Working Papers

  • 2015

    CEIC-15-06: "A Behavioral Decision Research Approach to Energy Efficiency"
    By Alex Davis, Gabrielle Wong-Parodi, and Tamar Krishnamurti

    Even when the benefits far outweigh the costs, many building owners do not invest in energy efficiency. We present a general framework for understanding energy efficiency investment decisions drawing on methods grounded in behavioral decision research. The approach begins with a normative analysis that characterizes how rational, self-interested agents or organizations should behave, follows with a descriptive analysis of actual decision-makers,and then concludes with policy recommendations for how to bridge that gap. We demonstrate the framework with a sample of class B and C office building owners, a population believed to systematically underinvest in energy efficiency. Using interviews and a survey, we find that while uncertainty and a lack of information about costs and energy savings play a critical role in their decision-making, a significant proportion of the population expressed aversion to debt and a lack of sensitivity to split incentives. Based on the results, we recommend providing owners of class B and C offices cost-benefit information and resolving energy savings uncertainty through grants that fully subsidize energy efficiency for a small part of a building. The approach can be applied to energy efficiency decision-making by anyone with training in behavioral research, bringing climate advocates and social scientists together. 


    CEIC-15-05: "Quantifying Sources of Uncertainty in Reanalysis Derived Wind Speed"
    By Stephen Rose and Jay Apt

    Reanalysis data is attractive for wind-power studies because it can offer wind speed data for large areas and long time periods and in locations where historical data are not available. However, reanalysis-predicted wind speeds can have significant uncertainties and biases relative to measure wind speeds. In this work we develop a model of the bias and uncertainty of CFS reanalysis wind speed than can be used to correct the data and identify sources of error. We find the CFS reanalysis data underestimates wind speeds at high elevations, at high measurement heights, and in unstable atmospheric conditions. For example, at a site with an elevation of 500 m and hub height of 80 m, the CFS reanalysis underestimates wind speed by 1.6 – 2.2 m/s. We also find a seasonal bias that correlates with surface roughness length used by the reanalysis model during the spring season. The corrections we propose reduce the average bias of reanalysis wind speed extrapolated to hub height to nearly zero, an improvement of 0.3 – 0.9 m/s. These corrections also reduce the RMS error by 0.1 – 0.4 m/s, a small improvement compared to the uncorrected RMS errors of 1.5 – 2.4 m/s. 


    CEIC-15-04: "The Economics of Commercial Demand Response for Spinning Reserve"
    By Michael Fisher, Jay Apt, Fallaw Sowell

    Demand response (DR) for spinning reserve may be appropriate for customers whose operational constraints preclude participation in energy and capacity DR programs. We investigate the private business case of an aggregator providing spinning reserve in California. Average costs to enable quick-response capability, obtained from California’s Automated Demand Response programs and the literature, were $230/kW of controlled load. Revenues are calculated using end use level hourly load profiles. With average annual revenue of ~$35/kW, steady end uses (e.g., lighting) are more than twice as profitable as seasonal end uses (e.g., cooling) because spinning reserve is needed year-round. Business segments with longer operating hours, such as groceries or lodging, have more revenue potential. However, average payback periods are longer than 5 years and thus do not present a compelling business case for an aggregator. Avoided carbon emission damages from using DR instead of fossil fuel generation for spinning reserve could justify incentives for DR resources.


    CEIC-15-03: "Geographic Smoothing of Solar PV"
    By Kelly Klima, and Jay Apt

    Demand response (DR) for spinning reserve may be appropriate for customers whose operational constraints preclude participation in energy and capacity DR programs. We investigate the private business case of an aggregator providing spinning reserve in California. Average costs to enable quick-response capability, obtained from California’s Automated Demand Response programs and the literature, were $230/kW of controlled load. Revenues are calculated using end use level hourly load profiles. With average annual revenue of ~$35/kW, steady end uses (e.g., lighting) are more than twice as profitable as seasonal end uses (e.g., cooling) because spinning reserve is needed year-round. Business segments with longer operating hours, such as groceries or lodging, have more revenue potential. However, average payback periods are longer than 5 years and thus do not present a compelling business case for an aggregator. Avoided carbon emission damages from using DR instead of fossil fuel generation for spinning reserve could justify incentives for DR resources. 


    CEIC-15-02: "The Health Effects of a USA Switch from Coal to Gas Electricity Generation"
    By Roger Lueken, Kelly Klima, W. Michael Griffin, and Jay Apt

    Abundant natural gas at low prices has prompted industry and politicians to welcome gas as a ‘bridge fuel’ between today’s coal intensive electric power generation and a future low-carbon grid. We used existing national datasets and publicly available models to investigate the upper limit to the emission benefits of natural gas in the USA power sector. As a bounding analysis case, we analyzed a switch of all USA coal plants to natural gas plants, occurring in 2016. Although the climate change effects would be modest, the human health benefits of such a switch are substantial: SO2 emissions are reduced by more than 90%, and NOX emissions by more than 60%. The costs of building and operating new gas plants likely exceed the health benefits; retrofitting coal plants with emission control technology is likely to be more cost effective. Policymakers should not be distracted by the modest climate change benefits; annual health damages could be reduced by ~$20 billion in the United States if coal plants are either replaced with gas plants or fitted with flue gas desulfurization emission controls. 


    CEIC-15-01: "Robust Resource Adequacy Planning in the Face of Coal Retirements"
    Roger Lueken, Jay Apt, Fallaw Sowell

    Over the next decade, many U.S. coal-fired power plants are expected to retire, posing a challenge to system planners. We investigate the resource adequacy requirements of the PJM Interconnection, and how procuring less capacity may affect reliability. Assuming that plant forced outages are independent of one another, we find that PJM’s 2010 reserve margin of 20.5% was sufficient to achieve the stated reliability standard of one loss of load event per ten years with 90% confidence. PJM could reduce reserve margins to 13% and still achieve levels of reliability accepted by other U.S. and international power systems with 90% confidence. Reducing reserve margins from 20.5% to 13% would reduce PJM’s capacity procurement by 11 GW, the same amount of coal capacity that PJM has identified as at high risk of retirement. However, if plant failures are caused by external events such as extreme weather and are correlated, reliability may be significantly lower than forecast by PJM’s current resource planning process (we consider correlated outages in sections 1.2.4 and 1.3.6). The risk posed by supply shortages is primarily due to very rare, but severe events. System operators should work to ensure that the system is robust to these extreme events.


  • 2014

    CEIC-14-05: "What can Reanalysis Data Tell us About Wind Power?"
    Stephen Rose and Jay Apt

    Reanalysis data sets have become a popular data source for large-scale wind power analyses of because they cover large areas and long time spans, but those data are uncertain representations of "true" wind speeds. In this work we develop a model that systematically quantifies the uncertainties across many sites and corrects for biases of the reanalysis data. We apply this model to 32 years of reanalysis data for 1002 plausible wind-plant sites in the U.S. Great Plains to estimate variability of wind energy generation and the smoothing effect of aggregating distant wind plants. We find the coefficient of variation (COV) of annual energy generation of individual wind plants in the Great Plains is 8-17%, but the COV of all those plants aggregated together is 3.6%, Similarly, the average variability of quarterly cash flow to equity investors in a single wind plant is 37%, but that can be reduced to 26 - 29% by small creating portfolios of two wind plants selected from regions with low correlations of wind speed.

    CEIC-14-04: "Is it Always Windy Somewhere? Occurrence of Low-Wind-Power Events over Large Areas"

    Mark A. Handschy, Stephen Rose, and Jay Apt

    As wind power grows from its present 4% market share in the US, knowing how often the wind fails and power must be supplied by other generators becomes important. The statistics of these low prob­ability events have “thin tails”; the wind fails less frequently than would be predicted by a Gaussian distribution. In order to investigate a future in which wind plants are geographically numerous, we examine the occur­rence frequency of low wind-power levels for arrays of wind generators simulated from anemometer data at nine tall-tower sites spread across the contiguous United States. We find that the number of low-power hours per year declines exponentially with the number N of sites comprising the array. Power levels below 5% of total capacity, for example, drop by a factor of about 60, from 2140 h/y for the median single site to 36 h/y for the generation aggregated from all nine sites. The systematic dependence of the low-power duration on both N and on power threshold is in accord with an explanation based on the theory of Large Deviations. Combining this theory for tail behavior with the normal distribution for behavior near the mean allows us to estimate the entire generation duration curve as a function of the number of sites in the array.


    CEIC-14-03: "Consumer Cost Effectiveness of CO2 Mitigation Policies in Restructured Electricity Markets"
    Jared Moore and Jay Apt

    We examine the cost of carbon dioxide mitigation to consumers in restructured markets under two policy instruments, a carbon price and renewable portfolio standards (RPS). To estimate the effect of policies on market clearing prices, we constructed an hourly economic dispatch model of the generators in PJM, ERCOT, and MISO. We find that the cost effectiveness of policies for consumers is strongly dependent on the price of natural gas and on the characteristics of the generators in the dispatch stack. If gas prices are low (~$4/MMBTU), a technology-agnostic, rational consumer seeking to minimize costs would prefer a carbon price over an RPS in every region. Expensive gas (~$7/MMBTU) requires a high carbon price to induce fuel switching and this leads to wealth transfers from consumers to low carbon producers. The RPS may be more cost effective for consumers because the added energy supply lowers market clearing prices and reduces CO2 emissions. We find that both policies have consequences in capacity markets and that the RPS can be more cost effective only if existing capacity supply remains adequate.


    CEIC-14-02: "The Social Costs and Benefits of Wind Energy: A Case Study of the PJM Interconnection"
    Roger Lueken, Jared Moore, and Jay Apt

    Large deployments of wind create social costs and benefits that are not captured by traditional levelized cost of electricity (LCOE) analyses. Social costs are due to the inherent variability and unpredictability of wind power; social benefits are due to reductions in greenhouse gas and criteria pollutant emissions from fossil fuel plants. We investigated the social costs and benefits of wind in the PJM Interconnection for two scenarios: a 2012 scenario with 1.5% of energy from wind, and a high wind scenario with 20% of energy from wind. We found that social costs are uncertain but significant when compared to wind's LCOE. Social costs range from $4/MWh -$74/MWh in the low wind scenario, with an expected value of $36/MWh; in the high wind scenario costs range from $9/MWh - $94/MWh with an expected value of $51/MWh. Pollution reduction benefits exceed social costs with very high probability; the median expected net benefit is $74/MWh for both the low and high wind scenarios. EPA regulations may reduce the pollution reduction benefits of additional wind in the future. If cross-state air pollution regulations result in binding emission caps at anticipated permit prices, policies that incentivize additional wind will not reduce criteria pollutant emissions. 


    CEIC-14-01: "The Climate and Health Effects of a USA Switch from Coal to Gas"
    Roger Lueken, Kelly Klima, W. Michael Griffin, and Jay Apt

    Abundant natural gas at low prices has prompted industry and politicians to welcome gas as a ‘bridge fuel’ between today’s coal intensive power and a future low-carbon grid. We use existing national datasets and publicly available models to examine how a shift from coal to natural gas will affect climate change and damages to human health. Climate benefits of a USA coal-to-gas switch are limited. Even at a low fugitive methane emissions rate, a full switch from coal to gas provides only a few months’ delay in reaching greenhouse gas levels that lead to dangerous climate impacts. On the other hand, human health benefits are substantial: reduced emissions of harmful criteria pollutants would further reduce annual health damages by ~$40 billion from anticipated 2015 levels. However, the costs of building and operating new gas plants likely exceed the health benefits; retrofitting coal plants with emission control technology is likely to be more cost effective. While human health in the United States can greatly benefit from policies that continue the switch from coal to gas, natural gas should not sidetrack policy from the goal of reducing global greenhouse gas emissions.

  • 2013

    CEIC-13-07: "Quantifying the Hurricane Catastrophe Risk to Offshore Wind Power"
    Stephen Rose, Paulina Jaramillo, Mitchell J. Small, and Jay Apt

    The U.S. Department of Energy has estimated that over 50 GW of offshore wind power will be required for the United States to generate 20% of its electricity from wind. Developers are actively planning offshore wind farms along the U.S. Atlantic and Gulf coasts and several leases have been signed for offshore sites. These planned projects are in areas that are sometimes struck by hurricanes. We present a method to estimate the catastrophe risk to offshore wind power using simulated hurricanes. Using this method, we estimate the fraction of offshore wind power simultaneously offline and the cumulative damage in a region. In Texas, the most vulnerable region we studied, 10% of offshore wind power could be offline simultaneously due to hurricane damage with a 100-year return period and 6% could be destroyed in any 10-year period. We also estimate the risks to single wind farms in four representative locations; we find the risks are significant but lower than those estimated in previously published results. Much of the hurricane risk to offshore wind turbines can be mitigated by designing turbines for higher maximum wind speeds, ensuring that turbine nacelles can turn quickly to track the wind direction even when grid power is lost, and building in areas with lower risk.


    CEIC-13-06: "Redesigning Bills: The Effect of Format on Responses to Electricity Use Information"
    Casey Canfield and Gabrielle Wong-Parodi

    Electricity bills could be a low-cost strategy for improving feedback about consumers’ home electricity use and helping households reduce carbon dioxide emissions. However, quantitative feedback may be difficult to understand, especially for consumers with low numeracy or low energy literacy. Here, we build on the health communication literature, which has identified formats for communicating risks to low-numerate individuals. Participants saw one of three formats for presenting electricity use information including (a) tables, (b) bar graphs, and (c) icon graphs. In their assigned format, each participant saw three information types: (a) historical use, (b) comparison to neighbors, and (c) appliance breakdown. Three main findings emerged: First, the table format generated on average the best understanding across all three information types, across participants of all numeracy and energy literacy levels. Second, the benefit of alternative graphical formats varied depending on information type, in terms of effects on understanding and trust and liking. Neighbor comparison information was liked least and had the lowest intentions for behavior change, despite being no harder to understand than the appliance breakdown information. Third, individuals with lower numeracy and energy literacy understood all formats less. We discuss implications for designing utility bills that are understandable and motivate consumers.


    CEIC-13-05: "The Effects of Bulk Electricity Storage on the PJM Market"
    Roger Lueken and Jay Apt

    Recent advancements in battery technologies may make bulk electricity storage economically feasible. We analyze the value of two electrochemical storage technologies and traditional pumped hydropower storage in the 2010 PJM day-ahead energy market, using a reduced-form unit commitment model. We find that large-scale storage would increase overall social welfare in PJM.

    However, the annualized capital costs of storage would exceed social welfare gains. Consumers would save up to $4 billion annually due to reduced peak prices and reduced reliance on expensive peaking generators. These savings are equivalent to ~10% of sales in the PJM day-ahead energy market. Savings come largely at the expense of generator surplus. Existing market mechanisms are insufficient to encourage the socially optimal quantity of storage. Storage reduces the profitability of generators and the need for peaking generation capacity. Storage modestly increases emissions of CO2 and other pollutants in a system with 2010 PJM characteristics.


    CEIC-13-04: "What Day-Ahead Reserves are Needed in Electric Grids with High Levels of Wind Power?"
    Brandon Mauch, Jay Apt, Pedro M.S. Carvalho, and Paulina Jaramillo

    Day-ahead load and wind power forecasts provide useful information for operational decision making, but they are imperfect and forecast errors must be offset with operational reserves and balancing (real-time) energy. Procurement of these reserves is of great operational and financial importance in integrating large-scale wind power. We present a probabilistic method to determine net load forecast uncertainty for day-ahead wind and load forecasts. Our analysis uses data from two different electric grids in the U.S. with similar levels of installed wind capacity and large differences in wind and load forecast accuracy due to geographic characteristics. We demonstrate that the day-ahead capacity requirements can be computed based on forecasts of wind and load. For 95% day-ahead reliability, this required capacity ranges from 2,100 MW to 5,700 MW for ERCOT and 1,900 MW to 4,500 MW for MISO (with 10 GW of installed wind capacity), depending on the wind and load forecast values. We also show that each MW of additional wind power capacity in ERCOT must be matched with up to 0.30 MW day-ahead dispatchable generation capacity. For MISO (with its more accurate forecasts), the requirement is 0.13 MW of dispatchable capacity for each MW of additional wind capacity.


