A new planning tool for analyzing power systems in detail, including the long-run technical, economic and environmental consequences of policy or investment interventions, is now available for download by the public, without charge, at E4ST.com. The Engineering, Economic and Environmental Electricity Simulation Tool and its components are described here, and its accuracy is assessed through predictions of actual LMPs in the Eastern Interconnection. The usefulness of the tool is illustrated by an evaluation of the commercial feasibility of a proposed electric transmission line connecting Hydro Quebec to New York City, the Champlain-Hudson Power Express.

%B 2016 49th Hawaii International Conference on System Sciences (HICSS) %I IEEE %C Koloa, HI, USA %P 2317 - 2325 %8 01/2016 %R 10.1109/HICSS.2016.290 %0 Conference Paper %B 48th Hawaii International Conference on System Sciences (HICSS) %D 2015 %T A Detailed Power System Planning Model: Estimating the Long-Run Impact of Carbon-Reducing Policies %A Daniel L. Shawhan %A John T. Taber %A Ray D. Zimmerman %A J. Yan %A Charles M. Marquet %A William D. Schulze %A Richard E. Schuler %A Robert J. Thomas %A Daniel J. Tylavsky %A Di Shi %A Li, Nan %A W. Jewell %A T. Hardy %A Zhouxing Hu %K reliability and markets %K RM12-002 %K SuperOPF %X In this paper, a much more detailed representation of the nation's electricity system than has been traditionally used in policy models is employed. This detailed representation greatly increases the computational difficulty of obtaining optimal solutions, but is necessary to accurately model the location of new investment in generation. Given the proposed regulation of CO2 emissions from US power plants, an examination of economically efficient policies for reducing these emissions is warranted. The model incorporates realistic physical constraints, investment and retirement of generation, and price-responsive load to simulate the effects of policies for limiting CO2 emissions over a twenty-year forecast horizon. Using network reductions for each of the three electric system regions in the U.S. And Canada, an optimal economic dispatch, that satisfies reliability criteria, is assigned for 12 typical hour-types in each year. Three scenarios are modeled that consider subsidies for renewables and either CO2 emissions regulation on new investment or cap-and-trade. High and low gas price trends are also simulated and have large effects on prices of electricity but small impacts on CO2 emissions. Low gas prices with cap-and-trade reduce CO2 emissions the most, large subsidies for renewables alone do not reduce carbon emissions much below existing levels. Extensive retirement of coal-fired power plants occurs in all cases. %B 48th Hawaii International Conference on System Sciences (HICSS) %I IEEE %C Kauai, HI %8 01/2015 %U http://ieeexplore.ieee.org/xpl/articleDetails.jsp?arnumber=7070115&refinements%3D4254321466%26filter%3DAND%28p_IS_Number%3A7069647%29 %R 10.1109/HICSS.2015.300 %0 Journal Article %J IEEE Transactions on Power Systems %D 2015 %T Stochastically Optimized, Carbon-Reducing Dispatch of Storage, Generation, and Loads %A Alberto J Lamadrid %A Daniel L. Shawhan %A Carlos E. Murillo-Sanchez %A Ray D. Zimmerman %A Zhu, Yujia %A Daniel J. Tylavsky %A Kindle, Andrew G. %A Dar, Zamiyad %K CERTS %K reliability and markets %K RM07-002 %X We present a new formulation of a hybrid stochastic-robust optimization and use it to calculate a look-ahead, security-constrained optimal power flow. It is designed to reduce carbon dioxide (CO2) emissions by efficiently accommodating renewable energy sources and by realistically evaluating system changes that could reduce emissions. It takes into account ramping costs, CO2 damages, demand functions, reserve needs, contingencies, and the temporally linked probability distributions of stochastic variables such as wind generation. The inter-temporal trade-offs and transversality of energy storage systems are a focus of our formulation. We use it as part of a new method to comprehensively estimate the operational net benefits of system changes. Aside from the optimization formulation, our method has four other innovations. First, it statistically estimates the cost and CO2 impacts of each generator's electricity output and ramping decisions. Second, it produces a comprehensive measure of net operating benefit, and disaggregates that into the effects on consumers, producers, system operators, government, and CO2 damage. Third and fourth, our method includes creating a novel, modified Ward reduction of the grid and a thorough generator dataset from publicly available information sources. We then apply this