Short-run Marginal Cost Research Articles

Incorporating operational constraints into long-term energy planning: The case of the Egyptian power system under high share of renewables

This study assesses the performance of Egypt's energy system on a short-term basis to ensure that it can handle a high share of renewable energy, as predicted in the long-term planning up to 2040. PLEXOS software is used for short-term analysis to simulate operational performance on an hourly basis while considering the constraints of Unit Commitment (UC) and Economic Dispatch (ED). The long-term energy planning model, which covered the years 2020–2040 with chosen representative years (2020 as the base year and 2025, 2030, 2035, and 2040), was validated by the short-term operational model. The results from the short-term analysis indicate that by the year 2040, 69.5 % of the electricity mix from renewable energy sources (excluding hydro) can be accommodated, representing a slightly lower capacity than the 70 % predicted by the long-term plan. Due to the high share of intermittent renewable energy sources, traditional generators will experience excessive cycling in 2040. The average weighted short-run marginal cost in 2040 is projected to be 7.8 USD/MWh, compared to 18.37 USD/MWh in 2020, due to the low operating costs of renewable energy plants and their high penetration in 2040. Various operational techniques have been suggested to reduce the curtailment of renewable energy to achieve only 1.2 % of the total energy generation of the system by 2040. Additionally, other adjustments to the system operation are being considered to maintain a balance in the power system on a short-term basis.

Damage or no damage from traffic: Re-examining marginal cost pricing for rail signalling maintenance

This paper re-examines the implementation of the short run marginal cost (SRMC) pricing principle with respect to rail infrastructure usage and empirically tests if there are rail infrastructure maintenance costs triggered by traffic but not caused by asset damage from traffic. This is important because current EU legislation stipulates that only costs related to infrastructure wear and tear from traffic are eligible for the direct cost-based element of track access charges. An econometric approach is applied to French panel data on signalling maintenance costs. The results show that the SRMC for infrastructure provision of these assets is not only related to asset damage costs caused by traffic, but can also be due to economic factors linked to increased line capacity utilisation: 1) higher cost per maintenance activity, and/or 2) increased preventative maintenance to curb delays. Our work offers an explanation as to why econometric and engineering approaches give different views of rail infrastructure cost variability and suggests that EU legislation on track access pricing may need to be revised.

The impact of access prices on train traffic: An econometric study for France

To guarantee fair and nondiscriminatory access to rail networks, European Commission raised the importance of regulation by promoting short run marginal cost. Thus, to recover the full cost of infrastructure, Infrastructure Managers may use mark ups over the marginal cost, using Ramsey pricing for example. However, a Ramsey pricing implementation for rail infrastructure is strongly limited by the lack of information about the demand elasticity of train paths. The aim of this article is to try to fill this gapby conducting an empirical research on the price sensitivity of the railway paths using a French dataset from 2003 to 2016. Preliminary results suggest that track access charges influence negatively the train path demand for high-speed trains and freight trains butdo not seem to influence the train path demand for regional trains under PSO. Nevertheless, if track access charges are related to the track category (UIC category) or to the kind of line (high speed or conventional) results may differ. Regarding regional and freight trains, the track category seems to determine the statistical significance of track access charges elasticity while the kind of line seems to explain the impacts on the demand of rail paths for high-speed trains.