    CEIC-13-03: "Near-term Economics and Equity of Balancing Area Consolidation to Support Wind Integration"
    Todd Ryan, Paulina Jaramillo, and Gabriela Hug

    Balancing area consolidation could have economic benefits and improve the reliability of the U.S. electricity network, especially when transitioning to a future with significantly increased levels of renewable generation. Yet there has been little consolidation since the Midwest Independent System Operator was created in 1998. This research addresses this disparity by measuring the size and equity of the near-term economic gains associated with balancing area consolidation in nine scenarios of different wind penetrations, natural gas prices, and efficiency gains associated with the frequency regulation market. This study finds that sharing of economic resources through balancing area consolidation is a policy that leads to economic gains that are Kaldor-Hicks efficient. These gains are equivalent to a total cost reduction of $0.02-$0.2/MWh but could be as high as $1.7/MWh. Additionally, the data show little economic motivation for consolidation given the near-term expectation of wind penetration (0%- 20% by energy). These results help to explain why BA consolidation is not more wide-spread: there are few benefits to consolidating today and those benefits are inequitably distributed among those consolidating.


    CEIC-13-02: "Forecasting For Direct Load Control In Energy Markets"
    Shira Horowitz, Brandon Mauch, and Fallaw Sowell

    A doubly censored Tobit model is used to forecast hourly air-conditioner usage for individual households. The model is appropriate for a range of temperatures so it is possible to accurately forecast the electricity load to help balance the electricity grid in new settings, eg. solar and wind generation. Individual models are simulated and summed to obtain aggregate forecasts and confidence intervals. The model allows for correlation between the individual shocks that occur in a region. This approach gives substantially more accurate results than the moving average method typically used for forecasting and measuring direct load control.


    CEIC-13-01: "Estimating the Potential of Controlled Electric Vehicle Charging to Reduce Operational and Capacity Expansion Costs for Electric Power Systems with a Renewable Portfolio Standard"
    Allison Weis, Paulina Jaramillo, Jeremy Michalek

    Electric power systems with substantial wind capacity require additional flexibility to react to rapid changes in wind farm output and mismatches in the timing of increased generation and increased demand. Controlled variable-rate charging of plug-in electric vehicles allows demand to be rapidly modulated, providing an alternative to using fast-responding natural gas plants for balancing supply with demand and potentially reducing costs of operation and new plant construction. We investigate the cost savings from controlled charging of electric vehicles, the extent to which these benefits increase in high wind penetration scenarios, and the trade-off between establishing a controlled charging program vs. increasing the capacity of generators in the power system. We construct a mixed integer linear programming model for capacity expansion, plant dispatch, and electric vehicle charging based on the NYISO system. We find that controlled charging can offer significant cost reductions in a system with 10% penetration of electric vehicles; however, the magnitude of these benefits is only slightly higher in a system a 20% renewable portfolio standard (RPS) compared to a system no RPS policy. In the systems examined, controlled vehicle charging reduces the costs of integrating electric vehicles but provides little additional cost benefits for integrating wind.

  • 2012

    CEIC-12-08: "Production Cost and Air Emissions Impacts of Coal-Cycling in Power Systems with Large-Scale Wind Penetration"
    David Luke Oates and Paulina Jaramillo

    Wind power introduces variability into electric power systems. Due to physical characteristics of wind, most of this variability occurs at inter-hour time scales and coal units are therefore technically capable of balancing wind. Operators of coal-fired units have raised concerns that additional cycling will be prohibitively costly. Using PJM bid-data, we observe that coal operators are likely systematically under-bidding their startup costs. We then consider the effects of a 20% wind penetration scenario in the coal-heavy PJM West area, both when coal units bid business as usual startup costs, and when they bid costs accounting for the elevated wear and tear that occurs during cycling. We conclude that while 20% wind leads to increased coal cycling under business as usual startup costs, including full startup costs shifts the burden of balancing wind onto more flexible units. This shift has benefits for CO2, NOX, and SO2 emissions as well as for the profitability of coal plants, as calculated by our dispatch model. It is therefore not clear that increased cycling needs to be a major concern for operators of coal plants in systems with high wind, nor for those concerned with reducing air emissions.


    CEIC-12-07: "Quantifying the Hurricane Catastrophe Risk to Offshore Wind Power"
    Stephen Rose, Paulina Jaramillo, Mitchell J. Small, Jay Apt

    The U.S. Department of Energy has estimated that over 50 GW of offshore wind power will be required for the United States to generate 20% of its electricity from wind. Developers are actively planning offshore wind farms along the U.S. Atlantic and Gulf coasts and several developers have signed leases for offshore sites. These planned projects will be located in areas that are sometimes struck by hurricanes. We present a method to estimate the catastrophe risk to offshore wind power using simulated hurricanes. Using this method, we estimate the fraction of offshore wind power offline simultaneously and the cumulative damage in a region. In Texas, the most vulnerable region we studied, 11% of offshore wind power could be offline simultaneously due to hurricane damage with a 100-year return period and 5% could be destroyed in any 10-year period. We also estimate the risks to single wind farms in four representative locations; we find the risks are significant but lower than those estimated in previously published results. Much of the hurricane risk to offshore wind turbines can be mitigated by designing turbines for higher maximum wind speeds, ensuring that turbine nacelles can turn quickly to track the wind direction even when grid power is lost, and building in areas with lower risk.


    CEIC-12-06: "An Effective Method for Modeling Wind Power Forecast Uncertainty"
    Brandon Mauch, Jay Apt, Pedro M.S. Carvalho and Mitchell J. Small

    Wind forecasts are an important tool for electric system operators. Proper use of wind power forecasts to make operating decisions must account for the uncertainty associated with the forecast. Data from different regions in the USA with forecasts made by different vendors show the forecast error distribution is strongly dependent on the forecast level of wind power. At low wind forecast power, the forecasts tend to under-predict the actual wind power produced, whereas when the forecast is for high power, the forecast tends to over-predict the actual wind power. Most of the work in this field neglects the influence of wind forecast levels on wind forecast uncertainty and analyzes wind forecast errors as a whole. The few papers that account for this dependence, bin wind forecast data and fit parametric distributions to actual wind power in each bin. In the latter case, different parameters and possibly different distributions are estimated for each data bin. We present a method to model wind power forecast uncertainty as a single closed-form solution using a logit transformation of historical wind power forecast and actual wind power data. Once transformed, the data become close to jointly normally distributed. We show the process of calculating confidence intervals of wind power forecast errors using the jointly normally distributed logit transformed data. This method has the advantage of fitting the entire dataset with five parameters while also providing the ability to make calculations conditioned on the value of the wind power forecast.


    CEIC-12-05: "The Cost of Curtailing Wind Turbines for Secondary Frequency Regulation Capacity"
    Stephen Rose and Jay Apt

    We analyze the cost of curtailing the active power output of a wind farm to provide secondary frequency regulation capacity. We calculate the regulation capacity available and its cost by simulating the active power output of a curtailed 100-MW wind farm with a hybrid of real speed data and simulated high-frequency turbulence. We find that a curtailed wind farm can provide secondary frequency regulation capacity at a cost lower than conventional generators in less than 1% of the 1440 1-hour periods studied. Although the operating cost of curtailing a wind farm for frequency regulation capacity is high, the capital cost of installing the hardware and software to enable curtailment for frequency regulation is low. For that reason, we suggest that it is reasonable that grid operators require wind farms to have the capability to curtail for frequency regulation, but we recommend that capability should be rarely used.


    CEIC-12-04: "Optimal Investment Timing and Capacity Choice for Pumped Hydropower Storage"
    Emily Fertig, Ane Marte Heggedal, Gerard Doorman, and Jay Apt

    Pumped hydropower storage can smooth output from intermittent renewable electricity generators and facilitate their large-scale use in energy systems. Germany has aggressive plans for wind power expansion, and pumped storage ramps quickly enough to smooth wind power and could profit from arbitrage on the short-term price fluctuations wind power strengthens. We consider five capacity alternatives for a pumped storage facility in Norway that practices arbitrage in the German spot market. Price forecasts given increased wind capacity are used to calculate profit-maximizing production schedules and annual revenue streams. Real options theory is used to value the investment opportunity, since unlike net present value, it accounts for uncertainty and intertemporal choice. Results show that the optimal investment strategy under the base scenario is to invest in the largest available plant approximately eight years into the option lifetime.


    CEIC-12-03: "The Effect of Long-distance Interconnection on Wind Power Variability"
    Emily Fertig, Warren Katzenstein, Jay Apt, and Paulina Jaramillo

    We use time- and frequency-domain techniques to quantify the extent to which long-distance interconnection of wind plants in the United States would reduce the variability of wind power output. Previous work has shown that interconnection of just a few wind plants across moderate distances could greatly reduce the ratio of fast to slow-ramping generators in the balancing portfolio. We find that interconnection of aggregate regional wind plants would not reduce this ratio further but would reduce variability at all frequencies examined (connecting ERCOT and CAISO, for example, would reduce variability by 32 % in CAISO and 17 % in ERCOT). Interconnection of just a few wind plants reduces the average hourly change in power output, but interconnection across regions provides little further reduction. Interconnection also reduces the magnitude of low-probability step changes and doubles firm power output (capacity available at least 92 % of the time) compared with a single region. First-order analysis indicates that balancing wind and providing firm power with local natural gas turbines would be more cost-effective than with transmission interconnection. For net load, increased wind capacity would require more balancing resources but in the same proportions by frequency as currently. This justifies treating wind as negative load.


    CEIC-12-02: "Equity and Efficiency in Residential Electricity Pricing"
    Shira Horowitz and Lester Lave

    Real-time pricing of electricity is theoretically more economically efficient than flat rate pricing. However, a switch from flat-rates to real-time rates means that many consumers will lose the cross-subsidy they are receiving under the flat rate, and may see an increase in their bills even if they have elastic demand. We use hourly load data from 1260 Commonwealth Edison residential customers on a standard flat rate electricity tariff from 2007 and 2008. We calculate which customers would have been better off and which customers would not under real time pricing with both elastic and inelastic demand and look at the general characteristics of these customers. We find that if customers do not respond to prices under RTP, then only 35% of customers save money, while the remainder loses. The greatest potential for savings is in the long run, from reduction in capacity costs.


    CEIC-12-01: "Hurricane Risk to Offshore Wind Turbines Along the U.S. Coast"
    Stephen Rose, Paulina Jaramillo, Mitchell J. Small, Iris Grossmann, and Jay Apt

    This paper applies the method developed by Rose, et al. to create a map of the hurricane risk to offshore wind farms along the Atlantic coast and Gulf coast of the U.S. The risk to offshore wind farms is lowest along the coast of Mid-Atlantic and New England regions. There is less than a 10% probability in those regions that hurricanes destroy more than 10% of a wind farm in 20 years in most counties. The risk to offshore wind farms is highest for counties along the Gulf of Mexico, in South Florida, and near Cape Hatteras, NC. There is greater than a 30% probability in those regions that hurricanes will destroy more than 10% of a wind farm in 20 years. The hurricane risk to offshore wind farms can be significantly decreased by adding backup power to ensure the turbines are able to rapidly yaw to point directly into the wind even when grid power has been lost.

  • 2011

    CEIC-11-08: "Optimal Investment Timing and Capacity Choice for Pumped Hydropower Storage"
    Emily Fertiga, Ane Marte Heggedal, Gerard Doorman, and Jay Apt

    Pumped hydropower storage can smooth output from intermittent renewable electricity generators, facilitating their large-scale use in energy systems. Germany has aggressive plans for wind power expansion, and pumped storage ramps quickly enough to smooth wind power and could profit from arbitrage on the short-term price fluctuations wind power strengthens. We consider five capacity alternatives for a pumped storage facility in Norway that practices arbitrage in the German spot market. Price forecasts given increased wind capacity are used to calculate profit-maximizing production schedules and annual revenue streams. Real options theory is used to value the investment opportunity, since unlike net present value, it accounts for uncertainty and intertemporal choice. Results show that the optimal investment strategy under the base scenario is to invest in the largest available plant approximately eight years into the option lifetime.


    CEIC-11-07: "What Properties of Grid Energy Storage are Most Valuable?"
    Eric Hittinger, J.F. Whitacre, Jay Apt

    While energy storage technologies have existed for decades, grid-level storage is still an immature industry and is experiencing relatively rapid improvements in performance and cost across a variety of technologies. In this innovation cycle, it is important to determine which energy storage properties are most valuable. Decreased capital cost, increased power capability, and increased efficiency all would improve the value of an energy storage technology and each has cost implications that vary by application, but there has not yet been an investigation of the marginal rate of technical substitution between storage properties. We use engineering-economic models of four energy storage technologies and examine their cost-effectiveness for four specific applications. We determine which properties have the greatest effect on cost-of-service by performing an extended sensitivity analysis on the storage properties for combinations of application and storage type. We find that capital cost of storage is consistently important, and identify applications for which power/energy limitations are important. Each combination is different and blanket statements are not always appropriate.


    CEIC-11-06: "Reserve Requirements for Primary Frequency Control Increase Sharply at High Levels of Wind Penetration"
    Daniel Schnitzer and Jay Apt

    Power system stability following a fault is protected by primary frequency control and also by the inertia of heavy generator rotors like those found in conventional power plants. Because non-hydro renewable resources provide the power system with much less inertia and frequency response, a large fault could induce damaging oscillations in a system with a high penetration of renewables, resulting in lost load.

    Time-domain simulations on a fully dynamic modified IEEE 14-bus test system were conducted to measure the effect of a fault on metrics for system stability with varying quantities of wind power and wind interconnection locations. In response to model uncertainty, a probabilistic metric resembling loss-of-load-probability (LOLP) was ultimately chosen. Scenarios vary wind power penetration from 0% to 28% of total installed capacity.

    Primary frequency control rapidly damps transients; we find that its reserve requirements increase sharply at high levels of wind penetration. Although these experiments should be run on a validated model of a major US interconnection to ascertain whether the observed trends are general, we find a sharp increase in LOLP as wind penetration nears 20% unless new primary frequency control resources (that can include energy storage) are added.


    CEIC-11-05: "Incorporating Seismic Concerns in Site Selection for Enhanced Geothermal Power Generation"
    Enes Hoşgör, Jay Apt and Baruch Fischhoff

    Enhanced geothermal electric generation systems (EGS) may provide significant reductions in greenhouse gas emissions, if they can be successfully sited. One potential threat to that siting is induced seismicity, which has led to EGS projects being stopped in Switzerland and Germany. We create and implement a framework for identifying regions with low risk of induced seismicity risk. Using a widely known and used model with high spatial resolution, we find that, to a first approximation, 60% of the best areas for EGS plants based on purely geological considerations meet this standard. Taking advantage of this potential requires two next steps in these regions. One is using the best available tools for local modeling of triggered seismicity, rather than the coarse national model used here. The second is creating a viable social process for securing the informed consent of local communities.


    CEIC-11-04: "The Cost of Solar Power Variability"
    Colleen Horin, Gilbert E. Cohen, and Jay Apt

    We compare the power spectra of a year of electricity generation data from the Nevada Solar One solar thermal plant, a Tucson Electric Power solar PV array, and a Texas wind farm. The analysis shows that solar photovoltaic electricity generation is one hundred times more variable at frequencies on the order of 10-3 Hz than solar thermal electricity generation, and the variability of wind generation lies between solar PV and solar thermal. We calculate the cost of variability of the two solar power sources by adding the costs of ancillary services and the energy required to compensate for its variability and intermittency. We compare this result with a previous estimate of the cost of wind variability and present a method for calculating the cost of variability taking into account imperfect forecasts.


