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This paper examines the effects of market restructuring initiatives that introduced competition into the United States electricity industry on the thermal efficiency of electricity generation. An empirical model is estimated on annual data for over 950 plants from 1996 to 2006. Model estimates show that access to wholesale electricity markets and retail choice together increased the efficiency of investor-owned plants by about nine percent and that these gains stem from organizational and technological changes within the plant. Although not directly targeted by restructuring initiatives, similar efficiency gains are also found for municipality-owned plants. This result suggests that the potential benefits from competition have spilled over to public electricity generation. [ABSTRACT FROM AUTHOR]

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 118- bus test network. The true relationship between congestion and reliability depends critically on identifying the relevant range of demand for evaluating any network externalities. [ABSTRACT FROM AUTHOR]

This paper examines changes in the utilization rates (annual capacity factors) of coal-burning power plants in the eastern United States after 1996, when federal regulators opened the transmission system to wholesale power markets. This and other accompanying market-oriented reforms were intended to improve efficiency by encouraging regional dispatch by independent system operators. If the reforms made dispatch more efficient, then utilization rates of high-cost plants should have fallen relative to those of low-cost plants since 1996. A difference-in-difference model using plant-level panel data indicates that relative utilization rates of high-cost plants did indeed fall after 1996, but only in regions with independent system operators. Simulations indicate cost savings on the order of two to three percent. [ABSTRACT FROM AUTHOR]

The Energy Modeling Forum 24 study included a set of policy scenarios designed to compare economy wide market-based and sectoral regulatory approaches of potential U.S. climate policy. Models from seven teams participated in this part of the study assessing economy-wide cap-and-trade climate policy and sectoral policies in the transportation and electric sector in terms of potential greenhouse gas emissions reductions, economic cost, and energy systems implications. This paper presents an overview of the results from the U.S. policy scenarios, and provides insights into the comparison of results from the participating models. In particular, various metrics were used to compare the model results including allowance price, the efficient frontier, consumption loss, GDP loss, and equivalent variation. We find that the choice of economic metric is an important factor in the comparison of model results. Among the insights, we note that the carbon price should cautiously be considered when other non-cap sectoral policies affecting emissions are assumed in tandem. We also find that a transportation sector policy is consistently shown to be inefficient compared to an economy-wide capand-trade policy with a comparable level of emissions reductions. [ABSTRACT FROM AUTHOR]

The transition to competitive wholesale and retail markets for electricity in the U. S. has been a difficult and contentious process. This paper examines the progress that has been made in the evolution of wholesale and retail electricity market institutions. Various indicia of the performance of these market institutions are presented and discussed. Significant progress has been made on the wholesale competition front but major challenges must still be confronted. The framework for supporting retail competition has been less successful, especially for small customers. Empirical evidence suggests that well-designed competitive market reforms have led to performance improvements in a number of dimensions and benefited customers through lower retail prices. [ABSTRACT FROM AUTHOR]

This paper estimates short- and long-run marginal production costs and returns to scale in electric power generation in the United States. We find substantial short-run diseconomies of scale at high output levels. A relatively large number of small and mid-sized firms have optimal capital stocks below actual levels. In contrast, several large firms have optimal capital stock targets substantially above current levels. These disparities in actual and optimal capital suggest a possible consolidation in the industry. [ABSTRACT FROM AUTHOR]

We apply an algorithm that optimizes the generation dispatch for a dominant firm to Colorado's electricity market and show that the dominant electricity generation firm can strategically congest transmission into the region to receive a maximum price over 50% of the time. When it does not get the maximum price, the dominant firm still receives an average markup more than 10% over the competitive price. We use this model to show how mitigation strategies such as enhancing the transmission grid, divesting the dominant firm 's generation assets, and promoting entry into the generation market can lower prices in a wholesale electricity generation industry by limiting a dominant firm 's market power. [ABSTRACT FROM AUTHOR]

A clean energy standard (CES) is a potential policy alternative to reduce carbon emissions in the electric sector. We analyze this policy under a range of technological assumptions, expanding on the Energy Modeling Forum (EMF) 24 study scenarios, using a new modeling tool, US-REGEN. We describe three innovative features of the model: treatment of spatial and temporal variability of renewable resources, cost-of-service electric sector pricing, and explicit representation of energy end-use specific capital. We find that varying technology assumptions results in vastly different futures, with large contrasts in the distribution and scale of inter-regional financial flows, and in the generation mix. We explore regional differences in how the costs of CES credits are passed through with cost-of-service vs. competitive pricing. Finally, we compare the CES to an economy-wide emissions cap. We find that although the two policies result in a similar generation mix, price and electricity end-use results differ. [ABSTRACT FROM AUTHOR]

We apply a U.S. electric-sector capacity-expansion and dispatch model to assess possible implications--changes in generation mix, system cost, CO2 emissions, distribution of renewable energy deployment--of a set of potential greenhouse gas mitigation policy options over a range of technology projections. The model used, ReEDS, provides unique spatial and temporal detail to ensure electric-system constraints of reliable load provision are maintained throughout the system's transformation. [ABSTRACT FROM AUTHOR]