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The recent interconnection and trade of electricity between NSW and Victoria is likely to exacerbate any misallocation of resources due to inefficient pricing. The aim of this article is to investigate the likely divergence between electricity generation costs using current market prices of coal and natural gas, and those when coal and natural gas are priced efficiently. To do so, the paper applies the concept of full social cost pricing to five different generation technologies in the two states. It concludes that the current movement to privatisation and interconnection in the electricity sector, while it may promote pricing closer to marginal private costs, will not result in efficient outcomes in the presence of external costs and the different tax regimes which currently apply to each generation fuel and in each state.

The purpose of this paper is to shed light on the governance choices of firms operating in the electricity distribution network operation activities. The study aims to consider both costs and benefits of different governance choices and to examine which of the activities could be outsourced and which it is preferable to keep in‐house. The study makes a distinction between the electricity retail services and electricity distribution network activities and focuses solely on the network business.

The study is based on a four‐staged process and utilizes the extended transaction cost economics as a theoretical framework. The research design includes in‐depth interviews with ten managers and CEOs of Finnish electrical utilities, analysis and interpretation of findings and verification of results by electricity network business experts.

The extended transactional cost economics theoretical framework and research design support analysis of governance structures and make‐or‐buy decisions. The findings demonstrate that the activities of the companies operating in the electricity distribution business differ in terms of potential long‐term efficiency effects when sourced from the market or made in‐house. The determinants of the governance choice depend partly on the nature and strategic importance of the activity in question. Operations management seems to be a function to be kept in‐house in the current market situation, whereas there are clear potential benefits that can be obtained by outsourcing field work activities. The results related to the governance of control room activities are more complicated.

This study brings not only the transaction costs but also the benefit‐side and the dynamic aspects of boundary choices under assessment.

In recognition of the urgency of the global need to reduce CO₂ emissions from the electricity sector, the purpose of this paper is to analyze the cost‐effectiveness of nuclear power and fossil‐fuel‐based power with and without the provision of carbon capture and storage in select, yet environmentally‐significant, group of countries – China, India, Russia, Korea, Pakistan, Poland, Argentina, Bulgaria and Romania.

The analyses are based on comparisons of electricity generation costs for nuclear and fossil‐fuel technologies. These costs, expressed in present value terms, are estimated on the basis of life‐cycle costs, employing detailed country‐specific technological and economic data and assumptions.

The analyses suggest that that the provision of carbon capture and storage is likely to result in a significant increase in the cost of electricity produced from fossil fuels (principally coal) in all countries represented in this paper. Such increase would completely erode the existing cost advantage enjoyed by fossil‐fuel power (in relation to nuclear power) in some countries (Argentina, Bulgaria, China, and India) and considerably enhance the existing cost‐advantage of nuclear power in other countries (Korea, Pakistan, Poland, Romania, and Russia).

Notwithstanding these limitations, the findings of this paper contribute appreciably to the emerging knowledge on this topic and provide useful foresight into the likely challenges of developing internationally acceptable policy prescriptions for mitigation CO₂ emissions from the electricity sector. At a mundane, yet important, level, this paper establishes a platform on which further analyses could be built.

Many institutions of higher education have committed to carbon neutrality. Given this goal, the main economic issue is minimizing cost. As for society as a whole, dominant decarbonization strategies are renewable electricity generation, electrification of end uses and energy efficiency. The purpose of this paper is to describe the optimum combination of strategies.

There are four questions for eliminating the primary institutional greenhouse gas emissions: how much renewable electricity to produce on-site; where and at what price to purchase the balance of renewable electricity required; how to heat and cool buildings without fossil fuels; and how much to invest in energy efficiency. A method is presented to minimize decarbonization costs by equating marginal costs of the alternates.

The estimated cost of grid-purchased carbon-free energy is the most important benchmark, determining both the optimal level of campus-produced renewable energy and the optimum efficiency investment. In the context of complete decarbonization, greater efficiency investments may be justified than when individual measures are judged only by fossil-fuel savings.

This paper discusses a theoretically ideal plan and implementation issues such as purchasing carbon-free electricity, calculating marginal costs of conserved energy, nonmarginal cost changes, uncertainty about achieving efficiency targets, and dynamic pricing. The principles described in this study can be used to craft a cost-minimizing decarbonization strategy.

While previous studies discuss decarbonization strategies, there is little economic guidance on which strategies are optimal, on how to combine strategies to minimize cost or how to identify a preferred path to decarbonization.

