data from that effort is integrated into this modeling work. In certain regions, there has been a research and development and commercialization trend moving from using low temperature PEM FCSs (e.g. with a stack temperature of around 80°C) to using HTPEM FCSs (e.g. with a stack temperature of around 160°C) and to using SOFC systems (e.g. with a stack temperature of around 700°C) for CHP building applications, given the higher temperature of the available waste heat from these systems. In this work FCS performance data is coupled with building energy system models from the U.S. Department of Energy (DOE) using EnergyPlus™ whole-building energy simulation software. Using these baseline reference commercial building model data, parameters are examined including heat demand for space heating and for domestic hot water heating over time, temperatures and water flow rates associated with this heat demand, and building electrical demand over time, to evaluate FCS integration within the building. Examining the data obtained through the simulation exercise in this work, it is found that in a large office building, with heat demand temperatures in the range of 82°C for space heating and 60°C for hot water heating, an HTPEM FCS with an exhaust temperature of 47°C can potentially access, at a maximum, 19% of the total building heating demand. By contrast, in a small office building, with heat demand temperatures in the range of 23°C (supply air temperature) for space heating and 60°C for hot water heating, it is found that this HTPEM FCS can potentially access, at a maximum, 90% of the total building heating demand. Examining the temporal characteristics of the building heat demand to determine FCS sizing, it is found that a maximum of 50% of the time, the heat demand can be served with an HTPEM FCS with a thermal capacity of 8 kilowatts (kW) (0.05 kW for small office) and an electrical capacity of approximately 4.5 kilowatts-electric (kWe) (0.45 kWe for small office). A maximum of 80% of the time, the heat demand can be served with an HTPEM FCS with a thermal capacity of 85 kW (0.16 kW for small office) and an electrical capacity of approximately 73 kWe (0.14 kWe for small office). The simulation results further indicate that an SOFC has advantages over an HTPEM FCS that originate from its higher exhaust temperature (between 25°C and 315°C), which allows it to meet a greater percentage of the building heating demand (up to 100%). This enables an SOFC to serve a larger percentage of the building stock and a wider variety of building heating systems. Furthermore, if the CHP FCSs are grid independent (i.e., it is not possible to supply electrical power back to the grid), then the heat-to-power ratio of an FCS can be an important parameter. In such a scenario, the heat-to-power ratio of an SOFC (approximately 0.33) is closer to the heat-to-power ratio of a building (approximately 0.081, averaged over an entire year). In a stand-alone configuration, when the CHP DG has a heat-to-power ratio that more closely matches that of the buildings, the utilization of the DG system is likely to be higher and its economics and environmental impacts more favorable.

Pacific Northwest National Laboratory (PNNL) is working with industry to independently monitor up to fifteen distinct 5 kilowatt-electric (kWe) combined heat and power (CHP) high temperature (HT) proton exchange membrane (PEM) fuel cell systems (FCSs) installed in light commercial buildings. This research paper discusses an evaluation of the first six months of measured performance data acquired at a one-second sampling rate from real-time monitoring equipment attached to the FCSs at building sites. Engineering performance parameters are independently evaluated. Based on an analysis of the first few months of measured operating data, FCS performance is consistent with manufacturer-stated performance. Initial data indicate that the FCSs have relatively stable performance and a long term average production of about 4.57 kWe of power. This value is consistent with, but slightly below, the manufacturer’s stated rated electric power output of 5 kWe. The measured system net electric efficiency has averaged 33.7%, based on the higher heating value (HHV) of natural gas fuel. This value, also, is consistent with, but slightly below, the manufacturer’s stated rated electric efficiency of 36%. The FCSs provide low-grade hot water to the building at a measured average temperature of about 48.4°C, lower than the manufacturer’s stated maximum hot water delivery temperature of 65°C. The uptime of the systems is also evaluated. System availability can be defined as the quotient of total operating time compared to time since commissioning. The average values for system availability vary between 96.1 and 97.3%, depending on the FCS evaluated in the field. Performance at Rated Value for electrical efficiency (PRVeff) can be defined as the quotient of the system time operating at or above the rated electric efficiency and the time since commissioning. The PRVeff varies between 5.6% and 31.6%, depending on the FCS field unit evaluated. Performance at Rated Value for electrical power (PRVp) can be defined as the quotient of the system time operating at or above the rated electric power and the time since commissioning. PRVp varies between 6.5% and 16.2%. Performance at Rated Value for electrical efficiency and power (PRVt) can be defined as the quotient of the system time operating at or above both the rated electric efficiency and the electric power output compared to the time since commissioning. PRVt varies between 0.2% and 1.4%. Optimization to determine the manufacturer rating required to achieve PRVt greater than 80% has been performed based on the collected data. For example, for FCS unit 130 to achieve a PRVt of 95%, it would have to be down-rated to an electrical power output of 3.2 kWe and an electrical efficiency of 29%.The use of PRV as an assessment metric for FCSs has been developed and reported for the first time in this paper. For FCS Unit 130, a 20% decline in electric power output was observed from approximately 5 kWe to 4 kWe over a 1,500 hour period between Dec. 14th 2011 and Feb. 14th 2012.

