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Impacts of Responsive Load in PJM: Load Shifting and Real Time Pricing

Kathleen Spees and Lester Lave

Year: 2008
Volume: Volume 29
Number: Number 2
DOI: 10.5547/ISSN0195-6574-EJ-Vol29-No2-6
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Abstract:
Load Shifting and Real Time Pricing Kathleen Spees* and Lester Lave** In PJM, 15% of electric generation capacity ran less than 96 hours, 1.1% of the time, over 2006. If retail prices reflected hourly wholesale market prices, customers would shift consumption away from peak hours and installed capacity could drop. We use PJM data to estimate consumer and producer savings from a change toward real-time pricing (RTP) or time-of-use (TOU) pricing. Surprisingly, neither RTP nor TOU has much effect on average price under plausible short-term consumer responses. Consumer plus producer surplus rises 2.8%-4.4% with RTP and 0.6%-1.0% with TOU. Peak capacity savings are seven times larger with RTP. Peak load drops by 10.4%-17.7% with RTP and only 1.1%-2.4% with TOU. Half of all possible customer savings from load shifting are obtained by shifting only 1.7% of all MWh to another time of day, indicating that only the largest customers need be responsive to get the majority of the short-run savings.



Econometric Estimation of Spatial Patterns in Electricity Prices

Stratford M. Douglas and Julia N. Popova

Year: 2011
Volume: Volume 32
Number: Number 2
DOI: 10.5547/ISSN0195-6574-EJ-Vol32-No2-4
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Abstract:
Information about the spatial structure of the transmission grid is relevant to understanding and predicting electricity prices, but this information has not been incorporated into empirical models of electricity prices in the literature. We propose the use of spatial econometric panel methods, discuss their formal characteristics in the context of electricity price data, and provide an application to a panel of PJM price data. Our econometric model includes a simple representation of the transmission system, and provides information about the effect of system constraints on the extent of electricity market integration. Empirical results confirm the existence of spatial patterns in electricity prices and illustrate their impact on estimation, forecasting, and interpolation.



Common Unobserved Determinants of Intraday Electricity Prices

Nikolaos S. Thomaidis, Gordon H. Dash, and Nina Kajiji

Year: 2019
Volume: Volume 40
Number: The New Era of Energy Transition
DOI: 10.5547/01956574.40.SI1.ntho
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Abstract:
This paper employs multilevel factor modelling techniques to unravel systematicunobserved determinants of the intraday and interzonal price curve dynamics forthe Pennsylvania-New Jersey-Maryland (PJM) interconnection. These techniquesmake an explicit separation of global drivers from region-specific common factors, thereby facilitating the identification of the actual sources of co-variability.Our empirical findings confirm the hypothesis that the common unobserved determinants of power prices in the PJM interconnection obey a block structure, someof which affect different segments of our panel. We argue that a multilevel factorapproach offers a more systematic and transparent representation of intertemporal and cross-sectional patterns in PJM electricity prices compared to alternativebrute-force VARMAX parametrizations and the single-level factor models, whichare often put forward in the literature as viable modelling alternatives.





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