Carbon pass-through rates on spot electricity prices in Australia

This study assesses the impact of the Australian Carbon Pricing Mechanism (CPM) on electricity prices in the National Electricity Market (NEM). An econometric model is designed to examine the influence of short-run marginal costs, electricity demand and emission intensities on carbon pass-through to spot electricity prices. Our sample period from July 2009 to June 2016 allows us to analyse three different sub-periods in order to quantify pass-through effects: the period before the CPM, the period when the pricing mechanism was effective, as well as the period after its repeal. Therefore, our study allows a comprehensive evaluation of the effect of carbon pricing on the Australian electricity spot market. Our results demonstrate a high degree of carbon costs pass-through across the considered markets, while the increase in electricity prices typically exceeds carbon costs, in particular for the markets in New South Wales, Queensland and South Australia. Furthermore, we find a negative relationship between carbon pass-through rates and emission intensities in the regional markets: pass-through rates were relatively low for Victoria that is characterised by electricity generation from fossil fuels and high emission intensities, while they were the highest for South Australia, a market with the lowest emission intensities and a higher share of renewable energy generation. We also find that for most markets, emission intensities were only reduced by a relatively small margin during the tax period and electricity prices have never reverted back to their pre-tax levels after the repeal of the tax. • The impact of the Carbon Pricing Mechanism (CPM) on Australian spot electricity prices is examined. • Results demonstrate that consumers were bearing the costs of carbon rather than generators. • Carbon costs pass-through estimates range from 100% to 290% across regional markets. • Evidence for a minor reduction in emission intensities during the CPM period is found. • Spot prices did not revert back to their pre-CPM levels after abolishment of the CPM.

Equilibrium Pricing with Duality-Based Method: Approach for Market-Oriented Capacity Remuneration Mechanism

The crucial design elements of a good capacity remuneration mechanism are market orientation, insurance of long-term power system adequacy, and optimal cross-border generation capacity utilization. Having in mind these design elements, this research aims to propose a financially fair pricing mechanism that will guarantee enough new capacity and will not present state aid. The proposed capacity remuneration mechanism is an easy-to-implement linear program problem presented in its primal and dual form. The shadow prices in the primal problem and dual variables in the dual problem are used to calculate the prices of firm capacity which is capacity needed for long-term power system adequacy under capacity remuneration mechanism. In order to test if the mechanism ensures sufficient new capacity under fair prices, the mechanism is tested on the European Network of Transmission System Operators for Electricity (ENTSO-E) regional block consisting of Austria, Slovenia, Hungary, and Croatia with simulation conducted for a period of one year with a one-hour resolution and for different scenarios of the credible critical events from a standpoint of security of supply; different amounts of newly installed firm capacity; different short-run marginal costs of newly installed firm capacity; and different capacity factors of newly installed firm capacity. Test data such as electricity prices and electricity load are referred to the year 2018. The results show that the worst-case scenario for Croatia is an isolated system scenario with dry hydrology that results with high values of indicators expected energy not served (EENS), loss of load expectation (LOLE), and loss of load probability (LOLP) for Croatia. Therefore, new capacity of several hundred MW is needed to stabilize these indicators at lower values. Price for that capacity depends on the range of installed firm capacity and should be in range of 1000–7000 €/MW/year for value of lost load (VoLL) in Croatia of 1000 €/MWh and 3000–22,000 €/MW/year for VoLL of 3100 €/MWh that correlates with prices from already established capacity markets. The presented methodology can assist policymakers, regulators, and market operators when determining capacity remuneration mechanism rules and both capacity and price caps. On the other hand, it can help capacity market participants to prepare the most suitable and near-optimal bids on capacity markets.

Managing Wind Turbine Generators with a Profit Maximized Approach

In Europe, at least 3 GW installed capacity of wind turbine generators (WTG) will fall out of subsidy schemes every year from 2021 onwards. An estimated 50% of this capacity cannot be replaced with new WTG due to commercial and legal restrictions. The remaining options are either to sell the electricity without subsidies on the wholesale electricity market—a novelty for most WTG, as most are receiving a feed-in tariff—or their dismantlement. Since the electricity market fixes the price at the intersection of demand and short run marginal production costs, WTG might struggle to generate enough revenues to cover their costs. This paper proposes an innovative commercialization strategy for WTG after the end of the feed-in tariff, namely a profit-maximized approach that focuses on synergies between revenues and costs when increasing the curtailments of the WTG. The two key elements of this approach are a more flexible and variable cost structure and a central overall optimization process. The paper proves the potential of this new strategy and highlights the necessity of further research for WTG at the end of their lifetime from a technical and commercial perspective, due to the impact on the initial investment decision and best allocation of subsides.

