Cicala, Steve. “Imperfect Markets versus Imperfect Regulation in U.S. Electricity.” In, 2016.Abstract

    This paper estimates changes in electricity generation costs caused by the introduction of market mechanisms to determine output decisions in service areas that were previously using command-and-control-type operations. I use the staggered transition to markets from 1999- 2012 to evaluate the causal impact of liberalization using a nationwide panel of hourly data on electricity demand and unit-level costs, capacities, and output. To address the potentially confounding effects of unrelated fuel price changes, I use machine learning methods to predict the allocation of output to generating units in the absence of markets for counterfactual pro- duction patterns. I find that markets reduce production costs by $3B per year by reallocating output among existing power plants: Gains from trade across service areas increase by 20% based on a 10% increase in traded electricity, and costs from using uneconomical units fall 20% from a 10% reduction in their operation.

    Agency, Environmental Protection. “Environmental Protection Agency. Emission Guidelines for Existing Stationary Sources: Electric Utility Generating Units.” In, 2014.Abstract



    This Regulatory Impact Analysis (RIA) discusses potential benefits, costs, and economic impacts of the proposed Emission Guidelines for Greenhouse Gas Emissions from Existing Stationary Sources: Electric Utility Generating Units (herein referred to EGU GHG Existing Source Guidelines). This RIA also discusses the potential benefits, costs and economic impacts of the proposed Standards of Performance for Greenhouse Gas Emissions from Reconstructed and Modified Stationary Sources (EGU GHG Reconstructed and Modified Source Standards).


    ES.1 Background and Context of Proposed EGU GHG Existing Source Guidelines Greenhouse gas pollution threatens Americans' health and welfare by leading to longlasting changes in our climate that can have a range of severely negative effects on human health and the environment. Carbon Dioxide (CO2) is the primary greenhouse gas pollutant, accounting for nearly three-quarters of global greenhouse gas emissions and 84 percent of U.S. greenhouse gas emissions. Fossil fuel-fired electric generating units (EGUs) are, by far, the largest emitters of GHGs, primarily in the form of CO2, among stationary sources in the U.S. In this action, the EPA is proposing emission guidelines for states to use in developing plans to address greenhouse gas emissions from existing fossil fuel-fired EGUs. Specifically, the EPA is proposing state-specific rate-based goals for carbon dioxide emissions from the power sector, as well as emission guidelines for states to use in developing plans to attain the statespecific goals. This rule, as proposed, would set in motion actions to lower the carbon dioxide emissions associated with existing power generation sources in the United States.

    Linares, Pedro, Francisco Javier Santos, Mariano Ventosa, and Luis Lapiedra. “Incorporating oligopoly, CO2 emissions trading and green certificates into a power generation expansion model.” Automatica 44, no. 6 (2008): 1608-1620. Publisher's VersionAbstract
    This paper presents a generation expansion model for the power sector which incorporates several features that make it very interesting for application to current electricity markets: it considers the possible oligopolistic behavior of firms, and incorporates relevant policy instruments, carbon emissions trading and tradable green certificates. It combines powerful traditional tools related to the detailed system operation with techniques for modeling the economic market equilibrium and a formulation for the resolution of the emissions permit and tradable green certificates market equilibrium. The model is formulated as a Linear Complementarity Problem (LCP) which allows the optimization problem for each firm considering the power, carbon and green certificate markets to be solved simultaneously. The model has been implemented in GAMS. An application to the Spanish power system is also presented.
    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.
    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
    Shanefelter, Jennifer Kaiser. “Restructuring, Ownership and Efficiency: The Case of Labor in Electricity Generation.” In, 2006. Publisher's VersionAbstract
    This analysis considers improvements in productive efficiency that can result from a movement from a regulated framework to one that allows for market-based incentives for industry participants. Specifically, I look at the case of restructuring in the electricity generation industry. As numerous industries and economies have undergone this sort of transition to varying degrees, it is instructive to assess the performance of market-based incentives relative to what was observed under tighter regulation. Using data from the electricity industry, this analysis considers the total effect of restructuring on one input to the production process – labor – as reflected in employment levels, payroll per employee and aggregate establishment payroll. Using concurrent payroll and employment data from non-utility ("merchant") and utility generators in both restructured and nonrestructured states, I estimate the effect of market liberalization, comprising both new entry and state-level legislation, on employment and payroll in this industry. I find that merchant owners of divested generation assets employ significantly fewer people, but that the payroll per employee is not significantly different from what workers at utility-owned plants are paid. As a result, the new merchant owners of these plants have significantly lower aggregate payroll expenses. Decomposing the effect into a merchant effect and a divestiture effect, I find that merchant ownership is the primary driver of these results.
    Grid, National. “Transmission and Wind Energy: Capturing the Prevailing Winds for the Benefit of Customers.” In, 2006.Abstract

