The utility of energy storage to improve the economics of wind–diesel power plants in Canada

Wind energy systems have been considered for Canada's remote communities in order to reduce their costs and dependence on diesel fuel to generate electricity. Given the high capital costs, low-penetration wind–diesel systems have been typically found not to be economic. High-penetration wind–diesel systems have the benefit of increased economies of scale, and displacing significant amounts of diesel fuel, but have the disadvantage of not being able to capture all of the electricity that is generated when the wind turbines operate at rated capacity.Two representative models of typical remote Canadian communities were created using HOMER, an NREL micro-power simulator to model how a generic energy storage system could help improve the economics of a high-penetration wind–diesel system. Key variables that affect the optimum system are average annual wind speed, cost of diesel fuel, installed cost of storage and a storage systems overall efficiency. At an avoided cost of diesel fuel of 0.30 $Cdn/kWh and current installed costs, wind generators are suitable in remote Canadian communities only when an average annual wind speed of at least 6.0 m/s is present. Wind energy storage systems become viable to consider when average annual wind speeds approach 7.0 m/s, if the installed cost of the storage system is less than 1000 $Cdn/kW and it is capable of achieving at least a 75% overall energy conversion efficiency. In such cases, energy storage system can enable an additional 50% of electricity from wind turbines to be delivered.     

Hydrogen as a long-term,large-scale energy storage solution when coupled with renewable energy sources or grids with dynamic electricity pricing schemes

One of the key challenges that still facing the adoption of renewable energy systems is having a powerful energy storage system (ESS) that can store energy at peak production periods and return it back when the demand exceeds the supply. In this paper, we discuss the costs associated with storing excess energy from power grids in the form of hydrogen using proton exchange membrane (PEM) reversible fuel cells (RFC). The PEM-RFC system is designed to have dual functions: (1) to use electricity from the wholesale electricity market when the wholesale price reaches low competitive values, use it to produce hydrogen and then convert it back to electricity when the prices are competitive, and (2) to produce hydrogen at low costs to be used in other applications such as a fuel for fuel cell electric vehicles. The main goal of the model is to minimize the levelized cost of energy storage (LCOS), thus the LCOS is used as the key measure for evaluating this economic point. LCOS in many regions in United States can reach competitive costs, for example lowest LCOS can reach 16.4¢/kWh in Illinois (MISO trading hub) when the threshold wholesale electricity price is set at $25/MWh, and 19.9¢/kWh in Texas (ERCOT trading hub) at threshold price of $20/MWh. Similarly, the levelized cost of hydrogen production shows that hydrogen can be produced at very competitive costs, for example the levelized cost of hydrogen production can reach $2.54/kg-H₂ when using electricity from MISO hub. This value is close to the target set by the U.S. Department of Energy.     

Seamless electricity trade between Canada and US Northeast

We analyze how the wholesale electricity market deregulation could modify exchanges between three Canadian regions (Ontario, Quebec and New Brunswick) and two US regions (New York and New England), on the base of their loads and available resources when the regulatory change took place in 1997. We find that the pre-1997 exchanges already made possible fuel cost savings of $397.2 million per year while deregulation adds annual savings of $358.7 million. Canadian regions are the main beneficiaries under the assumption that exports are priced at the marginal costs of the importing regions. Imports from the Canadian regions, although significant, are not large enough to lower the marginal costs of the US regions. Hence electricity deregulation across the border should not significantly decrease prices in the US regions although the latter are becoming more dependent upon imports from Canada. Greenhouse gas emissions increase by 4.3 Mt CO₂ eq. in the wake of the open wholesale electricity market because of the low cost of coal, particularly in Ontario. Environmental concerns and the limited availability of additional hydroelectric power in Canada could change the trade patterns as electricity demand continue to grow.     

The delivery of low-cost,low-carbon rural energy services

The provision of both electrical and mechanical energy services can play a critical role in poverty alleviation for the almost two billion rural users who currently lack access to electricity. Distributed generation using diesel generators remains a common means of electricity provision for rural communities throughout the world. Due to rising fuel costs, the need to address poverty, and consequences of global warming, it is necessary to develop cost efficient means of reducing fossil fuel consumption in isolated diesel microgrids. Based on a case study in Nicaragua, a set of demand and supply side measures are ordered by their annualized costs in order to approximate an energy supply curve. The curve highlights significant opportunities for reducing the costs of delivering energy services while also transitioning to a carbon-free electrical system. In particular, the study demonstrates the significant cost savings resulting from the implementation of conventional metering, efficient residential lighting, and electricity generation using renewable energy sources.     