Adaptive mechanisms to refund emissions payments

Carbon pricing is often discussed as a means by which to reduce power sector emissions, but typically faces opposition on the grounds that such schemes will increase wholesale electricity prices and have adverse impacts on the wider economy. Consequently, there is renewed focus on emissions pricing initiatives that have muted price impacts, with a Refunded Emissions Payments Scheme one such example. Under this mechanism, collected emissions payments are refunded to generators in proportion to energy output, with the net effect of the scheme resulting in each generator being subject to a net liability per MWh that is proportional to the difference between it’s own emissions intensity and the average emissions intensity of energy produced by regulated plant. A limitation of the scheme is the average emissions intensity of energy produced by regulated plant is only known after energy has been delivered, therefore there is some uncertainty with respect to each generator’s short-run marginal cost at the time of production. The presented framework addresses this issue by developing adaptive recalibration strategies that seek to make these net liabilities explicit. A rule-based updating strategy is developed, along with a highly generalisable model predictive control framework for updating scheme parameters. A case study using an agent-based framework is used to evaluate these mechanisms in the context of Australia’s National Electricity Market, and demonstrates how a policymaker could use such an approach to transparently update scheme parameters, and also accomplish auxiliary economic objectives.

Airport charges and marginal costs for Spanish airports before the process of partial privatization

Airport pricing is considered as one of the most relevant issues for policymakers. According transport policy, pricing schemes should be at least partially based on marginal costs. This article aims at comparing the most relevant aeronautical airport charges with their corresponding marginal costs for the Spanish airports in the period before the partial privatization process. To that end, we have built very detailed airport charge variables, and then, have estimated a flexible short-run variable cost function system using a panel of thirty-five airports over a 6-year period. The results show that the evolution of aeronautical airport charges does not follow the trend of marginal costs. Moreover, these charges are set above the short-run marginal costs with the exception of the smallest and insular airports. Finally, we find the existence of non-neutral technological change and excess of capacity for the Spanish airports.

Funding for roads in South Africa: Understanding the principles of fair and efficient road user charges

Roads support economic development and is one of the key economic infrastructures of South Africa. Funding for roads has been, and continues to be, controversial and faced with a multitude of challenges. The fuel levy, for instance, has for decades been the basis of road funding, but in recent years it has experienced declining effectiveness and efficiency. Both South African and international policy documents frequently propose the so-called user-pay principle to be adopted to fund land transport. It is frequently understood that the user-pay will imply sufficient revenue to sustain the road user, however this assumption is not entirely correct. In this paper the importance of roads to the economy is introduced which underscores the importance of an adequate and stable revenue source for road construction, maintenance and upgrade. The paper does emphasize that sufficient and adequate roads and hence funding is, however, not sufficient to support economic development. The paper defines and discuss the user-pay principle and the importance of charging road users efficient prices for road use. In transport, the term marginal social costs, sometimes also referred to as the principle of short run marginal social costs describes efficient road use prices. The paper discuss this concept as a road use charge. The technical difficulties of implementing marginal social cost is presented which are often the reason why alternative pricing regimes, such as average cost or long run marginal costs are adopted in practice. The paper concludes with a discussion on the way forward for South Africa.

Thought Experiment: Marginal Cost versus John M. Clark’s Workable Competition Pricing

This article compares numerical results for an original model of an industry using marginal cost pricing versus workable competition pricing with fluctuating demand with two alternative technologies. The article is a thought experiment in economics, carried out only in the imagination. The article presents a detailed numerical model of a basic industry, cement manufacturing with large numbers of sellers, cement manufacturers, and large numbers of buyers, the construction industry, operating independently with full knowledge of supply and demand conditions. In the model cement plants have linear total cost functions with absolute capacity limits. The article considers two alternative technologies: 1) plantL old plants with low fixed costs and high marginal costs and 2) plantK new plants with high fixed costs and low marginal costs. This study argues in support of John M. Clark (1884-1963) workable competition theory in contrast to marginal cost competition theory. The study examines likely equilibrium conditions under two alternate pricing systems: a) short-run marginal cost pricing and b) John M. Clark’s concept of workable competition. Workable competition raises prices above marginal costs in the off peak period and lowers prices in the peak periods. The study assumes frequency of off periods 6/7 and frequency of peak periods 1/7. The study claims, under the assumptions of the model, workable competition pricing add to consumer surplus over the cycle.