    CEIC-11-03: "Quantifying the Hurricane Risk to Offshore Wind Turbines"
    Stephen Rose, Paulina Jaramillo, Mitchell Small, Iris Grossmann and Jay Apt

    The U.S. Department of Energy has estimated that if the U.S. is to generate 20% of its electricity from wind, over 50 GW will be required from shallow offshore turbines. Hurricanes are a potential risk to these turbines. Turbine tower buckling has been observed in typhoons, but no offshore wind turbines have yet been built in the U.S. We present a probabilistic model to estimate the number of turbines that would be destroyed by hurricanes in an offshore wind farm. We apply this model to estimate the risk to offshore wind farms in four representative locations in the Atlantic and Gulf Coastal waters of the U.S. In the most vulnerable areas now being actively considered by developers, nearly half the turbines in a farm are likely to be destroyed in a 20-year period. We show that adding a capability to yaw the turbine's nacelle fast enough to follow the wind direction changes in a hurricane significantly reduces the risk the turbine will be destroyed. Reasonable mitigation measures - increasing the design reference wind load, ensuring that the nacelle can be turned into rapidly changing winds, and building most wind plants in the areas with lower risk - can greatly enhance the probability that offshore wind can help to meet the United States' electricity needs.


    CEIC-11-02: "Distribution Grid Reconfiguration Reduces Power Losses and Helps Integrate Renewables"
    Colleen Horin, Pedro M. S. Carvalho, and Jay Apt

    A reconfigurable network can change its topology by opening and closing switches on power lines. We use real wind, solar, load, and cost data and a model of a reconfigurable distribution grid to show that reconfiguration allows a grid operator to reduce operational losses as well as accept more intermittent renewable generation than a static configuration can. Net present value analysis of automated switch technology shows that the return on investment is negative for this test network when considering only loss reduction, but that the investment is attractive under certain conditions when reconfiguration is used to minimize curtailment.


    CEIC-11-01: "Power Consumption of Video Game Consoles Under Realistic Usage Patterns"
    E. Hittinger

    Video game consoles are becoming increasingly common in living rooms around America and can consume large amounts of electricity when in use. There have been a few studies in recent years examining the energy consumption of video game consoles, but bottom line figures rely strongly on assumptions about how the game consoles are used, and many of the assumptions used in earlier work are not in agreement with recently published usage patterns. This study merges the power consumption data from earlier work with newer video game console usage information to produce more accurate figures describing the overall energy use of video game consoles. By using more accurate data, this study comes to notably different conclusions than previous investigations.

    Previous work has overlooked both the effect of the WiiConnect24 service and the fact that the average Wii is used three times less than an average Xbox 360 or PS3. Taking these into account, the electricity consumption per hour of active use of the Nintendo Wii console is actually much higher than previously assumed and is higher than both the PS3 and the Xbox 360 under most reasonable scenarios.

    The WiiConnect24 service, which is active by default for a Wii console connected to the Internet, greatly increases the standby power of the Wii from 2 Watts to 9 Watts. Since most Wii consoles have been connected to the Internet, it is possible that the majority of Wii consoles have this service enabled. Taking the usage of the consoles into account, it is shown that the average Wii (with WiiConnect24 enabled) uses 550 Wh of electricity for each hour of use, which is significantly higher than the figures for the currently available Xbox 360 (125 Wh per hour of use) and PS3 (107 Wh per hour of use) consoles. Additionally, the average Wii (with WiiConnect24 enabled) consumes 97% of its electricity when it is in standby mode, versus 10 - 30% for the other consoles. Even with WiiConnect24 disabled, the average Wii consumes approximately the same amount of electricity for each hour of use as currently available models of PS3 and Xbox 360.

    Of most importance for consumers, it is shown that the total energy consumption of any of the video game consoles is small compared to the average residential electricity load, as long as the console is powered down when not in use. Even the console with highest annual electricity consumption, a launch model Xbox 360, accounts for only 1% of average residential electricity consumption under average usage patterns (or 2% if a 150W HDTV is also included). But if left on continuously, the same console would account for 15% of the average electricity load (25% with an HDTV left on as well). Additionally, the cost of electricity to operate a console is shown to be negligibly small compared with the cost of the system, games, and peripheral devices.

    Even though the current generation consoles differ in their services and energy use, their effect on total electricity use is quite small as long as they are powered down after use. Thus, gamers interested in reducing their energy use should concern themselves with more prominent energy use (such as transportation, heating/AC, or lighting), rather than fret over which video game console to purchase.

  • 2010

    CEIC-10-06: "Can a Wind Farm with Storage Survive in the Day-ahead Market?"
    Brandon Mauch, Pedro M.S. Carvalho, and Jay Apt

    We investigate the economic viability of coupling a wind farm with compressed air energy storage (CAES) to participate in the day-ahead electricity market. In our analysis we assume that renewable portfolio standards have been fully met and government subsidies have expired. Optimal hourly dispatch quantities of electricity for one year are calculated using a dynamic programming model with the objective of maximizing hourly revenues. Inputs for the model are wholesale electricity prices and wind power forecasts from a single wind farm. Dispatch quantities from the model are then used with measured wind power generation data to determine hourly profits for the wind farm.

    We find that annual revenue for the wind farm would not be enough to cover annualized capital costs of the wind farm and CAES facility when using market prices for Texas and Iowa during the years 2006 to 2009. We then estimate market prices with a carbon price of $20 and $50 per tonne CO2 and find that revenue would still not cover the capital costs. The implied cost per tonne of avoided CO2 for a profitable wind - CAES system is roughly $100, with large variability due to electric power prices.


    CEIC-10-05: "The Cost of Wind Power Variability"
    Warren Katzenstein and Jay Apt

    We develop a metric to quantify the sub-hourly variability cost of individual wind plants and show its use in valuing reductions in wind power variability. Our method partitions wind energy into hourly and sub-hourly components and uses corresponding market prices to determine the cost of variability. The metric is applicable to variability at all time scales faster than hourly, and can be applied to long-period forecast errors. We use publically available data at 15 minute time resolution to apply the method to ERCOT, the largest wind power production region in the United States. The range of variability costs arising from 15 minute to 1 hour variations (termed load following) for 20 wind plants in ERCOT was $6.79 to 11.5 per MWh (mean of $8.73 ±$1.26 per MWh) in 2008 and $3.16 to 5.12 per MWh (mean of $3.90 ±$0.52 per MWh) in 2009. Load following variability costs decrease as wind plant capacity factors increase, indicating wind plants sited in locations with good wind resources cost a system less to integrate.

    Twenty interconnected wind plants have a variability cost of $4.35 per MWh in 2008. The marginal benefit of interconnecting another wind plant diminishes rapidly: it is less than $3.43 per MWh for systems with 2 wind plants already interconnected, less than $0.7 per MWh for 4-7 wind plants, and less than $0.2 per MWh for 8 or more wind plants. This method can be used to value the installation of storage and other techniques to mitigate wind variability.


    CEIC-10-04: "Net Air Emissions from Electric Vehicles: The Effect of Carbon Price and Charging Strategies"
    Scott B. Peterson, J.F. Whitacre, and Jay Apt

    Plug-in hybrid electric vehicles (PHEVs) may become part of the transportation fleet on time scales of a decade or two. We calculate the electric grid load increase and emissions due to vehicle battery charging in PJM and NYISO with the current generation mix, the current mix with a $50/tonne CO2 price, and this case but with existing coal generators retrofitted with 80% CO2 capture. PHEV fleet percentages between 0.4 and 50% are examined. Vehicles with small (4 kWh) and large (16 kWh) batteries are modeled with driving patterns from the National Household Transportation Survey. Three charging strategies and three scenarios for future electric generation are considered. When compared to 2020 CAFE standards, net CO2 emissions in New York are reduced by switching from gasoline to electricity, but coal-heavy PJM shows no significant benefit unless coal units are fitted with CCS or replaced with lower CO2 generation. NOx is reduced in both RTOs, but SO2 increases.


    CEIC-10-03: "Generating Wind Time Series as a Hybrid of Measured and Simulated Data"
    Stephen Rose and Jay Apt

    Certain applications, such as analyzing the effect of a wind farm on grid frequency regulation, require several years of wind power data measured at intervals of a few seconds. This paper develops a method to generate long non-stationary wind speed time series sampled at high rates by combining measured and simulated data. Measured wind speed data, typically 10 - 15 minute averages, captures the non-stationary characteristics of wind speed variation: diurnal variations, the passing of weather fronts, and seasonal variations. Simulated wind speed data, generated from spectral models, "fills in" the gaps between the empirical data. The wind speed time series generated with this method agree very well with measured time series, both qualitatively and quantitatively. The power output of a wind turbine simulated with wind data generated by this method demonstrates energy production, ramp rates, and reserve requirements that closely match the power output of a turbine simulated turbine with measured wind data.


    CEIC-10-02: "Economics of Compressed Air Energy Storage to Integrate Wind Power: A Case Study in ERCOT"
    Emily Fertig and Jay Apt

    Compressed air energy storage (CAES) could be paired with a wind farm to provide firm, dispatchable baseload power, or serve as a peaking plant and capture upswings in electricity prices. We present a firm-level engineering-economic analysis of a wind/CAES system with a wind farm in central Texas, load in Houston, and a CAES plant whose location is profit-optimized. Transmission and CAES capacities are optimized under three electricity price scenarios. Using 2008 hourly prices, the economically optimal CAES expander capacity is unrealistically large - 20 GW - and dispatches for only a few hours per week when prices are highest. A $300/MWh price cap and contract price each render the wind/CAES system unprofitable. A baseload wind/CAES system is less profitable than a natural gas combined cycle (NGCC) plant at carbon prices less than $130/tCO2 (2008 data) to $300/tCO2 (2009 data). Using the wind/CAES system in regulation markets as well as the balancing energy market raises profit only slightly.

    Social benefits of CAES paired with wind include avoided construction of new generation capacity, improved air quality during peak times, and increased economic surplus, but may not outweigh the private cost of the CAES system nor justify a subsidy.


    CEIC-10-01: "Compensating for Wind Variability Using Co-Located Natural Gas Generation and Energy Storage"
    Eric Hittinger, J.F. Whitacre, Jay Apt

    Wind generation presents variability on every time scale, which must be accommodated by the electric grid. Limited quantities of wind power can be successfully integrated by the current generation and demand-side response mix but, as deployment of variable resources increases, the resulting variability becomes increasingly difficult and costly to mitigate. We model a co-located power generation/energy storage block which contains wind generation, a gas turbine, and fast-ramping energy storage. Conceptually, the system is designed with the goal of producing near-constant "baseload" power at a reasonable cost while still delivering a significant and environmentally meaningful fraction of that power from wind. The model is executed in 10 second time increments in order to correctly reflect the operational limitations of the natural gas turbine. A scenario analysis identifies system configurations that can generate power with 30% of energy from wind, a variability of less than 0.5% of the desired power level, and an average cost around $70/MWh. The systems described have the most utility for isolated grids, such as Hawaii or Ireland, but the study has implications for all electrical systems seeking to integrate wind energy and informs potential incentive policies.

  • 2009

    CEIC-09-07: "The Variability of Interconnected Wind Plants"
    Warren Katzenstein, Emily Fertig, Jay Apt

    We present the first frequency-dependent analyses of the geographic smoothing of wind power's variability, analyzing the interconnected measured output of 20 wind plants in Texas. Reductions in variability occur at frequencies corresponding to times shorter than ~24 hours and are quantified by measuring the departure from a Kolmogorov spectrum. At a frequency of 2.8x10-4 Hz (corresponding to 1 hour), an 87% reduction of the variability of a single wind plant is obtained by interconnecting 4 wind plants. Interconnecting the remaining 16 wind plants produces only an additional 8% reduction. At a frequency of 4.6x10-5 Hz (6 hours), interconnecting 6 wind plants produces a 68% reduction in variability and interconnecting the remaining 14 wind plants produces only an additional 8% reduction. We use step-change analyses and correlation coefficients to compare our results with previous studies, finding that wind power ramps up faster than it ramps down for each of the step change intervals analyzed and that correlation between the power output of wind plants 200 km away is half that of co-located wind plants. To examine variability at very low frequencies, we estimate yearly wind energy production in the Great Plains region of the United States from automated wind observations at airports covering 36 years. The estimated wind power has significant inter-annual variability and the severity of wind drought years is estimated to be about half that observed nationally for hydroelectric power.


    CEIC-09-06: "Public Preferences of Electricity Portfolios with CCS and Other Low-Carbon Technologies"
    Lauren A. Fleishman; Wändi Bruine de Bruin; and M. Granger Morgan

    For low-carbon electricity generating technologies to play a significant role in the reduction of atmospheric CO2 emissions, the public must accept their wide-spread deployment. This study asked members of the general public to rank ten technologies (e.g., wind, nuclear, coal with CCS, natural gas), and seven realistic low-carbon portfolios composed of these technologies. Participants received comprehensive and carefully balanced materials that systematically explained the costs and benefits of each. These materials were developed with input from domain experts to ensure correct information, and pilot-tested with members of the general public to ensure understanding. After ranking the technologies and the portfolios, participants also rated their overall opinion of CCS.

    Participants’ rankings of technologies suggest that they most favored energy efficiency, followed by nuclear, integrated gasification combined-cycle coal (IGCC) with CCS and wind. The most preferred portfolio included a mix of these four technologies. IGCC with CCS was preferred to pulverized coal with CCS, whether presented as a technology or within a portfolio. Coal technologies with CCS were preferred over those without CCS. Participants’ rankings suggest acceptance of CCS, when presented in comparison to other technologies and within a low-carbon portfolio. However, when participants considered the technology in isolation, their ratings showed only slightly favorable opinions of CCS. This finding suggests a reluctant acceptance of CCS, given the alternatives. We conclude that the general public may be willing to reluctantly accept CCS, nuclear and other low-carbon technologies, once they fully understand the benefits, cost and limitations of the alternatives.


    CEIC-09-05: "Implications of Compensating Property-Owners for Geologic Sequestration of CO2"
    R. Lee Gresham, Jay Apt, M. Granger Morgan, Sean T. McCoy

    Geologic sequestration (GS) of carbon dioxide (CO2) is contingent upon securing the legal right to use deep subsurface pore space. Under the assumption that compensation is required to use pore space for GS, we examine the cost of acquiring rights to sequester 160-million metric tons of CO2 (the 30-year emissions output for an 800 megawatt power plant at 90% capture efficiency) using a probabilistic model to simulate the temporal-spatial distribution of subsurface CO2 plumes in several brine-filled sandstones in Pennsylvania and Ohio. For comparison, the Frio Sandstone in the Texas Gulf Coast and the Mt. Simon Sandstone in Illinois were also analyzed. The predicted CO2 plume distributions have a median range of 3,700 km2 to 9,600 km2 for the Ohio and Pennsylvania sandstones compared to 320 km2 and 300 km2 for the thicker Frio and Mt. Simon Sandstones. We model the cost to use pore space in Pennsylvania and Ohio and, alternatively, the cost of piping CO2 from Pennsylvania and Ohio to the Mt. Simon or Frio Sandstones. The results suggest that pore space acquisition costs could be significant, and that using thin local formations for sequestration may be more expensive than piping CO2 to thicker formations at distant sites.


