Do topological models provide good information about vulnerability in electric power networks?

In order to identify the extent to which results from topological graph models are useful for modeling vulnerability in electricity infrastructure, we measure the susceptibility of power networks to random failures and directed attacks using three measures of vulnerability: characteristic path lengths, connectivity loss and blackout sizes. The first two are purely topological metrics. The blackout size calculation results from a model of cascading failure in power networks. Testing the response of 40 areas within the Eastern US power grid and a standard IEEE test case to a variety of attack/failure vectors indicates that directed attacks result in larger failures using all three vulnerability measures, but the attack vectors that appear to cause the most damage depend on the measure chosen. While our topological and power grid model results show some trends that are similar, there is only a mild correlation between the vulnerability measures for individual simulations. We conclude that evaluating vulnerability in power networks using purely topological metrics can be misleading

Operational constraints and hydrologic variability limit hydropower in supporting wind integration

Climate change mitigation will require rapid adoption of low-carbon energy resources. The integration of large-scale wind energy in the United States (US) will require controllable assets to balance the variability of wind energy production. Previous work has identified hydropower as an advantageous asset, due to its flexibility and low-carbon emissions production. While many dams currently provide energy and environmental services in the US and globally, we find that multi-use hydropower facilities would face significant policy conflicts if asked to store and release water to accommodate wind integration. Specifically, we develop a model simulating hydroelectric operational decisions when the electric facility is able to provide wind integration services through a mechanism that we term ‘flex reserves’. We use Kerr Dam in North Carolina as a case study, simulating operations under two alternative reservoir policies, one reflecting current policies and the other regulating flow levels to promote downstream ecosystem conservation. Even under perfect information and significant pricing incentives, Kerr Dam faces operational conflicts when providing any substantial levels of flex reserves while also maintaining releases consistent with other river management requirements. These operational conflicts are severely exacerbated during periods of drought. Increase of payments for flex reserves does not resolve these operational and policy conflicts

Competitive Energy Options for Pennsylvania

Pennsylvania’s commercial and industrial customers are concerned that electricity prices in the Commonwealth put them at a disadvantage with respect to competitors in nearby states. Retail rates (averaged over all rate classes) in three neighboring states increased by 13 to 118% when rate caps expired in those states. At the end of 2010, rate caps will have expired throughout Pennsylvania. Data compiled by the Industrial Energy Consumers of Pennsylvania indicate that load serving entities in the Commonwealth expect rate increases from 30 to 75 percent when the caps are lifted. The Pennsylvania Office of the Small Business Advocate reports that commercial customers have similar expectations. This study examines the electricity prices offered to commercial and industrial customers and evaluates options for competitive electricity prices for commercial and industrial customers.</p

Deregulation/Restructuring Part II: Where Do We Go From Here?

The authors reject calls for reregulation. An alternative is to solicit offers for long-term contracts that specify fixed and generating prices for each plant. The contracts would specify the number of times a generator could be asked to shut down, as well as the availability and reliability of the unit. Units whose offers are accepted would be paid their fixed offer if they complied with the terms of the contract and their generation offer for each MWh they were asked to supply.</p

Market Power in Deregulated Wholesale Electricity Markets: Issues in Measurement and the Cost of Mitigation

An analysis of three recently deregulated markets—California, PJM, and New York—finds that none of them can be regarded as highly competitive, contrary to what conventional measures of market power indicate. Auctions for generation are unlikely to be competitive and costly steps will be needed to mitigate market power, likely eroding any benefits from increased operating efficiency in deregulated markets. Thus, FERC and state legislators need to reexamine the desirability of deregulating the generation portion of the industry.</p

Lessons from the Failure of U.S. Electricity Restructuring

Blind faith is unlikely to produce a free market that is competitive. Substituting markets for traditional regulation is only one choice among many policy instruments to achieve a goal of lower prices; such substitution should not be in itself a goal.</p

A Cautionary Tale: US Electricity Sector Reform

<p>In the 1970s, the US electric utility industry was faced with rising costs and sluggish demand. Efforts at lowering costs and revitalising the industry through competition have largely been disappointing. Consumers have not seen prices fall, except where regulators have intervened. The merchant sector has suffered a financial crisis, hurting competition in both wholesale and retail markets. Advocates for deregulation assert that minor changes to market rules and regulations will yield the benefits promised. We argue that things are not so simple. Successful deregulation requires markets to be competitive and complete, neither of which is true in the US. Creating competitive markets is not impossible, but doing so imposes costs on the system which may outweigh the benefits of deregulation.</p

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

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.</p