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Search indexed NASA NTRS and DOE OSTI research on propulsion, heat transfer, battery materials and energy systems. Follow report and document links to the original sources.

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At least 37 records · Page 2

Simple Retrofit High-Efficiency Natural Gas Water Heater Field Test

High performance water heaters are typically more time consuming and costly to install in retrofit applications, making high performance water heaters difficult to justify economically. However, recent advancements in high performance water heaters have targeted the retrofit market, simplifying installations and reducing costs. Four high efficiency natural gas water heaters designed specifically for retrofit applications were installed in single-family homes along with detailed monitoring systems to characterize their savings potential, their installed efficiencies, and their ability to meet household demands. The water heaters tested for this project were designed to improve the cost-effectiveness and increase market penetration of high efficiency water heaters in the residential retrofit market. The retrofit high efficiency water heaters achieved their goal of reducing costs, maintaining savings potential and installed efficiency of other high efficiency water heaters, and meeting the necessary capacity in order to improve cost-effectiveness. However, the improvements were not sufficient to achieve simple paybacks of less than ten years for the incremental cost compared to a minimum efficiency heater. Significant changes would be necessary to reduce the simple payback to six years or less. Annual energy savings in the range of $200 would also reduce paybacks to less than six years. These energy savings would require either significantly higher fuel costs (greater than $1.50 per therm) or very high usage (around 120 gallons per day). For current incremental costs, the water heater efficiency would need to be similar to that of a heat pump water heater to deliver a six year payback.

32 ENERGY CONSERVATION, CONSUMPTION, AND UTILIZATI↗

Simple Retrofit High-Efficiency Natural Gas Water Heater Field Test

High-performance water heaters are typically more time consuming and costly to install in retrofit applications, making high performance water heaters difficult to justify economically. However, recent advancements in high performance water heaters have targeted the retrofit market, simplifying installations and reducing costs. Four high efficiency natural gas water heaters designed specifically for retrofit applications were installed in single-family homes along with detailed monitoring systems to characterize their savings potential, their installed efficiencies, and their ability to meet household demands. The water heaters tested for this project were designed to improve the cost-effectiveness and increase market penetration of high efficiency water heaters in the residential retrofit market. The retrofit high efficiency water heaters achieved their goal of reducing costs, maintaining savings potential and installed efficiency of other high efficiency water heaters, and meeting the necessary capacity in order to improve cost-effectiveness. However, the improvements were not sufficient to achieve simple paybacks of less than ten years for the incremental cost compared to a minimum efficiency heater. Significant changes would be necessary to reduce the simple payback to six years or less. Annual energy savings in the range of $200 would also reduce paybacks to less than six years. These energy savings would require either significantly higher fuel costs (greater than $1.50 per therm) or very high usage (around 120 gallons per day). For current incremental costs, the water heater efficiency would need to be similar to that of a heat pump water heater to deliver a six year payback.

03 NATURAL GAS↗

Building America Case Study: Simple Retrofit High-Efficiency Natural Gas Water Heater Field Test, Minneapolis, Minnesota

High performance water heaters are typically more time consuming and costly to install in retrofit applications, making high performance water heaters difficult to justify economically. However, recent advancements in high performance water heaters have targeted the retrofit market, simplifying installations and reducing costs. Four high efficiency natural gas water heaters designed specifically for retrofit applications were installed in single-family homes along with detailed monitoring systems to characterize their savings potential, their installed efficiencies, and their ability to meet household demands. The water heaters tested for this project were designed to improve the cost-effectiveness and increase market penetration of high efficiency water heaters in the residential retrofit market. The retrofit high efficiency water heaters achieved their goal of reducing costs, maintaining savings potential and installed efficiency of other high efficiency water heaters, and meeting the necessary capacity in order to improve cost-effectiveness. However, the improvements were not sufficient to achieve simple paybacks of less than ten years for the incremental cost compared to a minimum efficiency heater. Significant changes would be necessary to reduce the simple payback to six years or less. Annual energy savings in the range of $200 would also reduce paybacks to less than six years. These energy savings would require either significantly higher fuel costs (greater than $1.50 per therm) or very high usage (around 120 gallons per day). For current incremental costs, the water heater efficiency would need to be similar to that of a heat pump water heater to deliver a six year payback.