The marginal-cost pricing for a competitive wholesale district heating market: A case study in the Netherlands

District heating represents a viable way to reduce carbon dioxide emissions in the built environment. This paper aims to assess the extent to which the market revenues of multiple heat production technologies can cover their fixed costs in a competitive wholesale district heating market. Marginal-cost pricing is applied in a case study of the Netherlands. A linear programming model incorporating heat supply and demand is developed to obtain hourly dispatch and heat market prices. It is concluded that low carbon heat generation technologies tend to have low short-run marginal costs. All examined heat producers have an under-recovery of fixed costs in a range between 60% and 90% except the waste incineration combined heat and power plant. It has an overall return on investment of 44% and 12% within the reference and heat pump scenario respectively. Although marginal-cost pricing may ensure cost-efficient dispatch, the market revenues are far from enough to recoup the investment costs for the majority of the heat producer, let alone the network costs. Significant additional remuneration is required to sustain a competitive heat market and ensure sufficient investment in new generation capacity in the long run.

Deploying gas power with CCS: The role of operational flexibility, merit order and the future energy system

Combined cycle gas turbine (CCGT) power plants are an important part of many electricity systems. By fitting them with carbon capture their CO2 emissions could be virtually eliminated. We evaluate CCGT plants with different variations of post combustion capture using amine solvents, covering a range of options, including solvent storage, partial capture and shifting the energy penalty in time. The analysis is based on the UK electricity system in 2025. The behaviour of individual CCGT plants is governed by the plant’s place in the merit order and to a lesser extent by CO2 reduction targets for the electricity system. In the UK, CCGT plants built from 2016 onwards will emit ∼90% of the CO2 emissions of the whole CCGT fleet in 2025. The typical ‘base case’ CCGT plant with capture is designed to capture 90% of the CO2 emissions and to operate dynamically with the power plant. Downsizing the capture facility could be attractive for low-merit plants, i.e. plants with high short-run marginal costs. Solvent storage enables electricity generation to be decoupled in time from the energy penalty associated with carbon capture. Beyond a few minutes of solvent storage, substantial tanks would be needed. If solvent storage is to play an important role, it will require definitions of ‘capture ready’ to be expanded to ensure sufficient land is available.

Electricity tariff reforms, welfare impacts, and energy poverty implications

Like other energy-exporting countries, Brunei Darussalam has pursued an energy pricing policy that sets energy prices below market rates. The country introduced tariff reforms replacing the declining block tariff (DBT) scheme by an increasing block tariff (IBT) structure in 2012. The reform, however, was a rate structure change and not a subsidy removal, and electricity tariffs in the country remained lower than the long-run marginal cost. The study investigated a subsidy removal scenario, setting the tariff rate at the short-run marginal cost which is around 200% higher than the current average tariff rate. The results show that with IBT, welfare losses and the increase in electricity expenditures would be high for non-poor households; for those living in urban areas and for those engaged in white-collar jobs, and it would have been the reverse had the government not introduced tariff rate structure reforms. Under price elasticity scenarios, welfare losses would be high under inelastic than elastic demand case for both IBT and DBT cases. Electricity expenditures, however, would remain below 5% level – far lower than the energy poverty threshold level of 10% of household income. The tariff structure reform, therefore, shielded the lowest-income households from potential impacts of subsidy removal.

Getting prices right in structural electricity market models

Electricity market models are widely employed to study the role, impacts and economic viability of new technologies. Sources of arbitrage, such as storage and transmission, are increasingly seen as essential for integrating higher shares of variable renewables. Understanding their operation and business case requires models which accurately represent time-series of wholesale electricity prices.We show that the prevailing assumption of generators bidding short-run marginal cost, such as in the merit order stack, substantially underestimates the spread and volatility of hourly wholesale prices. To compound this, the lack of transparent outputs from previous electricity market modelling studies makes it impossible to scrutinise the prevailing methods or provide a detailed inter-comparison.We demonstrate a simple modification to the short-run marginal cost approach that delivers improved variability in modelled prices: allowing generators to make a spread of bids, below cost for their first megawatts of capacity, above for their last. Using this model we demonstrate the impact of price variability on the operation and profitability of storage, highlighting the urgent need for greater awareness of this aspect of market model performance.

