Weiss, Jurgen, and Hoff Stauffer. “A Simple Solution to a Very Old Problem.” The Electricity Journal 19, no. 4 (2006): 56-59. Publisher's VersionAbstract

    The authors propose to eliminate the perverse incentives utilities have to resist energy-reduction options by guaranteeing approved fixed-cost recovery, while offering positive incentives, as well.

      Sotkiewicz, Paul, and Mario Vignolo. “Towards a Cost Causation Based Tariff for Distribution Networks with DG.” In, 2006.Abstract
      This paper decomposes the effects of the transition from an average cost distribution tariff to a cost causation based distribution tariff, in terms of time and location, that uses nodal prices to recover losses and an “extent-of-use” method to recover fixed network costs based on use at coincident peak. Our decomposition is designed so that the effects of using coincident peak and location for fixed network charges, as well as using marginal losses under constraints recovering the exact amount of losses, and recovering exactly the cost of network service in total can be isolated and analyzed separately. We apply our tariff transition and decomposition method to an example network with data from Uruguay to isolate the various effects with and without a distributed generation (DG) resource. We show moving to coincident peak charges and to fully charging for marginal losses while rebating the merchandising surplus through the fixed charges have the greatest effects on changes in distribution tariff charges. DG provides countervailing cost changes to distribution tariffs for loads through loss reductions and the implicit “creation” of new network capacity for which it is paid. The interaction of all these effects may lead to outcomes that are counter-intuitive, which further supports the need to decompose the tariff changes to fully understand the reasons for the direction and magnitude of changes in tariff charges in the transition to tariffs based more on cost causation.
      Transmission Risk Hedging Products: Solutions for the Market and Consequences for the TSOs.” In, 2006.Abstract

      Executive Summary

      In the framework of the EC Regulation 1228/2003, the goal of this background paper is to provide a description of the different market based solutions available for transmission risk hedging in congestion management. This paper presents three different transmission risk hedging products that can be offered to the market in the field of cross-border trade and congestion management. Due to various facts several price zones exist within the overall European electricity market where the demand of each zone is met in real time by the production of the respective zone and a zone specific market price is found (e.g. on the respective Power Exchange). This raises the question of how a market player wishing to buy electricity in a certain price zone and to sell it in another one can hedge the risk of a price difference emerging between those zones. This paper describes the three main kinds of transmission risk hedging products identified by ETSO: • Physical Transmission Rights (PTRs); • Financial Transmission Rights (FTRs); • Financial Contracts for Differences (CfDs); The paper also provides a first evaluation of the different solutions adopting a markets’ perspective. From a practical perspective, the implementation of forward PTRs only requires a minimum of market infrastructure and contractual arrangements. This is probably the reason for this product to be widely and successfully implemented on most European interconnections. However, Market Splitting or Coupling or co-ordinated implicit auctions would be the main prerequisite towards the implementation of marketbased FTRs and CfDs in Europe. Vice versa, in case Implicit Auctions (Market Splitting or Coupling) are introduced FTRs form a reasonable complement to those schemes for transmission hedging.

      Alliance, The New England Energy. “A Review of Electricity Industry Restructuring in New England.” In, 2006.Abstract

      Excerpt from the Introduction:


      The New England states were among the first in the nation to restructure wholesale and retail electricity markets beginning in the late 1990s. In large part, the action was prompted by the burden of having the highest electricity costs in the country, which created hardships for residential consumers and handicapped many businesses from competing on a “level playing field” with companies located outside the region.2 Restructuring required most electric utilities to: sell their generating plants, allow consumers to choose among electricity suppliers and procure electricity for those consumers not choosing an electricity supplier – while remaining regulated and responsible for local distribution service. Wholesale restructuring involved creating a fair and reliable market for competition in generating electricity while ensuring equal access to transmission grids. Once established, the wholesale market caused electricity to become a commodity with prices set not by regulators, but by market rules and the balance between supply and demand.

      Chandley, John, and William W. Hogan. “A Path To Preventing Undue Discrimination and Preference In Transmission Services.” In, 2006.Abstract

      Excerpt from the Introduction:


      The Federal Energy Regulatory Commission proposals for Order 888 Open Access Transmission Tariff (OATT) reform arise from a continuing frustration with the Commission’s efforts to provide open access to transmission both for its own sake and to support competitive markets. The Commission has found it difficult to meet the basic requirement to avoid undue discrimination and preference in transmission services. This difficulty follows in part from the nature of the electricity grid. But more important, the transmission access procedures promulgated in Order 888 are not consistent with the requirements of reliable and efficient operation of the grid, nor do they support workable competitive markets. A better approach, more closely aligned with actual grid operations and compatible with competitive principles, is obviously needed. Unfortunately, the narrow focus in the Commission’s Notice of Proposed Rulemaking (NOPR) does not allow it to see the problems inherent in the current Order 888 framework that must be addressed to achieve the Commission’s goals.

      After many prior attempts at broader reforms to meet its expansive goals for industry reforms, the Commission seeks now to narrow its scope to advancing limited changes to the OATT. The focus is on improving the consistency and transparency of the determination of available transfer capability (ATC) as the primary means to address undue discrimination. But if inconsistent ATC calculations and methods are not the underlying problem, then the proposed “solutions” will fail.

      The emphasis of the past analyses has been on the defects of the OATT contract path and ATC framework. Although the Commission’s own analyses have recognized these defects, the Commission has not been able to address these matters without entangling itself in a larger debate about electricity market design and electricity restructuring. Given the impasse, it may be that the emphasis on ATC imposes too much on the Commission if it is to find a path to preventing undue discrimination and preference in transmission services. A different approach is needed.

      Michaels, Robert. “Vertical Integration and the Restructuring of the U.S. Electricity Industry.” In, 2006.Abstract

      Excerpt from the Executive Summary:

      Debates on restructuring the U.S. electricity industry are often about the degree to which market relationships should replace transactions that formerly took place within regulated, vertically integrated utilities. Markets for the purchase of energy by vertically unintegrated distribution utilities are clearly feasible, but vertical deintegration of existing systems may eliminate some operational and reliability benefits that are important in light of the unique characteristics of electricity. Politicians and policy analysts have almost totally disregarded a large body of academic literature regarding the efficiencies that are gained through vertical integration in the electricity sector. At the same time, those parties have enthusiastically embraced other studies that purport to estimate the benefits of switching to a so-called restructured regime consisting of independent generation and integrated transmission and distribution. The result has been the passage of electricity utility restructuring laws that may create production inefficiencies that shrink the net benefits of any move toward market provision of power supplies.

      Sotkiewicz, Paul, and Mario Vignolo. “The Value of Intermittent Wind DG under Nodal Prices and Amp-mile Tariffs.” In, 2006.Abstract
      Abstract — In this paper we apply the recently proposed Nodal Pricing and Amp-Mile tariffs for distribution networks to the case where a wind distributed generator is located in the network. The ability of this tariff structure to capture the real cost and benefits of DG is analyzed for this case of intermittent generation using real wind and network data from Uruguay and a standard wind turbine. A comparison is made in relation to the case with no DG placed in the network, to the case with controllable DG and to the case of intermittent DG of different capacity factors. We find that in expectation intermittent wind DG does little to reduce overall line losses or reduce peak line utilization. Consequently, under nodal pricing and amp-mile tariffs the intermittent wind resource collects very little additional revenue over the case where the intermittent wind DG source is simply paid the price of power exclusive of losses and is not compensated for freeing up network capacity