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Markets in Real Electric Networks Require Reactive Prices

William W. Hogan

Year: 1993
Volume: Volume14
Number: Number 3
DOI: 10.5547/ISSN0195-6574-EJ-Vol14-No3-8
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Abstract:
Differences in locational spot prices in an electric network provide the natural measure of the price for transmission. The ubiquitous problem of loop flow requires different economic intuition for interpreting the implications of spot pricing. The DC-Load model is the usual approximation for estimating spot prices, although it ignores reactive power effects. This approximation is best when thermal constraints create congestion in the network. In the presence of voltage constraints, the DC-Load model is insufficient, and the full AC-Model is required to determine both real and reactive power spot prices.



Regulatory Policy Regarding Distributed Generation by Utilities: The Impact of Restructuring

Jay Morse

Year: 1997
Volume: Volume 18
Number: Special Issue
DOI: 10.5547/ISSN0195-6574-EJ-Vol18-NoSI-9
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Abstract:
Electricity industry restructuring is only now beginning to focus on the role of utilities in distributed generation (DG). This paper examines whether, as restructuring unfolds, regulators may permit investor-owned distribution companies to own DG, and if so, under what terms. Concomitantly, the paper explores how ownership of DG by distribution companies impacts electricity restructuring. The paper concludes that regulated utilities should readily obtain approval to install DG on utility sites as long as the utility remains vertically integrated. Approval is also possible for vertically integrated or restructured utilities to provide DG at customer sites if it is shareholder-funded and connected on the customer's side of the meter. However, distribution company ownership of DG at utility sites or on the utility's side of the meter conflicts with electricity industry restructuring. Regulatory approval under restructuring is therefore highly problematical. Should regulatory approval be granted, the need to mitigate vertical market power is likely to precipitate the disaggregation of the distribution company.



Economic Inefficiency of Passive Transmission Rights in Congested Electricity Systems with Competitive Generation

Shmuel S. Oren

Year: 1997
Volume: Volume18
Number: Number 1
DOI: 10.5547/ISSN0195-6574-EJ-Vol18-No1-3
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Abstract:
The main thesis of this paper is that passive transmission rights such as Transmission Congestion Contracts (TCCs) that are compensated ex-post based on nodal prices resulting from optimal dispatch by an Independent System Operator (ISO) will be preempted by the strategic bidding of the generators. Thus, even when generation is competitive, rational expectations of congestion will induce implicit collusion enabling generators to raise their bids above marginal costs and capture the congestion rents, leaving the TCCs uncompensated. These conclusions are based on a Cournot model of competition across congested transmission links where an ISO dispatches generators optimally based on bid prices. We characterize the Cournot equilibrium in congested electricity networks with two and three nodes. We show that absent active transmission rights trading, the resulting equilibrium may be at an inefficient dispatch and congestion rents will be captured by the generators. We also demonstrate how active trading of transmission rights in parallel with 42 competitive energy market can prevent the price distortion and inefficient dispatch associated with passive transmission rights.



Implementation of Priority Insurance in Power Exchange Markets

Robert Wilson

Year: 1997
Volume: Volume18
Number: Number 1
DOI: 10.5547/ISSN0195-6574-EJ-Vol18-No1-5
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Abstract:
Traders in a power exchange can use insurance to hedge against losses from curtailment by the system operator. If the system operator is liable for these reimbursements then its incentives encourage efficient real-time dispatch. This paper reviews the details of implementing such a scheme when third-party insurers offer insurance in an auxiliary competitive market, or the power exchange operates as a mutual insurance association of the traders. Because higher reimbursements entail higher service priorities, the actuarial premium for pure insurance must be accompanied by a surcharge for service priority. The amount of this surcharge can be inferred from the price of pure insurance. The Appendix shows that omission of this surcharge distorts traders' incentives in the power exchange.



Modeling Cournot Competition in an Electricity Market with Transmission Constraints

Bert Willems

Year: 2002
Volume: Volume23
Number: Number 3
DOI: 10.5547/ISSN0195-6574-EJ-Vol23-No3-5
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Abstract:
This paper studies Cournot competition with two generators who share one transmission line with a limited capacityto supply price-taking consumers. In such a game the network operator needs a rule to allocate transmission capacity. Three rules are studied: all-or-nothing, proportional, and efficient rationing. The first result is that if the network operator taxes the whole congestion rent, the generators strategically change their production quantities, such that the network operator obtains no congestion rent. This gives poor incentives for investment in transmission capacity. The second result is that the network operator can create competition among the generators, which can increase welfare. Marginal nodal congestion pricing, which is optimal under perfect competition, is sub-optimal when generators can set their production quantities freely. It does not generate revenue for the network operator, nor does it increase competition among the generators.