32 ENERGY CONSERVATION, CONSUMPTION, AND UTILIZATI↗

Life Cycle Assessment of Future Photovoltaic Electricity Production from Residential-scale Systems Operated in Europe

The photovoltaics (PV) industry is growing rapidly to meet the increasing demand of green power. As the industry grows, the manufacturing processes and the material and energy efficiencies of PV cells and panels are improving. To assess the impacts of this trend, future scenarios of single-crystalline (single-Si, also known as mono-crystalline) silicon and cadmium-telluride (CdTe) PV systems installed on European residences were established. Assessment of the improvement potential of PV electricity-generating technologies such as single-Si and CdTe could be considered in long-term energy strategy decisions. This study aims to provide scenario-based information about the environmental per-formance of single-Si and CdTe PV modules produced and operated in the far future (2030 to 2050). The deployment application assessed considers European residential roofs. We made scenario-dependent projections of key parameters for single-Si and CdTe PV panels manufactured in 2050. The parameters included cell efficiency, module efficiency, wafer thickness, cutting losses, kerf losses, silver use, glass thickness and operational lifetime. This study combines developments for these parameters with projections of the environmental performance of electricity mixes in the main manufacturing countries/regions (European Union, China and the United States of America) and with projections of the environ-mental performance of basic material production (aluminium, copper, magnesium, nickel, pig iron, zinc, clinker and flat glass) in the far future. The three scenarios used in the assessment of future PV electricity were categorized into three classes: 'business as usual' (BAU), 'realistic improvement' (REAL) and 'optimistic improvement' (OPT). It estimates the current life cycle greenhouse gas emissions of single-Si PV electricity produced on the roofs of European residences to be approximately 80 grams CO2-equi-valent per kWh (g CO2-eq per kWh). Based on the projected changes to key parameters and the background system, life cycle greenhouse gas (GHG) emissions could be reduced to 65% (scenario BAU), 31% (scenario REAL) and 18% (scenario OPT) of that value in the far future. Results for other life cycle assessment (LCA) metrics are also assessed in this study such as: non-renewable cumulative energy demand, acidification potential, human toxicity potential, photochemical ozone creation potential, particulate matter formation potential, and land use. We calculated the total energy payback time (EPBT) and the non-renewable energy payback time (NREPBT) in the far future of single-crystalline silicon-based PV panels operated in Europe by dividing the estimate of non-renewable cumulative energy demand of PV electricity for the given scenario by the non-renewable cumulative energy demand of the scenario-dependent national and regional non-renewable residual electricity mixes. The study estimates the payback time could be reduced from 2.4 years today to 1.7, 1.2 and 1.2 years (scenarios BAU, REAL and OPT, respectively) in the far future, based on the assumptions and projections in the analysis. It finally estimates the current life cycle greenhouse gas emissions of CdTe PV electricity produced on the roofs of European residences to be approximately 30 g CO2-eq per kWh. Based on the projected changes to key parameters and the background system, life cycle GHG emissions could be reduced to 70% (scenario BAU), 44% (scenario REAL) and 32% (scenario OPT) of that value in the far future.

14 SOLAR ENERGY↗

Techno-economic analysis of the impact of dynamic electricity prices on solar penetration in a smart grid environment with distributed energy storage

