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This paper aims to present a multi-period dynamic power project financing model to produce pragmatic estimates of benchmark wholesale power prices based on the principles of normal profit. This, in turn, can guide policymakers as to whether price spikes or bidding above marginal cost in wholesale electricity markets warrants any investigation at all. One of the seemingly complex areas associated with energy-only wholesale electricity pools is at what point market power abuse is present on the supply side. It should not be this way. If a theoretically robust measure of normal profit exists, identification of potential market power abuse is straightforward. Such a definition readily exists and can be traced back to the ground-breaking work of financial economists in the 1960s.

Using a multi-period dynamic power project model, the authors produce pragmatic and theoretically robust measures of normal profit for project financed plant and plant financed on balance sheet. These model results are then integrated into a static partial equilibrium model of a power system. The model results are in turn used to guide policymaking on generator bidding in energy-only power markets.

Under conditions of perfect plant availability and divisibility with no transmission constraints, energy-only markets result in clearing prices which are not economically viable in the long run. Bidding must, therefore, deviate from strict short-run marginal cost at some stage. To distinguish between quasi-contributions to substantial sunk costs and market power abuse, a pragmatic and robust measure of normal profit is required.

This article finds policymakers can be guided by an ex-post analysis of base energy prices against pragmatic estimates for the long-run marginal cost of the base plant, and an ex-ante analysis of call option prices along the forward curve against pragmatic estimates of the carrying cost of the peaking plant.

The representative firm model is used to demonstrate that competitive markets yield least‐cost production in the long run. This model is deficient in two respects: The demonstration's validity is suspect and it fails to show that least‐cost production occurs in the short run as well.

Suggests a spatial conjunctive use model of an irrigation project in which the utility invest optimally for the water distribution system and charge farmers the shadow price of surface and groundwater. Seepage from the irrigation canal and on the field are assumed to recharge the groundwater aquifer. Particular attention was given to the effects of conveyance on the allocation of both surface and groundwater resources and the distribution of rents. An empirical model indicated that higher conveyance costs skew the distribution of water as well as rents over the project area. This suggests that the tail farmers need to face a substantially higher price for water if the system deteriorates and conveyance costs increase in the long run.

Current antitrust doctrine seemingly accepts average variable cost as one possible boundary between competitive and predatory pricing. Certain authors contend, however, that equally efficient rivals can sometimes be excluded from a market even when a dominant firm prices above its own average variable cost. A model is developed to test for predatory conduct in one such case. This model is applied to the reconstituted lemon juice industry. It shows that under certain conditions, even prices above average variable cost can be exclusionary.

In his elegant demonstration of the fundamental limitation of Steiner's theory of peak load pricing Buchanan has correctly retained Steiner's analytical technique and all but one of the original assumptions. Buchanan has made his point with admirable clarity; yet it seems worthwhile to re‐examine the issue with the aid of indifference map analysis, as it facilitates the location of Paretian equilibria and also the easy relaxation of the main restrictive assumptions.

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.

Local governments are often forced to purchase expertise for non-recurring analyses, such as rate setting for water and sewer services, because it is not cost-effective for these governments to maintain such expertise in-house or because independent analyses are preferred by watch-dog agencies or mandated by state statutes. However, like many ostensibly value-neutral analytical studies, these studies inevitably entail policy choices of which elected policy makers may not be aware. External analysts may not be aware of idiosyncratic factors, and they apply boilerplate perspectives that may not be responsive to local preferences. These perspectives limit policy options, although they may appear to be value-neutral. Policy makers must take an active role in these analytical studies in order to ensure that local preferences and specific factors are considered. Citizen committees comprised of residents with the necessary expertise, or experts from local colleges and universities may be able to provide the necessary oversight.

The most problematic area of any carbon policy debate is the treatment of incumbent CO2 intensive coal‐fired electricity generators. Policy applied to the electricity sector is rarely well guided by macroeconomic theory and modeling alone, especially in the case of carbon where the impacts are concentrated, involve a small number of firms and an essential service. The purpose of this paper is to examine the consequences of poor climate change policy development on the efficiency of capital markets within the Australian electricity sector.

The authors conducted a survey of Australian project finance professionals to determine the risk profiles to be applied to the electricity sector, in the event a poorly‐designed climate change policy is adopted.

The Australian case study finds that if zero compensation results in the financial distress of project financed coal generators, finance costs for all plant rises, including new gas and renewables, leading to unnecessary increases in electricity prices. Accordingly, an unambiguous case for providing structural adjustment assistance to coal generators exists on the grounds of economic efficiency.

Accordingly, the paper shows that an unambiguous case for providing structural adjustment assistance to coal generators exists, on the grounds of economic efficiency.

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.

Within the new public management (NPM) context, this paper aims to examine the inclusion of equity issues in pricing policy development and implementation in the water industry in Australia.

A review of literature relevant to the pricing of water shows equity issues have four dimensions which tend to be, at best, only implicitly considered. An empirical illustration employing a transaction cost framework is provided of a case in which change in pricing mechanisms was strongly suggested.

An equity paradox emerges as an explanation of why 63.7 per cent of Queensland urban water entities chose not to adopt the user-pays pricing mechanism for water. This suggests that the balance between “equity” and “efficiency” continues to be required in policy development for water pricing. Equity of access and that of distribution continue to be significant factors. As well, equity of interest and of return must be considered, especially under a user-pays pricing mechanism.

In respect of NPM considerations, it is argued that consideration of the four dimensions of equity in the implementation of a water pricing policy will resolve contradictions with, and paradoxes met in dealing with efficiency.

The argument used in the paper is interdisciplinary. References and terms used include those which are social, economic, and environmental from an accounting and management perspective.