A disaggregate econometric analysis of electricity distribution capital costs

Under the assumption that electric utilities minimize their capital, labor, and electric losses costs in each local distribution system, capital input demand functions are developed at a highly disaggregated level and econometrically estimated, using cross-sectional data on 55 communities served by Long Island Lighting Company. These functions are then used to clarify such policy issues as the allocation of joint capital costs on the basis of marginal costs, the existence of economies of scale and density, and the appropriateness of natural monopoly status for electricity distribution.     

Determinants of the costs of carbon capture and sequestration for expanding electricity generation capacity

This study models the costs of electricity generation with carbon capture and sequestration (CCS), from generation at the power plant to carbon injection at the reservoir, examining the economic factors that affect technology choice and CCS costs at the individual plant level. The results suggest that natural gas and coal prices have profound impacts on the carbon price needed to induce CCS. To extend previous analyses we develop a "cost region" graph that models technology choice as a function of carbon and fuel prices. Generally, the least-cost technology at low carbon prices is pulverized coal, while intermediate carbon prices favor natural gas technologies and high carbon prices favor coal gasification with capture. However, the specific carbon prices at which these transitions occur is largely determined by the price of natural gas. For instance, the CCS-justifying carbon price ranges from $27/t CO₂ at high natural gas prices to $54/t CO₂ at low natural gas prices. This result has important implications for potential climate change legislation. The capital costs of the generation and CO₂ capture plant are also highly important, while pipeline distance and criteria pollutant control are less significant.     

Comparing electricity distribution network revenues and costs in New South Wales,Great Britain and Victoria

A decade ago, electricity distribution network revenues per customer in New South Wales (NSW) were twice those in Great Britain (GB). Recent price controls imply that by 2014 they will be nearly four times as high. This paper examines possible reasons for this. The main reason does not seem to be geography, operating environment or industry structure. GB and Victoria have managed to accommodate increasing demand at broadly constant or even declining costs and revenues while delivering higher quality of service, while NSW has not. The regulatory framework and the practice of the regulatory body within that framework seem relevant. Australian regulators have not used benchmarking techniques as the GB regulator has. Perhaps the most important explanatory factor is private ownership in GB and Victoria compared to state ownership in NSW. This could also impact on the nature and effectiveness of regulation.     

Operational strategy and marginal costs in simple trigeneration systems

As a direct result of economic pressures to cut expenses, as well as the legal obligation to reduce emissions, companies and businesses are seeking ways to use energy more efficiently. Trigeneration systems (CHCP: Combined Heating, Cooling and Power generation) allow greater operational flexibility at sites with a variable demand for energy in the form of heating and cooling. This is particularly relevant in buildings where the need for heating is restricted to a few winter months. In summer, the absorption chillers make use of the cogenerated heat to produce chilled water, avoiding waste heat discharge. The operation of a simple trigeneration system is analyzed in this paper. The system is interconnected to the electric utility grid, both to receive electricity and to deliver surplus electricity. For any given demand required by the users, a great number of operating conditions are possible. A linear programming model provides the operational mode with the lowest variable cost. A thermoeconomic analysis, based on marginal production costs, is used to obtain unit costs for internal energy flows and final products as well as to explain the best operational strategy as a function of the demand for energy services and the prices of the resources consumed.     

US marginal electricity grid mixes and EV greenhouse gas emissions

Battery electric vehicles (BEVs) are often portrayed as “green,” implying negligible greenhouse gas (GHG) emissions. While BEVs are zero emission vehicles, the electrical power generators used to recharge vehicle batteries do emit copious GHGs. Some analysts have estimated the power plant GHG emissions due to charging EV batteries using the average electrical generator grid mix for a given region. However, the GHG protocol specifies that analysts should use the marginal grid mixes to accurately calculate GHG emissions from adding EVs to the vehicle fleet. This paper utilizes the marginal grid mixes for each electrical power region in the US, and calculates the vehicle-weighted average GHG emissions for the entire country. These calculations demonstrate that, on the average, each BEV that displaces a gasoline hybrid electric vehicle (HEV) will increase GHGs by more than 7% and each PHEV put in service will increase GHGs by an average of 10% compared to a gasoline HEV.     

