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.     

External costs of electricity generation options in Lithuania

This article deals with external cost of electricity generation in Lithuania. The external costs of electricity generation are the most important environmental criteria shaping decisions within the electricity system. External costs of electricity generation were calculated based on ExternE methodology for Lithuania during EU (European Union) Framework 6 project Cost Assessment for Sustainable Energy Systems (CASES). The article presents the methodology and results of external costs of electricity generation in Lithuania. The assessment of external costs provided that future energy policy should be oriented towards the renewable energy generation technologies having the lowest external costs. External costs for electricity generation technologies were analysed in terms of external costs categories, electricity generation technologies life cycle stages and time frame 2010–2030.     

Increasing marginal costs and the efficiency of differentiated feed-in tariffs

We study optimal subsidies for renewable energy (RE) generation to internalize external benefits from inter-temporal learning-by-doing spillovers, taking into account increasing marginal costs at the industry level due to limited availability of sites suitable for RE. We find that the optimal RE subsidy is differentiated according to productivity and derive a condition on production and spillovers under which less efficient, i.e. more costly, technologies should receive higher support, as common in actual policy-making. We show that such a support of technological diversification is optimal if (i) productive sites are scarce, which limits future utilization of knowledge and if (ii) technologies mature rapidly with little further scope for learning. Prima facie evidence for these elasticities for Germany, Denmark and UK suggests that support for technology diversification is the optimal approach for these countries.     

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.     

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.     

Synergies and trade-offs between governance and costs in electricity system transition

Affordability and costs of an energy transition are often viewed as the most influential drivers. Conversely, multi-level transitions theory argues that governance and the choices of key actors, such as energy companies, government and civil society, drive the transition, not only on the basis of costs. This paper combines the two approaches and presents a cost appraisal of the UK transition to a low-carbon electricity system under alternate governance logics. A novel approach is used that links qualitative governance narratives with quantitative transition pathways (electricity system scenarios) and their appraisal. The results contrast the dominant market-led transition pathway (Market Rules) with alternate pathways that have either stronger governmental control elements (Central Co-ordination), or bottom-up proactive engagement of civil society (Thousand Flowers). Market Rules has the lowest investment costs by 2050. Central Co-ordination is more likely to deliver the energy policy goals and possibly even a synergistic reduction in the total system costs, if policies can be enacted and maintained. Thousand Flowers, which envisions wider participation of the society, comes at the expense of higher investment and total system costs. The paper closes with a discussion of the policy implications from cost drivers and the roles of market, government and society.     

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.     

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.     

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.     

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.     

Greenhouse gas emission intensity factors for marginal electricity generation in Canada

In Canada, each province has its own electric utility system, and each system is responsible for meeting the demand of its customer base. Electricity demand in all provinces is highly variable throughout the day, as well as during the year. In order to achieve a good match between electricity demand and generation, a mix of base, intermediate and peaking load power plants is used, which uses different fuel sources. When a renewable energy technology or an energy efficiency measure that results in electricity savings is implemented on a regional, provincial and national scale, the electricity savings reflect in the peak (marginal) electricity generation. Thus, the greenhouse gas (GHG) emission reduction due to the reduction in electricity generation corresponds to the fuel used to generate the electricity at the margin. In Canada, the fuel used for marginal electricity generation varies from province to province and from hour to hour. To estimate the reduction in GHG emissions due to reducing electricity generation at the margin, it is necessary to have information on the fuel mix used to generate the marginal electricity for each province on a suitable time scale. With such information, it is possible to estimate a marginal GHG emission intensity factor for each province, which would provide the amount of GHG emissions produced as result of producing 1 kWh of electricity on the margin. However, such information is regarded confidential by most electric utilities and is not made public. In this paper, methodologies are presented to estimate the GHG intensity factors (GHGIFs) for marginal electricity generation for each province of Canada based on the information available in the public domain. The GHGIFs developed for each province are also presented, which are expected to be valid within the next 5‐year horizon. Copyright © 2010 John Wiley & Sons, Ltd.