External costs from electricity generation of China up to 2030 in energy and abatement scenarios

This paper presents estimated external costs of electricity generation in China under different scenarios of long-term energy and environmental policies. Long-range Energy Alternatives Planning (LEAP) software is used to develop a simple model of electricity demand and to estimate gross electricity generation in China up to 2030 under these scenarios. Because external costs for unit of electricity from fossil fuel will vary in different government regulation periods, airborne pollutant external costs of SO₂, NO_x, PM₁₀, and CO₂ from fired power plants are then estimated based on emission inventories and environmental cost for unit of pollutants, while external costs of non-fossil power generation are evaluated with external cost for unit of electricity. The developed model is run to study the impact of different energy efficiency and environmental abatement policy initiatives that would reduce total energy requirement and also reduce external costs of electricity generation. It is shown that external costs of electricity generation may reduce 24–55% with three energy policies scenarios and may further reduce by 20.9–26.7% with two environmental policies scenarios. The total reduction of external costs may reach 58.2%.     

External costs of fossil electricity generation: Health-based assessment in Thailand

Airborne pollutants from fossil fuel burning in electricity generation potentially contribute a number of consequent environmental impacts. In order to indicate the actual costs of energy, a so-called external cost has become of growing concerns internationally. This study aims to evaluate the external costs related to human health degradation resulting from Thai electricity generation produced from fossil fuel which operated during the period from 2006 to 2008. Impact Pathway Approach (IPA) was applied in the analysis. The advections of the criteria pollutants (SO₂, NO_X, and PM₁₀) including secondary particulates (sulfate and nitrate aerosols) had been simulated using the CALMET/CALPUFF modeling system. Subsequently, the exposure-response functions (ERFs) were used to quantify the marginal damage to public health. Finally, costs of such damages were then estimated based on welfare economics. The results showed that the criteria pollutants caused significant damage to both premature mortality and morbidity. The average damage cost was totally about 600 million 2005 US$ annually which ranged between 0.05 and 4.17 US$ cent kWh⁻¹ depending on fuel types. It implies that the external costs are significant to the determination of electricity market price. With the damage costs being included, the electricity price will reflect the true costs of the generation which will be beneficial to the society as a whole.     

Analysis of CO2 emissions reduction potential in secondary production and semi-fabrication of non-ferrous metals

Industrial sector growth in developing countries requires the provision of alternatives to guarantee sustainable development. Improving energy efficiency and fuel switching are two measures to reduce CO₂ emissions in the industrial sector, with natural gas and low-carbon electricity as the most feasible options in the short term. In this work, a linear programming optimization model has been developed to study the potential of energy efficiency improvement and fuel substitution for CO₂ emissions reduction, at national level in the non-ferrous metals industry. The energy resource/end-use device allocation problem in secondary metal production and semi-fabrication has been modeled. Using this model, the particular case of Colombia, where low-carbon electricity is available, has been studied. By improving energy efficiency, energy use and CO₂ emissions can be reduced significantly, 73% and 72%, respectively, at negative costs. Further CO₂ emissions reductions, up to 88%, are possible with fuel switching to low-carbon electricity, increasing the costs for the energy system; however, cost reductions caused by energy efficiency improvement outweigh cost increments of fuel switching. Benefits achieved with fuel substitution using low-carbon electricity can be lost if hydropower is not available; in such a case, efficient natural gas-fired end-use devices are preferable.     

Use of the task configuration system (TCS) for the design and on-line optimization of power plants operating with variable loads

The main purpose of this work is to show the ability of the TCS (task configuration system) to perform both the design and the operation optimization of power plants. The TCS is a module that permits to set the main task of each one of the equipments of the system and consequently setting how they respond to variable loads. In this work, the TCS was applied to a micro cogeneration plant of 60 kW in which both the electrical and the thermal loads were variable. Primarily, the design optimization of the nominal power of the equipments and of the TCS configuration was performed for the loads and electricity/fuel costs assumed in the design. After this operational optimizations in cases where the loads and electricity/fuel costs were doubled and then halved in relation to the standard case were performed. The results presented the TCS in a very robust way in most of the cases even the operational conditions being very different from the originally assumed. Based on the results, it is possible to defend the use of the TCS to decrease the risk of high initial investments made in cogeneration systems.     