Historical costs of coal-fired electricity and implications for the future

We study the cost of coal-fired electricity in the United States between 1882 and 2006 by decomposing it in terms of the price of coal, transportation cost, energy density, thermal efficiency, plant construction cost, interest rate, capacity factor, and operations and maintenance cost. The dominant determinants of cost have been the price of coal and plant construction cost. The price of coal appears to fluctuate more or less randomly while the construction cost follows long-term trends, decreasing from 1902 to 1970, increasing from 1970 to 1990, and leveling off since then. Our analysis emphasizes the importance of using long time series and comparing electricity generation technologies using decomposed total costs, rather than costs of single components like capital. By taking this approach we find that the history of coal-fired electricity suggests there is a fluctuating floor to its future costs, which is determined by coal prices. Even if construction costs resumed a decreasing trend, the cost of coal-based electricity would drop for a while but eventually be determined by the price of coal, which fluctuates while showing no long-term trend.     

Optimal electricity supply reliability using customer shortage costs

This paper describes an economic cost-benefit method for determining the optimal power system capacity and reliability of electricity supply using customer shortage costs. The approach is based upon identifying a system plan that simultaneously considers cost-of-service as well as value-of-service, and maximizes the net economic benefits taking into account the interdependence between electricity reliability, price, and demand. In contrast to the existing literature on this subject, which considers only customer outage costs, this paper argues that it is the related but considerably broader notion of customer shortage cost that is more relevant in the context of optimizing the reliability of electricity supply. The paper develops a method for estimating shortage costs and sketches an integrated framework for optimizing reliability using such costs.     

External costs of electricity production: case study Croatia

Because electricity production is one of the major sources of pollution, and at the same time is the most centralised one, environmental issues in power system operation and planning are gaining ever-increasing attention. It is very difficult to compare environmental impacts of various electricity generation technologies and fuel types because they are extremely divergent. The most widely accepted common denominator today is the so-called external cost by which a monetary value is associated with environmental damage.In this paper, damages to human health resulting from Croatian thermal power plants annual operation are presented. Stack emissions have been translated into ambient concentrations by atmospheric dispersion modelling. Existing data on relations between human health degradation and ground concentrations of the analysed pollutants have been used. Geographic information software has been used in order to account for spatially dependent data.Monetary values have been assigned to the estimated human health damage. External costs resulting from impact of Croatian thermal power plants airborne emissions on human health have been calculated. The total Croatian thermal power system external costs, resulting from impacts on human health, are presented and discussed.     

Estimating the value of wind energy using electricity locational marginal price

There is an increasing interest in adding renewables such as wind to electricity generation portfolios in larger amounts as one response to concern about atmospheric carbon emissions from our energy system and the resulting climate change. Most policies with the aim of promoting renewables (e.g., RPS, FIT) do not explicitly address siting issues, which for wind energy are currently approached as the intersection of wind resource, land control, and transmission factors. This work proposes the use of locational marginal price (LMP), the location and time specific cost of electricity on the wholesale market, to signal locations where generation can address electricity system insufficiency. After an examination of the spatial and temporal behavior of LMP in Michigan over the first two years of wholesale market operation, this work combines LMP with wind speed data to generate a value metric. High value sites in Michigan tend to be sites with higher wind speeds, with the bulk of value accruing in the fall and winter seasons.     

Generation capacity adequacy in interdependent electricity markets

This paper deals with the practical problems related to long-term security of supply in regional electricity markets with transmission constraints. Differences between regulatory policies and market designs in terms of generation adequacy policies may distort the normal functioning of the neighboring markets, as well as the reliability of supply. We test the effect of heterogeneous regulatory design between two interdependent markets: energy-only market, price-capped market without capacity mechanisms and price-capped markets with forward capacity contracts obligation. We rely on a long-term market simulation model in system dynamics that characterizes expansion decision in a competitive regime. The results show that differences in market designs affect both price and reliability of supply in the two markets. We examine both the short and long terms effect, and how free-riding may occur where capacity adequacy policies are adopted in one market but not the other. The main finding is that the lack of harmonization between local markets in policies to ensure capacity adequacy may lead to undesirable side effects.     

Economic costs of electricity supply interruptions: US and foreign experience

This paper investigates the costs of interruptions in electricity service to customers. This information is a key input in planning power system reliability using an economic cost-benefit approach. The paper reviews the literature from the perspective of identifying alternate methodological approaches used, their strengths and weaknesses, and potential for bias; it presents and compares outage cost estimates found in the literature on a common denominator basis; it attempts to explain the sources of the wide range of variation observed in different study estimates; and it identifies the need for further work on this important topic.     

