7,803 research outputs found

    Regulation of transmission expansion in Argentina Part I: State ownership, reform and the Fourth Line

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    From 1992 to 2002, major expansions of the Argentine electricity transmission sector depended on users proposing, voting and paying for such expansions, which were then put out to competitive tender. Commentators hold this novel policy to have been unsuccessful, mainly on the ground that it substantially delayed investment in a much needed “Fourth Line” to Buenos Aire. This paper challenges this interpretation. The policy was chosen because the conventional regulatory framework could not be trusted to deliver more efficient transmission investment decisions. The delay to the Fourth Line was short. Most importantly, the Fourth Line was not economic. Hence the delay was beneficial both in deferring and in reducing costs. It indicated a need to reappraise transmission investment policy because the availability of gas had made it more economic to generate electricity near Buenos Aires than to transmit it a long distance.Argentina, electricity, transmission, regulation

    Transmissionmanagementforcongestedpowersystem:Areviewof concepts,technicalchallengesanddevelopmentofanewmethodology

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    Transmissionnetworkshavesomeconstraintsthatshouldbeaddressedinordertoensuresufficient\ud control tomaintainthesecuritylevelofapowersystemwhilemaximisingmarketefficiency.Themost\ud obviousdrawbackoftransmissionconstraintsisacongestionproblemthatbecomesanobstacleto\ud perfect competitionamongthemarketparticipantssinceitcaninfluence spotmarketpricing.Asthe\ud power flow violatestransmissionconstraints,redispatchinggeneratingunitsisrequiredandthiswill\ud cause thepriceateverynodetovary.Thismanuscriptpresentsconcepts,technicalchallengesand\ud methodology forinvestigatinganalternativesolutiontotheredispatchmechanismandthenformulates\ud LMP schemeusinganoptimisationtechniquethatmaywellcontrolcongestionasthemainissue.The\ud LMP schemearevariedandimprovedtotakeintoaccounttheenergyprice,congestionrevenue,costof\ud losses, aswellasthetransmissionusagetariffbyutilisingshiftfactor-basedoptimalpower flow\ud (SF-OPF), whichisderivedfromthewell-knownDCoptimalpower flow(DC-OPF)mode

    Collinsville solar thermal project: energy economics and dispatch forecasting (final report)