Comparing least cost scenarios for 100% renewable electricity with low emission fossil fuel scenarios in the Australian National Electricity Market

Policy makers face difficult choices in planning to decarbonise their electricity industries in the face of significant technology and economic uncertainties. To this end we compare the projected costs in 2030 of one medium-carbon and two low-carbon fossil fuel scenarios for the Australian National Electricity Market (NEM) against the costs of a previously published scenario for 100% renewable electricity in 2030. The three new fossil fuel scenarios, based on the least cost mix of baseload and peak load power stations in 2010, are: (i) a medium-carbon scenario utilising only gas-fired combined cycle gas turbines (CCGTs) and open cycle gas turbines (OCGTs); (ii) coal with carbon capture and storage (CCS) plus peak load OCGT; and (iii) gas-fired CCGT with CCS plus peak load OCGT. We perform sensitivity analyses of the results to future carbon prices, gas prices, and CO₂ transportation and storage costs which appear likely to be high in most of Australia. We find that only under a few, and seemingly unlikely, combinations of costs can any of the fossil fuel scenarios compete economically with 100% renewable electricity in a carbon constrained world. Our findings suggest that policies pursuing very high penetrations of renewable electricity based on commercially available technology offer a cost effective and low risk way to dramatically cut emissions in the electricity sector.     

Biomass and district-heating systems

New technologies for biomass gasification are being developed which increase the potential to cogenerate electricity and may reduce costs compared with steam turbine technology. Cogeneration is a more energy-efficient way to convert biomass into heat and electricity than separate electricity and heat production. The potential to cogenerate electricity in the Swedish district-heating systems is estimated to be 20% of current electricity production when using combined cycle technology. The electricity and heat costs from cogeneration with biomass are higher than the costs from fossil fuel plants at current fuel prices when external costs are excluded.     

Internalizing externalities of electricity generation: An analysis with MESSAGE-MACRO

This paper examines the global impacts of a policy that internalizes the external costs (related to air pollution damage, excluding climate costs) of electricity generation using a combined energy systems and macroeconomic model. Starting point are estimates of the monetary damage costs for SO₂, NO_X, and PM per kWh electricity generated, taking into account the fuel type, sulfur content, removal technology, generation efficiency, and population density. Internalizing these externalities implies that clean and advanced technologies increase their share in global electricity production. Particularly, advanced coal power plants, natural gas combined cycles, natural gas fuel cells, wind and biomass technologies gain significant market shares at the expense of traditional coal- and gas-fired plants. Global carbon dioxide emissions are lowered by 3% to 5%. Sulfur dioxide emissions drop significantly below the already low level. The policy increases the costs of electricity production by 0.2 (in 2050) to 1.2 € cent/kWh (in 2010). Gross domestic product losses are between 0.6% and 1.1%. They are comparatively high during the initial phase of the policy, pointing to the need for a gradual phasing of the policy.     

On the economics of a hydrogen bus fleet powered by a wind park – A case study for Austria

This paper investigates the economics of a fuel cell bus fleet powered by hydrogen produced from electricity generated by a wind park in Austria. The main research question is to simultaneously identify the most economical hydrogen generation business model for the electric utility owning wind power plants and to evaluate the economics of operating a fuel cell bus fleet, with the core objective to minimize the total costs of the overall fuel supply (hydrogen production) and use (bus and operation) system. For that, three possible operation modes of the electrolyzer have been identified and the resulting hydrogen production costs calculated. Furthermore, an in-depth economic analysis of the fuel cell buses as well as the electrolyzer technology has been conducted. Results show that investment costs are the largest cost factor for both technologies. Thus, continuous hydrogen production with the smallest possible electrolyzer is the economically most favorable option. In such an operation mode (power grid), the costs of production per kg/H₂ were the lowest. However, this means that the electrolyzer cannot be solely operated with electricity from the wind park, but is also dependent on the electricity mix from the grid. For fuel cell buses, the future cost development will depend very much on the respective policies and funding programs for the market uptake, as to date, the total cost of use for the fuel cell bus is more than two times higher than the diesel bus. The major final conclusion of this paper is that to make fuel cell electric busses competitive in the next years today severe policy interferences, such as subsidies for these busses as well as electrolyzers and bans for fossil energy, along with investments in the setup of a hydrogen infrastructure, are necessary.     