The United States (U.S.) Department of Energy (DOE)’s Pacific Northwest National Laboratory (PNNL) is spearheading a program with industry to deploy and independently monitor five kilowatt-electric (kWe) combined heat and power (CHP) fuel cell systems (FCSs) in light commercial buildings. This publication discusses results from PNNL’s research efforts to independently evaluate manufacturer-stated engineering, economic, and environmental performance of these CHP FCSs at installation sites. The analysis was done by developing parameters for economic comparison of CHP installations. Key thermodynamic terms are first defined, followed by an economic analysis using both a standard accounting approach and a management accounting approach. Key economic and environmental performance parameters are evaluated, including (1) the average per unit cost of the CHP FCSs per unit of power, (2) the average per unit cost of the CHP FCSs per unit of energy, (3) the change in greenhouse gas (GHG) and air pollution emissions with a switch from conventional power plants and furnaces to CHP FCSs; (4) the change in GHG mitigation costs from the switch; and (5) the change in human health costs related to air pollution. CHP FCS heat utilization is expected to be less than 100% at several installation sites. Specifically at six of the installation sites, during periods of minimum building heat demand (i.e. summer season), the average in-use CHP FCS heat recovery efficiency based on the higher heating value of natural gas is expected to be only 24.4%. From the power perspective, the average per unit cost of electrical power is estimated to span a range from $15–19,000/kilowatt-electric (kWe) (depending on site-specific changes in installation, fuel, and other costs), while the average per unit cost of electrical and heat recovery power varies between $7,000 and $9,000/kW. From the energy perspective, the average per unit cost of electrical energy ranges from $0.38 to $0.46/kilowatt-hour-electric (kWhe), while the average per unit cost per unit of electrical and heat recovery energy varies from $0.18 to $0.23/kWh. These values are calculated from engineering and economic performance data provided by the manufacturer (not independently measured data). The GHG emissions were estimated to decrease by one-third by shifting from a conventional energy system to a CHP FCS system. The GHG mitigation costs were also proportional to the changes in the GHG gas emissions. Human health costs were estimated to decrease significantly with a switch from a conventional system to a CHP FCS system. A unique contribution of this paper, reported for the first time here, is the derivation of the per unit cost of power and energy for a CHP device from both standard and management accounting perspectives. These expressions are shown in Eq. (21) and Eq. (31) for power, and in Eq. (24) and Eq. (34) for energy. This derivation shows that the average per unit cost of power is equal to the average per unit cost of electric power applying a management accounting approach to this latter calculation. This term is also equal to the average per unit cost of heat recovery power applying a management accounting approach. A similar set of relations hold for the average per unit cost of energy. These derivations underscore the value of using Eq. (21) for economic analyses to represent the average per unit cost of electrical power, heat recovery power, or both, and using and Eq. (24) for energy.

Energy storage has recently attracted significant interest as an enabling technology for integrating stochastic, variable renewable power into the electric grid. To meet the renewable portfolio standards targets imposed by 29 U.S. states and the District of Columbia, electricity production from wind technology has increased significantly. At the same time, wind turbines, like many renewables, produce power in a manner that is stochastic, variable, and non-dispatchable. These attributes introduce challenges to generation scheduling and the provision of ancillary services. To study the impacts of the stochastic variability of wind on regional grid operation and the role that energy storage could play to mitigate these impacts, Pacific Northwest National Laboratory (PNNL) has developed a series of linked, complex techno-economic-environmental models to address two key questions: A) What are the future expanded balancing requirements necessary to accommodate enhanced wind turbine capacity, so as to meet the renewable portfolio standards in 2020? Specific analyses are conducted for the four North American Electric Reliability Corporation (NERC) western subregions. B) What are the most cost-effective technological solutions for providing either fast ramping generation or energy storage to serve these balancing requirements? PNNL applied a stochastic approach to assess the future, expanded balancing requirements for the four western subregions with high wind penetration in 2020. The estimated balancing requirements are quantified for four subregions: Arizona-New Mexico-Southern Nevada (AZ-NM-SNV), California-Mexico (CA-MX), Northwest Power Pool (NWPP), and Rocky Mountain Power Pool (RMPP). Model results indicate that the new balancing requirements will span a spectrum of frequencies, from minute-to-minute variability (intra-hour balancing) to those indicating cycles over several hours (inter-hour balancing). The sharp ramp rates in the intra-hour balancing are of significant concern to grid operators. Consequently, this study focuses on analyzing the intra-hour balancing needs. A detailed, life-cycle cost (LCC) modeling effort was used to assess the cost competitiveness of different technologies to address the future intra-hour balancing requirements. Technological solutions considered include combustion turbines, sodium sulfur (NaS) batteries, lithium ion (Li-ion) batteries, pumped-hydro energy storage (PHES), compressed air energy storage (CAES), flywheels, redox flow batteries, and demand response (DR). Hybrid concepts were also evaluated. For each technology, distinct power and energy capacity requirements are estimated. LCC results for the sole application of intra-hour balancing indicate that the most cost competitive technologies include Na-S batteries, flywheels, and Li-ion assuming future cost reductions. Demand response using smart charging strategies was found to also be cost-competitive with natural gas combustion turbines. This finding is consistent among the four subregions and is generally applicable to other regions.