    CEIC-09-04: "The Air Quality and Human Health Effects of Integrating Utility-Scale Batteries into the New York State Electricity Grid"
    Elisabeth A. Gilmore, Jay Apt, Rahul Walawalkar , Peter J. Adams and Lester B. Lave

    In a restructured electricity market, utility-scale energy storage technologies such as advanced batteries can generate revenue through energy arbitrage by charging when prices are low and discharging when electricity prices are high. This strategy also changes the magnitude and distribution of air quality emissions, ambient concentrations, human health effects and social costs and benefits. We evaluate these effects with a case study of 500 MW sodium-sulfur battery installations with 80% roundtrip efficiency displacing peak electricity generators in New York City from 1 – 5 pm and charging using off-peak generation in the New York Independent System Operator (NYISO) electricity grid from 1 – 6 am during summer. First, we map displaced and charging plant types to generators in the NYISO. Second, we convert the changes in emissions into ambient concentrations with a chemical transport model, the Particulate Matter Comprehensive Air Quality Model with extensions (PMCAMx). Finally, we transform the concentrations into their equivalent human health effects and social benefits and costs. Focusing on the relationship between premature mortality and fine particulate matter (PM2.5), we calculate a benefit of 4.5 ¢/kWh and 17 ¢/kWh from displacing a natural gas and distillate fuel oil fueled peaking plant, respectively, in New York City. By contrast, ozone (O3) concentrations increase due to the decrease in nitrogen oxide (NOx) emissions, although the magnitude of the social cost is less certain. Adding the air quality costs from charging, we find that displacing a distillate fuel oil peaking plant yields a net social benefit, while displacing the natural gas peaking plant has a net social cost. Additionally, by using the present base-load capacity for charging, the upstate population experiences an increase in adverse health effects. If wind generation is utilized to charge the battery, both the upstate charging location and New York City would benefit. The Air Quality and Human Health Effects of Integrating Utility-Scale Batteries into the New York State Electricity Grid.


    CEIC-09-03: "The Economics of Using PHEV Battery Packs for Grid Storage"
    Scott Peterson, Jay Whitacre, and Jay Apt

    We examine the potential economic implications of using vehicle batteries to store grid electricity generated at off-peak hours for off-vehicle use during peak hours. Hourly electricity prices in three U.S. cities were used to arrive at daily profit values, while the economic losses associated with battery degradation were calculated based on data collected from A123 Systems LiFePO4/Graphite cells tested under combined driving and off-vehicle electricity utilization. For a 16 kWh vehicle battery pack, the maximum annual profit with perfect market information and no battery degradation cost ranged from ~$140 to $250 in the three cities. If the measured battery degradation is applied, however, the maximum annual profit (if battery pack replacement costs fall to $5,000 for a 16 kWh battery) decreases to ~$10-$120. It appears unlikely that these profits alone will provide sufficient incentive to the vehicle owner to use the battery pack for electricity storage and later off-vehicle use. We also estimate grid net social welfare benefits from avoiding the construction and use of peaking generators that may accrue to the owner, finding that these are similar in magnitude to the energy arbitrage profit.


    CEIC-09-02: "Lithium-Ion Battery Cell Degradation Resulting from Realistic Vehicle and Vehicle-to-Grid Utilization"
    Scott Peterson, Jay Apt, and Jay Whitacre

    The effects of combined driving and vehicle-to-grid (V2G) usage on the lifetime performance of relevant commercial Li-ion cells were studied. We derived a nominal realistic driving schedule based on aggregating driving survey data and the Urban Dynamometer Driving Schedule, and used a vehicle physics model to create a daily battery duty cycle. Different degrees of continuous discharge were imposed on the cells to mimic afternoon V2G use to displace grid electricity. The loss of battery capacity was quantified as a function of driving days as well as a function of integrated capacity and energy processed by the cells. The cells tested showed promising capacity fade performance: more than 95% of the original cell capacity remains after thousands of driving days worth of use. Statistical analyses indicate that rapid vehicle motive cycling degraded the cells more than slower, V2G galvanostatic cycling. These data are intended to inform an economic model.


    CEIC-09-01: "Large Blackouts in North America: Historical Trends and Policy Implications"
    Paul Hines, Jay Apt, and Sarosh Talukdar

    Using data from the North American Electric Reliability Council (NERC) for 1984-2006, we find several notable trends. We find that the frequency of large blackouts in the United States has not decreased over time, that there is a statistically significant increase in blackout frequency during peak hours of the day and during late summer and mid winter months (although non-storm-related risk is nearly constant through the year) and that there is strong statistical support for the previously observed power-law statistical relationship between blackout size and frequency. We do not find that blackout sizes and blackout durations are significantly correlated. These trends hold even after controlling for increasing demand and population and after eliminating small events, for which the data may be skewed by spotty reporting. Trends in blackout occurrences, such as those observed in the North American data, have important implications for those who make investment and policy decisions in the electricity industry. We provide a number of examples that illustrate how these trends can inform benefit-cost analysis calculations. Also, following procedures used in natural disaster planning we use the observed statistical trends to calculate the size of the 100-year blackout, which for North America is 186,000 MW.

  • 2008

    CEIC-08-05: "Optimizing Transmission from Distant Wind Farms"
    Sompop Pattanariyankool and Lester B. Lave

    We explore the optimal size of the transmission line from distant wind farms, modeling the tradeoff between transmission cost and benefit from delivered wind power. We also examine the benefit of connecting a second wind farm, requiring additional transmission, in order to increase output smoothness. Since a wind farm has a low capacity factor, the transmission line would not be heavily loaded, on average; depending on the time profile of generation, for wind farms with capacity factor of 29-34%, profit is maximized for a line that is about ¾ of the nameplate capacity of the wind farm. Although wind generation is inexpensive at a good site, transmitting wind power over 1,000 miles (about the distance from Wyoming to Los Angeles) doubles the delivered cost of power. As the price for power rises, the optimal capacity of transmission increases. Connecting wind farms lowers delivered cost when the wind farms are close, despite the high correlation of output over time. Imposing a penalty for failing to deliver minimum contracted supply leads to connecting more distant wind farms.


    CEIC-08-04: "The Spectrum of Power from Utility-Scale Wind Farms and Solar Photovoltaic Arrays"
    Jay Apt and Aimee Curtright

    The power spectral density of the output of utility-scale wind farms and solar photovoltaic (PV) arrays is examined to provide information on the character of fluctuations in real power output; the power spectrum constrains the character of fill-in power. Both one second and one hour samples from several wind farms and ten second and one minute resolution data from four solar PV arrays are analyzed. The measured output power for wind follows a Kolmogorov spectrum over more than four orders of magnitude, from 30 seconds to 2.6 days. That for PV is significantly flatter; thus fluctuations at short time scales are larger relative to those at long time scales for PV than for wind. While wind’s capacity factor varies from 32% at the sites examined to 40% at excellent sites, the capacity factor for a 4.6 MW PV array in Arizona is determined to be 19% over two years.


    CEIC-08-03: "Electricity Prices and Costs Under Regulation and Restructuring"
    Seth Blumsack, Lester B. Lave, and Jay Apt

    Restructuring of the electricity industry was expected to improve the operating efficiency of electric power generators, leading to lower production costs and retail prices. Most studies conclude that there have been some efficiency gains, but the subject of whether retail prices have fallen has been contentious. The existing literature has a number of shortcomings, including the use of blunt or inappropriate definitions of restructuring, failure to incorporate the effects of regulatory decisions regarding price caps and stranded cost recovery, and the use of highly aggregated data. Our study addresses many of these problems and thus represents a significant improvement on existing work. We use a detailed firm-level data set to estimate how the markets and institutions established as a part of “restructuring” have affected the difference between prices and costs. Based on a number of different definitions, we find that utilities that have undergone restructuring display significantly higher price-cost markups than utilities that remained traditionally regulated. We find that some elements of restructuring are associated with higher price-cost margins, while others appear to be uncorrelated with prices and costs. The combination of introducing retail competition into an electric utility’s operating territory and divestiture of that utility’s generating assets has increased costs, but has increased prices even more. In particular, we find an average difference of 2 to 3 cents per kWh between prices and costs that is explained by restructuring rather than by increases in fuel prices. We conclude that restructuring has been beneficial to companies that restructured, but the evidence is far less clear concerning benefits to consumers.


    CEIC-08-02: "Short Run Effects of a Price on Carbon Dioxide Emissions from U.S. Electric Generators"
    Adam Newcomer, Seth A. Blumsack, Jay Apt, Lester B. Lave, and M. Granger Morgan

    The price of delivered electricity will rise if generators have to pay for carbon dioxide emissions through an implicit or explicit mechanism. There are two main effects that a substantial price on CO2 emissions would have in the short run (before the generation fleet changes significantly). First, consumers would react to increased price by buying less, described by their price elasticity of demand. Second, a price on CO2 emissions would change the order in which existing generators are economically dispatched, depending on their carbon dioxide emissions and marginal fuel prices. Both the price increase and dispatch changes depend on the mix of generation technologies and fuels in the region available for dispatch, although the consumer response to higher prices is the dominant effect. We estimate that the instantaneous imposition of a price of $35 per metric ton on CO2 emissions would lead to a 10% reduction in CO2 emissions in PJM and MISO at a price elasticity of -0.1. Reductions in ERCOT would be about one-third as large. Thus, a price on CO2 emissions that has been shown in earlier work to stimulate investment in new generation technology also provides significant CO2 reductions before new technology is deployed at large scale.


    CEIC-08-01: "Trends in the History of Large Blackouts in the United States"
    Paul Hines, Jay Apt and Sarosh Talukdar

    Despite efforts to mitigate blackout risk, the data available from the North American Electric Reliability Council (NERC) for 1984-2006 indicate that the frequency of large blackouts in the United States is not decreasing. This paper describes the data and methods used to come to this conclusion and several other patterns that appear in the data. These patterns have important implications for those who make investment and policy decisions in the electricity industry. Several example calculations show how these patterns can significantly affect the decision-making process.

  • 2007

    CEIC-07-15: "Measuring the Benefits and Costs of Regional Electric Grid Integration"
    Seth Blumsack

    Ten years have passed since the process of electricity restructuring got underway in the United States. Whether the experiment has been successful is a highly controversial and hotly-debated subject, as are the next steps that policymakers should take. If restructuring and RTOs have been successful, then perhaps other regions should take the lead of PJM and the Northeastern United States. If restructuring has not been a success, then policymakers face a series of painful choices about whether further reforms should be enacted, or whether the entire system should be dismantled.

    Successful design artifacts can only arise out of a good problem formulation. That is, the goals of the artifact must be precisely enumerated, a set of performance metrics must be defined, and most importantly, there must be a good verification process for ensuring that the artifact meets the specified goals. If electricity restructuring in the United States fails, it is not because of Enron or any other group of stakeholders, but rather because the markets and institutions emerged from a poor formulation of the problem that restructuring was supposed to solve. California’s doomed market was designed without sufficient input from experienced engineers; by default this yielded an incomplete set of performance metrics and a verification process somewhere between terrible and nonexistent. The current controversy over regional integration in markets and electric grids stems from a lack of clarity regarding the policy goals underlying restructuring. Whether lower prices for consumers, open access to transmission, or the promotion of markets itself is the ultimate goal is far from clear. Just as problematic as the lack of well-defined policy goals is the lack of well-defined metrics for verifying whether the policy goals have been met. Good metrics are objective, thorough, consensual, and are reflected in policy decisions.


    CEIC-07-14: "Do RTOs Promote Renewables? A Study of State-Level Data over Time"
    Kathleen Spees and Lester Lave

    We examine data for the 48 contiguous states from calendar years 1990 to
    2005 to explore whether a state's membership in an organized wholesale market promotes the development of renewable electricity generation. Since states in regional transmission organizations (RTOs) generate most of the renewable electricity, some have asserted this is a benefit of RTOs. We find that, in contrast to wind, much of the development of geothermal, wood, and waste biomass took place prior to states joining RTOs. The development of solar and geothermal is concentrated in only a few states, preventing a firm conclusion about the role of RTOs. Our statistical analysis of wind, wood, and waste estimated a structural model of renewables development using feasible generalized least squares to correct for autocorrelation and heteroscedasticity. The estimated coefficients have the hypothesized signs except for the negative, statistically significant coefficient for membership in an RTO, implying that membership in an RTO impedes the development of the wind resource. The regressions for wood and waste biomass do not show a significant coefficient with RTO membership. We explored a wide range of plausible specifications for the relationship between renewables, membership in an RTO, and other factors, finding little indication that RTOs promote renewables. We cannot explain the indication that RTOs are negatively correlated with the development of wind.


    CEIC-07-13: "Analyzing PJM's Economic Demand Response Program"
    Rahul Walawalkar, Seth Blumsack, Jay Apt, and Stephen Fernands

    We analyze the economic welfare properties of the economic demand response program in the PJM electricity market. The program provides a number of subsidies and side payments to customers who agree to reduce load in a given hour. The program features a price level or "trigger point," currently set at $75/MWh, at or beyond which incentive payments for load reduction are made available. No incentives are available when market prices are below the trigger point. Particularly during peak hours, the program does save money for the system, but the subsidies involved introduce distortions into the market. We simulate demand-side bidding into the PJM market during 2006, and compare the social welfare gains with the subsidies paid to price-responsive load. We find that the largest economic effect comes from large wealth transfers from generators to non price-responsive loads. Based on the current incentive payment structure, we estimate that the social welfare gains exceed the distortions introduced by the subsidies. Lowering the "trigger point" increases the transfer from generators to loads, but may result in the subsidy outweighing the social welfare gains due to load curtailment.


    CEIC-07-12: "The Spectrum of Power from Utility-Scale Wind Farms and Solar Photovoltaic Arrays"
    Jay Apt and Aimee Curtright

    The power spectral density of the output of utilityscale wind farms and solar photovoltaic (PV) arrays is examined to provide information on the character of fluctuations in real power output; the power spectrum constrains the character of fill-in power. Both one second and one hour samples from several wind farms and ten second and one minute resolution data from four solar PV arrays are analyzed. The measured output power for wind follows a Kolmogorov spectrum over more than four orders of magnitude, from 30 seconds to 2.6 days. That for PV is significantly flatter; thus fluctuations at short time scales are larger relative to those at long time scales for PV than for wind. While wind’s capacity factor varies from 32 % at the sites examined to 40% at excellent sites, the capacity factor for a 4.6 MW PV array in Arizona is determined to be 19% over two years.


    CEIC-07-11: "Implications of Generator Siting for CO2 Pipeline Infrastructure"
    Adam Newcomer and Jay Apt

    The location of a new electric power generation system with carbon capture and sequestration (CCS) affects the profitability of the facility and determines the amount of infrastructure required to connect the plant to the larger world. Using a probabilistic analysis, we examine where a profit maximizing independent power producer would locate a new generator with carbon capture in relation to a fuel source, electric load, and carbon sequestration site. Based on models of costs for transmission lines, CO2 pipelines, and fuel transportation, we find that it is always preferable to locate a CCS power facility nearest the electric load, reducing the losses and costs of bulk electricity transmission. This result suggests that a power system with significant amounts of CCS requires a very large CO2 pipeline infrastructure.


    CEIC-07-10: "Storing Syngas Lowers the Carbon Price for Profitable Coal Gasification"
    Adam Newcomer and Jay Apt

    Integrated gasification combined cycle (IGCC) electric power generation systems with carbon capture and sequestration have desirable environmental qualities, but are not profitable when the carbon dioxide price is less than approximately $50 per metric ton. We examine whether an IGCC facility that operates its gasifier continuously but stores the syngas and produces electricity only when daily prices are high may be profitable at significantly lower CO2 prices. Using a probabilistic analysis, we have calculated the plant-level return on investment (ROI) and the value of syngas storage for IGCC facilities located in the US Midwest using a range of storage configurations. Adding a second turbine to use the stored syngas to generate electricity at peak hours and implementing 12 hours of above ground high pressure syngas storage significantly increases the ROI and net present value. Storage lowers the carbon price at which IGCC enters the US generation mix by approximately 25%.


    CEIC-07-09: "Measuring the Benefits and Costs of Regional Electric Grid Integration"
    Seth Blumsack

    No abstract available.