This study investigates the technical and economic feasibility of using high levels of solar energy penetration up to 400 MW into a smart grid system of 60,000 smart houses. A novel non-cooperative Stackelberg game is introduced that incorporates the profitability of the supply-side and helps in solving problems related to overgeneration and photovoltaic curtailment. The non-cooperative game is intended to find the optimal dynamic prices that would leverage distributed storage through the demand-side to stabilize the power grid operation. Ten cases are studied with five photovoltaic plant sizes and two battery designs. Here, a novel quantitative analysis of high levels of solar penetration as a percentage of the total electricity demand is introduced to evaluate the technical feasibility of the studied cases. To evaluate the economic viability of the proposed smart grid system, four metrics were used: the levelized cost of energy, the levelized cost of storage, the payback period, and the net present value. Two out of ten studied cases were concluded to be the most promising cases, one with a solar photovoltaic plant size of 200 MW and the other with 300 MW. The case with 300 MW solar plant is preferred as it paves the way for more solar energy deployment with a solar penetration percentage up to 67.78%. This case had a payback period of 10.72 years and a net present value of $\$51.44$ M for the solar plant and a payback period of 12.06 years and a net present value of $\$40.75$ M for the demand-side.

14 SOLAR ENERGY↗

Solving the duck curve in a smart grid environment using a non-cooperative game theory and dynamic pricing profiles

With the intermittency that comes with electricity generation from renewables, utilizing dynamic pricing will encourage the demand-side to respond in a smart way that would minimize the electricity costs and flatten the net electricity demand curve. Determining the optimal dynamic pricing profile that would leverage distributed storage to flatten the curve is a novel idea that needs to be studied. Moreover, the economic feasibility of utilizing distributed electrical energy storage is still not given in the literature. Therefore, in this paper, a novel way of solving a citywide dynamic model using a bilevel programming algorithm is introduced. The problem is developed as a novel non-cooperative Stackelberg game that utilizes air-conditioning systems and electrical storage through the end-users to determine the optimal dynamic pricing profile. The results show that the combined effect of utilizing demand-side air-conditioning systems and distributed storage together can flatten the curve while employing the optimal dynamic pricing profile. An economic study is performed to determine the economic feasibility of 20 different cases with different battery designs and the level of solar penetration. Three metrics were used to evaluate the economic performance of each case: the levelized cost of storage, the levelized cost of energy, and the simple payback period. Most cases had levelized cost of storage values lower than 0.457 $/kWh, which is the lower bound available in the literature. Seven out of 16 cases have a simple payback period shorter than the lifetime of the system (25 years). The case with a 100 MW PV power plant and a battery storage of size 597 MWh, was found to be the most promising case with a simple payback period of 12.71 years for the photovoltaic plant and 19.86 years for the demand-side investments.

29 ENERGY PLANNING, POLICY, AND ECONOMY↗

Commercial Building Planning and Retrofitting Strategy for Grid Services

The increasing integration of distributed energy resources (DERs) plays an important role in improving energy consumption efficiency. In September 2020, the Federal Energy Regulatory Commission (FERC) approved Order 2222 which opens wholesale electricity markets to small capacity DERs. The benefit of this new FERC Order 2222 is that DERs, such as rooftop solar panels and batteries, will be able to participate in regional electricity markets and provide grid services. Meanwhile, the planning and operation strategies of DERs are facing new challenges to account for the impact of the wholesale market with numerous uncertainty factors. Therefore, in this paper, we propose a new planning and retrofitting model for long-term commercial buildings that considers both DER investment and market participation. Specifically, we explore the capability of implementing DERs for grid services. The effectiveness of the proposed model is validated using real-world data. Simulation results also validate that participating in grid services can significantly increase revenues through appropriate building energy management and shorten the payback period of DER investments.

building energy management↗

WorkingFluid Selection and Technoeconomic Optimization of a Turbocompression CoolingSystem

Abstract Low grade waste heat recovery presents an opportunity to utilize typically wasted energy to reduce overall energy consumption and improve system efficiencies. In this work, the technoeconomic performance of a turbocompression cooling system (TCCS) driven by low grade waste heat in the engine coolant of a large marine diesel generator set is investigated. Five different working fluids were examined to better understand the effects of fluid characteristics on system performance: R134a, R245fa, R1234ze(E), R152a, and R600a. A coupled thermodynamic, heat exchanger, and economic simulation was developed to calculate the simple payback period of the waste heat recovery system, which was minimized using a search and find optimization routine with heat exchanger effectiveness as the optimization parameter. A sensitivity study was performed to understand which heat exchanger effectiveness had the largest impact on payback period. Of the five working fluids examined, a TCCS with R152a as the working fluid had the lowest payback period of 1.46 years with an initial investment of $181,846. The R152a system was most sensitive to the two-phase region of the power cycle condenser. The R1234ze(E) system provided the largest return on investment over a ten year lifetime of $1,399,666.