Dynamic assessment of capacity investment in electricity market considering complementary capacity mechanisms

This paper proposes a decentralized market-based model for long-term capacity investment decisions in a liberalized electricity market. Investment decisions are fundamentally based on total revenues gained by investors. In most electricity markets, the complementary mechanisms are designed to ensure a desired level of reliability while covering investment costs of the suppliers. In such an environment, investment decisions are highly sensitive to expectation of price signals in both of energy market and capacity mechanisms. In this work, the system dynamics concepts are used to model the structural characteristics of electricity market such as, long-term firms’ behavior and relationships between variables, feedbacks, and time delays by appropriately bundling the energy market and capacity mechanisms. The market oriented capacity price as well as non-competitive capacity payments and a proposed hybrid capacity mechanism are linked with the energy market in the model. Such a decision model enables both the generation companies and the regulators gaining perfect insights into the possible consequences of different decisions they make under different policies and market conditions. In order to examine the performance of the electricity market with different capacity mechanisms, a case study is presented which exhibits the effectiveness of the proposed model.     

Productivity growth and deregulation of Japanese electricity distribution

Deregulation of Japanese electric power industry began in 1995. After the amendment of Electricity Utility Industry Law in 1995, competition was partially introduced in a generation sector and retail competition started from 2000. Eligibility to choose suppliers was gradually extended from larger to smaller customers. As of 2008, almost all customers except households can choose their electricity suppliers. Based upon both previous implementation result of competition policy and review on their achievement, Japanese government will begin new policy debate in 2013 to assess further retail competition which includes household customers. To prepare for policy suggestion on the future electric power industry, this study examines the cost structure of Japanese electricity distribution. For the purpose, we estimate a multi-product translog cost function of Japanese electricity distribution from 1983 to 2003. Using the estimated cost function, we calculate several economic measures such as productivity growth, technical change and economies of scale and scope. The empirical results of this study indicate the improvement in productivity growth after deregulation.     

Expected electricity costs for the US Mod 2 windmill

Robert Lowe presents here an analysis of the expected cost of electricity production from the US Mod 2 windmill, using accounting criteria currently recommended for energy technologies in the UK. The results show that if expected cost targets are met, the Mod 2 design will be a highly economic means of generating electricity.     

CO2 mitigation costs for new renewable energy capacity in the Mexican electricity sector using renewable energies

Carbon dioxide mitigation costs for the Mexican power sector are calculated in order to compare the business as usual (BAU) scenario, based on natural gas capacity growth, to a transition scenario where electricity generation growth using natural gas after 2007 is replaced by renewable energies (solar, wind, hydro and biomass). The mitigation costs are obtained using the following parameters: natural gas price, discount rate and technological progress. The latter is expressed in terms of the anticipated decrease in capital costs, as reported in electricity generation technological literature. Our results show that when technological progress is considered, CO₂ mitigation costs decrease rapidly from 14 $/tCO₂ (in this paper $ express 1997 US dollars and t means metric tons) to zero when the price of natural gas nears 2.68 $/GJ, (for some readers, it can be useful to know that 1.0 US$1997/GJ is 1.19 US$2001/MMBTU) which is almost the same as the 2002 price. This means that for middle natural gas prices a “no regrets” situation can be achieved. Our results also show that for prices higher than 2.80 $/GJ, the incorporation of the technological progress parameter transforms the transition scenario into a “no regrets” scenario for all the discount rate values considered in this study.     

Power system interconnection in developing countries and the equilibration of marginal costs

A method is proposed for the calculation of the benefits in power system interconnection which arise from the equilibration of marginal costs on the connected systems. The method is applied to the adjacent systems of Malaysia and Singapore. The benefits arising from the equilibration of marginal costs are shown to be significant compared to those which arise from the reduction of reserve margins.     

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.     

Conditions and costs for renewables electricity grid connection: Examples in Europe

This paper compares conditions and costs for RES-E grid connection in selected European countries. These are Germany, the Netherlands, the United Kingdom, Sweden, Austria, Lithuania and Slovenia. Country specific case studies are presented for wind onshore and offshore, biomass and photovoltaic power systems, as based on literature reviews and stakeholder interviews. It is shown that, especially for wind offshore, the allocation of grid connection costs can form a significant barrier for the installation of new RES-E generation if the developer has to bear all such costs. If energy policy makers want to reduce the barriers for new large-scale RES-E deployment, then it is concluded that the grid connection costs should be covered by the respective grid operator. These costs may then be recouped by increasing consumer tariffs for the use of the grid.     

Internalising external costs of electricity and heat production in a municipal energy system

Both energy supply and waste treatment give rise to negative effects on the environment, so-called external effects. In this study, monetary values on external costs collected from the EU′s ExternE project are used to evaluate inclusion of these costs in comparison with an energy utility perspective including present policy instruments. The studied object is a municipal district heating system with a waste incineration plant as the base supplier of heat. The evaluation concerns fuels used for heat production and total electricity production, for scenarios with external costs included and for a scenario using the present policy instrument.