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    The primary aim of this report is to help negotiate a Power Purchase Agreement (PPA) for the proposed hybrid gas-Linear Frensel Reflector (LFR) plant at Collinsville, Queensland, Australia.  The report’s wider appeal is the discussion of the current situation in Australian National Electricity Market (NEM) and techniques and methods used to model the NEM’s demand and wholesale spot prices for the lifetime of the proposed plant. Executive Summary 1        Introduction This report primarily aims to provide both dispatch and wholesale spot price forecasts for the proposed hybrid gas-solar thermal plant at Collinsville, Queensland, Australia for its lifetime 2017-47.  These forecasts are to facilitate Power Purchase Agreement (PPA) negotiations and to evaluate the proposed dispatch profile in Table 3.  The solar thermal component of the plant uses Linear Fresnel Reflector (LFR) technology.  The proposed profile maintains a 30 MW dispatch during the weekdays by topping up the yield from the LFR by dispatch from the gas generator and imitates a baseload function currently provided by coal generators.  This report is the second of two reports and uses the findings of our first report on yield forecasting (Bell, Wild & Foster 2014b). 2        Literature review The literature review discusses demand and supply forecasts, which we use to forecast wholesale spot prices with the Australian National Electricity Market (ANEM) model. The review introduces the concept of gross demand to supplement the Australian Electricity Market Operator’s (AEMO) “total demand”.  This gross demand concept helps to explain the permanent transformation of the demand in the National Electricity Market (NEM) region and the recent demand over forecasting by the AEMO.  We also discuss factors causing the permanent transformation.  The review also discusses the implications of the irregular ENSO cycle for demand and its role in over forecasting demand. Forecasting supply requires assimilating the information in the Electricity Statement of Opportunities (ESO) (AEMO 2013a, 2014c).  AEMO expects a reserve surplus across the NEM beyond 2023-24.  Compounding this reserve surplus, there is a continuing decline in manufacturing, which is freeing up supply capacity elsewhere in the NEM.  The combined effect of export LNG prices and declining total demand are hampering decisions to transform proposed gas generation investment into actual investment and hampering the role for gas as a bridging technology in the NEM.  The review also estimates expected lower and upper bounds for domestic gas prices to determine the sensitivity of the NEM’s wholesale spot prices and plant’s revenue to gas prices. The largest proposed investment in the NEM is from wind generation but the low demand to wind speed correlation induces wholesale spot price volatility.  However, McKinsey Global Institute (MGI 2014) and Norris et al. (2014a) expect economically viable energy storage shortly beyond the planning horizon of the ESO in 2023-24.  We expect that this viability will not only defer investment in generation and transmission but also accelerate the growth in off-market produced and consumed electricity within the NEM region. 2.1     Research questions The report has the following overarching research questions: What is the expected dispatch of the proposed plant’s gas component given the plant’s dispatch profile and expected LFR yield? What are the wholesale spots prices on the NEM given the plant’s dispatch profile? The literature review refines the latter research question into five more specific research questions ready for the methodology: What are the half-hourly wholesale spots prices for the plant’s lifetime without gas as a bridging technology? Assuming a reference gas price of between 5.27/GJto5.27/GJ to 7.19/GJ for base-load gas generation (depending upon nodal location;) and for peak-load gas generation of between 6.59/GJto6.59/GJ to 8.99/GJ; and given the plant’s dispatch profile What are the half-hourly wholesale spots prices for the plant’s lifetime with gas as a bridging technology? Assuming some replacement of coal with gas generation How sensitive are wholesale spot prices to higher gas prices? Assuming high gas prices are between 7.79/GJto7.79/GJ to 9.71/GJ for base-load gas generation (depending upon nodal location); and for peak-load gas generation of between 9.74/GJto9.74/GJ to 12.14/GJ; and What is the plant’s revenue for the reference gas prices? How sensitive is the plant’s revenue to gas as a bridging technology? How sensitive is the plant’s revenue to the higher gas prices? What is the levelised cost of energy for the proposed plant? 3        Methodology In the methodology section, we discuss the following items: dispatch forecasting for the proposed plant; supply capacity for the years 2014-47 for the NEM; demand forecasting using a Typical Meteorological Year (TMY); and wholesale spot prices calculation using ANEM, supply capacity and total demand define three scenarios to address the research questions: reference gas prices; gas as a bridging technology; and high gas prices. The TMY demand matches the solar thermal plant’s TMY yield forecast that we developed in our previous report (Bell, Wild & Foster 2014b).  Together, these forecasts help address the research questions. 4        Results In the results section we will present the findings for each research question, including the TMY yield for the LFR and the dispatch of the gas generator given the proposed dispatch profile in Table 3; Average annual wholesale spot prices from 2017 to 2047 for the plant’s node for: Reference gas prices scenario from 18/MWhto18/MWh to 38/MWh Gas as a bridging technology scenario from 18/MWhto18/MWh to 110/MWh High gas price scenario from 20/MWhto20/MWh to 41/MWh The combined plants revenue without subsidy given the proposed profile: Reference gas price scenario 36millionGasasabridgingtechnologyscenario36 million Gas as a bridging technology scenario 52 million High gas price scenario $47 million 5        Discussion In the discussion section, we analyse: reasons for the changes in the average annual spot prices for the three scenarios; and the frequency that the half-hourly spot price exceeds the Short Run Marginal Cost (SRMC) of the gas generator for the three scenarios for: day of the week; month of the year; and time of the day. If the wholesale spot price exceeds the SRMC, dispatch from the gas plant contributes towards profits.  Otherwise, the dispatch contributes towards a loss.  We find that for both reference and high gas price scenarios the proposed profile in Table 3 captures exceedances for the day of the week and the time of the day but causes the plant to run at a loss for several months of the year.  Figure 14 shows that the proposed profile captures the exceedance by hour of the day and Figure 16 shows that only operating the gas component Monday to Friday is well justified.  However, Figure 15 shows that operating the gas plant in April, May, September and October is contributing toward a loss.  Months either side of these four months have a marginal number of exceedances.  In the unlikely case of gas as a bridging scenario, extending the proposed profile to include the weekend and operating from 6 am to midnight would contribute to profits. We offer an alternative strategy to the proposed profile because the proposed profile in the most likely scenarios proves loss making when considering the gas component’s operation throughout the year.  The gas-LFR plant imitating the based-load role of a coal generator takes advantage of the strengths of the gas and LFR component, that is, the flexibility of gas to compensate for the LFR’s intermittency, and utilising the LFR’s low SRMC.  However, the high SRMC of the gas component in a baseload role loses the flexibility to respond to market conditions and contributes to loss instead of profit and to CO2 production during periods of low demand. The alternative profile retains the advantages of the proposed profile but allows the gas component freedom to exploit market conditions.  Figure 17 introduces the perfect day’s yield profile calculated from the maximum hourly yield from the years 2007-13.  The gas generator tops up the actual LFR yield to the perfect day’s yield profile to cover LFR intermittency.  The residual capacity of the gas generator is free to meet demand when spot market prices exceed SRMC and price spikes during Value-of-Lost-Load (VOLL) events.  The flexibility of the gas component may prove more advantageous as the penetration of intermittent renewable energy increases. 6        Conclusion We find that the proposed plant is a useful addition to the NEM but the proposed profile is unsuitable because the gas component is loss making for four months of the year and producing CO2 during periods of low demand.  We recommend further research using the alternative perfect day’s yield profile. 7        Further Research We discuss further research compiled from recommendation elsewhere in the report. 8        Appendix A Australian National Electricity Market Model Network This appendix provides diagrams of the generation and load serving entity nodes and the transmission lines that the ANEM model uses.  There are 52 nodes and 68 transmission lines, which make the ANEM model realistic.  In comparison, many other models of the NEM are highly aggregated. 9        Appendix B Australian National Electricity Market Model This appendix describes the ANEM model in detail and provides additional information on the assumptions made about the change in the generation fleet in the NEM during the lifetime of the proposed plant