method to estimating the impacts of wind power, energy storage, and operational policies. %B IEEE Transactions on Power Systems %V 30 %P 1064 - 1075 %8 03/2015 %N 2 %! IEEE Trans. Power Syst. %R 10.1109/TPWRS.2014.2388214 %0 Journal Article %J Resource and Energy Economics %D 2014 %T Does a detailed model of the electricity grid matter? Estimating the impacts of the Regional Greenhouse Gas Initiative %A Daniel L. Shawhan %A John T. Taber %A Di Shi %A Ray D. Zimmerman %A Yan, Jubo %A Charles M. Marquet %A Yingying Qi %A Mao, Biao %A Richard E. Schuler %A William D. Schulze %A Daniel J. Tylavsky %K CERTS %K electricity markets %K reliability and markets %K RM11-005 %X The consequences of environmental and energy policies in the U.S. can be severely constrained by physical limits of the electric power grid. Flows do not follow the shortest path but are distributed over all lines in accordance with the laws of physics, so grid operators must select which generation units to operate at each moment, not only to minimize production costs, but also to prevent the system from collapsing because of line overloads. Because of the complexity of power grid operation, computing limitations have until very recently made it impossible to solve a policy analysis or planning model that combines realistic modeling of flows with a detailed transmission system model and the prediction of generator investment and retirement. We construct and solve a model of the eastern US and Canada that combines these characteristics. Then, because a smaller model would be usable for some additional purposes, we explore the effects of transmission model simplification on the accuracy of simulation results. To evaluate the amount of detail necessary, we simulate the short- and long-term effects of imposing a price on the carbon dioxide emissions from the power plants in nine northeastern US states, as the Regional Greenhouse Gas Initiative does. We consider three grid models that simplify the actual 62,000-node system to varying degrees. Our 5000-node model matches the 62,000-node model very closely. We use it as the basis for evaluating the more simplified models: a 300-node model and a model with just one node, i.e. no transmission constraints. With each of the three models, we predict the carbon dioxide emission impacts, electricity price impacts, and generator entry and exit impacts of the emission price, over the next 20 years. We find that most of the impact predictions produced by the 300- and one-node models differ from those of the 5000-node model by more than 20%, and some by much more. Fortunately, the 5000-node model, and others with its combination of transmission detail, realistic flows, entry prediction, and retirement prediction can be used for many useful purposes. %B Resource and Energy Economics %V 36 %P 191 - 207 %8 01/2014 %N 1 %! Resource and Energy Economics %R 10.1016/j.reseneeco.2013.11.015 %0 Conference Paper %B 2014 North American Power Symposium (NAPS) %D 2014 %T Improved dc network model for contingency analysis %A Sood, P. %A Daniel J. Tylavsky %A Yingying Qi %K CERTS %K Power system modeling %K RM11-005 %X Contingency analysis is employed by system operators to estimate post-disturbance power system robustness. For large system like WECC or the Eastern Interconnection (EI) the computational burden and time consumed for full blown ac analysis is tremendous. Also, a recent upsurge in the area of electric energy markets and transmission/generation planning has created a niche for computationally efficient and yet reliable, simple and robust power flow models. This has intensified the inclination of researchers to come up with equivalent dc networks that match ac solutions as close as possible. This paper introduces a novel method of deriving dc model using PTDF approach. The performance of this model is then compared to the several other dc models for single branch outage contingencies. Furthermore, shortcomings of several dc models shall be analyzed. %B 2014 North American Power Symposium (NAPS) %I IEEE %C Pullman, WA, USA %P 1 - 6 %8 09/2014 %R 10.1109/NAPS.2014.6965414 %0 Journal Article %J IEEE Transactions on Power Systems %D 2014 %T A Novel Bus-Aggregation-Based Structure-Preserving Power System Equivalent %A Di Shi %A Daniel J. Tylavsky %K CERTS %K power system planning %K RM11-005 %X The challenges power systems engineers are facing today require the development of new system planning tools for analyzing generation and environmental policy options in the transmission-constrained electricity market. The requirements of a power-system equivalent to be used with such tools are very different from those assumed