Three Paradoxes with The Cobb-Douglas Production Function

The output elasticities of inputs seem all about what an applied researcher is concerned with. The Cobb-Douglas production functions formulae possess the convenient property that the exponents of inputs readily represent the output elasticities of inputs such that the sum of these exponents reveal whether there are increasing, constant or decreasing returns to scale. However, there are also some inconveniencies with this type of production functions. In this paper we will investigate three of them. First of all, the short run marginal cost functions obtained from the Cobb-Douglas type of production functions can be both convex and concave depending on the magnitude of the technical coefficient of labor input. Unfortunately, this awkward behavior cannot be explained with the economic theory. Secondly, when the variable input labor with a given level of Technical productivity is complemented with a once-and-for-all increase in the amount of physical capital input, the labor becomes more and more productive as the usage of labor increases. This clearly stands in contrast with the Law of Diminishing Marginal Returns. Finally, we find ever-increasing returns to ‘Technical productivity of labor’, keeping the amounts of labor and physical capital constant, which is again surprising. Key words : paradox; convex and concave marginal costs; Cobb-Douglas production function; increasing rate of return to Technical productivity of labor. JEL classification : D2, D3, D4. DOI : 10.7176/EJBM/11-1-12

The technology and cost structure of a natural gas pipeline: Insights for costs and rate-of-return regulation

This note details a complete microeconomic characterization of the physical relationships between input use and the level of output of a simple point-to-point gas pipeline system and uses it to contribute to the public policy discussions pertaining to the economic regulation of natural gas pipelines. We show that the engineering equations governing the design and operations of that infrastructure can be approximated by a single production equation of the Cobb-Douglas type. We use that result to inform three public policy debates. First, we prove that the long-run cost function of the infrastructure formally verifies the condition for a natural monopoly, thereby justifying the need of regulatory intervention in that industry. Second, we examine the conditions for cost-recovery in the short-run and contribute to the emerging European discussions on the implementation of short-run marginal cost pricing on interconnector pipelines. Lastly, we analyze the performance of rate-of-return regulation in that industry and inform the regulatory policy debates on the selection of an appropriate authorized rate of return. We highlight that, contrary to popular belief, the socially desirable rate of return can be larger than the market price of capital for that industry.

Duality Based Risk Mitigation Method for Construction of Joint Hydro-Wind Coordination Short-Run Marginal Cost Curves

This study analyzes the short-run hydro generation scheduling for the wind power differences from the contracted schedule. The approach for construction of the joint short-run marginal cost curve for the hydro-wind coordinated generation is proposed and applied on the real example. This joint short-run marginal cost curve is important for its participation in the energy markets and for economic feasibility assessment of such coordination. The approach credibly describes the short-run marginal costs which this coordination bears in “real life”. The approach is based on the duality framework of a convex programming and as a novelty combines the shadow price of risk mitigation, which quantifies the hourly cost of mitigating risk, and the water shadow price, which quantifies the marginal cost of electricity production. The proposed approach is formulated as a stochastic linear program and tested on the case of the Vinodol hydropower system and the wind farm Vrataruša in Croatia. The result of the case study is a family of 24 joint short-run marginal cost curves. The proposed method is expected to be of great interest to investors as it enables risk mitigation for investors with diverse risk preferences, from risk-averse to risk-seeking.

