Generators supplying electricity markets are subject to volatile input and output prices and uncertain fuel availability. Price-risk may be hedged to a considerable extent but fuel-risk — water flows in the case of hydro and gas availability in the case of thermal plants — may not be. We show that a price-taking generator will only generate when the output price exceeds its marginal cost by an amount that reflects the value of the option to delay the use of stored fuel. The corresponding offer price is different from the theorized offer prices of static uniform auctions and more akin to pay-as-bid auction prices. We argue that the option value of delaying fuel use, which is an increasing function of spot price volatility and the uncertainty about fuel availability, must be considered when evaluating whether market power is present in electricity markets. The engineering approach to simulating an electricity supply curve, which has been used in market power evaluations to date, may lead to supply curves that are quite different from those that recognize possible fuel availability limitations, even in the complete absence of market power.
The restructuring of the energy industry from regulated vertically-integrated monopolies to competitive markets has been described as "one of the largest single industrial reorganizations in the history of the world." With 9.4 million residential and 1.2 million business electric and natural gas accounts able to choose among a number of energy providers, New York State is recognized as a leader in this area. New York has adopted a flexible approach which has allowed policies to be guided and shaped by the successes and challenges experienced in this and other states, and by continuously evolving market conditions.
This approach has required an ongoing appraisal of the status of New York's markets and the identification of further steps to be taken to promote the long-range vision adopted by the New York State Public Service Commission (NYPSC or the Commission). As a part of that ongoing effort, this report assesses the current state of New York's wholesale electric markets and retail electric and gas markets, describes progress that has been made over the past several years in creating such markets, and identifies opportunities for continued progress toward robust competition in New York State's energy industry.
Excerpt from the Executive Summary:
Over the past several years, a number of groups have questioned whether implementation of coordinated wholesale electricity markets in several regions of the United States has benefited retail electricity customers. The development of these markets was motivated in large part by a desire to achieve increased short-term and long-term efficiency in the generation and delivery of electricity through increased reliance on market mechanisms. Along with this came the expectation of lower retail electricity prices, similar to what occurred in other industries that have undergone a deregulation, such as long-distance telephone service, passenger airlines, and interstate trucking. Spurred by recent increases in electricity prices, some groups have called for a re-examination of the deregulated market structure adopted in coordinated markets in the Midwest, Mid-Atlantic and Northeast (i.e., LMP pricing, day-ahead markets based on security- constrained unit commitment, and financial transmission rights). Some critics have even called for a return to the previous system of rate of return regulation and control area operation by vertically integrated utilities.
This paper provides an empirical analysis demonstrating that the implementation of coordinated markets has served to reduce the increase in average consumer rates that has resulted from increases in input costs for electricity generation. In addressing this policy question the issue is not whether average consumer rates have risen or declined in recent years, but whether they are lower than they would have been absent implementation of coordinated markets. In fact, average electricity rates have risen over the period since the implementation of coordinated markets, but this increase has occurred in all regions of the country as a result of increasing fuel prices, regardless of market structure.
As distributed generation (DG) becomes more widely deployed distribution networks become more active and take on many of the same characteristics as transmission. We propose the use of nodal pricing that is often used in the pricing of short-term operations in transmission. As an economically efficient mechanism, nodal pricing would properly reward DG for reducing line losses through increased revenues at nodal prices, and signal prospective DG where it ought to connect with the distribution network. Applying nodal pricing to a model distribution network we show significant price differences between busses reflecting high marginal losses. Moreover, we show the contribution of a DG resource located at the end of the network to significant reductions in losses and line loading. We also show the DG resource has significantly greater revenue under nodal pricing reflecting its contribution to reduced line losses and loading.
In this paper we propose a method for the allocation of fixed (capital and non-variable operation and maintenance) costs at the medium voltage (MV) distribution level. The method is derived from the philosophy behind the widely used MW- mile methodology for transmission networks that bases fixed cost allocations on the “extent of use” that is derived from load flows. We calculate the “extent of use” by multiplying the total consumption or generation at a busbar by the marginal current variations, or power to current distribution factors (PIDFs) that an increment of active and reactive power consumed, or generated in the case of distributed generation, at each busbar, produces in each circuit. These PIDFs are analogous to power transfer distribution factors (PTDFs).
Unlike traditional tariff designs that average fixed costs on a per kWh basis across all customers, the proposed method provides more cost reflective price signals and helps eliminate possible cross-subsidies that deter profitable (in the case of competition) or cost-effective (in the case of a fully regulated industry) deployment of DG by directly accounting for use and location in the allocation of fixed costs. An application of this method for a rural radial distribution network is presented.
There is growing evidence that the cost savings potential of the Title IV SO2 cap-and-trade program is not being reached. PUC regulatory treatment of compliance options appears to provide one explanation for this finding. That suggests that PUCs and utility companies should work together to develop incentive plans that will encourage cost-minimizing behavior for compliance with the EPA’s recently issued Clean Air Interstate Rule.