Engineering↗

Business Case for a Micro-Combined Heat and Power Fuel Cell System in Commercial Applications

Combined heat and power fuel cell systems (CHP-FCSs) provide consistent electrical power and hot water with greater efficiency and lower emissions than alternative sources. These systems can be used either as baseload, grid-connected, or as off-the-grid power sources. This report presents a business case for CHP-FCSs in the range of 5 to 50 kWe. Systems in this power range are considered micro-CHP-FCS. For this particular business case, commercial applications rather than residential or industrial are targeted. To understand the benefits of implementing a micro-CHP-FCS, the characteristics that determine their competitive advantage must first be identified. Locations with high electricity prices and low natural gas prices are ideal locations for micro-CHP-FCSs. Fortunately, these high spark spread locations are generally in the northeastern area of the United States and California where government incentives are already in place to offset the current high cost of the micro-CHP-FCSs. As a result of the inherently high efficiency of a fuel cell and their ability to use the waste heat that is generated as a CHP, they have higher efficiency. This results in lower fuel costs than comparable alternative small-scale power systems (e.g., microturbines and reciprocating engines). A variety of markets should consider micro-CHP-FCSs including those that require both heat and baseload electricity throughout the year. In addition, the reliable power of micro-CHP-FCSs could be beneficial to markets where electrical outages are especially frequent or costly. Greenhouse gas emission levels from micro-CHP-FCSs are 69 percent lower, and the human health costs are 99.9 percent lower, than those attributed to conventional coal-fired power plants. As a result, FCSs can allow a company to advertise as environmentally conscious and provide a bottom-line sales advantage. As a new technology in the early stages of adoption, micro-CHP-FCSs are currently more expensive than alternative technologies. As the technology gains a foothold in its target markets and demand increases, the costs will decline in response to improved manufacturing efficiencies, similar to trends seen with other technologies. Transparency Market Research forecasts suggest that the CHP-FCS market will grow at a compound annual growth rate of greater than 27 percent over the next 5 years. These production level increases, coupled with the expected low price of natural gas, indicate the economic payback period will move to less than 5 years over the course of the next 5 years. To better understand the benefits of micro-CHP-FCSs, The U.S. Department of Energy worked with ClearEdge Power to install fifteen 5-kWe fuel cells in the commercial markets of California and Oregon. Pacific Northwest National Laboratory is evaluating these systems in terms of economics, operations, and their environmental impact in real-world applications. As expected, the economic analysis has indicated that the high capital cost of the micro-CHP-FCSs results in a longer payback period than typically is acceptable for all but early-adopter market segments. However, a payback period of less than 3 years may be expected as increased production brings system cost down, and CHP incentives are maintained or improved.

CHP, business case↗

Energy-Efficient and Comfortable Buildings through Multivariate Integrated Control (ECoMIC)