in the traditional network reduction process. To solve this issue, a novel structure-preserving network equivalent is proposed in this paper for modeling large power systems in the context of analyzing policy options and emissions. In the proposed method, a power system is first clustered into zones based on the similarity of the power transfer distribution factors (PTDFs); network reduction is achieved by aggregating buses (generators/loads) on a zonal basis and modeling inter-zonal transactions (power flows) using equivalent transmission lines. The proposed equivalent is superior to existing bus-aggregation-based equivalents in its accuracy under both the base case and change-case operating conditions. In addition, the method is more computationally efficient than other bus aggregation methods proposed heretofore. This paper also examined several classic clustering techniques and identified their performance and computational efficiencies when applied to very large power systems. The proposed network equivalencing approach is tested on an illustrative six-bus system as well as the 62,000-bus and 80,000-branch Eastern Interconnection (EI). %B IEEE Transactions on Power Systems %P 1 - 10 %8 10/2014 %! IEEE Trans. Power Syst. %R 10.1109/TPWRS.2014.2359447 %0 Conference Paper %B 2014 North American Power Symposium (NAPS) %D 2014 %T An optimization based generator placement strategy in network reduction %A Zhu, Yujia %A Daniel J. Tylavsky %K CERTS %K network reduction %K optimal power flow (OPF) %K reliability and markets %K RM11-005 %XSolving the optimal power flow (OPF) problem on a large power system is computationally expensive. Network reduction and ac-to-dc network conversion can relieve this burden by simplifying the full system model to a smaller and mathematically simpler model. Traditional reduction methods, like Ward reduction, fractionalize generators when the buses they are attached to are removed, and scatters these fractions to topologically adjacent buses. In some OPF applications, this type of generator modeling is problematic. An improved approach is to keep generators intact by moving them whole to buses in reduced model and then redistributing loads to maintain base-case line flows. Determining generator placement using a traditional shortest electrical distance (SED) based method may result in cases where the OPF solution on reduced model is infeasible while the full model has a feasible solution. In this paper, an improved generator placement method is proposed. Tests show that the proposed method yields a better approximation to the full model OPF solutions and is more likely to produce a reduced model with a feasible solution if the unreduced model has a feasible solution.

%B 2014 North American Power Symposium (NAPS) %I IEEE %C Pullman, WA, USA %P 1 - 6 %8 09/2014 %R 10.1109/NAPS.2014.6965401 %0 Journal Article %J IEEE Transactions on Smart Grid %D 2012 %T An Adaptive Method for Detection and Correction of Errors in PMU Measurements %A Di Shi %A Daniel J. Tylavsky %A Logic, Naim %K AARD %K CERTS %K phasor measurement units (PMUs) %K RM12-002 %K SuperOPF %X PMU data are expected to be GPS-synchronized measurements with highly accurate magnitude and phase angle information. However, this potential accuracy is not always achieved in actual field installations due to various causes. It has been observed in some PMU measurements that the voltage and current phasors are corrupted by noise and bias errors. This paper presents a novel method for detection and correction of errors in PMU measurements with the concept of calibration factors. The proposed method uses nonlinear optimal estimation theory to calculate calibration factor using a traditional model of an untransposed transmission line with unbalanced load. This method is intended to work as a prefiltering scheme that can significantly improve the accuracy of the PMU measurement for further use in system state estimation, transient stability monitoring, wide area protection, etc. Case studies based on simulated data are presented to demonstrate the effectiveness and robustness of the proposed method. %B IEEE Transactions on Smart Grid %V 3 %P 1575 - 1583 %8 12/2012 %N 4 %! IEEE Trans. Smart Grid %R 10.1109/TSG.2012.2207468 %0 Conference Paper %B 2012 North American Power Symposium (NAPS 2012) %D 2012 %T Impact of assumptions on DC power flow model accuracy %A Yingying Qi %A Di Shi %A Daniel J. Tylavsky %K CERTS %K Power system modeling %K RM11-005 %X The industry seems to be sanguine about the performance of dc power-flow models, but recent research has shown that the performance of different formulations is highly variable. Considering