Distribution of costs induced by the integration of RES-E power

This article focuses on the distribution of costs induced by the integration of electricity generation from renewable energy sources (RES-E). The treatment to distribute these costs on different market actors is crucial for its development. For this purpose, individual actors of electricity markets and several cost categories are identified. According to the defined cost structure, possible treatments to distribute the individual cost categories on different relevant actors are described. Finally, an evaluation of the cost distribution treatments based on an economic analysis is given. Economic efficiency recommends that clearly attributable (shallow) grid connection as well as (deep) grid costs are charged to the corresponding RES-E producer and that the RES-E producers are also charged the regulating power costs. However, deep grid integration costs should be updated to reflect evolving scarcities. Also regulating power costs should reflect actual scarcity and thus be symmetric and based on real-time prices, taking into account the overall system imbalance. Moreover, the time span between the closure of the spot market and actual delivery should be chosen as short as possible to enable accurate RES-E production forecasts.     

Seamless electricity trade between Canada and US Northeast

We analyze how the wholesale electricity market deregulation could modify exchanges between three Canadian regions (Ontario, Quebec and New Brunswick) and two US regions (New York and New England), on the base of their loads and available resources when the regulatory change took place in 1997. We find that the pre-1997 exchanges already made possible fuel cost savings of $397.2 million per year while deregulation adds annual savings of $358.7 million. Canadian regions are the main beneficiaries under the assumption that exports are priced at the marginal costs of the importing regions. Imports from the Canadian regions, although significant, are not large enough to lower the marginal costs of the US regions. Hence electricity deregulation across the border should not significantly decrease prices in the US regions although the latter are becoming more dependent upon imports from Canada. Greenhouse gas emissions increase by 4.3 Mt CO₂ eq. in the wake of the open wholesale electricity market because of the low cost of coal, particularly in Ontario. Environmental concerns and the limited availability of additional hydroelectric power in Canada could change the trade patterns as electricity demand continue to grow.     

Using renewables to hedge against future electricity industry uncertainties—An Australian case study

A generation portfolio modelling was employed to assess the expected costs, cost risk and emissions of different generation portfolios in the Australian National Electricity Market (NEM) under highly uncertain gas prices, carbon pricing policy and electricity demand. Outcomes were modelled for 396 possible generation portfolios, each with 10,000 simulations of possible fuel and carbon prices and electricity demands. In 2030, the lowest expected cost generation portfolio includes 60% renewable energy. Increasing the renewable proportion to 75% slightly increased expected cost (by $0.2/MWh), but significantly decreased the standard deviation of cost (representing the cost risk). Increasing the renewable proportion from the present 15% to 75% by 2030 is found to decrease expected wholesale electricity costs by $17/MWh. Fossil-fuel intensive portfolios have substantial cost risk associated with high uncertainty in future gas and carbon prices. Renewables can effectively mitigate cost risk associated with gas and carbon price uncertainty. This is found to be robust to a wide range of carbon pricing assumptions. This modelling suggests that policy mechanisms to promote an increase in renewable generation towards a level of 75% by 2030 would minimise costs to consumers, and mitigate the risk of extreme electricity prices due to uncertain gas and carbon prices.     

A new approach to congestion pricing in electricity markets: Improving user pays pricing incentives

Electricity pricing has traditionally been based on average cost pricing where consumers pay a ‘flat’ tariff based upon the average cost of production and transportation of electricity. The introduction of new ‘smart’ meters allows electricity providers to differentiate tariffs on the basis of time. Utilising congestion pricing theory, the energy industry has embraced ‘time-of-use’ (ToU) tariffs with a view to more efficiently pricing electricity. This paper demonstrates that pricing as a function of demand variability (reflecting capacity utilisation) is a more appropriate alternative to existing ToU tariffs for more efficiently allocating costs to end users. We call this new alternative pricing model ‘first derivative ratio’ FDR pricing. This new approach to congestion pricing could be applied to markets other than electricity, such as road transportation.     

Energy taxation in a small, open economy: Social efficiency gains versus industrial concerns

Welfare analyses of energy taxes typically show that systems with uniform rates perform better than differentiated systems, especially if revenue can be recycled by cutting taxes that are more distortionary. However, in practical policy, efficiency gains must be traded off against industrial concerns. Presumably, energy-dependent industries of small, open economies will suffer relatively more if taxed. This computable general equilibrium (CGE) study examines the social costs of compensating the energy-intensive export industries in Norway for their profit losses from imposing the same electricity tax on all industries. The costs are surprisingly modest. This is explained by the role of the Nordic electricity market, which is still limited enough to respond to national energy tax reforms. Thus, an electricity price reduction partly neutralizes the direct impact of the tax on profits. In addition, we examine the effects of different compensation schemes and find significantly lower compensation costs when the scheme is designed to release productivity gains.     