    CEIC-07-08: "A Centrality Measure for Electrical Networks"
    Paul Hines and Seth Blumsack

    We derive a measure of “electrical centrality” for AC power networks, which describes the structure of the network as a function of its electrical topology rather than its physical topology. We compare our centrality measure to conventional measures of network structure using the IEEE 300-bus network. We find that when measured electrically, power networks appear to have a scale-free network structure. Thus, unlike previous studies of the structure of power grids, we find that power networks have a number of highly-connected “hub” buses. This result, and the structure of power networks in general, is likely to have important implications for the reliability and security of power networks.


    CEIC-07-07: "Deregulation/Restructuring, Where Should We Go from Here?"
    Lester Lave, Jay Apt, and Seth Blumsack

    Electricity market restructuring is widely seen as having failed. Many of the same groups who pressed for deregulation now find themselves seeking re-regulation. But re-regulation will reintroduce the flaws and problems that led people to seek deregulation; in addition, re-regulation will introduce the additional problem of how to value competitive market assets for inclusion in the regulated rate base. We reject calls for re-regulation. Our 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.


    CEIC-07-06: "Should a Coal-fired Power Plant be Replaced or Retrofitted?"
    Dalia Patiño-Echeverri, Benoît Morel, Jay Apt, and Chao Chen

    In a cap-and-trade system, a power plant operator can choose to operate while paying for the necessary emissions allowances, retrofit emissions controls to the plant, or replace the unit with a new plant. Allowance prices are uncertain, as are the timing and stringency of requirements for control of mercury and carbon emissions. We model the evolution of allowance prices for SO2, NOx, Hg, and CO2 using geometric Brownian motion with drift, volatility, and jumps, and use an options-based analysis to find the value of the alternatives. In the absence of a carbon price, only if the owners have a planning horizon longer than 30 years would they replace a conventional coal-fired plant with a high-performance unit like a supercritical plant; otherwise, they would install SO2 and NOx controls on the existing unit. An expectation that the CO2 price will reach $50/tonne in 2020 makes IGCC with carbon capture and sequestration attractive today even for planning horizons as short as 20 years. A carbon price below $40/tonne is unlikely to produce investments in carbon capture for electric power.


    CEIC-07-05: "The Character of Power Output from Utility-Scale Photovoltaic Systems"
    Aimee E. Curtright and Jay Apt

    Power produced by utility-scale solar photovoltaic (PV) systems has fluctuations on both short and long timescales. Power spectral density analysis provides information on the character of these power fluctuations. Examination of the correlation and step size of the power output between several PV sites within a multi-site system allows assessment of geographic diversification for addressing intermittency. Both techniques provide insight into the characteristics of required firm power and / or demand response required to accommodate large-scale PV deployment.


    CEIC-07-04: "For Energy Security and Greenhouse Gas Reductions, Plugin Hybrids a More Sensible Pathway than Coal-to-Liquids Gasoline"
    Paulina Jaramillo and Constantine Samaras

    The House Committee on Energy and Commerce (2007) is considering enacting policies to subsidize the production of transportation fuel from coal-to-liquid projects (CTL). This policy would enhance national security by lowering oil imports, but encouraging plug-in hybrids is a less costly policy that also reduce oil imports and does more to lower greenhouse gas (GHG) emissions. This paper compares GHG emissions of CTL gasoline to the emissions of plug-in hybrid vehicles powered with electricity generated with coal. A life cycle approach is used so that all stages of the life cycle of each fuel, from production to use, are included. This analysis allows us to better identify benefits, or disadvantages, of an energy future that includes coal as a transportation fuel.


    CEIC-07-03: "The Aging Workforce: Electricity Industry Challenges and Solutions"
    Lester B. Lave, Michael Ashworth and Clark Gellings

    Recruiting and training new workers have become essential skills for companies. As senior workers retire, companies must find ways to keep the essential knowledge for running the company from walking out the door.


    CEIC-07-02: "Impacts of Responsive Load in PJM: Load Shifting and Real Time Pricing"
    Kathleen Spees and Lester Lave

    We use a short-term equilibrium model to evaluate the impacts of a demand response in the Pennsylvania-New Jersey-Maryland (PJM) Regional Transmission Organization Territory. The supply model is based on market data. In a load-shifting simulation, we find that half of all possible customer savings can be obtained by shifting only 1.7% of all MWh to another time of day, indicating that small demand-side changes can make a large difference. In a real-time pricing (RTP) scenario, we explore the implications of constant elasticities of demand varying from 0 to -1. Producer surplus impacts are small, varying from a 0.5% loss to a 0.4% gain. Consumer surplus and consumption can increase up to 4.3% and 3.9%, respectively. Large reductions in peak demand can be achieved even with a small amount of responsiveness; at elasticities -0.2 and -1, peak load drops by 10.3% and 16.2% respectively with RTP, which would relieve tens of billions in capacity investments over PJM. The more easily managed time of use pricing (TOU) drops peak load only 2.5% and 3.6% at elasticities -0.2 and -1, respectively. Total surplus increase from a change to TOU pricing is only 27.0-28.5% of the increase from a change to RTP. These results suggest that the largest benefit from RTP comes from reducing peak capacity investments; TOU pricing, while easier to manage, offers only a fraction of these benefits and requires almost the same infrastructure investment as RTP.


    CEIC-07-01: "Demand Response and Electricity Market Efficiency"
    Kathleen Spees and Lester Lave

    Increasing the responsiveness of electricity customers to price is important for three reasons: 1. reducing peak demand lowers costs and allows consumers to stop buying kilowatt-hours when the cost is more than they are willing to pay, 2. load shedding can increase system reliability when there is insufficient supply, as when a large generator or transmission line trips and goes off-line, and 3. load might be able to provide regulation and spinning reserve at lower costs than generation. An automated system would allow customers to react in real time to cut back buying expensive power and to alleviate emergency conditions. Customers of gasoline, natural gas, fresh produce, fresh meat, and many other products face prices that vary with the cost of production; they are not happy when prices rise, but have learned to deal with these situations. We review published studies of demand response and electricity conservation to explore the conceptual issues and the quantitative range of expenses.

  • 2006

    CEIC-06-12: "The Value of Using Coal Gasification as a Long-Term Natural Gas Hedge for Ratepayers"
    David C. Rode and Paul S. Fischbeck

    Natural gas has become a commodity of extraordinary volatility, with a growing share of demand met by imports. Demand growth resulting from the rapid expansion of gas-fired power-generation capacity over the last decade has introduced a substantial element of fuel price risk into basic goods (natural gas and electricity) required by consumers, exacerbating the already-high level of price volatility in natural gas used for heating.

    Because of the highly inelastic nature of both electricity and home-heating demand, volatility in natural gas prices can be a particular burden to residential and commercial consumers. Despite the potentially significant value to be gained from developing a means of limiting price risk for consumers, there are very few alternatives available for long-term hedging of natural gas prices. Coal gasification represents not only a means of obtaining a large long-term supply of natural gas at a reasonable price, but also one of the few alternatives available as a long-term physical hedge for natural gas price volatility. In this paper we determine the value of using coal gasification as a long-term hedge to consumers and discuss the potential value to gas utilities. Although the results presented in this paper can be applied generally, our analysis focuses specifically on the value to Indiana residential and commercial heating consumers of a proposed SNG project in Southwest Indiana.


    CEIC-06-11: "Decomposing Congestion and Reliability"
    Seth Blumsack, Marija Ilić, and Lester B. Lave

    Policy surrounding the North American transmission grid, particularly in the wake of electric-industry restructuring and following the blackout of August, 2003, has treated network congestion and network reliability as if they were separable and independent system attributes. Except for a few special cases, congestion and reliability are not independent, and may not even be separable in any meaningful way. Using the DC power flow model with linear ATC, we provide a method for decomposing a change in network topology into a congestion effect and a reliability effect. We provide analytical expressions describing the topological conditions under which a given network addition or outage will affect congestion and reliability, and prove some sufficiency conditions and some necessary conditions for congestion and reliability to be independent. These include (i) the network is series-parallel; (ii) demand is completely price-inelastic; (iii) all customers value reliability identically; and (iv) the grid operator does not discriminate among customers when forced to physically ration consumption.


    CEIC-06-10: "Modeling the Operation and Maintenance Costs of a Large Scale Tidal Current Turbine Farm"
    Ye Li and H. Keith Florig

    Among the many ocean energy technologies under development, the tidal turbine farm has been proposed as an environmentally friendly ocean energy converter application. Although the technology and capital costs of ocean energy turbines are understood, the economics of operating a gang of turbines as an energy farm has yet to be analyzed. In this paper, a planning, operation and maintenance model for tidal turbine farms is proposed. The system is modeled using life-cycle assessment, incorporating a variety of time-dependent variables. Model components include farm construction and planning, operation strategy, regular maintenance, and emergency maintenance. Preliminary numerical simulation results are shown in a case study for a potential site.


    CEIC-06-09: "A Quantitative Analysis of the Relationship Between Congestion and Reliability in Electric Power Networks"
    Seth Blumsack, Lester B. Lave, and Marija Ilić

    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 118-bus test network. The true relationship between congestion and reliability depends critically on identifying the relevant range of demand for evaluating any network externalities.


    CEIC-06-08: "Topological Elements of Transmission Pricing and Planning"
    Seth Blumsack, Lester B. Lave, and Marija Ilić

    Lagging investment in the North American transmission grid, due in part to ISO/RTO decisions, has increased costs to consumers and eroded system reliability. Regulatory policy distinguishes transmission investments that have primarily economic benefits from those that primarily enhance reliability. Economic investments, which benefit a few generators and customers, are to be handled using market incentives. Reliability investments, which benefit all grid participants, are to remain regulated and the costs spread over all participants. We show that the economic-reliability distinction does not hold and that transmission planning requires an analysis of network topology and demand. One ubiquitous network topology allows investors to profit from harming the network by building lines that cause congestion,. More fundamentally, a clear distinction between reliability and congestion seldom exists; the relationship between the two system attributes depends on the level of demand, as well as network topology. Network investment requires a power flow analysis of current and proposed topology and demand. A subsystem analysis focused on specific beneficiaries neglects the risk-management tradeoffs of congestion and reliability.


    CEIC-06-07: "Planning for Natural Disasters in a Stochastic World"
    Lester B. Lave and Jay Apt

    We examine the risks of natural disasters, such as hurricanes, floods, and earthquakes to find the optimal public reaction, including structures to control the disaster (such as dams and levees) and evacuation. Protection of life should be handled by warning and evacuation leaving property protection to be optimized via benefit-cost analysis. Mandatory insurance can both inform people of the risks and stop them from claiming public funds to compensate them from natural disaster losses. A high level of protective structures is warranted in areas at high risk of natural disasters, but the cost of these structures should be borne locally.


    CEIC-06-06: "Power System Harmonic State Estimation and Observability Analysis via Sparsity Maximization"
    Huaiwei Liao

    Harmonic state estimation (HSE) is used to locate harmonic sources and estimate harmonic distributions in power transmission networks. When only a limited number of harmonic meters are available, existing HSE methods have limited effectiveness due to observability problems. This paper describes a new system-wide harmonic state estimator that can reliably identify harmonic sources using fewer meters than unknown state variables. Note there are only a small number of simultaneous harmonic sources among the suspicious buses.

    We propose the concept of S-Observability by extending observability analysis to general underdetermined estimation when considering the sparsity of state variables. We show the underdetermined HSE can become observable with proper measurement arrangements by applying the sparsity of state variables. We formulate the harmonic state estimation as a constrained sparsity maximization problem based on L1-norm minimization. It can be solved efficiently by an equivalent linear programming. Numerical experiments are conducted in the IEEE 14-bus power system to test the proposed method. The underdetermined system contains nine meters and thirteen suspicious buses. The results show that the proposed sparsity maximization approach can reliably identify harmonic sources when presence of measurement noises, model parameter deviations and small non-zero injections.


    CEIC-06-05: "Learning from Wind: A Framework for Effective Low-carbon Energy Diffusion"
    Constantine T. Samaras

    Over the past twenty-five years, wind power has evolved from an emerging alternative energy source to a commercially viable utility-scale technology that can play a role in a low-carbon future. Wind turbines have matured technically from simple machines constructed with off-the-shelf motor components to carefully optimized advanced power generation systems with a worldwide manufacturer and supplier base. Advancements in wind power occurred through actions in both the engineering and public policy institutional arenas. This research examines the technologies, policies, and inter-industry spillovers that have enabled the exponential growth of installed wind power from 1999 through 2005 and analyzes the relative efficacies of the various policies and actors that comprise the wind innovation system. It provides engineers and policymakers a program management and policy design framework for continued development of wind energy as well as for other emerging low-carbon energy technologies.

    Spillovers from technical domains outside of wind energy are found to have played a critical role in enabling wind to achieve significant levels of penetration into the energy system. This suggests that energy policies designed to leverage spillovers across interdependent industries may be more effective at encouraging low-carbon energy adoption compared with policies tailored toward promoting a specific technology.


    CEIC-06-04: "Economics of Electric Energy Storage for Energy Arbitrage and Regulation in New York"
    Rahul Walawalkar, Jay Apt, Rick Mancini

    Unlike markets for storable commodities, electricity markets depend on the real-time balance of supply and demand. Although much of the present-day grid operates effectively without storage, cost-effective ways of storing electrical energy can help make the grid more efficient and reliable. We investigate the economics of two emerging electric energy storage (EES) technologies: sodium sulfur batteries and flywheel energy storage systems in New York state’s electricity market. The analysis indicates that there is a strong economic case for EES installations in the New York City region for applications such as energy arbitrage, and that significant opportunities exist throughout New York state for regulation services. Benefits from deferral of system upgrades may be important in the decision to deploy EES. Market barriers currently make it difficult for energy-limited EES such as flywheels to receive revenue for voltage regulation. Charging efficiency is more important to the economics of EES in a competitive electricity market than has generally been recognized.  


    CEIC-06-03: "An options theory method to value Electricity Financial Transmission Rights"
    Dalia Patiño-Echeverri and Benoit Morel

    In deregulated electricity markets, members of today’s electricity industry face financial risks that either did not exist or were not so significant in the former days of vertically integrated utilities. One example of these risks is the one associated to transmission congestion costs, which can be hedged with Financial Transmission Rights (FTRs).

    Evidence that in the auction of annual FTRs in PJM, clearing prices included a “risk-premium” that “hedgers” paid to reduce the risk of highly volatile congestion charges, and “insurers” charged for bearing this risk, confirms the idea that hedging comes always at a cost, and motivates the questions of 1) how to find the value of these hedging instruments and 2) how efficient are the markets where these are traded.

    The valuation of hedging instruments like FTRs posses a challenge because traditional methods to value financial derivatives do not directly apply. In this paper we extend the paradigm of options valuation to 1) Present, and apply a formula for the “fair value” of the premium of the FTR based on the probability distribution function of the corresponding Congestion Charges. 2) Argue that in PJM the lack of competition among insurers and the competition among hedgers increases the premium received by the former ones and paid by the others. 3) Argue that in PJM the higher the number of transactions for the same Point-to-point combination, the higher the premium paid by hedgers and received by insurers.


    CEIC-06-02: "Can the U.S. have Reliable Electricity?"
    Jay Apt, Lester B. Lave, M. Granger Morgan

    Nuclear power plant operators have greatly increased reliability over the past two decades. What can the electric power industry as a whole learn from their experience


    CEIC-06-01: "The Spectrum of Power From Wind Turbines"
    Jay Apt

    The power spectral density of the output of wind turbines can provide information on the character of fluctuations in turbine output. Here both one second and one hour samples are used to estimate the power spectrum of several wind farms. The measured output power follows a Kolmogorov spectrum over more than four orders of magnitude, from 30 seconds to 2.6 days. The spectrum constrains the character of fill-in power which must be provided to compensate for wind's fluctuations when wind is deployed at large scale. Installing enough linear ramp rate generation to fill in fast fluctuations with amplitudes of 1% of the maximum fluctuation would oversize the fill-in generation capacity by a factor of two for slower fluctuations. A more efficient solution is feasible.