The Short-Run Value of Nonutility-Generated Electricity

The Public Utilities Regulatory Policies Act (PURPA) of 1978 and the associated rulings of the Federal Energy Regulatory Commission (FERC) obligate the electric utilities to purchase electricity generated by qualifying facilities at the utility's avoided cost of alternative energy. They include no further indication of how this cost should be calculated and leave the actual implementation to the state's regulatory authorities. In this work, a computer simulation model was developed to study the short-run value of electricity that is generated by private entities and offered for sale to the electric utilities. Using the production simulation theory, the model determines how a set of generation units at different locations can be dispatched in the most economic way to meet a certain electric demand. The model then calculates the short-run value of nonutility-generated electricity by assuming the variable operational costs of electricity production will remain unchanged for any penetration of nonutility power. Several penetration scenarios were simulated using a hypothetical utility case. The short-run value of nonutility-generated electricity was found to increase with increased penetrations up to a maximum level before it starts decreasing as a result of the displacement of intermediate and base load capacity. Moreover, neither of the utility's marginal fuel costs calculated before and after the inclusion of the nonutility resources in the utility generation mix proved to capture the short-run value of the nonutility-generated electricity.     

Baseload electricity from wind via compressed air energy storage (CAES)

This study investigates two methods of transforming intermittent wind electricity into firm baseload capacity: (1) using electricity from natural gas combined-cycle (NGCC) power plants and (2) using electricity from compressed air energy storage (CAES) power plants. The two wind models are compared in terms of capital and electricity costs, CO₂ emissions, and fuel consumption rates. The findings indicate that the combination of wind and NGCC power plants is the lowest-cost method of transforming wind electricity into firm baseload capacity power supply at current natural gas prices (∼$6/GJ). However, the electricity supplied by wind and CAES power plants becomes economically competitive when the cost of natural gas for electric producers is $10.55/GJ or greater. In addition, the Wind-CAES system has the lowest CO₂ emissions (93% and 71% lower than pulverized coal power plants and Wind-NGCC, respectively) and the lowest fuel consumption rates (9 and 4 times lower than pulverized coal power plants and Wind-NGCC, respectively). As such, the large-scale introduction of Wind-CAES systems in the U.S. appears to be the prudent long-term choice once natural gas price volatility, costs, and climate impacts are all considered.     

National electricity planning in settings with low pre-existing grid coverage: Development of a spatial model and case study of Kenya

We develop a spatial electricity planning model to guide grid expansion in countries with low pre-existing electricity coverage. The model can be used to rapidly estimate connection costs and compare different regions and communities. Inputs that are modeled include electricity demand, costs, and geographic characteristics. The spatial nature of the model permits accurate representation of the existing electricity network and population distribution, which form the basis for future expansion decisions. The methodology and model assumptions are illustrated using country-specific data from Kenya. Results show that under most geographic conditions, extension of the national grid is less costly than off-grid options. Based on realistic penetration rates for Kenya, we estimate an average connection cost of $1900 per household, with lower-cost connection opportunities around major cities and in denser rural regions. In areas with an adequate pre-existing medium-voltage backbone, we estimate that over 30% of households could be connected for less than $1000 per connection through infilling. The penetration rate, an exogenous factor chosen by electricity planners, is found to have a large effect on household connection costs, often outweighing socio-economic and spatial factors such as inter-household distance, per-household demand, and proximity to the national grid.     

Risk hedging against the fuel price fluctuation in energy service business

Energy service business, or energy service company (ESCO), is expanding among industrial users as a means of energy saving. The ESCO business normally tends to become a long-term operation. During the operation, fluctuations of fuel and electricity costs significantly impact on the stability of the profit from ESCO business. Therefore, it is essential to reduce the risk of fuel and electricity cost fluctuations. Generally, a transaction called “financial derivative” is used as a measure of hedging against the fuel price fluctuation. In the case of ESCO business, it is necessary to manage the risk of both electricity and fuel price fluctuations because the variation in electricity price strongly affects the profit from ESCO as that in fuel price does.     