their pervasive use, the accuracy of dc power-flow models is of great concern. In this paper, three dc power-flow formulations are examined: the classical dc power-flow model, dc power-flow model with loss compensation and the so-called a-matching dc power-flow model. These three models are tested in three systems of different sizes, ranging from 10 buses to 62,000 buses. By comparing the dc power-flow results with the ac power-flow results, the paper concludes that the a-matching formulation has the highest accuracy among three dc power flow formulations. %B 2012 North American Power Symposium (NAPS 2012) %I IEEE %C Champaign, IL, USA %P 1 - 6 %8 09/2012 %@ 978-1-4673-2306-2 %R 10.1109/NAPS.2012.6336395 %0 Conference Paper %B 2012 IEEE Power & Energy Society (PES) General Meeting %D 2012 %T An improved bus aggregation technique for generating network equivalents %A Di Shi %A Daniel J. Tylavsky %K CERTS %K RM11-005 %XThe requirements of a network equivalent to be used in a planning tool (such as the SuperOPF being developed at Cornell) for analyzing policy options, impacts on reliability, costs and emissions for networks as vast as the entire Eastern Interconnection, are very different from those assumed in the development of traditional equivalencing procedures. In this paper, a novel network equivalencing approach using bus aggregation techniques is proposed that shows promise for modeling such large systems in the context of analyzing policy options and emissions. This approach is superior to the existing bus aggregation methods in that a) under the base case, the equivalent-system inter-zonal power flows exactly match those calculated using the full-network-model b) as the operating conditions change, errors in line flows are minimized c) the method is more computationally efficient than other bus aggregation methods proposed heretofore. The proposed method is tested on an illustrative six-bus system and promising results are observed.

%B 2012 IEEE Power & Energy Society (PES) General Meeting %I IEEE %C San Diego, CA %P 1 - 8 %8 07/2012 %@ 978-1-4673-2727-5 %R 10.1109/PESGM.2012.6344668 %0 Conference Paper %B 2012 North American Power Symposium (NAPS) %D 2012 %T Optimal generation investment planning: Pt. 1: network equivalents %A Di Shi %A Daniel L. Shawhan %A Li, Nan %A Daniel J. Tylavsky %A John T. Taber %A Ray D. Zimmerman %A William D. Schulze %K CERTS %K Eastern Interconnection %K investment planning %K optimal power flow (OPF) %K Power system modeling %K reliability and markets %K RM11-005 %XThe requirements of a network equivalent to be used in new planning tools are very different from those used in traditional equivalencing procedures. For example, in the classical Ward equivalent, each generator in the external system is broken up into fractions. For newer long-term investment applications that take into account such things as greenhouse gas (GHG) regulations and generator availability, it is computationally impractical to model fractions of generators located at many buses. To overcome this limitation, a modified- Ward equivalencing scheme is proposed in this paper. The proposed scheme is applied to the entire Eastern Interconnection (EI) to obtain several backbone equivalents and these equivalents are tested for accuracy under a range of operating conditions. In a companion paper, the application of an equivalent developed by this procedure is used to perform optimal generation investment planning.

%B 2012 North American Power Symposium (NAPS) %I IEEE %C Champaign, IL, USA %P 1 - 6 %8 09/2012 %@ 978-1-4673-2306-2 %R 10.1109/NAPS.2012.6336375 %0 Conference Paper %B 2012 North American Power Symposium (NAPS) %D 2012 %T Optimal generation investment planning: Pt. 2: Application to the ERCOT system %A Li, Nan %A Di Shi %A Daniel L. Shawhan %A Daniel J. Tylavsky %A John T. Taber %A Ray D. Zimmerman %A William D. Schulze %K CERTS %K investment planning %K Power system modeling %K power system planning %K reliability and markets %K RM11-005 %XPower system planning and market behavioral analysis using the full model of a large-scale network, such as the entire ERCOT system, are computationally expensive. Reducing the full network into a small equivalent is a practical way to reduce the computational burden. In a companion paper, a modified-Ward equivalencing procedure has been proposed. In this paper, the proposed scheme is applied to the ERCOT system to obtain several backbone equivalents, the accuracy of which are tested under a range of operating conditions. The ERCOT equivalent is used in a system planning tool to perform optimal generation investment studies with promising results observed.