  • 2005

    CEIC-05-09: "Lessons from the Failure of U.S. Electricity Restructuring"
    Seth A. Blumsack, Jay Apt, and Lester B. Lave

    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.


    CEIC-05-08: "The Regulatory Environment for Interconnected Electric Power Micro-grids: Insights from State Regulatory Officials"
    Douglas E. King

    Targeted use of distributed energy resources (DERs) can have considerable benefit for customer-generators as well as legacy utilities and their customers. The micro-grid concept is an extension of traditional DER applications that in some contexts can yield greater benefits at lower per-unit costs. Despite the expected benefits, micro-grids suffer from underadoption and underinvestment, partly because of an uncertain regulatory environment in which micro-grids are perceived neither as traditional utilities nor conventional DERs. Results from a survey of regulatory officials across the country support this argument. Only 17 of 27 participating states indicated that the installation and operation of a micro-grid is probably or definitely legal, and then only under certain circumstances and subject to varying stipulations. Among those 17 states, only 4 indicated that existing laws for the interconnection and operation of DERs would apply to micro-grid systems. No states have clear guidance for the regulatory oversight of micro-grid systems once they are installed, and most respondents indicated that such oversight would be conducted on a case-by-case basis. This paper discusses the survey and relevant insights, and concludes with a summary of recommendations for regulatory changes that could reduce uncertainty and facilitate micro-grid market development.


    CEIC-05-07: "Controlling Cascading Failures with Cooperative Autonomous Agents"
    Paul Hines and Sarosh Talukdar

    Cascading failures in electricity networks cause blackouts and blackouts often come with severe economic and social consequences. Cascading failures are typically initiated by a set of equipment outages that cause operating constraint violations. These initiating events can be triggered by naturally occurring events, such as a wind storm, or human intervention, such as a terrorist attack. When violations persist in a network they can trigger additional outages which in turn may cause further violations. This paper proposes a method for limiting the social costs of cascading failures by eliminating violations before a dependent outage occurs. This global problem is solved using a new application of distributed model predictive control. Specifically, our method is to create a network of autonomous agents, one at each bus of a power network. The task assigned to each agent is to solve the global control problem with limited communication abilities. Each agent builds a simplified model of the network based on locally available data and solves its local problem using model predictive control and cooperation. Through extensive simulations with IEEE test networks, we find that the autonomous agent design meets its goals with limited communication. Experiments also demonstrate that cooperation among software agents can vastly improve system performance. Finally, we discuss the relevance of this work to some current policy issues.


    CEIC-05-06: "Transmission Line Reliability, Climate Change and Extreme Weather"
    Gibson Peters, Tony DiGioia Jr., P.E.,Chris Hendrickson, and Jay Apt

    Transmission lines in service today in the US have been designed using a multitude of design approaches and structural loading criteria. The principal cause of structural failures is associated with weather events that produce loads that exceed the structural loading design criteria. In some cases, failures have been the result of inadequate design, construction and/or maintenance practices, airplane or vehicle accidents and criminal activities.

    The cost of storm-caused transmission outages is significant, costing utilities and users on the order of $270 million per year and $2.5 billion per year (2003 $’s) respectively. The cost of storm damages may be under-appreciated by utilities and regulators since standard industry reliability indices (SAIDI & SAIFI) omit the costs of large storm related outages.

    Currently available data suggest that the frequency and severity of hurricanes and ice storms will increase in the future. There has been a doubling of Category 4 and 5 Atlantic hurricanes from 1970 to 2004 which is the same time period during which ocean temperatures have increased. If this trend continues, it will have a significant impact on utility and user costs due to structural failures. Studies have shown that increases in CO2 levels in the atmosphere could increase hurricane wind velocities by about 10%, resulting in an increase in wind loading of about 20%.

    Under current policy, there is a lack of financial incentives for transmission line owners to upgrade/uprate, refurbish and/or build new lines. For example transmission line owners in restricted jurisdictions do not incur penalties associated with user costs caused by storm outages.

    Based on the above observations and conclusions, recommendations are made concerning the collection and scope of SAIDI & SAIFI data, the adoption of a Survivability Design Concept, the adoption of transmission line investment incentives and the revision of structural loading design criteria manuals to include survivability design concepts and the impacts of climate change.


    CEIC-05-05: "CO2 Capture from Ambient Air: An Example System"
    Joshuah K. Stolaroff, Greg V. Lowry & David W. Keith

    In order to mitigate climate change, deep reductions in CO2 emissions will be required in the coming decades. Carbon capture and storage will likely play a large role in these reductions. As a compliment to capturing CO2 from point sources, CO2 can be captured from ambient air, offsetting emissions from distributed sources. In this paper, we show that CO2 capture from air is physically and thermodynamically feasible, discuss the various routes available, and explain why NaOH solution is a viable sorbant for largescale capture. An example system using NaOH spray is presented. With experimental data and a variety of numerical techniques, the mass transfer of CO2 to falling drops of NaOH solution is calculated, and an example contacting system developed. The cost and energy requirements of the contacting system are estimated and combined with estimates from industry and other research to estimate the cost of the complete system. We find that the cost of capturing CO2 with the complete system would fall between 240 and 550 $/t-C, and improvements are suggested which could reduce the cost by about 100 $/t-C from the upper bound. Policy implications of this result are discussed.


    CEIC-05-04: "Controlling Cascading Failures with Cooperative Autonomous Agents"
    Paul Hines

    Cascading failures in electricity networks cause blackouts, which often lead to severe economic and social consequences. Cascading failures are typically initiated by a set of equipment outages that cause operating constraint violations. When violations persist in a network they can trigger additional outages which in turn may cause further violations. This paper proposes a method for limiting the social costs of cascading failures by eliminating violations before a dependent outage occurs. This global problem is solved using a new application of distributed model predictive control. Specifically, our method is to create a network of autonomous agents, one at each bus of a power network. The task assigned to each agent is to solve the global control problem with limited communication abilities. Each agent builds a simplified model of the network based on locally available data and solves its local problem using model predictive control and cooperation. Through extensive simulations with IEEE test networks, we find that the autonomous agent design meets its goals with limited communication. Experiments also demonstrate that cooperation among software agents can vastly improve system performance.

    While the principle contribution of this paper is the development of a new method for controlling cascading failures, several aspects of the included results are also relevant to contemporary policy problems. Firstly, this paper demonstrates that it is possible to perform some network control tasks without large-scale centralization. This property could be valuable in the US where centralization of control and regulatory functions has proved politically difficult. Secondly, this paper presents preliminary estimates of the benefits, costs, and risks associated with this technology. With some additional development, the methods will be useful for evaluating and comparing grid control technologies.


    CEIC-05-03: "A Broad Assessment of Manure to Power Technology and Investigation of a Potential Wind-biogas Synergy"
    Kyle Meisterling

    The purpose of this paper is to present a broad assessment of animal manure to power technologies, and to investigate the possibility that manure to power could be coupled with a wind generator on-farm to produce more dispatchable power than with either technology alone. Flexible engineering and economic models are developed to determine the amount of energy available from manure; to characterize operation of anaerobic digesters; and to model a farm-level generating system which includes a wind turbine, digester, and methane storage. Maximum electrical generating capacity from manure in the U.S. is approximately 5.4 GW, with 2.7 GW coming from manure handled as solids (incineration or gasification), and 2.7 GW from anaerobic digestion of liquid manure. The cost of electricity from anaerobic digestion is approximately $ 0.06 / kWh for a farm with 700 dairy cows. Methane emissions from agriculture account for 7% of anthropogenic methane emissions in the U.S. Therefore, greenhouse gas reductions from anaerobic digestion, due to avoided methane emissions from manure storage, are substantial on a per kWh basis. A model of a digester system coupled with wind generation is presented, and a case study is carried out for a representative hog farm in NW Iowa. Compared to the stand-alone digester system, the coupled system provides 65% more baseload power in summer, and 170% more during spring. The cost of this electricity is approximately $0.075 / kWh. This cost is comparable to a stand-alone digester system operated as a peaking unit operated 12 hours per day.


    CEIC-05-02: "A Technical and Economic Assessment of Transport and Storage of CO2 in Deep Saline Aquifers for Power Plant Greenhouse Gas Control"
    Sean McCoy

    Global efforts to reduce greenhouse gas emissions have stimulated considerable interest in carbon capture and sequestration (CCS) as a potential “bridging technology” that can achieve significant CO2 emission reductions while allowing fossil fuels to be used until alternative energy sources are more widely deployed. Electric power plants are among the most attractive sources for CCS since they are point sources that are responsible for 39.3% of all anthropogenic CO2 emissions in the United States. From an engineering standpoint, the most promising sinks for the storage of captured CO2 appear to be geological formations. Options for the storage of CO2 include: producing and depleted oil reservoirs, deep unminable coal seams and, deep saline aquifers. This paper presents engineering and economic models of transport of CO2 by pipeline to the storage site and geological storage in deep saline aquifers. A case study considering storage of CO2 from a 500 MW pulverized coal (PC) power plant in the Wabamun Lake area of Alberta, Canada has shown that the median cost of transport and storage is $1.94 per tonne of CO2 stored ranging from a 5th percentile of $0.78 per tonne to a 95th percentile $14.59 per tonne. The variability of the transport and storage cost is found to be primarily due to the reservoir parameters, transport distance, and plant capacity factor. Based on these results, the cost of transport and storage is a small part of the total cost of CCS, but there will be cases in which the cost of transport and storage are large. The strong dependence of the transport and storage cost on the reservoir parameters implies that cost estimates for transport and storage must take this variability into account, and that policies aimed at encouraging reductions in CO2 emissions in the power sector via CCS must recognize that this option may not be economically viable in all cases.


    CEIC-05-01: "Competition Has Not Lowered US Industrial Electricity Prices"
    Jay Apt

    Previous studies have shown that significant price reductions resulted from deregulation in airlines, trucking, railroads, and natural gas. Retail electricity price data from 1990 through 2003 show no such benefit to industrial customers.

  • 2004

    CEIC-04-09: "Autonomous Agents and Cooperation for the Control of Cascading Failures in Electric Grids"
    Paul Hines, Huaiwei Liao, Dong Jia, and Sarosh Talukdar

    A power system can be thought of as a stochastic hybrid system: a Finite State Machine whose states involve continuous variables with uncertain dynamics. Transitions in this machine correspond to outages of generation and transmission equipment. A cascading failure corresponds to a series of such transitions whose net effect is a blackout. We present evidence that the probability of cascading failures is subject to phase transitions—large and abrupt changes that result from only small changes in system stress. We suggest a network of distributed, autonomous agents to reduce the ill effects of cascading failures. These agents improve their decisions by cooperating (sharing goals and exchanging information with their neighbors). Results from experiments on the IEEE 118 bus test case are included.


    CEIC-04-08: "Phase Transitions in the Probability of Cascading Failures"
    Huaiwei Liao, Jay Apt, Sarosh Talukdar

    A cascading failure can be thought of as an alternating sequence of equipment-outages and threshold crossings. This paper studies the probability of such failures in two simple models of electric power networks. The experimental results display phase transitions--large and abrupt changes in the probability of a cascading failure with only small changes in network stress. We conjecture that such phase transitions also occur in actual power networks. If this conjecture is true, on-line techniques for assessing the risk of cascading failures could be based on searching the neighborhood of the current operating point for the nearest phase transition.


    CEIC-04-07: "Distributed Model Predictive Control for Electric Grids"
    Paul Hines, Dong Jia, and Sarosh Talukdar

    Cascading failures cause blackouts with high social costs. A cascading failure can be thought of as an alternating sequence of equipment outages and constraint violations. We describe a network of fast-acting, autonomous agents for shortening such sequences. The agents work by eliminating violations before they can cause further outages. They make their decisions with DMPC—a distributed adaptation of the Model Predictive Control technique. Each agent has a suite of models, specialized for its location in the grid. It uses these models to predict what the other agents will do and how the grid will respond. Each agent optimizes its decisions with respect to the predictions. In tests on small grids, these prediction-based optima come close to the true, global optima. In other words, the agents seem able to make good decisions. Future work includes extending the tests to larger grids, and augmenting DMPC with cooperation and automatic learning.


    CEIC-04-06: "Are Renewables Portfolio Standards Cost-effective Emission Abatement Policy?"
    Katerina Dobesova, Jay Apt and Lester B. Lave

    Renewables portfolio standards (RPS) could be an important policy instrument for 3P and 4P control. We examine the costs of renewable power, accounting for the federal production tax credit, the market value of a renewable credit, and the value of producing electricity without emissions of SO2, NOx, mercury, and CO2. We focus on Texas, which has a large RPS and is the largest electricity producer and one of the largest emitters of pollutants and CO2. We estimate the private and social costs of wind generation in an RPS compared with the current cost of fossil generation, accounting for the pollution and CO2 emissions. We find that society paid about 5.7 ¢/kWh more for wind power, counting the additional generation, transmission, intermittency and other costs. The higher cost includes credits amounting to 1.1 ¢/kWh in reduced SO2, NOx, and Hg emissions. These pollution reductions and lower CO2 emissions could be attained at about the same cost using pulverized coal (PC) or natural gas combined cycle (NGCC) plants with carbon capture and sequestration (CCS); the reductions could be obtained more cheaply with an integrated coal gasification combined cycle (IGCC) plant with CCS.


    CEIC-04-05: "Clean Air and Affordable Electricity?"
    Dalia Patiño-Echeverri, Zhiyong Wu and Marija Ilic

    Performance criteria of the power industry such as environmental impact, electricity prices, and quality/reliability of the service are functions of fuel market, government regulations, the state of the art of technology, and the combined actions of different industry participants. We argue that to prescribe optimal government interventions, it is imperative to understand as much as possible about the dynamics of the interaction between industry participants, as well as the interactions with fuel and technology markets. In this paper we propose a model that relates air emissions and electricity prices with government policies regarding allocation of emissions allowances, fines, subsidies and investments in R&D. We present results of the simulation of a simplified model.


    CEIC-04-04: "Comparative Assessments of Fossil Fuel Power Plants With C02 Capture and Storage"
    Edward S. Rubin, Anand B. Rao and Chao Chen

    Studies of CO2 capture and storage (CCS) costs necessarily employ a host of technical and economic assumptions regarding the particular technology or system of interest, including details regarding the capture technology design, the power plant or gas stream treated, and the methods of CO2 transport and storage. Because the specific assumptions employed can dramatically affect the results of an analysis, published studies are often of limited value to researchers, analysts and industry personnel seeking results for alternative assumptions or plant characteristics. In the present paper, we use a generalized modeling tool to estimate and compare the emissions, efficiency, resource requirements and costs of PC, IGCC and NGCC power plants on a systematic basis. This plant-level analysis explores a broader range of key assumptions than found in recent studies we reviewed. In particular, the effects on cost comparisons of higher natural gas prices and differential plant utilization rates are highlighted, along with implications of financing and operating assumptions for IGCC plants. The impacts of CCS energy requirements on plant-level resource requirements and multi-media emissions also are quantified. While some CCS technologies offer ancillary benefits via the co-capture of certain criteria air pollutants, the increases in specific fuel consumption, reagent use, solid wastes and other air pollutants associated with current CCS systems are found to be significant. To properly characterize such impacts, an alternative definition of the "energy penalty" is proposed in lieu of the prevailing use of this term.


    CEIC-04-03: "Rethinking Electricity Deregulation"
    Lester B. Lave, Jay Apt, and Seth Blumsack

    Proponents of free markets for electricity assert that minor fixes to the California market and to FERC’s standard market design (SMD) would generate lower prices. We disagree. Designing a competitive market that remedies the problems seen in California and other restructured markets is difficult; emulating even good ISOs like PJM will not do the job. Each one of the problems can be overcome, but the costs of doing so might make full deregulation unattractive.