Modelling of thermal energy storage in industrial energy systems the method development of MIND

Industrial energy efficiency is of vital importance as regards environment and industrial profitability. Optimisation of industrial energy systems may show a way towards improved use of resources in energy supply as well as in production processes.The deregulation of the electricity market in some countries increases flexibility in electricity contracts. Taking advantage of the price structure in these contracts is one of the ways to minimise the energy costs and decrease the influence on the environment. Thermal energy stores are very suitable facilities for achieving these goals, having the capability of moving energy use from one period of time to another and thereby influencing not only energy cost but also costs related to power demand if electric energy use is involved.In this paper, the influence on energy costs, energy and material flows resulting from the use of energy storage is discussed. Energy storage has been modelled by using MIND (Method for analysis of INDustrial energy systems) in the form that has recently been developed by the author. A case study from the pulp and paper industry has been used to verify this.     

The benefits of integrating European electricity markets

The European Commission's Target Electricity Model (TEM) aims to integrate EU electricity markets. This paper estimates the potential benefit of coupling interconnectors to increase the efficiency of trading day-ahead, intra-day and balancing services across borders. Further gains are possible by eliminating unscheduled flows and avoiding the curtailment of renewables with better market design. In the short run the gains could be as high as €3.9 billion/yr, more than 100% of the current gains from trade. About one-quarter of this total comes from day-ahead coupling and another third from shared balancing. If shared balancing is so valuable, completing the TEM becomes more urgent, and regulators should ensure these gains are paid to interconnectors to make the needed investment in the cross-border links more commercially profitable.     

Progress of renewable electricity replacing fossil fuels

Dramatic fall in costs of renewable energy in the last 24 months has not only accelerated the replacement of fossil fuels by renewable energy in electricity generation. The low cost renewable electricity is now starting to replace fossil fuels in other sectors.One reason is that renewable electricity is now cheaper per unit energy than oil, about the same price as fossil methan but, still, more expensive than coal. Another reason is that electricity often offer other opportunities, such as cheaper transport, better control, higher energy efficiency in final production of energy services and lower local environmental costs.     

Electricity tariffs based on long-run marginal costs for central grid system of Oman

The electricity tariffs in Oman are subsidized and are based on a cost accounting approach and do not reflect the true cost incurred in generating, transmitting and distributing a kilowatt-hour of electricity at the consumer end. This paper presents the electricity tariff based on the estimation of long-run marginal cost at generation, 33 kV, and 415 voltage level for Ministry of Housing, Electricity & Water (MHEW) interconnected power system of Oman. The result shows that at the generation level a marginal kW costs US$ 75 per year and a marginal kWh costs 2.07 ¢/kWh. These costs increase as we move downstream from generation to consumer end. The average cost of electricity at the consumer end connected at 415 V is 6.52 ¢/kWh or 25.17 Bz/kWh.     

Electricity prices and generator behaviour in gross pool electricity markets

Electricity market liberalisation has become common practice internationally. The justification for this process has been to enhance competition in a market traditionally characterised by statutory monopolies in an attempt to reduce costs to end-users. This paper endeavours to see whether a pool market achieves this goal of increasing competition and reducing electricity prices. Here the electricity market is set up as a sealed bid second price auction. Theory predicts that such markets should result with firms bidding their marginal cost, thereby resulting in an efficient outcome and lower costs to consumers. The Irish electricity system with a gross pool market experiences among the highest electricity prices in Europe. Thus, we analyse the Irish pool system econometrically in order to test if the high electricity prices seen there are due to participants bidding outside of market rules or out of line with theory. Overall we do not find any evidence that the interaction between generator and the pool in the Irish electricity market is not efficient. Thus, the pool element of the market structure does not explain the high electricity prices experienced in Ireland.     

Optimisation of merged district-heating systems—benefits of co-operation in the light of externality costs

Studies have shown that separate actors can benefit from co-operation around heat supply. Such co-operation, for example, might be between an industry selling waste heat to a district-heating system or two district-heating systems interconnecting their respective systems. Co-operation could also be expected to reduce the environmental impacts of the energy systems by choosing the plants with the lowest emissions. It is widely accepted that the production of heat and electricity causes damage to the environment. This damage often imposes a cost on society, but not on company responsible. In general, using a broader system perspective when analysing local energy systems results in a lower total cost, more efficient use of plants and a greater potential for producing electricity in combined heat-and-power (CHP) plants. Internalising the externality costs in the energy system model facilitates the study of what co-operation can mean for reducing emissions. This study shows that co-operation between the two systems is on the whole cost-effective, but the benefits are greater when external costs are not included in the calculation. Considering externality costs in combination with current electricity prices would lead to a higher system cost, but the quantity of emission gases will be lower. If, on the other hand, the calculation is made taking externality costs and corresponding adjusted electricity prices (the adjustment being necessary to compensate for the additional cost due to externality costs) into consideration, the quantities of emission gases will rise because more heat-and-power will be generated by one of the CHP plants.     