An analysis of storage revenues from the time-shifting of electrical energy in Germany and Great Britain from 2010 to 2016

The purpose of this paper is to investigate the level of revenues available to storage operators through the bulk time-shifting of electrical energy in Germany and Great Britain over the 7 years from 2010 to 2016, and to analyse the impact of volatility and underlying mean price on the potential revenues that a storage operator could theoretically capture. The analysis is carried out using an algorithm adapted from previous work, coupled with new empirical hourly price data from the German and Great British day-ahead electrical markets, and using characteristics typical of a pumped-storage hydropower scheme (1000 MWh, 125 MW charge and discharge, and 75% round-trip efficiency). Our results suggest that volatility rather than average price is the dominant factor affecting storage revenues, with a 1% increase in volatility implying an increase in mean daily storage revenues of €300 in Germany and £550 in Great Britain for the simulated storage plant. In comparison, an increase in underlying mean prices of €1 per MWh leads to an increase in mean daily revenue of €100 in Germany, with a £1 per MWh increase in underlying mean prices leading to an increase in mean daily revenue of £380 in Great Britain. We also find that during the period 2010–2016, the times when the highest revenue is derived have moved from late morning to early evening, which we attribute to the increase in low short-run marginal cost solar PV electricity in both markets suppressing the day-ahead wholesale electrical prices. In addition, we find a large increase in storage operator revenues in Britain in the last quarter of 2016, due to a number of events that impacted the price of electricity, however these would have been difficult to predict with any degree of certainty. This paper therefore highlights the perennial problem of forecasting the time-shifting revenue for electrical energy, with its high degree of variation from one year to the next that would undoubtedly impact the financing of these capital-intensive projects that seek to capture these variable revenues.

The Techno-Economics of Small-Scale Residential Heating in Low Carbon Futures

Existing studies that consider the techno-economics of residential heating systems typically focus on their performance within present-day energy systems. However, the energy system within which these technologies operate will need to change radically if climate change mitigation is to be achieved. This article addresses this problem by modelling small-scale heating techno-economics in the context of significant electricity system decarbonisation. The current electricity market price regime based on short run marginal costs is seen to provide a very weak investment signal for electricity system investors, so an electricity price regime based on long run marginal energy costs is also considered, using a case study of the UK in 2035. The economic case for conventional boilers remains stronger in most dwelling types. The exception to this is for dwellings with high annual heat demand. Sensitivity studies demonstrate the impact of factors such as price of natural gas, carbon intensity of the central grid and thermodynamic performance. Fuel cell micro combined heat and power shows most potential under the long run electricity price regime, and heat pumps under the short run electricity price regime. This difference highlights the importance of future electricity market structure on consumer choice of heating systems in the future.

Antitrust and the Movement of Technology

Patents create strong incentives for collaborative development. For many technologies fixed costs are extremely high in relation to variable costs. A second feature of technology that encourages collaborative development is the need for interoperability or common standards. Third, in contrast to traditional commons, intellectual property commons are almost always nonrivalrous on the supply side. If ten producers all own the rights to make a product covered by a patent, each one can make as many units as it pleases without limiting the number that others can make. That might seem to be a good thing, but considered ex ante it may not give producers the correct incentive to develop the patented technology in the first place. In any event, product differentiation in the output market will typically be sufficient to eliminate the problem of returns that are driven to short run marginal cost. In its Bement and General Electric decisions the Supreme Court permitted the members of a patent pool to set the product price, reasoning that the protections given by the patent laws are intended to meter the correct amount of innovation, and an explicit cartel selects the same output and price as a single firm. This reasoning confuses patent value with the value of collusion in the product market. Permitting the firms to collude on product price incorrectly predicates the value of the entire cartel markup to the patents.Often patents are pooled because the problem of identifying and defending boundaries is so significant that the patents are worthless or may even have negative value. The Supreme Court alluded to this problem without specifically addressing it in its March, 2012, Mayo Clinic v. Prometheus decision. A firm will pool when the cost of identifying and defending individual boundaries exceeds the cost of forming an IP commons. Nevertheless, the social cost of using pooling to reverse the effects of worthless patents is substantial. First are the significant costs of operating an economically useless system for acquiring the patent rights in the first place. Then are the significant costs of creating and operating a pool that is designed to reverse the consequences of worthless patent grants.Under United States antitrust law no firm has a general duty to deal with rivals. One difference between refusals to share ordinary productive assets and refusals to share IP rights is that ordinary productive assets can typically be replicated by others. But a patent gives a right to the technology that it covers and makes it unlawful for rivals to duplicate that technology, even if they do so on their own.