    CEIC-04-02: "Consumer Strategies for Controlling Electric Water Heaters under Dynamic Pricing"
    Chong Hock K. Goh and Jay Apt

    Electricity used to heat water represents 9% of residential demand in the USA and can be 40% in other countries. Hourly residential use of hot water is often anti-coincident with the peak generation of electricity, presenting an opportunity for reducing consumer costs under dynamic pricing during the afternoon generation peak. We have examined the effects of three strategies on customer costs under dynamic pricing: timed power interruption (long used by certain utilities), a price-sensitive thermostat, and a double period setback timer. Systems which lower the water temperature set points are as economical as power interruption systems, and result in higher minimum water temperature. Our model predicts that a setback thermostat will keep the tank water warmer than a load interruption timer with very similar electricity use. The setback thermostat and the more complex price-sensitive thermostat achieve similar water temperatures and consumer savings.


    CEIC-04-01: "Electrical Blackouts: Repeating our Mistakes"
    Jay Apt, Lester B. Lave, Sarosh Talukdar, M. Granger Morgan, and Marija Ilic

    The causes of blackouts run much deeper than individual errors, and the air traffic control system provides a model for a better way to operate the power grid.

  • 2003

    CEIC-03-18: "A Current Study of Automatic Meter Reading Solutions via Power Line Communications"
    Chong Hock K Goh

    It is more expensive to generate electricity during peak hours, yet consumers are not paying the more expensive rate for peak-hour electricity. It will be more economically efficient if consumers pay varying prices, depending on when they use electricity, instead of the current system where an average price rate is used. Hence we need to send real-time pricing to consumers. We look at current Automatic Meter Reading (AMR) solutions via Power Line Communications (PLC). If current AMR technology allows meter readings to be sent via power lines quickly and cheaply, then sending real-time pricing via power lines is feasible. In this study, we consider 3 companies that provide AMR solutions to existing customers, and make a comparison of their AMR technologies.


    CEIC-03-17: "Guidance for Drafting State Legislation to Facilitate the Growth of Independent Electric Power Micro-Grids"
    Douglas King and M. Granger Morgan

    A variety of small-scale electric generation technologies are now available. Many of these can operate as combined heat and electric power (CHP) systems that achieve much higher overall end-use energy efficiencies than conventional systems. In addition, solid state power electronics and advanced computer control technology make it possible to condition and control the local use of electric power, and interconnections to the distribution system, in ways that had previously not been possible.

    We believe that new legislation that would permit the development of independent micro-grids should be passed in states where such systems are not now allowed, or where present laws and regulation discourage their development. It is our belief that such enabling legislation could unleash a wave of technological and business innovations similar to what occurred in telecommunications after the 1968 Carterphone Decision allowed customers to attach non-Bell devices such as phones, answering machines, fax machines, and modems to the public telephone system.


    CEIC-03-16: "Market Dynamics Driven by the Decision-making of Both Power Producers and Transmission Owners"
    Anna Minoia, Damien Ernst, and Marija Ilic

    In this paper we consider an electricity market in which not only the power producers but also the transmission owners can submit a bid. The market is cleared at each stage by minimizing the sum of the production prices and the transmission prices. A model of the strategic behavior is formulated for the different agents of the system. This strategic behavior modelling leads to a market dynamics that can be used to determine the different payoffs of the agents over a temporal horizon. Simulations are carried out for several configurations of this two node power system. The influence of the transfer capacity and the market structure on the payoffs of the different agents is discussed.  


    CEIC-03-15: "Market Dynamics Driven by the Decision-making Power Producers"
    Damien Ernst, Anna Minoia, and Marija Ilic

    In this paper we consider a tool for analyzing the market outcomes when a set of competitive agents (power producers) interact through the market place. The market clearing mechanism is based on the location marginal price scheme. A model of the strategic behavior is formulated for the agents. Each one chooses its bid in order to maximize its profit by assuming that the other agents will post the same bid as at the previous clearing of the market, and by knowing the network characteristics. The income of each agent over a certain temporal horizon for different power system configurations (the addition of new transmission capabilities, new power plants) is evaluated by assuming a market dynamics and by integrating this dynamics over the chosen temporal horizon. The mathematical formulation, for the sake of simplicity, is related to a two node power system. In the simulations, the influence of different conditions (line transfer capacity, the number and size of generators, the presence of portfolio) on market outcomes is analyzed, and interesting and sometimes counter-intuitive results are found.


    CEIC-03-14: "Maintaining Stability with Distributed Generation in a Restructured Industry"
    Judith Cardell and Marija Ilic

    A set of reduced order, linearized, dynamic models for distributed generators is developed along with a framework for modeling the generators in a power distribution system. Analysis of this distributed system structure raises two issues. The first is that the simulations demonstrate, unexpectedly, that a small load disturbance is capable of causing frequency instability in the primary dynamics of the distributed generators. Eigenanalysis of the instability suggests that it is a system phenomenon. The second issue is that the system matrix is found to not have a block diagonal dominant structure raisi ng questions over the possible implementation of decentralized control strategies. A method to regain system stability along with an example of implementing this method are presented, along with the generator models.


    CEIC-03-13: "Temporal Hotspots in Emission Trading Programs: Evidence From The Ozone Transport Commission’s NOX Budget"
    Alexander E. Farrell

    The use of Market Mechanisms and Incentives (MM&I) for environmental protection has increased over the last several years, and proposals for new MM&I policies are increasing. Notable (perhaps even principal) among these proposals are cap-and-trade (C/T) systems, which as the name implies, create a permanent limit on total emissions yet provide firms with flexibility in compliance. Several concerns have been raised about the environmental and economic outcomes of C/T systems, in particular about the potential for “hot spots” and about the viability of markets in emission allowances. Environmentalists are concerned that C/T systems may allow for localized pollution problems while industry is concerned that there be a large, stable enough market in allowances so that they can count on being able to buy or sell allowances at reasonable and predictable prices (Dudek and Goffman 1992; Solomon and Rose 1992; Campbell and Holmes 1993; Chinn 1999). The results so far have been mixed on both counts, some emission trading programs have had problems with hot spots and environmental justice issues and others have not (Drury 1999; Swift 2001). Similarly, some emission allowance markets have been successful and others have not (Foster and Hahn 1995; Carlson et al. 2000; Israels et al. 2002).

    This paper examines several key aspects of an early multi-state C/T system designed to control oxides of nitrogen (NOX) in nine Northeastern States, the Ozone Transport Commission’s (OTC) NOX Budget. Several earlier papers have examined the political economy of the OTC NOX Budget (Farrell 2001; Farrell and Morgan 2003). Electricity generating plants, including co-generators, dominate regulated facilities in the OTC NOX Budget (representing more than 90% of seasonal NOX emissions) and will have a key role in the upcoming NOX SIP Call, so this paper focuses on the electric power sector (U.S. Environmental Protection Agency 1998).


    CEIC-03-12: "Cascading Failures: Survival vs. Prevention"
    Sarosh N. Talukdar, Jay Apt, Marija Ilic, Lester B. Lave, and M. Granger Morgan

    Measures can be taken to reduce the number of large-scale power losses due to failures of the generation and high voltage transmission grid such as the August 14, 2003 blackout. However, such failures cannot be eliminated. The survival of essential missions is a more tractable problem than the prevention of all large cascading failures, and its solutions are verifiable. We propose that serious attention be directed towards assuring the continuation of essential missions even after the grid has failed. We outline a program to lower the social costs of power failures through successful preservation of those essential missions.


    CEIC-03-11: "Electric Gridlock: A National Solution"
    Jay Apt and Lester B. Lave

    Preventing future blackouts requires increasing the capacity and reliability of the transmission grid. This can be accomplished by building more lines as well as by increasing the capacity and controllability of existing lines, both requiring billions of dollars of investment. New technology, from Flexible AC Transmission System (FACTS) to improved data acquisition and control (SCADA) systems would do much to increase the operational capacity and reliability of existing lines. R&D promises still larger advances in the future, such as SMES (Superconducting magnetic energy storage), FCL (Fault-current limiter), and HTS (High-temperature superconductor) cable.

    During and immediately after the blackout, political leaders stated that the blackout was unacceptable and should never happen again. This is political rhetoric that is unlikely to produce substantial government appropriations or approval of price hikes to pay for the investments. We propose a more realistic goal: The amount of loss and inconvenience from cascading failures should be no greater, averaged over a decade or so, than the loss and inconvenience due to natural hazards such as ice storms.

    Present systems for paying transmission operators do not provide both proper incentives for new investment at the same time that they discourage use of the congested segments of the grid. We propose a two-part tariff. This two-part tariff would both encourage customers and generators to locate in places with low LMP, and would give investors in new transmission lines the incentive to build needed capacity.


    CEIC 03-10: "Introducing Electric Power into a Multi-Disciplinary Curriculum for Network Industries"
    Marija Ilic, Jay Apt, Pradeep Khosla, Lester Lave, Granger Morgan, Sarosh Talukdar

    A qualitatively different graduate level curriculum for teaching electric power systems is needed. The motivation for such a new curriculum is outlined, and a specific program, now being implemented at Carnegie Mellon University, is described. The new curriculum: (1) provides students with a multidisciplinary introduction to the changing problems of the industry; (2) stresses the need for teaching systematic approaches to formulating power system problems; and, (3) integrates teaching of the fundamentals for power systems with the fundamentals for other network industries. The program, referred to as the MS in Electric Power Systems (MSEPS) Program, is being developed as a special power-focused track within Carnegie Mellon's existing multi-disciplinary Information Networking Institute (INI).


    CEIC 03-08: "Risk Analysis and Project Capital Structures"
    David C. Rode, Peter R. Lewis, and Paul S. Fischbeck

    The problems experienced recently in the power generation sector have permeated through from project sponsors to the financial institutions that invested, whether through debt or equity, in power projects. In many cases, insufficient attention to the careful measurement and management of risks exacerbated, if not caused, these problems. Now, as financial institutions and investors face the task of restructuring these troubled assets, it is critically important to prevent history from repeating itself by ensuring that any restructuring activities not only recognize the risks facing power generating assets, but also that those risks are communicated effectively among the various stakeholders. In addition, it is important for all of the stakeholders to understand how the restructuring process itself is influenced by risk and risk-taking behavior. This paper develops a framework for using simulation analysis as a common platform from which to communicate about financing risks and capital structure.


    CEIC 03-07: "Distributed Power Generation: Rural India – A Case Study"
    Anshu Bharadwaj and Rahul Tongia

    In this paper, we present an analysis of a rural distribution network to examine what the benefits of decentralized generation would be for meeting rural loads. We use load flow analysis to simulate the line conditions for actual rural feeders in India, and quantify the loss reduction and system improvement by having decentralized generation available. We also present a framework for valuing ancillary services from the generator, viz., reactive power. This provides a starting point for utilities in developing countries to better plan their systems to meet dispersed loads, while optimizing for renewables and other decentralized generation sources.


    CEIC 03-06: "Transmission Line Siting: A Quantitative Analysis of Transmission Demand and Siting Difficulty"
    Shalini Vajjhala

    Recent events, such as the California energy crisis, have focused national attention on the growing demand for electricity in the United States and the simultaneously lagging development of electricity transmission infrastructure. Although the nation’s transmission grid began as a series of local connections for regional reliability, expanding interconnects and state deregulation have gradually transformed the system into a competitive superhighway for electricity trading. In spite of recent extreme examples of the nation’s ailing grid and the widespread call for new transmission construction, transmission line siting is a difficult and time-consuming process often resulting in construction delays or cancellations of new lines. Problems with individual siting projects have been attributed primarily to public opposition, regulatory inconsistencies, geographic or topographical constraints, and lack of investment incentive; however, most of the information about siting difficulty is anecdotal and project-specific, and there is little comprehensive empirical analysis on the factors affecting transmission line siting.

    This paper develops four unique measures of transmission line siting difficulty and based on these measures, presents a regression model for quantitatively evaluating the factors affecting siting at the state-level. The four measures of the dependent variable, siting difficulty, are 1) an economic measure based on variations in the marginal cost of electricity production, 2) a physical measure of the difference between proposed and actual transmission construction, 3) a geographic measure of the co-location of generation capacity and demand load centers within a state, and 4) a subjective measure from a survey of industry experts’ perceptions. Using these four measures of siting difficulty, this paper also evaluates perceived and actual siting constraints using a series of regression analyses. The results from these measures and analyses parallel documented perceptions of siting constraints and serve as quantitative counterpart to existing anecdotal information on siting. Overall, the framework that this research provides for characterizing siting difficulty and siting constraints has the potential to serve as a tool for communication between siting agencies, foster a common understanding of the siting problem, and address existing issues with inter-agency coordination. In a field dominated by uncertainty and anecdote, this paper provides a guide for characterizing the demand for transmission construction, evaluating specific siting problems, and coordinating siting solutions.


    CEIC 03-05: "A Life Cycle Analysis of Electricity Generation Technologies: Health and Environmental Implications of Alternative Fuels and Technologies"
    Joule Bergerson & Lester Lave

    Increases in electricity demand and the retirement of old generating plants necessitate investment in new generation. Increasingly stringent environmental regulations, together with other regulatory requirements and uncertainty over future fuel prices, complicate the choice of appropriate fuels and technologies. Electricity generation, a major source of CO2, SOx, NOx, and suspended particles, also produces large quantities of solid waste, and contributes to water pollution. To make informed decisions about refurbishing old plants or investing in new ones, companies, concerned citizens, and government officials need good information about the environmental implications of each fuel and generation technology. New issues have surfaced recently, such as discharges of mercury and total greenhouse gas emissions. Since other potential issues loom, (e.g. other heavy metals), an environmental analysis must examine the life cycle of each fuel/technology, from extraction of the materials to disposal of residuals. We review studies examining the life cycle environmental implications of each fuel and technology. We focus on the coal fuel cycle since: (1) it accounts for more than half of the electricity generated in the USA, (2) historically, the coal fuel cycle has been highly damaging to the environment and to health, (3) there are huge coal reserves in the USA, China, and Russia, and (4) the fuel is inexpensive to mine and likely to be used in large quantities in the future. We begin with an examination of the methods of life cycle analysis. We then present a brief historical overview of the research studies. Finally, we review and critique the alternative methods used for life cycle analysis. Our focus is the recent studies of the health and environmental implications of each technology. The studies agree that coal mining, transport, and combustion pose the greatest health and environmental costs. Among fossil fuel fired generators, natural gas power turbines are the most benign technology. Light water nuclear reactors received a great deal of attention in the early literature, but are neglected in recent U.S. studies. The earlier studies found that the health and environmental costs of light water reactors were low, at least for the portions of the fuel cycle that were evaluated. The studies did not evaluate the disposal of spent fuel and so are incomplete. Recent advances in life cycle analysis offer a large improvement over the methods of three decades ago and should help in choosing among fuels and technologies as well as modifying designs and practices to lower the health and environmental costs.


    CEIC 03-04: "Should We Transport Coal, Gas or Electricity: Cost, Efficiency & Environmental"
    Joule Bergerson

    We examine the life cycle costs, environmental discharges, and deaths of moving coal via rail, coal-gas via pipeline, and electricity via wire from the Powder River Basin (PRB) in Wyoming to Texas. Which method has least social cost depends on how much additional investments in rail line, transmission, or pipeline infrastructure are required, as well as the amount of a carbon tax, whether underground sequestration of carbon-dioxide is allowed and works, and the level of transmission losses. All methods generate significant environmental discharges. Transporting 50 million tons of PRB coal by rail to Texas is cheapest since the infrastructure is in place; it requires 130 million gallons of diesel fuel and results in the death of 15 people. Shipping the energy via transmission lines requires additional generation and more mining. Gasifying the coal is somewhat more expensive, but has important environmental advantages compared to a pulverized coal boiler.