Feed-in tariff and market electricity price comparison: The case of cogeneration units in Croatia

In August 2007, the Government of the Republic of Croatia instituted a feed-in tariff system, requiring the Croatian Electricity Market Operator (HROTE) to off-take the electricity produced from renewable energy sources or cogeneration units fueled by natural gas. Analysis of the off-take electricity price range, which depends on the net electrical output and electricity market trends, indicates that it is more cost effective for cogeneration units greater than 1 MW to sell their electricity on the exchange market. This was confirmed by developing a mathematical model to calculate the cost-effectiveness ratio of a cogeneration unit. This ratio represents the relation between the profit spread, i.e. the difference between the profit generated from selling the electricity on the exchange market and the profit made from dispatching the electricity to HROTE, as well as the total investment costs. The model can be applied for changes in certain parameters, such as the net electrical output, volatility and spot electricity price. The Monte Carlo method is used to obtain the most probable cost-effectiveness ratio and average future electricity price. Together with these two economic parameters and market price analysis, it is possible to calculate and calibrate an acceptable off-take electricity price.     

On the reduction of electric energy consumption in electrolysis: A thermodynamic study

Electricity is the major component in the cost of hydrogen production via electrolysis. This study aims to reduce electric energy consumption in electrolysis and replace it with lower cost thermal energy. An idealized thermodynamic analysis of hydrogen production by electrolysis at higher temperatures is presented, with particular emphasis on isolating the work and thermal components of the required energy. There is significant advantage in using thermal energy from another complementary process to overheat the inlet steam to meet this need. The electricity demand for electrolysis, under reasonable conditions, can thus be reduced to 26.63 kWh kg^?1. Introducing multiple stages can further reduce this to 25.22 kWh kg^?1 and more significantly, greatly reduce the temperature of the thermal energy needed. At lower utilizations, it is possible to reduce the electrical requirement to below 20 kWh kg^?1, which is less than half the most aggressive targets for electrolyzer improvements.     

A new hybrid ocean thermal energy conversion–Offshore solar pond (OTEC–OSP) design: A cost optimization approach

Solar thermal electricity (STE) generation offers an excellent opportunity to supply electricity with a non-CO₂ emitting technology. However, present costs hamper widespread deployment and therefore research and development efforts are concentrated on accelerated cost reductions and efficiency improvements. Many focus on the latter, but in this paper we rather focus on attaining very low levelised electricity costs (LEC) by designing a system with very low material cost, while maintaining appreciable conversion efficiency and achieving low maintenance cost. All investigated designs were dimensioned at a 50 MW scale production. Calculated LECs show that a new proposed hybrid of ocean thermal energy conversion with an offshore solar pond (OTEC–OSP) may have the lowest LEC of 0.04 €/kWh. Addition of a floating offshore solar pond (OSP) to an OTEC system increases the temperature difference in the Rankine cycle, which leads to an improved efficiency of 12%, while typical OTEC efficiencies are 3%. This higher efficiency leads to much lower investments needed for power blocks, while the OSP is fabricated using very low-cost plastic foils. The new OTEC–OSP design can be located in many sunny coastal areas in the world.     

Industrial DSM in a deregulated European electricity market—a case study of 11 plants in Sweden

In 2004 Sweden will become part of a common European electricity market. This implies that the price of electricity in Swedish will adapt to a higher European electricity price due to the increase in cross-border trading. Swedish plant is characterized as more electricity-intensive than plant on the European continent, and this, in combination with a higher European electricity price will lead to a precarious scenario.This paper studies the energy use of 11 plants in the municipality of Oskarshamn in Sweden. The aim is to show how these plants can reduce their electricity use to adapt to a European level. We have found that the plants could reduce their use of electricity by 48% and their use of energy by 40%. In a European perspective, where coal-condensing power is assumed to be the marginal production that alters as the electricity demand changes, the decrease in the use of electricity in this study leads to a reduction in global emissions of carbon dioxide of 69,000 tonne a year.Electricity generated in Sweden emits very low emissions of carbon dioxide and have thus consequently very low external cost. The freed capacity in Sweden could therefore replace electricity generated with higher external cost and as a result lower the total external cost in Europe. The emissions from the saved electricity could also be valuable within the EU emissions trading scheme, if the emissions calculation is done assuming the marginal electricity is fossil fuel based.     