This project aims to develop an integrated control solution for enhanced energy efficiency and user comfort in commercial buildings. The developed technology is a zone-based control framework that minimizes energy usage while maintaining occupants’ visual and thermal comfort through control of electric lights, motorized venetian blinds and thermostats. The control framework is designed following a modular, scalable and flexible architecture to facilitate easy integration with exiting building management systems. The control framework contains two key algorithms: 1) the lighting load balancing algorithm and 2) the thermostat control algorithm. The lighting load balancing algorithm adopts a model-based closed-loop control approach to determine the optimal electric light and venetian blind settings. It is formulated into an optimization problem with minimizing lighting-related energy consumptions as the objective and delivering adequate task light and preventing daylight glare as the constraints. The thermostat control algorithm is based on a well-established thermal comfort model and formulated as a root-finding problem to dynamically determine the optimal thermostat setpoint for both energy savings and improved thermal comfort. To address building-wide scalability, a system architecture was developed for the zone-based control technology. Three levels of services are defined in the architecture: external services, facility level services and zone level services. The zone-level service includes the control algorithms described above as well as the corresponding interfaces, profiles, sensors and actuators to realize the zone controller. The facility level services connect to the zones through a backbone network, handle supervisory level information and controls, and thus facilitate building-wide scalability. The external services provide communication capability to entities outside of the building for grid interaction and remote access. Various aspects of the developed control technology were evaluated and verified through both simulations and testbed implementations. Simulations coupling a DOE medium office reference building in EnergyPlus building simulation software and a prototype controller in Matlab were performed. During summer time in a mixed-humid climate zone, the simulations revealed reductions of 27% and 42% in electric lighting load and cooling load, respectively, when compared to an advanced base case with daylight dimming and blinds automatically tilted to block direct sun. Two single-room testbeds were established. The testbed at Philips Lighting business building (Rosemont, IL) was designed for quantifying energy performance of integrated controls. This particular implementation achieved 40% and 79% savings on lighting and HVAC energy, respectively, compared to a relatively simple base case operated on predefined schedules. While the resulting energy savings was very encouraging, it should be noted that there may be several caveats associated with it. 1) The test was run during late spring and early summer, and the savings numbers might not be directly used to extrapolate the annual energy savings. 2) Due to the needs for separate control and metering of the small-scale demonstrator within a large building, the HVAC system, hence the corresponding savings, did not represent a typical energy code-compliant design. 3) The light level in the control case was regulated at a particular setpoint, which was lower than then the full-on light level in the base case, and the savings resulted from tuning down the light level to the setpoint was not attributable to the contribution of the developed technology. The testbed at the Lawrence Berkeley National Laboratory (Berkeley, CA) specifically focused on glare control integration, and has demonstrated the feasibility and capability of the glare detection and prevention technique. While the short one-month test in this testbed provided a functional indication of the developed technology, and it would require at least a full solstice-to-solstice cycle to ruinously quantify the performance, which was not possible within the project timeframe. There are certain limitations inherited from the operational assumptions, which could potentially affect the effectiveness and applicability of the developed control technologies. The system takes a typical ceiling-mounting approach for the photosensor locations, and therefore, the control performance relies on proper commissioning or the built-in intelligence of the photosensor for pertinent task light level estimations. For spaces where daylight penetration diminishes significantly deeper into the zone, certain modification to the control algorithms is required to accommodate multiple lighting control subzones and the corresponding sensors for providing a more uniform light level across the entire zone. Integrated control of visual and thermal comfort requires the lighting control zone and thermal control zone to coincide with each other. In other words, the area illuminated by a lighting circuit needs to be the same area served by the thermostat. Thus, the original zoning will potentially constrain the applicability of this technology in retrofitting projects. This project demonstrated the technical feasibility of a zone-based integrated control technology. From the simulation results and testbed implementations, up to 60% lighting energy savings in daylit areas relative to a “no-controls” case can easily be achieved. A 20% reduction of whole building energy consumption is also attainable. In the aspect of occupant comfort, the testbed demonstrated the ability to maintain specified light level on the workplane while promptly mitigate daylight glare 90% of the time. The control system also managed to maintain the thermal environment at a comfortable level 90% of the time. The aspect of system scalability was guaranteed by the system architecture design, based on which the testbeds were instantiated. Analysis on the aspect of economic benefit has yielded an about 6-year payback time for a medium-sized building, including the installation of all hardware and software, such as motorized blinds and LED luminaires. The payback time can be significantly reduced if part of the hardware is already in place for retrofitting projects. It needs to be noted that since the payback analysis was partly based on the testbed performance results, it is constrained by the caveats associated with the testbed implementations. The main uncertainty lies in the contribution from the space conditioning energy savings as it was non-trivial to realistically configure a room-size HVAC system for directly extrapolating whole-building HVAC energy savings. It is recommended to further evaluate the developed technology at a larger scale, where the lighting and HVAC energy consumption can be realistically measured at the building level, to more rigorously quantify the performance potentials.