Rural area power supply in Nigeria: A cost comparison of the photovoltaic, diesel/gasoline generator and grid utility options

A large proportion of the population of Nigeria reside in the rural communities. In this work, the financial costs of providing centralized (photovoltaic) PV generating system of various capacities—to satisfy different load requirements—in a remote village in Nigeria is compared with the cost of grid extension over a distance of 1.8 km. Comparison is also made with the centralised diesel generator power supply option. In addition, the costs of decentralised PV home systems are compared with those of decentralised gasoline generator systems. For all the systems, the initial capital costs and the life cycle costs over a 20-year life cycle are reported. Sensitivity analysis was performed using variations in module costs, diesel fuel prices and grid extension distance. The results suggest that PV has a remarkable potential as a cost-effective option for low-power electrical energy supply to the rural communities in the country.     

Fuel Cells as Clean Energy Converters

Abstract

A fuel cell is a device in which the energy of a fuel is converted directly into electricity direct current by an electrochemical reaction without resorting to a burning process, rather than to heat by a combustion reaction. The chemical energy of the fuel is released in the form of an electrical energy instead of heat when the fuel is oxidized in an ideal electrochemical cell. Energy conversion by a fuel cell depends largely upon catalytic electrodes, which accomplishes the electrochemical reaction to convert fuel into electric energy without involving the burning process. Efficiencies of fuel cells (40–85%) are considerable high compared to heat engines. Catalysts are so expensive that electricity from most fuel cells costs about a thousand times more than the same amount derived from conventional sources. The need is to develop the catalysts from the different precursors to succeed in the necessary chemical reactions in an effective way.     

Testing activity‐based costing to large‐scale combined heat and power plant using bioenergy

This paper deals with the energy production and economics of a large‐scale biomass‐based combined heat and power (CHP) plant. An activity‐based costing model was developed for estimating the production costs of the heat and power of the bio‐CHP. A 100 MW plant (58 MW heat, 29 MW electricity) was used as reference. The production process was divided into four stages: fuel handling, fluidized bed boiler, turbine plant, and flue gas cleaning. The boiler accounted for close to 50% of the production costs. The interest rates and the utilization rate of the CHP had a significant effect on the profitability. We found that below 4000–4500 h per year utilization, the electricity production turned unprofitable. However, the heat production remained profitable with high interest rate (10%) and a low utilization rate (4000 h). The profitability also depended on the type of biomass used. We found that, e.g. with moderate interest rates and high utilization rate of the plant, the bio‐CHP plant could afford wood and Reed canary grass as fuel sources. Copyright © 2013 John Wiley & Sons, Ltd.     

Reducing cycling costs in coal fired power plants through power to hydrogen

The increase of renewable share in the energy generation mix makes necessary to increase the flexibility of the electricity market. Thus, fossil fuel thermal power plants have to adapt their electricity production to compensate these fluctuations. Operation at partial load means a significant loss of efficiency and important reduction of incomes from electricity sales in the fossil power plant. Among the energy storage technologies proposed to overcome these problems, Power to Gas (PtG) allows for the massive storage of surplus electricity in form of hydrogen or synthetic natural gas. In this work, the integration of a Power to Gas system (50 MWe) with fossil fuel thermal power plants (500 MWe) is proposed to reduce the minimum complaint load and avoid shutdowns. This concept allows a continuous operation of power plants during periods with low demand, avoiding the penalty cost of shutdown. The operation of the hybrid system has been modelled to calculate efficiencies, hydrogen and electricity production as a function of the load of the fossil fuel power plant. Results show that the utilisation of PtG diminishes the specific cost of producing electricity between a 20% and 50%, depending on the framework considered (hot, warm and cold start-up). The main contribution is the reduction of the shutdown penalties rather than the incomes from the sale of the hydrogen. At the light of the obtained results, the hybrid system may be implemented to increase the cost-effectiveness of existing fossil fuel power plants while adapting the energy mix to high shares of variable renewable electricity sources.