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Analyzing California's Power Crisis

Ahmad Faruqui, Hung-po Chao, Vic Niemeyer, Jeremy Platt and Karl Stahlkopf

Year: 2001
Volume: Volume22
Number: Number 4
DOI: 10.5547/ISSN0195-6574-EJ-Vol22-No4-2
No Abstract



What future(s) for liberalized electricity markets: efficient, equitable or innovative?

David M Newbery

Year: 2018
Volume: Volume 39
Number: Number 1
DOI: 10.5547/01956574.39.1.dnew
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Abstract:
Well-designed electricity liberalization has delivered effciency gains, but political risks of decarbonizing the sector have undermined investment incentives in en-ergy-only markets, while poorly designed regulated tariffs have increased the cost of accommodating renewables. The paper sets out principles from theory and public economics to guide market design, capacity remuneration, renewables support and regulatory tariff setting, with an illustration from a high capital cost low variable cost electricity system. Such characteristics are likely to become more prevalent with increasing renewables penetration, where poor regulation is already threatening current utility business models. The appendix develops and applies a method for determining the subsidy justifed by learning spillovers from solar PV.



Enhancing Intraday Price Signals in U.S. ISO Markets for a Better Integration of Variable Energy Resources

Ignacio Herrero, Pablo Rodilla, and Carlos Batlle

Year: 2018
Volume: Volume 39
Number: Number 3
DOI: 10.5547/01956574.39.3.iher
View Abstract

Abstract:
Efficient operation of power systems increasingly requires accurate forecasting of load and variable energy resources (VER) production, along with flexible resources and markets, capable of adapting to changing conditions in the intraday horizon. It is of utmost importance to reflect these needs in price signals, to align the incentives of market agents with the new challenges. The two-settlement system used by U.S. ISOs falls short to provide efficient intraday economic signals and a cost reflective allocation of intraday rescheduling costs. This paper advocates for a multi-settlement system, which entails calculating intraday prices as forecasts are updated and re-schedules are executed. This approach incorporates more granular prices, as in European intraday markets, while keeping the efficient centralized dispatch logic of the ISO model. A stylized case example illustrates the virtues of a multi-settlement system, which sends cost reflective signals, and consequently facilitates VER integration.



Economic Inefficiencies of Cost-based Electricity Market Designs

Francisco D. Munoz, Sonja Wogrin, Shmuel S. Oren, and Benjamin F. Hobbs

Year: 2018
Volume: Volume 39
Number: Number 3
DOI: 10.5547/01956574.39.3.fmun
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Abstract:
Some restructured power systems rely on audited cost information instead of competitive bids for the dispatch and pricing of electricity in real time, particularly in hydro systems in Latin America. Audited costs are also substituted for bids in U.S. markets when local market power is demonstrated to be present. Regulators that favor a cost-based design argue that this is more appropriate for systems with a small number of generation firms because it eliminates the possibilities for generators to behave strategically in the spot market, which is a main concern in bid-based markets. We discuss existing results on market power issues in cost- and bid-based designs and present a counterintuitive example, in which forcing spot prices to be equal to marginal costs in a concentrated market can actually yield lower social welfare than under a bid-based market design due to perverse investment incentives. Additionally, we discuss the difficulty of auditing the true opportunity costs of generators in cost-based markets and how this can lead to distorted dispatch schedules and prices, ultimately affecting the long-term economic efficiency of a system. An important example is opportunity costs that diverge from direct fuel costs due to energy or start limits, or other generator constraints. Most of these arise because of physical and financial inflexibilities that become more relevant with increasing shares of variable and unpredictable generation from renewables.



UK Electricity Market Reform and the Energy Transition: Emerging Lessons

Michael Grubb and David Newbery

Year: 2018
Volume: Volume 39
Number: Number 6
DOI: 10.5547/01956574.39.6.mgru
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Abstract:
The 2013 Electricity Market Reform (EMR) was a response to the twin problems of securing efficient finance for a new generation of low carbon investments, and delivering reliability along with a growing share of renewables in its energy-only market. Four EMR instruments combined to revolutionize the sector; stimulating unprecedented technological and structural change. Competitive auctions for both firm capacity and renewable energy have seen prices far lower than predicted and the entry of unexpected new technologies. A carbon price floor displaced coal, whose share fell from 46% in 1995 to 7% in 2017, halving CO2. Renewables grew from under 4% in 2008 to 22% by 2017, projected at 30+% by 2020 despite a political ban on onshore wind. Neither the technological nor regulatory transitions are complete, and the results to date highlight other challenges, notably to transmission pricing and locational signals. EMR is a step forwards, not backwards; but it is not the end of the story.



Ensuring Capacity Adequacy in Liberalised Electricity Markets

Nicolas Astier and Xavier Lambin

Year: 2019
Volume: Volume 40
Number: Number 3
DOI: 10.5547/01956574.40.3.nast
View Abstract

Abstract:
This paper studies wholesale electricity markets where an exogenous price cap is enforced, compromising both short- and long-term incentives. To guarantee capacity adequacy, policy-makers may provide support for generation through a capacity remuneration mechanism (CRM) and/or encourage demand response (DR). Such mechanisms are formalised within a common simple analytical framework, clarifying how these mechanisms relate to each other. We then divide them into two categories, depending on whether their implementation requires transactions to be made based explicitly on spot prices higher than the price cap. While mechanisms that keep implicit these high marginal costs are likely to be preferred from a political perspective, they also appear to be less efficient. If they are to be implemented nonetheless, we suggest that the price cap should be set higher than the marginal cost of the most expensive plant, and highlight that challenges for demand-response integration in CRMs remain.



Evaluation of Risks for Electricity Generation Companies through Reconfiguration of Bidding Zones in Extended Central Western Europe

Caroline Deilen, Tim Felling, Robin Leisen, and Christoph Weber

Year: 2019
Volume: Volume 40
Number: The New Era of Energy Transition
DOI: 10.5547/01956574.40.SI1.cdei
View Abstract

Abstract:
In Central Western Europe, a reconfiguration of bidding zones for electricity is frequently discussed as a way to improve congestion management. The current EU guideline on Capacity Allocation and Congestion Management even envisages reviews of the bidding zone configuration (BZC) in regular intervals of three years. Such a change of BZCs gives rise to additional regulatory risk for generation companies. Their expected net present value depends on local prices, which are directly influenced by the BZC. The paper at hand develops a methodology to investigate the impact of this regulatory risk. Therefore the risk of bidding zone changes is modeled using a partly-meshed scenario tree. The risk factors reflected therein are uncertainties in grid developments, in combination with other risks such as changing coal and gas spreads, demand, or renewable infeed variations. Results are compared to the current BZC in Europe and to a nodal setup.





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