32 ENERGY CONSERVATION, CONSUMPTION, AND UTILIZATI↗

Techno-Economic, Feasibility, and Life Cycle Analysis of Renewable Propane: 2025 Update

To clarify the current and future landscape for renewable propane (RP) production, this work evaluates the value proposition of recovering RP from existing and planned hydroprocessed esters and fatty acids (HEFA) biorefineries and surveys emerging technologies under development or deployment. HEFA biorefineries co-produce a propane-rich fuel gas stream, normally used to meet HEFA process heat requirements, from which propane can be recovered and sold to create an additional revenue stream alongside liquid transportation fuels such as renewable diesel (RD) and sustainable aviation fuel (SAF). This report updates and extends a 2022 analysis of RP recovery from HEFA facilities by escalating capital and operating costs to 2024 prices, incorporating recent policy developments (including the Section 45Z Clean Fuel Production Credit), evaluating RP recovery for both RD- and SAF-focused HEFA facilities at two scales (3,000 and 75,000 barrels per day of feedstock), and quantifying the impact of RP recovery on HEFA liquid-fuel carbon intensity (CI) and associated tax credits using the 45ZCF-GREET model. For a 3,000 BPD RD-focused HEFA facility, approximately 3.5 million gallons per year (MGPY) of RP can be recovered; in this base case, the estimated payback period is 18 months based on the total installed cost of the RP recovery equipment and 36 months based on the total capital investment for the entire RP recovery project. The payback period is slightly shorter for the analogous SAF-focused configuration (approximately 4.3 MGPY RP). Sensitivity analysis shows that CAPEX magnitude, RP recovery plant scale, and CI-driven tax credit valuations are the dominant determinants of project viability. RP recovery may increase the CI of HEFA liquid fuels, which can reduce liquid-fuel tax credits (a key revenue stream for the HEFA biorefinery) and lengthen payback periods. However, RP recovery generally remains economically favorable across a wide range of plausible scenarios and market conditions. The report also summarizes emerging pathways that could expand future RP supply.

09 BIOMASS FUELS↗

Comparative economics of space resource utilization

Physical economic factors such as mass payback ratio, total payback ratio, and capital payback time are discussed and used to compare the economics of using resources from the Moon, Mars and its moons, and near Earth asteroids to serve certain near term markets such as propellant in low Earth orbit or launched mass reduction for lunar and Martian exploration. Methods for accounting for the time cost of money in simple figures of merit such as MPRs are explored and applied to comparisons such as those between lunar, Martian, and asteroidal resources. Methods for trading off capital and operating costs to compare schemes with substantially different capital to operating cost ratio are presented and discussed. Areas where further research or engineering would be extremely useful in reducing economic uncertainty are identified, as are areas where economic merit is highly sensitive to engineering performance - as well as areas where such sensitivity is surprisingly low.

Cutler, Andrew Hall↗

Economic Sizing of Batteries for the Smart Home: Preprint

This paper presents a methodology to economically size a home battery based on parametric analysis using home energy management system (HEMS) software to optimally dispatch the battery along with controllable loads under several use cases. We account for connected equipment, controls, renewable resources, and other factors such as building characteristics and utility tariffs. The paper defines an analytical pathway for such a sizing tool, develops initial sizing guidance, and clarifies technical and market opportunities for home batteries in the context of existing and emerging equipment and control technologies. A parametric analysis that included 132 scenarios has been performed based on different combinations of pertinent parameters. Results indicate that four variables dominate the decision-making process: application scenarios (new construction or retrofit), utility tariffs, existence of HEMS, and the anticipated payback time. Life-cycle cost analysis indicated that in the absence of utility incentives, batteries plus HEMS have a payback time of longer than 10 years for new construction under a time-of-use rate structure and feed-in tariff; larger batteries have a longer payback time but may provide more benefits to utilities on reducing power backfeed under certain circumstances.