Pacific Northwest National Laboratory (PNNL) is working with industry to independently monitor up to fifteen distinct 5 kilowatt-electric (kWe) combined heat and power (CHP) high temperature (HT) proton exchange membrane (PEM) fuel cell systems (FCSs) installed in light commercial buildings. This research paper discusses an evaluation of the first six months of measured performance data acquired at a one-second sampling rate from real-time monitoring equipment attached to the FCSs at building sites. Engineering performance parameters are independently evaluated. Based on an analysis of the first few months of measured operating data, FCS performance is consistent with manufacturer-stated performance. Initial data indicate that the FCSs have relatively stable performance and a long term average production of about 4.57 kWe of power. This value is consistent with, but slightly below, the manufacturer’s stated rated electric power output of 5 kWe. The measured system net electric efficiency has averaged 33.7%, based on the higher heating value (HHV) of natural gas fuel. This value, also, is consistent with, but slightly below, the manufacturer’s stated rated electric efficiency of 36%. The FCSs provide low-grade hot water to the building at a measured average temperature of about 48.4°C, lower than the manufacturer’s stated maximum hot water delivery temperature of 65°C. The uptime of the systems is also evaluated. System availability can be defined as the quotient of total operating time compared to time since commissioning. The average values for system availability vary between 96.1 and 97.3%, depending on the FCS evaluated in the field. Performance at Rated Value for electrical efficiency (PRVeff) can be defined as the quotient of the system time operating at or above the rated electric efficiency and the time since commissioning. The PRVeff varies between 5.6% and 31.6%, depending on the FCS field unit evaluated. Performance at Rated Value for electrical power (PRVp) can be defined as the quotient of the system time operating at or above the rated electric power and the time since commissioning. PRVp varies between 6.5% and 16.2%. Performance at Rated Value for electrical efficiency and power (PRVt) can be defined as the quotient of the system time operating at or above both the rated electric efficiency and the electric power output compared to the time since commissioning. PRVt varies between 0.2% and 1.4%. Optimization to determine the manufacturer rating required to achieve PRVt greater than 80% has been performed based on the collected data. For example, for FCS unit 130 to achieve a PRVt of 95%, it would have to be down-rated to an electrical power output of 3.2 kWe and an electrical efficiency of 29%.The use of PRV as an assessment metric for FCSs has been developed and reported for the first time in this paper. For FCS Unit 130, a 20% decline in electric power output was observed from approximately 5 kWe to 4 kWe over a 1,500 hour period between Dec. 14th 2011 and Feb. 14th 2012.

To examine the role that energy storage could play in mitigating the impacts of the stochastic variability of wind generation on regional grid operation, the Pacific Northwest National Laboratory (PNNL) examined a hypothetical 2020 grid scenario in which additional wind generation capacity is built to meet renewable portfolio standard targets in the Western Interconnection. PNNL developed a stochastic model for estimating the balancing requirements using historical wind statistics and forecasting error, a detailed engineering model to analyze the dispatch of energy storage and fast-ramping generation devices for estimating size requirements of energy storage and generation systems for meeting new balancing requirements, and financial models for estimating the life-cycle cost of storage and generation systems in addressing the future balancing requirements for sub-regions in the Western Interconnection. Evaluated technologies include combustion turbines, sodium sulfur (Na-S) batteries, lithium ion batteries, pumped-hydro energy storage, compressed air energy storage, flywheels, redox flow batteries, and demand response. Distinct power and energy capacity requirements were estimated for each technology option, and battery size was optimized to minimize costs. Modeling results indicate that in a future power grid with high-penetration of renewables, the most cost competitive technologies for meeting balancing requirements include Na-S batteries and flywheels.