%B 2012 North American Power Symposium (NAPS) %I IEEE %C Champaign, IL, USA %P 1 - 6 %8 09/2012 %@ 978-1-4673-2306-2 %R 10.1109/NAPS.2012.6336374 %0 Journal Article %J European Transactions on Electrical Power %D 2011 %T Transmission line parameter identification using PMU measurements %A Di Shi %A Daniel J. Tylavsky %A Koellner, Kristian M. %A Logic, Naim %E Joe H. Chow %K AARD %K phasor measurement units (PMUs) %K RM11-005 %X Accurate knowledge of transmission line (TL) impedance parameters helps to improve accuracy in relay settings and power flow modeling. To improve TL parameter estimates, various algorithms have been proposed in the past to identify TL parameters based on measurements from Phasor Measurement Units (PMUs). These methods are based on the positive sequence TL models and can generate accurate positive sequence impedance parameters for a fully transposed TL when measurement noise is absent; however, these methods may generate erroneous parameters when the TLs are not fully transposed or when measurement noise is present. PMU field-measure data are often corrupted with noise and this noise is problematic for all parameter identification algorithms, particularly so when applied to short TLs. This paper analyzes the limitations of the positive sequence TL model when used for parameter estimation of TLs that are untransposed and proposes a novel method using linear estimation theory to identify TL parameters more reliably. This method can be used for the most general case: short/long lines that are fully transposed or untransposed and have balanced/unbalance loads. Besides the positive/negative sequence impedance parameters, the proposed method can also be used to estimate the zero sequence parameters and the mutual impedances between different sequences. This paper also examines the influence of noise in the PMU data on the calculation of TL parameters. Several case studies are conducted based on simulated data from ATP to validate the effectiveness of the new method. Through comparison of the results generated by this novel method and several other methods, the effectiveness of the proposed approach is demonstrated. %B European Transactions on Electrical Power %V 21 %P 1574 - 1588 %8 05/2011 %N 4 %! Euro. Trans. Electr. Power %R 10.1002/etep.522 %0 Journal Article %J International Journal of Emerging Electric Power Systems %D 2010 %T Efficient Market Design and Public Goods, Part II: Theoretical Results %A David Toomey %A William D. Schulze %A Robert J. Thomas %A James S. Thorp %A Daniel J. Tylavsky %A Richard E. Schuler %K CERTS %K electricity markets %K market design %K power system economics %K reliability and markets %X Electric power is traditionally comprised of valued services, including real and reactive power, voltage, frequency and reliability in its most general sense. In this second part of our two-part paper we show mathematically that of these, only real and reactive power are purely private goods, in that power consumed by one customer cannot be used by another and customers can be excluded from receiving any power. The other ancillary services, including voltage, frequency and reliability are shown to be public goods. The first order conditions presented clearly illustrate that the public goods occurring in electric power systems comprise a significant problem for market design. %B International Journal of Emerging Electric Power Systems %V 11 %8 01/2010 %N 1 %R 10.2202/1553-779X.2300 %0 Report %D 2009 %T Facilitating Environmental Initiatives While Maintaining Efficient Markets and Electric System Reliability Final Project Report %A William D. Schulze %A Robert J. Thomas %A Timothy D. Mount %A Richard E. Schuler %A Ray D. Zimmerman %A Daniel J. Tylavsky %A Daniel L. Shawhan %A Doug Mitarotonda %A John T. Taber %K Market mechanisms %K reliability and markets %K reliability management %K RM12-002 %XWe use an alternating-current model of the power network in northeastern North America to predict the effects of several different incentive-based carbon dioxide regulations. We use all of the kinds of flow equations and constraints that govern the actual system. To our knowledge, this report is the first to analyze an environmental policy using an alternating-current model of a power network. This report makes three contributions to the environmental and energy economics literature. The first is to demonstrate and further develop the use of alternating current modeling. The second is to compare the predictions of an alternating-current model with those of a direct-current approximation of the same model and with an unlimited-transmission model of the same region. This comparison is a test of whether our more complex modeling is warranted. The third contribution is to predict the effects of different incentive-based carbon dioxide emission regulations on emissions and total variable cost. Among other scenarios, we simulate a U.S.-only regulation, a Canada-only regulation, the Regional Greenhouse Gas Initiative ("RGGI") in the presence of a drought, the effects of exempting smaller generators from a carbon dioxide regulation (as done in RGGI), and the interaction of incentive-based carbon dioxide and sulfur dioxide regulations. We have not previously seen any of these examined in the literature. In addition, we consider the impact of long-run demand response that can mitigate the impact of regulation by reducing demand for electricity.

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