Electricity Price Volatility and the Marginal Cost of Congestion: An Empirical Study of Peak Hours on the NYISO Market, 2001-2004

Lester Hadsell and Hany A. Shawky

Year: 2006
Volume: Volume 27
Number: Number 2
DOI: 10.5547/ISSN0195-6574-EJ-Vol27-No2-9
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Abstract:
We examine the volatility characteristics of the NYISO Day Ahead and Real Time electricity markets for peak hours from January 2001 to June 2004. GARCH models are used to study the differences in volatility across zones. We find that price volatility is higher but less persistent in the Real Time market than in the Day Ahead market. Furthermore, we document the importance of transmission congestion and empirically estimate its impact on volatility in electricity prices. We also examine the Day Ahead premium and show how it is related to volatility in Real Time prices. The implications for participants in these markets are discussed.



A Quantitative Analysis of the Relationship Between Congestion and Reliability in Electric Power Networks

Seth Blumsack, Lester B. Lave and Marija Ilic

Year: 2007
Volume: Volume 28
Number: Number 4
DOI: 10.5547/ISSN0195-6574-EJ-Vol28-No4-4
View Abstract

Abstract:
Restructuring efforts in the U.S. electric power sector have tried to encourage transmission investment by independent (non-utility) transmission companies, and have promoted various levels of market-based transmission investment. Underlying this shift to �merchant� transmission investment is an assumption that new transmission infrastructure can be classified as providing a congestion-relief benefit or a reliability benefit. In this paper, we demonstrate that this assumption is largely incorrect for meshed interconnections such as electric power networks. We focus on a particular network topology known as the Wheatstone network to show how congestion and reliability can represent tradeoffs. Lines that cause congestion may be justified on reliability grounds. We decompose the congestion and reliability effects of a given network alteration, and demonstrate their dependence through simulations on a 118bus test network. The true relationship between congestion and reliability depends critically on identifying the relevant range of demand for evaluating any network externalities.



Long-run Cost Functions for Electricity Transmission

Juan Rosellón, Ingo Vogelsang, and Hannes Weigt

Year: 2012
Volume: Volume 33
Number: Number 1
DOI: 10.5547/ISSN0195-6574-EJ-Vol33-No1-5
View Abstract

Abstract:
Electricity transmission has become the pivotal industry segment for electricity restructuring. Yet, little is known about the shape of transmission cost functions. Reasons for this can be a lack of consensus about the definition of transmission output and the complexitity of the relationship between optimal grid expansion and output expansion. Knowledge of transmission cost functions could help firms (Transcos) and regulators plan transmission expansion and could help design regulatory incentive mechanisms. We explore transmission cost functions when the transmission output is defined as point-to-point transactions or financial transmission right (FTR) obligations and particularly explore expansion under loop-flows. We test the behavior of FTR-based cost functions for distinct network topologies and find evidence that cost functions defined as FTR outputs are piece-wise differentiable and that they contain sections with negative marginal costs. Simulations, however, illustrate that such unusual properties do not stand in the way of applying price-cap incentive mechanisms to real-world transmission expansion. Key words: Electricity transmission, Cost function, Incentive regulation, Merchant investment, Congestion management



Improving Congestion Management: How to Facilitate the Integration of Renewable Generation in Germany

Friedrich Kunz

Year: 2013
Volume: Volume 34
Number: Number 4
DOI: 10.5547/01956574.34.4.4
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Abstract:
In this paper the German congestion management regime is analyzed and future congestion management costs are assessed given a higher share of intermittent renewable generation. In this context, cost-based re-dispatching of power plants and technical flexibility through topology optimization are considered as market-based and technical congestion management methods. To replicate the current market regime in Germany a two-step procedure is chosen consisting of a transactional spot market model and a congestion management model. This uniform pricing model is compared to a nodal pricing regime. The results show that currently congestion can mainly be managed by re-dispatching power plants and optimizing the network topology. However, congestion management costs tend to increase significantly in future years if the developments of transmission as well as generation infrastructure diverge. It is concluded that there is a need for improving the current congestion management regime to achieve an efficient long-term development of the German electricity system.



Comparison of congestion management techniques: Nodal, zonal and discriminatory pricing

Pär Holmberg and Ewa Lazarczyk

Year: 2015
Volume: Volume 36
Number: Number 2
DOI: 10.5547/01956574.36.2.7
View Abstract

Abstract:
Wholesale electricity markets use different market designs to handle congestion in the transmission network. We compare nodal, zonal and discriminatory pricing in general networks with transmission constraints and loop flows. We conclude that in large games with many producers and certain information, the three market designs result in the same efficient dispatch. However, zonal pricing with counter-trading results in additional payments to producers in export-constrained nodes, which leads to inefficient investments in the long-run.




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