The United States (U.S.) Department of Energy (DOE)’s Pacific Northwest National Laboratory (PNNL) is spearheading a program with industry to deploy and independently monitor five kilowatt-electric (kWe) combined heat and power (CHP) fuel cell systems (FCSs) in light commercial buildings. This publication discusses results from PNNL’s research efforts to independently evaluate manufacturer-stated engineering, economic, and environmental performance of these CHP FCSs at installation sites. The analysis was done by developing parameters for economic comparison of CHP installations. Key thermodynamic terms are first defined, followed by an economic analysis using both a standard accounting approach and a management accounting approach. Key economic and environmental performance parameters are evaluated, including (1) the average per unit cost of the CHP FCSs per unit of power, (2) the average per unit cost of the CHP FCSs per unit of energy, (3) the change in greenhouse gas (GHG) and air pollution emissions with a switch from conventional power plants and furnaces to CHP FCSs; (4) the change in GHG mitigation costs from the switch; and (5) the change in human health costs related to air pollution. CHP FCS heat utilization is expected to be less than 100% at several installation sites. Specifically at six of the installation sites, during periods of minimum building heat demand (i.e. summer season), the average in-use CHP FCS heat recovery efficiency based on the higher heating value of natural gas is expected to be only 24.4%. From the power perspective, the average per unit cost of electrical power is estimated to span a range from $15–19,000/kilowatt-electric (kWe) (depending on site-specific changes in installation, fuel, and other costs), while the average per unit cost of electrical and heat recovery power varies between $7,000 and $9,000/kW. From the energy perspective, the average per unit cost of electrical energy ranges from $0.38 to $0.46/kilowatt-hour-electric (kWhe), while the average per unit cost per unit of electrical and heat recovery energy varies from $0.18 to $0.23/kWh. These values are calculated from engineering and economic performance data provided by the manufacturer (not independently measured data). The GHG emissions were estimated to decrease by one-third by shifting from a conventional energy system to a CHP FCS system. The GHG mitigation costs were also proportional to the changes in the GHG gas emissions. Human health costs were estimated to decrease significantly with a switch from a conventional system to a CHP FCS system. A unique contribution of this paper, reported for the first time here, is the derivation of the per unit cost of power and energy for a CHP device from both standard and management accounting perspectives. These expressions are shown in Eq. (21) and Eq. (31) for power, and in Eq. (24) and Eq. (34) for energy. This derivation shows that the average per unit cost of power is equal to the average per unit cost of electric power applying a management accounting approach to this latter calculation. This term is also equal to the average per unit cost of heat recovery power applying a management accounting approach. A similar set of relations hold for the average per unit cost of energy. These derivations underscore the value of using Eq. (21) for economic analyses to represent the average per unit cost of electrical power, heat recovery power, or both, and using and Eq. (24) for energy.

Stationary combined heat and power (CHP) fuel cell systems (FCSs) can provide electricity and heat for buildings and can reduce greenhouse gas (GHG) emissions significantly if they are configured with an appropriate installation and operating strategy. The maximizing emission reduction and economic saving simulator (MERESS) is an optimization tool that was developed to evaluate novel strategies for installing and operating CHP FCSs in buildings. These novel strategies include networking, load following, and the use of variable heat-to-power ratios, all of which industry typically has not implemented. A primary goal of models like MERESS is to use relatively inexpensive simulation studies to identify more financially and environmentally effective ways to design and install FCSs. Models like MERESS can incorporate the pivotal choices that FCS manufacturers, building owners, emission regulators, competing generators, and policy makers make, and empower them to evaluate the effect of their choices directly. MERESS directly evaluates trade-offs among three key goals: GHG reductions, energy cost savings for building owners, and high sales revenue for FCS manufacturers. MERESS allows one to evaluate these design trade-offs and to identify the optimal control strategies and building load curves for installation based on either (1) maximum GHG emission reductions or (2) maximum cost savings to building owners. Part I discusses the motivation and key assumptions behind MERESS model development. Part II discusses run results from MERESS for a California town and makes recommendations for further FCS installments (Colella , 2011, “Optimizing the Design and Deployment of Stationary Combined Heat and Power Fuel Cell Systems for Minimum Costs and Emissions—Part II: Model Results,” ASME J. Fuel Cell Sci. Technol., 8(2), p. 021002).