32 ENERGY CONSERVATION, CONSUMPTION, AND UTILIZATI↗

Applying Value at Risk Analysis towards Energy Efficiency Investments

Value at Risk (VaR) is a measure of risk for potential losses within a portfolio of investments. Investments in energy efficiency in a manufacturing environment compete in terms of payback period, ease of investment, and transaction costs with other investments (production, safety, engineering, etc.). Because manufacturers have limited amounts of capital to allocate, investments in productivity tend to be prioritized over energy efficiency projects that offer similar paybacks. Value at Risk (VaR) can be used to quantify how risk-weighted expenditures change over time. Energy efficiency investments are often believed to offer relatively stable payoffs compared to changes in production and other assets, particularly when evaluated using methodologies such as simple payback. Incorporating methodologies such as VaR can provide a stronger business case for energy efficiency investments by quantifying value beyond what is captured in other Return on Investment calculations.In this paper we outline a methodology for applying VaR in the context of the variety of investments made by manufacturing organizations. Additionally, we profile the stability of energy efficiency (EE) and renewable energy (RE) investments compared to other types of investments made in manufacturing. By applying VaR to these investments, energy managers can better translate the financial benefits of energy-related capital projects in a way that is more compelling to Corporate Finance and Treasury departments. This common language also allows Corporate Finance and Treasury departments to support large, strategic deployments of capital for such projects based on a targeted objective – the management of financial risk for the organization’s shareholders.

Levine, Eli↗

An Updated Life Cycle Assessment of Utility-Scale Solar Photovoltaic Systems Installed in the United States

Given the high deployment targets for solar photovoltaics (PV) needed to meet U.S. decarbonization goals, and the limited carbon budget remaining to limit global temperature rise, accurate accounting of the energy-use and greenhouse-gas emissions over the life-cycle of PV systems is needed. In the United States, most PV systems are large utility-scale systems which use single-axis trackers and central inverters, which are not commonly examined in existing life-cycle assessment (LCA) literature. In this study, we present a cradle-to-grave LCA of a typical silicon U.S. utility PV (UPV) installation which is consistent with the utility system features documented in the annual NREL PV system cost benchmark reports. We analyze and present results for four main metrics: cumulative energy demand (CED), greenhouse gas (GHG) emissions, energy payback time (EPBT), and carbon payback time (CPBT). We consider six primary manufacturing options: three based on an imported PV module supply chain (comparing low-carbon imports, high-carbon imports, and average imports), and three based on a potential domestic PV module supply chain (comparing low-carbon U.S. regions, high-carbon U.S. regions, and average U.S. regions). These manufacturing options were then paired with installation locations to create six main cases: low-carbon options were installed in Phoenix (Arizona), high-carbon options were installed in Seattle (Washington), and average options were installed in Fredonia (Kansas). These locations were selected to represent a range of irradiance and grid mixes in the United States, in order to illustrate the likely range of EPBTs and CPBTs possible across the United States. For all six cases, a sensitivity analysis for end-of-life (EOL) handling was explored to capture current and future management options: landfilling, partial recycling, and high-quality recycling. For the purposes of this report, the benchmark system was defined to use an average imported supply chain with partial recycling, installed in Fredonia (Kansas). CED results show ratios at or below 0.1 MJ oil-eq /MJgenerated which demonstrates efficient use of primary energy resources (below a 1:1 ratio), and represents a slight improvement over previous results in literature. GHG emissions per kWh range from 10-36 g CO 2 e, which are consistent with or lower than previous results published by NREL and IEA-PVPS. We use a graphical approach for calculating EPBT and CPBT in this report, which improves upon methods typically used in literature by accounting for non-linearity and avoiding data quality issues associated with long-term projections. EPBT was determined to vary from 0.5 to 1.2 years, with a benchmark EPBT of 0.6 years; CPBT was shown to vary from 0.8 to 20 years, with benchmark CPBT of 2.1 years, which is lower than other estimates from recent literature (typically >2 years).