The purpose of this paper is to examine how active consumers, i.e. consumers that can inter-temporally shift their load, can influence electricity prices. As demonstrated in this paper, inter-temporal load shifting can induce negative electricity prices, a recurring phenomenon on power exchanges.

The paper presents a novel electricity-market model assuming a nodal-pricing, energy-only spot market with active consumers. This study formulates an economic equilibrium problem as a linear program and uses an established six-node case study to compare equilibrium prices of a model with inflexible demand to a model with flexible demand of active consumers.

This study illustrates that temporal coupling of hourly market clearing through load shifting of active consumers can cause negative electricity prices that are not observed in a model with ceteris paribus inflexible demand. In such situations, where compared to the case of inflexible demand more flexibility is available in the system, negative electricity prices signal lower total system costs. These negative prices result from the use of demand flexibility, which, however, cannot be fully exploited due to limited transmission capacities, respectively, loop-flow restrictions.

Literature indicates that negative electricity prices result from lacking flexibility. The results illustrate that active consumers and their additional flexibility can lead to negative electricity prices in temporally coupled markets, which in general contributes to increased system efficiency as well as increased use of renewable energy sources. These findings extend existing research in both the area of energy flexibility and causes for negative electricity prices. Therefore, policymakers should be aware of such (temporal coupling) effects and, e.g. continue to allow negative electricity prices in the future that can serve as investment signals for active consumers.

The purpose of this article is to analyse electricity supply in the Solomon Islands face extraordinarily expensive electricity tariffs – currently set at 96 c/kWh – making them amongst the highest in the world. Power is supplied by a fleet of diesel generators reliant on imported liquid fuels. In this article, the authors model the 14,100 kW power system on the island of Guadalcanal and demonstrate that by investing in a combination of hydroelectric and solar photovoltaic generating capacity, power system costs and reliability can be improved marginally. However, when the authors model a 3-Party Covenant (3PC) Financing structure involving a credit wrap by the Commonwealth of Australia, electricity production costs fall by 50 per cent, thus resulting in meaningful increases in consumer welfare.

This study’s approach uses an integrated levelised cost of electricity model and dynamic partial equilibrium power system model. Doing so enables the authors to quickly analyse the rich blend of fixed, variable and sunk costs of generating technology options. The authors also focus on the cost of capital that is likely to be achieved under various policy settings.

The authors find that a 3PC Financing policy can substantially reduce the production costs associated with capital-intensive power projects in an unrated sovereign nation. Such a policy and associated prescriptions are not specific to the Solomon Islands or power generation. The conceptual framework and associated financial logic that underpins the initiative can be generalised to other “user pays” infrastructure projects and to other developing nations. The broad applicability of 3PC financing means that it is not country specific, project specific or asset class specific.

It is important to note that the analysis in this paper has a number of limitations in that the authors do not deal with rural electrification or distribution network costs. The focus of this paper is to identify policy interventions that are capable of making profound changes to the cost and the reliability of wholesale electricity production.

The focus of this paper is to identify a policy intervention capable of making profound changes to the cost and the reliability of wholesale electricity production. While there is nothing novel associated with a 3PC Financing per se, the authors are unaware of its direct use as a form of delivering foreign aid. A 3PC Financing has the effect of shifting the source of aid funding from fiscal account surplus/deficit (i.e. cash outlays) to balance sheet (i.e. credit wrap). However, this is not a “magic pudding” – 3PC Financing creates an asset-backed contingent liability and will have the effect of reducing the donor country’s own debt capacity by a commensurate amount, holding the nation’s credit rating constant.

Lignite coal-fired power plants are the main electricity generators in the province of Saskatchewan, Canada. Although burning lignite coal to generate power is economical, it produces significant greenhouse gases making it a big challenge to Canada’s international commitment on emission reduction. However, abundant agricultural crops and sawdust produced in Saskatchewan put the province in a good position to produce and use agri-pellets as an alternative fuel to generate electricity. This study aims to conduct an economic and environmental analysis of the replacement of lignite coal by agri-pellets as the fuel for Saskatchewan’s coal-fired power plants.

The study estimates the economic and environmental costs and benefits of two alternative fuels for power plants. The economic analysis is based on the pellet production and transportation costs from farms to production sites and from the production sites to power plants. In the production process, biomass precursors are densified with and without additives to produce fuel agri-pellets with appropriate mechanical durability and high heating value per volume unit. The environmental analysis involves estimation of greenhouse gas emissions and their social costs for lignite coal and different types of agri-pellets under different scenarios for pellet production and transportation.