    Executive Summary

    The potential benefits of wind power as a clean, renewable, economic, domestically avail- able power source have captured the attention of energy policy leaders, consumers, and the electricity industry. The United States (US) has tremendous wind energy resources. California is viewed as one of the leaders in the modern US wind industry in terms of capacity installed; however, 16 other states have even greater wind potential. Only a small portion of that potential has been tapped. The US currently derives approximately 1% of its electricity from wind power, whereas parts of Europe use wind power to meet up to 25% or more of their electricity needs.

    In 2005, wind power in the US grew rapidly and became more competitive as volatile natu- ral gas prices increased and crude oil prices reached record highs. Improved technology, federal tax credits and public policies that encourage utilities to use clean energy sources helped fuel the growth from coast to coast. Projections are that US wind capacity could reach 100 gigawatts (GW) by 2020, meeting 6% or more of national electricity needs.1

    The objective of this paper is to examine the transmission policy issues around wind and renewable sources of generation. Reliability and commercial issues are reviewed, both in the US and abroad, and recommendations are provided for effective integration of wind sources into the US electric system. Key findings of this paper are:

    ■ Over-reliance in the US on any one fuel type results in reliability and economic consequences, highlighting the benefits of diversified energy resources.

    ■ Wind generation is becoming an economic power source, and has the further benefit of mitigating environmental climate change concerns.

    ■ In order to tap the vast potential of new generation sources such as wind power in the US, we must address the existing challenges in generator interconnection and trans- mission cost and planning policies.

    ■ The current US transmission system was not built to support competitive regional markets nor is it sufficient to integrate planned and potential new generation sources; additional transmission infrastructure will be required.

    ■ Operating techniques for intermittent generation resources, properly structured market rules, and effective transmission policies for regional planning, cost allocation, and cost recovery and incentives will help to facilitate wind power as well as other new sources of generation.

    ■ Transcos (for-profit independent transmission companies) focus on delivering low-cost reliable energy to consumers by facilitating robust electricity markets and providing transmission access to new generation sources including renewable energy. Because of their for-profit structure, a further advantage is that Transcos can be held firmly accountable by regulators for system performance and operating costs.

    ■ Robust transmission infrastructure policies in countries outside the US have helped them progress toward achieving their goals for renewable sources of energy while maintaining system reliability. The challenges to effective integration of wind power in the US are not insurmountable; they can be addressed with industry, public, and regulatory commitment.

    ■ Several countries, including Denmark, Germany, Spain and the UK have had coordinated government efforts and policies to facilitate wind power, and these are proving very effective. Some areas of North America, such as Alberta and Texas, are also employing planning and cost allocation policies that are helpful to new generation sources.

    Specific recommendations for changes needed to take advantage of US renewable resources to the benefit of electricity market users and customers are:

    ■ Employ greater use of available operational techniques, such as wind forecasting tools, for reliable operation of wind resources;

    ■ Properly structure market rules to address imbalance and capacity value in a manner that reliably and economically facilitates renewable generation sources;

    ■ Engage industry and stakeholders in long-term, robust, and comprehensive regional planning for transmission infrastructure, including infrastructure needed for new sources of generation;

    ■ Incorporate economic and customer cost metrics, in addition to reliability, into regional planning processes;

    ■ Implement workable cost-allocation and recovery mechanisms to recoup the costs of transmission infrastructure improvements;

    ■ Provide regulatory incentives for transmission infrastructure investment and independent ownership/operation of the nation’s transmission system.

    Sotkiewicz, Paul, and Jesus Vignolom. “Allocation of Fixed Costs in Distribution Networks with Distributed Generation.” In, 2005.Abstract

    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.

    Cavanagh, Ralph. “California Overcomes an Electricity Crisis.” The Electricity Journal (2001).Abstract
    Since an electricity crisis began in California in May of 2000, it has been widely misdiagnosed. The nation’s most energy efficient state has been accused of profligacy; its powerplant siting system has been characterized as obstructionist; and the failure of blackouts to materialize during the summer of 2001 has been credited to good weather, a sinking economy and punitive price increases. None of this is true.