14 SOLAR ENERGY↗

The economic impacts of carbon emission trading scheme on building retrofits: A case study with U.S. medium office buildings

As a popular emission reduction tool, the carbon emission trading scheme (ETS) can potentially add an economic incentive for building owners to retrofit buildings in addition to the cost savings in energy. However, the additional economic benefits of building retrofits brought by ETS has not been quantitively investigated yet. Here, in order to fill this gap, this study proposed a systematic economic evaluation method to investigate the economic impacts of ETS on building retrofits. The reduction of the payback period and the increase of the return on investment are adopted as evaluation metrics. Using medium office buildings as an example, this study predicted the economic impacts of ETS on building retrofits at four locations in the U.S., and three different carbon prices were investigated. The results show that carbon prices have significant economic impacts on building retrofits. With the relatively low forecasted time-variant carbon prices (around 10 USD per ton), the economic impacts of ETS on building retrofits are small. When carbon prices increase, the impacts of ETS would be up to 25% for 50 USD per ton (current prices in European Union) and 51% for 100 USD per ton. Furthermore, locations with more fossil energy have higher relative changes in the payback period and ROI but are more sensitive to carbon prices.

29 ENERGY PLANNING, POLICY, AND ECONOMY↗

A Demonstration System for Capturing Geothermal Energy from Mine Waters beneath Butte, Montana

Executive Summary An innovative 50-ton ground-source heat pump (GSHP) system was installed to provide space heating and cooling for a 56,000 square foot (5,200 square meter) building in Butte Montana, in conjunction with its heating and chiller systems. Butte is a location with winter conditions much colder than the national average. The GSHP uses flooded mine waters at 78F (25C) as the heat source and heat sink. The heat transfer performance and efficiency of the system were analyzed using data from January through July 2014. This analysis indicated that for typical winter conditions in Butte, Montana, the GSHP could deliver about 88% of the building’s annual heating needs. Compared with a baseline natural-gas/electric system, the system demonstrated at least 69% site energy savings, 38% source energy savings, 39% carbon dioxide emissions reduction, and a savings of $17,000 per year (40%) in utility costs. Assuming a $10,000 per ton cost for installing a production system, the payback period at natural gas costs of $9.63/MMBtu and electricity costs of $0.08/kWh would be in the range of 40 to 50 years. At higher utility prices, or lower installation costs, the payback period would obviously be reduced.

32 ENERGY CONSERVATION, CONSUMPTION, AND UTILIZATI↗

JUSTIFI: Software for Improving Performance Objectives via Energy Efficiency

With growing energy supply concerns and rising costs, energy efficiency is a critical component of industrial energy resilience and competitiveness by directly reducing energy operating costs. Energy efficiency projects in manufacturing also yield valuable benefits to other key metrics, such as improved quality, reduced maintenance costs, improved safety, decreased pollution, and enhanced productivity. However, it is difficult to receive approval for energy efficiency projects, so implementation rates are low, even when meeting capital project payback period criteria. The inclusion and quantification of non-energy benefits (NEBs) in the decision-making process for energy efficiency projects can improve the overall financial payback period while demonstrating a positive impact on the firm's key performance metrics and business strategy. Despite their significant financial and strategic value, NEBs are rarely factored into decision-making due to lack of tools to effectively identify and quantify them. Therefore, a comprehensive and integrative approach is needed for the rapidly evolving energy landscape. To address these challenges, through funding from U.S. Department of Energy, our new assessment methodology integrates common continuous improvement six sigma concepts, such as the DMAIC process, and a protocol of guiding questions, into energy efficiency assessments to identify NEBs. We have also developed open-source software, JUSTIFI, to guide users through this process, data collection, and quantification. It is designed to be used concurrently with DOE energy system analysis software suite, MEASUR. Our methodology and tools inform energy assessors, firm engineering, decision makers, and workforce seeking to increase energy resilience and to maximize benefits aligned with performance metrics.

29 ENERGY PLANNING, POLICY, AND ECONOMY↗