The results show that although the total cost of electricity is lower for coal than agri-pellets, the gap shrinks when social costs and specifically a carbon price of $50/tonne are included in the model. The cost of electricity in lignite coal-fired power plants would also be on par with agri-pellets-fired power plants if the carbon price is between U$68 and $78 per tonne depending on the power plant locations. Therefore, a transition from coal to agri-pellet fuels is feasible if a high-enough price is assigned to carbon. The method and the results can be generalized to other places with similar conditions.

There are a few caveats in this study as follows. First, the fixed costs associated with the transformation of the existing coal-fired power plants to pellet-fired plants are not considered. Second, the technological progress in the transportation sector, which would favor the net benefits of using pellets versus coal, is not included in the analysis. Finally, the study does not address the possible political challenges facing the transition in the context of the Canadian federal system.

The study results indicate that the current carbon price of $50 per tonne is not sufficient to make the agri-pellets a feasible source of alternative energy in Saskatchewan. However, if carbon pricing continues to rise by $15 annually starting in 2022, as announced, a transition from coal to agri-pellets will be economically feasible.

Canada is committed to reduce its emission according to the Paris agreement, and therefore, needs to have a concrete policy to find alternative energy sources for its coal-fired power plants. This study examines the challenges and benefits of such transition using the existing agri-pellet resources in Saskatchewan, a province with abundant agricultural residues and coal-fired power plants. The findings indicate that a significant emission reduction can be achieved by using agri-pellets instead of coal to produce electricity. The study also implies that the transition to renewable energy is economical when social costs of carbon (carbon tax) is included in the analysis.

As far as the authors know, this is the first study providing a socio-economic analysis for a possible transition from the coal-fired power plants to a more clean and sustainable renewable energy source in one of the highest carbon dioxide (CO₂) producer provinces in Canada: Saskatchewan. The study builds upon the technical production of three agri-pellets (oat hull, canola hull and sawdust) and estimates the economic and environmental costs of alternative fuels under different scenarios.

The purpose of this study is to develop an optimization method for charging plans with the implementation of time-of-day (TOD) electricity tariff, to reduce electricity bill.

Two optimization models for charging plans respectively with fixed and stochastic trip travel times are developed, to minimize the electricity costs of daily operation of an electric bus. The charging time is taken as the optimization variable. The TOD electricity tariff is considered, and the energy consumption model is developed based on real operation data. An optimal charging plan provides charging times at bus idle times in operation hours during the whole day (charging time is 0 if the bus is not get charged at idle time) which ensure the regular operation of every trip served by this bus.

The electricity costs of the bus route can be reduced by applying the optimal charging plans.

This paper produces a viable option for transit agencies to reduce their operation costs.

The objective of the paper is to analyse the economic justification of introducing deregulation to Israel's regulated electricity market and infer whether such a policy change makes sense for the country.

The paper employs an analytical model of electricity market equilibrium under regulation and deregulation. It considers two technologies – coal‐fired generators and combined cycle gas turbines, and two time‐of‐day prices – peak and off‐peak. It analyzes pricing, revenues, profits and consumer surplus both for the regulated industry and the deregulated industry where firms compete, during the peak and off‐peak periods, according to the Cournot conjecture. The model is then applied to the Israeli case.

The analysis shows that a workably competitive electricity market with financially viable firms does not improve net benefits to Israeli society. A deregulated market is likely to yield smaller net benefits than a regulated market, and certainly a smaller consumer surplus. This happens since efficiency improvements in generation costs under deregulation will not be sufficient to compensate for the reduction in consumer surplus due to higher electricity prices under deregulation.

The simplifications used in the analytical model for ease of analysis and presentation could have influenced some results.

The findings of the paper would have significant relevance for electricity sector deregulation in Israel and other regions that currently have a regulated electricity sector (e.g. Hong Kong, Africa, and many parts of North America).

The value of the paper lies in its ability to demonstrate the inherent weaknesses of the deregulation policy through an analytical model.

This paper aims to analyze efficiency of the subsidies granted by the Spanish authorities. The case study focuses on wind-generated electricity. We will study what type of subsidy is most efficient considering the economic and technical data of an existing wind power installation in Spain. A sensitivity analysis is made in order to provide judgment elements to propose the form of the more convenient subsidy. In view of the results obtained, we will evaluate the efficiency of subsidies granted by Spanish authorities.