Bidding strategy of wind-thermal energy producers

This paper presents a stochastic mixed-integer linear programming approach for solving the self-scheduling problem of a price-taker thermal and wind power producer taking part in a pool-based electricity market. Uncertainty on electricity price and wind power is considered through a set of scenarios. Thermal units are modelled by variable costs, start-up costs and technical operating constraints, such as: forbidden operating zones, ramp up/down limits and minimum up/down time limits. An efficient mixed-integer linear program is presented to develop the offering strategies of the coordinated production of thermal and wind energy generation, having as a goal the maximization of profit. A case study with data from the Iberian Electricity Market is presented and results are discussed to show the effectiveness of the proposed approach.     

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.     

Greenhouse gas emissions reduction by use of wind and solar energies for hydrogen and electricity production: Economic factors

This study addresses economic aspects of introducing renewable technologies in place of fossil fuel ones to mitigate greenhouse gas emissions. Unlike for traditional fossil fuel technologies, greenhouse gas emissions from renewable technologies are associated mainly with plant construction and the magnitudes are significantly lower. The prospects are shown to be good for producing the environmentally clean fuel hydrogen via water electrolysis driven by renewable energy sources. Nonetheless, the cost of wind- and solar-based electricity is still higher than that of electricity generated in a natural gas power plant. With present costs of wind and solar electricity, it is shown that, when electricity from renewable sources replaces electricity from natural gas, the cost of greenhouse gas emissions abatement is about four times less than if hydrogen from renewable sources replaces hydrogen produced from natural gas. When renewable-based hydrogen is used in a fuel cell vehicle instead of gasoline in a IC engine vehicle, the cost of greenhouse gas emissions reduction approaches the same value as for renewable-based electricity only if the fuel cell vehicle efficiency exceeds significantly (i.e., by about two times) that of an internal combustion vehicle. It is also shown that when 6000 wind turbines (Kenetech KVS-33) with a capacity of 350 kW and a capacity factor of 24% replace a 500-MW gas-fired power plant with an efficiency of 40%, annual greenhouse gas emissions are reduced by 2.3 megatons. The incremental additional annual cost is about $280 million (US). The results provide a useful approach to an optimal strategy for greenhouse gas emissions mitigation.     

MODEST-An energy-system optimisation model applicable to local utilities and countries

MODEST, an energy-system optimisation model is described. It has been applied to a typical local Swedish electricity and district-heating utility and to the national power system. Present and potential installations and energy flows should be considered and their best combination can be obtained through optimisation. MODEST uses linear programming to minimise the capital and operation costs of energy supply and demand-side management. Seasonal, weekly, and diurnal variations of, for example, demand, costs, and capacities are considered. MODEST may be used to decide which investments to make, the dimensioning of new installations, and the operation of all system components. The municipal utility under study should now expand its heat production using woodchips. Electricity export or nuclear phase-out will probably raise the Swedish electricity prices. In this case, cost minimisation is achieved by introducing combined heat and power (CHP) production in the municipality. Fossil fuels should be used in the cogeneration plant at current taxation levels but biofuels are favourable if higher environmental fees are imposed for CO₂ emissions. Biomass capacity expansion could decrease local CO₂ emissions by 80%. Efficiency improvements for electricity use have robust profitability at high electricity prices. The Swedish electricity demand may be satisfied without nuclear power and fossil fuels through massive biomass use, wind-power supply, and energy conservation.     

Analysis of CO2 emissions reduction potential in secondary production and semi-fabrication of non-ferrous metals

Industrial sector growth in developing countries requires the provision of alternatives to guarantee sustainable development. Improving energy efficiency and fuel switching are two measures to reduce CO₂ emissions in the industrial sector, with natural gas and low-carbon electricity as the most feasible options in the short term. In this work, a linear programming optimization model has been developed to study the potential of energy efficiency improvement and fuel substitution for CO₂ emissions reduction, at national level in the non-ferrous metals industry. The energy resource/end-use device allocation problem in secondary metal production and semi-fabrication has been modeled. Using this model, the particular case of Colombia, where low-carbon electricity is available, has been studied. By improving energy efficiency, energy use and CO₂ emissions can be reduced significantly, 73% and 72%, respectively, at negative costs. Further CO₂ emissions reductions, up to 88%, are possible with fuel switching to low-carbon electricity, increasing the costs for the energy system; however, cost reductions caused by energy efficiency improvement outweigh cost increments of fuel switching. Benefits achieved with fuel substitution using low-carbon electricity can be lost if hydropower is not available; in such a case, efficient natural gas-fired end-use devices are preferable.