    A Quantitative Analysis of Pricing Behavior In California’s Wholesale Electricity Market During Summer 2000

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    During the Summer of 2000, wholesale electricity prices in California were nearly 500% higher than they were during the same months in 1998 or 1999. This price explosion was unexpected and has called into question whether electricity restructuring will bring the benefits of competition promised to consumers. The purpose of this paper is to examine the factors that explain this increase in wholesale electricity prices. We simulate competitive benchmark prices for Summer of 2000 taking account of all relevant supply and demand factors --- gas prices, demand, imports from other states, and emission permit prices. We then compare the simulated competitive benchmark prices with the actual prices observed. We find that there is a large gap between our benchmark competitive prices and observed prices, suggesting that the prices observed during summer 2000 reflect, in part, the exercise of market power by suppliers. We then proceed to examine supplier behavior during high-price hours. We find evidence that suppliers withheld supply from the market that would have been profitable for price-taking firms to sell at the market price.electricity, market power, deregulation

    Market and Economic Modelling of the Intelligent Grid: End of Year Report 2009

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    The overall goal of Project 2 has been to provide a comprehensive understanding of the impacts of distributed energy (DG) on the Australian Electricity System. The research team at the UQ Energy Economics and Management Group (EEMG) has constructed a variety of sophisticated models to analyse the various impacts of significant increases in DG. These models stress that the spatial configuration of the grid really matters - this has tended to be neglected in economic discussions of the costs of DG relative to conventional, centralized power generation. The modelling also makes it clear that efficient storage systems will often be critical in solving transient stability problems on the grid as we move to the greater provision of renewable DG. We show that DG can help to defer of transmission investments in certain conditions. The existing grid structure was constructed with different priorities in mind and we show that its replacement can come at a prohibitive cost unless the capability of the local grid to accommodate DG is assessed very carefully.Distributed Generation. Energy Economics, Electricity Markets, Renewable Energy

    A Review of ISO New England's Proposed Market Rules

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    This report reviews the proposed rules for restructured wholesale electricity markets in New England. We review the market rules, both individually and collectively, and identify potential problems that might limit the efficiency of these markets. We examine alternatives and identify the key tradeoffs among alternative designs. We believe that the wholesale electricity market in New England can begin on December 1, 1998. However, improvements are needed for long-run success. We have identified four major recommendations: 1. Switch to a multi-settlement system. 2. Introduce demand-side bidding. 3. Adopt location-based transmission congestion pricing, especially for the import/export interfaces. 4. Fix the pricing of the ten minute spinning reserves.Auctions; Multiple Object Auctions; Electricity Auctions
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