    CEIC 03-03: "The Cost of Regulatory Uncertainty in Air Emissions for a Coal-fired Power Plant"
    Dalia Patiño Echeverri

    Uncertainty about the extent and timing of changes in environmental regulations for coal fired power plants makes the difficult problem of selecting a compliance strategy even harder. Capital investments made today under uncertainty can limit future compliance options or make them very expensive. In this paper, we present a method for computing the cost of operating a moderate-sized, coal-fired power plant under different conditions of future regulatory uncertainty. Using a Multi-Period Decision Model (MPDM) that captures the decisions (both capital investment and operating) that a power plant owner must make each year, the framework employs a Stochastic Optimization Model (SOM), nested in the MPDM to find the strategy that minimizes the expected net present value (ENPV) of plant operations over a fixed planning horizon. By comparing model runs under different uncertainty conditions, the cost of regulatory uncertainty can be calculated.


    CEIC 03-02: "A Technical and Economic Assessment of Selexol-based CO2 Capture Technology for IGCC Power Plants"
    Chao Chen

    Increasing CO2 emissions and concerns about potential climate change are arousing great interest in the technical and economic feasibility of capturing CO2 from large energy system, such as coal-based power plants. Performance and cost models of a Selexol-based CO2 absorption system for capturing CO2 from an advanced power system (Integrated Gasification Combined Cycle, IGCC) have been developed and integrated with an existing IGCC modeling framework without CO2 capture. The integrated model has been applied to study the feasibility, cost and uncertainties of carbon capture and sequestration at both greenfield and repowered IGCC plants. The analysis shows that based on commercially available technology, the cost of CO2 avoided for an IGCC power plant is half that for a conventional combustion plant with a chemical absorption process. For IGCC systems, the uncertainty associated with CO2 transport and storage has the largest impact on the cost of CO2 avoided. Under suitable conditions, IGCC repowering was shown to be an attractive option for reducing CO2 emissions from existing coal-fired plants. Compared to building greenfield IGCC plants, IGCC repowering also provides an option for introducing new power generation technology with lower risk to utilities.


    CEIC 03-01: "Fossil Electricity and CO2 Sequestration: How Natural Gas Prices, Initial Conditions and Retrofits Determine the Cost of Controlling CO2 Emissions"
    Timothy L. Johnson, David W. Keith

    Stabilization of atmospheric greenhouse gas concentrations will require significant cuts in electric sector carbon dioxide (CO2) emissions. The ability to capture and sequester CO2 in a manner compatible with today’s fossil-fuel based power generation infrastructure offers a potentially low-cost contribution to a larger climate change mitigation strategy. The extent to which carbon capture and sequestration (CCS) technologies might lower the cost of CO2 control in competitive electric markets will depend on how they displace existing generating units in a system’s dispatch order, as well as on their competitiveness with abatement alternatives. This paper assumes a perspective intermediate to the more common macro-economic or plant-level analyses of CCS and employs an electric system dispatch model to examine how natural gas prices, sunk capital, and the availability of coal plant retrofits affect CCS economics. Despite conservative assumptions about cost, CCS units are seen to provide significant reductions in base-load CO2 emissions at a carbon price below 100 $/tC. In addition, the availability to retrofit coal plants for post-combustion CO2 capture is not seen to lower the overall cost of CO2 abatement.

  • 2002

    CEIC 02-09: “Is the Answer to Climate Change Blowing In the Wind?”
    Joseph DeCarolis, David W. Keith

    The use of fossil fuels to produce electricity generates significant environmental impacts, and has led to an intense interest in a cleaner and more affordable electricity supply. Electricity from wind power provides an alternative to conventional generation that can yield significant reductions in carbon dioxide emissions and fossil fuel use. Discussions of large-scale wind must address the problems posed by the spatial distribution and intermittency of the wind resource. The greenfield analysis presented in this paper provides a first-order economic characterization of wind in a baseload system in which long-distance electricity transmission, storage, and backup gas capacity are used to supplement the variable wind power output to meet a fixed load. The utilization of wind to help meet a fixed load simplifies the analysis and provides a useful proxy for a model that incorporates the complex supply and demand dynamics that characterize electricity markets. The results of this preliminary model indicate that baseload wind is capable of effecting deep cuts in carbon emissions at a cost competitive with other zero emissions energy technologies such as nuclear or coal with carbon capture.

    For a copy of this paper please contact David Keith


    CEIC 02-08: “A Power Quality Study of Carnegie Mellon University”
    Yinglan Tan

    Carnegie Mellon University is a highly digitized university that has advanced research laboratories and sophisticated research and development operations. It is therefore useful to determine the nature and magnitude of power outages that a premier research institution like Carnegie Mellon faces, and the causes of these outages to mitigate future losses. Another objective of this study is to calibrate survey-based studies. The study advances the literature on existing survey-based studies and find that the perceptions of administrators pertaining to power quality losses are overstated. Based on power quality measurements, we affirm the hypothesis that Carnegie Mellon has a relatively stable power system with no serious disability. However, we find that costs of power outages pertaining to staff, students and faculty in certain departments to be significantly high and propose a set of remedial recommendations. The study also provide a range estimate of $5 million to $15 million for the total annual losses accruing to Carnegie Mellon.


    CEIC 02-07: "The Regulatory Environment for Small Independent Micro-grid Companies"
    M. Granger Morgan and Hisham Zerriffi

    New technology, including low cost solid-state electronic sensors, control systems and power electronics, as well as cost-effective distributed co-generation technology, holds the potential to open new commercial opportunities for micro-grids that would operate on a small-scale underneath traditional regulated distribution utilities. What is the regulatory environment that would be faced by non-utility parties that might wish to develop and run small micro-grids that contain distributed generation? In the spring of 2002, this question was explored with a survey administered to eight current and former state utility regulators who serve on the EPRI Advisory Board. The survey outlined several different business models under which a small micro-grid might be operated, and asked similar questions in each case. The results show that small commercial micro-grids with distributed generation in an unregulated competitive environment underneath traditional distribution systems, face large regulatory barriers in much of the U.S. today. Micro-grids operated as co-ops appear to face similar, though somewhat smaller, barriers.


    CEIC 02-06: "The Model of Pivotal Oligopoly Applied to Electricity"
    Markets” Dimitri Perekhodstev, Lester B. Lave, Seth Blumsack

    Electricity industry is featured by the exceptionally inelastic demand, which has to be met by all means. Not meeting the demand may result in the power going down for all customers, the consequences of which are very costly. This feature leaves the participants of the electricity market much more room to manipulate the market and exercise the market power than in any other market. Inelastic demand is the reason why the usual measures of market concentration do not predict the possible market behavior in the electricity markets. Some new methods to assess the potential market power have been applied. They use the intuitive idea that the electricity market is concentrated and the risk of market power is very high whenever the largest supplier in the area owns the capacity, which is more than the supply margin during the peak hours. We provide theoretic justification for using the market concentration indices based on the supply margin. We developed the game-theoretic model of the uniform price auction with the capacity constrained generators. It gives the idea on the expected market price at different levels of demand. In particular, the model predicts that the expected market-clearing price depends on the minimum number of firms that need to act in concert to drive the price up. The significant market power can be exercised even when the supply margin is about the capacity of four to five largest generators. We propose to use the index of market concentration based on the minimum number of firms that may constitute the pivotal group at the given demand level.


    CEIC 02-05: "Electricity and Conflict: Advantages Of A Distributed System"
    Hisham Zerriffi, Hadi Dowlatabadi, and Alex Farrell

    In times of war, attacking infrastructure is a common military tactic – and electric power systems are obvious targets. Moreover, the rise of organized and systematic global terrorism has demonstrated that an attack on an electricity system is an issue for all countries, not just those undergoing conflict or at war. This paper details a quantitative comparison of the reliability of an electricity system based on distributed natural-gas fired units to a traditional system based on large centralized plants. The model shows that the distributed system can be significantly more reliable under stress. The cost of electricity for the centralized and distributed systems was calculated. The cost calculation includes a heat credit for cogeneration in the distributed case and the social costs due to reliability degradation. Even without considering the benefits of robustness under conflict conditions, a DG can result in cost savings of up to 16% with moderate cogeneration. Under the conflict conditions considered, the cost of electricity can be up to 50% lower with a DG system as compared to a centralized system. These savings increase if more cogeneration is used. These findings suggest that distributed systems can provide electricity more reliably and at a cost savings both under normal operating conditions and under conditions of stress, such as in a conflict area.

    For a copy of this paper please contact Hisham Zerriffi


    CEIC 02-04: "Emissions From Distributed Generation"
    Neil D. Strachan and Alex Farrell

    This study takes a new approach to evaluating emissions from DG-CHP applications, by calculating emissions for the total energy supply system including both heat and power and comparing various DG-based and central station-based systems systematically across a range of HPR values. The overall approach is to first characterize typical DG technologies and applications in use as baseload DG today or likely to be used in the future. Then, a simulation model is developed and parameterized so that costs and emissions can be determined. The sensitivity of the results to greater levels of emission controls is also examined. Economic and policy implications are considered.


    CEIC-02-03: "Modeling the Potential Savings of an Air Conditioner Reset Demand Response Program"
    Peter van der Heijden

    This report discusses the results of a model that simulates Allegheny Power's Electricity Price Response Pilot Program. This demand response program increases the setting on the thermostat of residential customer’s air conditioners when the wholesale market price reaches a certain minimum value. This way the program reduces the electricity demand for that period. The model is written in Visual Basic 6.0 and makes use of Excel to import historical data from and export output into.

    The simulations showed that the program reduces the fluctuation in a customer’s bills for the period that the program is active. Whether this is true for the entire year depends on whether the customer’s demand is heating dominated or cooling dominated. Results also show that though the program is successful from a reduction of peak demand point of view this currently is not the case for the utility: the economical success depends on the overhead costs associated with the installation and operation of the hourly demand meter. With advancements in the technology and economies of scale these costs should go down and the program should become economically feasible.


    CEIC-02-02: "Residual Risk and the Valuation of Leases under Uncertainty and Limited Information"
    David C. Rode, Paul S. Fischbeck, and Steve R. Dean

    For a variety of tax, accounting, and economic reasons, leasing has become an enormously popular method of financing the acquisition of capital assets. In particular, for power generation assets, the use of leasing products (including synthetic and leveraged leases) has grown substantially in recent years. However, the long-lived nature of most power generation assets, together with their often unique physical and economic characteristics, makes estimation of their residual values challenging. In an environment where uncertainties are commonplace and in which capital structures are often highly leveraged, even small changes in residual values can have a significant impact on the profitability of financial institutions and other investors. This article outlines a framework for analyzing the uncertainty in residual values for assets, such as power generation facilities, for which few data points exist.


    CEIC-02-01: "Monte Carlo Methods for Appraisal and Valuation: A Case Study of a Nuclear Power Plant"
    David C. Rode, Paul S. Fischbeck, and Steve R. Dean

    Appraisals typically are conducted using four standard methods approved by the American Society of Appraisers. For large-scale, technically unique projects, such as chemical and power plants, and old industrial practices, these standard methods are insufficient. These types of projects contain political, technical, and economic risks that are not accounted for in standard valuation methods. To include these risks in an appraisal, a Monte Carlo simulation method can be used. Probability distributions are used to model the appropriate uncertainty. Modeling future decisions that may have to be made concerning the project can also be included to add insight to the risk involved. A case study of a nuclear power plant is presented. The use of Monte Carlo methods and the modeling of future decisions decreased the worth of the plant by 28% as compared to a standard income capitalization method.

  • 2001

    CEIC-01-05: "The First Year of the NOx Budget"
    Alexander E. Farrell

    One of the largest and most innovative emissions trading programs yet was started up last year, the northeast’s NOX Budget. Designed to address the region’s chronic problem of summertime ozone (or smog) problem, it controls emissions of nitrogen oxides (NOX) from large stationary sources, most of which are power plants. It is important to understand the NOX Budget for several reasons. First, controlling power plant NOX may be on the horizon in many places, especially the Midwest. Second, the NOX Budget has several unique features which might be useful in other proposed emissions trading programs. Third, it shows how restructuring helps make market-based environmental regulation work better.


    CEIC-01-04: "Electricity and Conflict: An Evaluation of Distributed Co-Generation as an Economic and Reliable Solution"
    Hisham Zerriffi, Hadi Dowlatabadi, and Neil Strachan

    The record of the conflicts in Bosnia-Herzegovina and Lebanon indicates the need to consider deliberate attacks when planning electric power systems in areas with the potential for conflict. It is hypothesized that a distributed system based primarily upon natural gas cogeneration facilities will be more economical and robust. A previously developed green-field system optimization model found that distributed cogeneration using internal combustion natural gas fired engines was the lowest cost option to supply both electricity and heat, resulting in substantial savings. This analysis will be augmented with a robustness engineering analysis. To determine the reliability advantages of distributed generation, a Monte Carlo simulation was developed to conduct generating capacity adequacy assessments. The model was used to determine the Loss of Load Expectation (hr/yr.) and Loss of Energy Expectation (MWh/yr.) for both a standard test system (consisting of 32 generating units) and for a system consisting of 284 identical 12 MW units. In order to simulate the effects of conflict on the system, the mean time to repair for each unit was increased and the reliability indices re-calculated. The results show that the system consisting of a large number of smaller units is up to 5 times less sensitive to changes in the MTTR.


    CEIC-01-03: "Distributed Generation and Path Dependency"
    Neil Strachan

    Distributed generation (DG) provides energy and emissions savings for a single installation, provided consistent electricity and heat loads are available. But unless DG has a significant market penetration, it cannot be an important tool in meeting energy policy goals. Widespread use of DG represents an alternative system architecture for the generation and delivery of electricity and heat. A green-field cost optimization of seasonally varying energy system demands, showed utilization of DG provided overall cost savings of around 25%. This model was used to investigate the implications of introducing DG into an energy system with existing generation plant. Sizeable penetration of DG for base-load application results in system cost and emissions savings. However, a reduced utilization of 46% for existing capacity suggests potentially stranded assets. Ongoing modeling investigates endogenous implications of DG penetration including mechanisms for compensating stranded assets, natural gas costs, evolving demand and DG economies of scale.


    CEIC-01-02: "Multi-lateral Emission Trading: Implications for International Efforts from Two U.S. Examples"
    Alexander E. Farrell and M. Granger Morgan

    Common property regimes that privatize international common pool resources are often proposed as efficient means of managing environmental problems. One such approach is the use of marketable emission allowances to control atmospheric pollution, most common in the United States, which has been suggested for the control of greenhouse gas (GHG) emissions in order to avoid dangerous changes to the earth’s climate. A significant problem for the development of such common property regimes is heterogeneity among potential participants. Another is the set of practical difficulties associated with establishing and operating an emission trading program. This problem is exacerbated for the case of international GHG emissions by the lack of examples of multi-lateral emissions trading programs from which lessons for successful implementation can be drawn. This paper looks at two such efforts to establish inter-state marketable emissions permit programs for the control of nitrogen oxides (NOX) in the eastern United States, focusing on the implications of heterogeneity among the participants and practical aspects of emissions trading.


    CEIC-01-01: "Capacity Withholding Equilibrium in Wholesale Electricity Markets"
    Lester B. Lave and Dimitri Perekhodstev

    We model the incentives for electricity generators to withhold capacity in a "California" deregulated market structure, where all producers are paid the price charged by the highest priced generator that is called upon to provide power. We use an N-player Nash equilibrium model based on marginal costs of the generation firms, assuming completely inelastic industry demand and complete information. When the marginal cost schedule is continuous, generators are always motivated to withhold capacity. The more convex (curved) is the marginal cost schedule or the more heterogeneous the generating firms, the greater is the incentive to withhold. When the marginal cost schedule is discrete rather than continuous, withholding incentives are "lumpy." Only above some threshold level of market demand does withholding behavior become beneficial. The curvature and heterogeneity of the discontinuous marginal cost schedule affects the level of threshold that allows profitability to increase from withholding. We apply the model to power generation in California and are able to predict aspects of market behavior.