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| 1 |
ID:
191284
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| Summary/Abstract |
In this paper we investigate the relationship between increasing shares of renewable generation and the wholesale market revenues of coal-fired generating units in Australia's National Electricity Market (NEM). Renewable generation may influence coal generator revenues both through decreased spot market prices and reduced dispatch allocation. We use autoregressive distributed lag (ARDL) models on a high-frequency (30-min) panel dataset between July 2017 and June 2021. We find that a one MWh increase in wind and solar generation each is associated with decreases in coal generator revenues of 0.0062–0.0083 and 0.0041 to 0.0054 AUD2012 respectively, per megawatt of installed coal-fired generating capacity. These results can inform managerial and policy decisions regarding the likelihood of more premature coal plant exits in the coming decades.
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| 2 |
ID:
121370
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2013.
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| Summary/Abstract |
A key challenge internationally is the design of future electricity systems which will bring about emissions savings and fuel security at least cost. Peat is used to generate electricity in several EU countries, mainly to take advantage of indigenous resources and increase fuel mix diversity. The Irish government has introduced a target of 30% cofiring of peat and biomass by 2015. This paper assesses the feasibility of achieving this target by calculating the available indigenous biomass resource capable of being cofired; the cost of meeting the target; the benefits in terms of carbon abatement; and finally the present value in economic terms of meeting the target. Results demonstrate that Ireland has only half the necessary resource to meet the 30% target and that the net cost of doing so is greater than the cost of what is currently being paid for peat, in all of the scenarios considered. Thus, it is concluded that while it may be technically possible to meet the target by combining national resources with imported biomass this is never the least cost option, and as a result the targeted focus of Government policy may need to be reconsidered.
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| 3 |
ID:
116980
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2012.
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| Summary/Abstract |
We present a mixed-integer, linear programming model for determining optimal interconnection for a given level of renewable generation using a cost minimisation approach. Optimal interconnection and capacity investment decisions are determined under various targets for renewable penetration. The model is applied to a test system for eight regions in Northern Europe. It is found that considerations on the supply side dominate demand side considerations when determining optimal interconnection investment: interconnection is found to decrease generation capacity investment and total costs only when there is a target for renewable generation. Higher wind integration costs see a concentration of wind in high-wind regions with interconnection to other regions.
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| 4 |
ID:
149976
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| Summary/Abstract |
Conventionally the required instantaneous balance generation-load is achieved by adjusting production to fit variable consumer demand. Nowadays, a significant and increasing segment of generation is renewable. But renewable production cannot be scheduled on request since its generation is dependent on nature (wind, sun, …). In this context, demand-side management (DSM) would help since it would be advisable for part of the flexibility to be provided by the demand.
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| 5 |
ID:
132598
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2014.
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| Summary/Abstract |
In the last decade, the EU has driven forward the development and connection of renewable power sources across Europe. This has changed the way in which distribution networks operate, moving from a passive system, to a more active system where generation and demand are located closer together with system states being more complex and variable. Increased penetration of renewable generation into distribution networks is presenting a number of challenges to Distribution Network Operators (DNOs) including the provision of network access in capacity constrained networks. The introduction of Active Network Management (ANM) is enabling an increase in renewable generation connections through enhanced network access in otherwise 'full' networks.
This paper presents a way in which DNOs might move towards Business as Usual (BAU) arrangements for ANM schemes. It is necessary to determine the curtailment arrangements, or Principles of Access (PoA), and from this estimate generation access under ANM and the flow of services and money for different scenarios. In this paper, a comprehensive literature review, detailed case study evaluation on early ANM schemes, quantitative curtailment assessment for different PoA and a qualitative analysis of business models for different ANM PoA is presented in turn with conclusions drawn from these three approaches.
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| 6 |
ID:
171473
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| Summary/Abstract |
This paper analyzes the recent expansion of transmission lines in Texas, essentially completed in 2013 at a cost of approximately $7 billion. This project was intended to improve access to areas with high wind generation potential and the resulting increase in wind generation reduced fuel costs and emissions from the displaced fossil fuel generators. I find that the value of the resulting emissions reduction from additional wind generation is approximately twice that of the fuel savings. Additionally, when incorporating the value of reduced emissions, increased generation from already existing wind turbines alone could offset about half of the annualized cost of this transmission expansion while using only 2% of the new transmission capacity. Incorporating the value of emissions reductions could make extending transmission lines to access high quality wind resources more viable, especially if production from already-existing wind turbines in the area are being non-trivially curtailed, as was true in this case.
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| 7 |
ID:
137659
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| Summary/Abstract |
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.
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