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The article demonstrates the characteristics of wind power variability and net load variability in multiple power systems based on real data from multiple years. Demonstrated characteristics includ ...

The International Agroinformatics Alliance (IAA) is a coalition of public and private institutions that are cooperating to develop a platform for computationally advanced collaborative analysis of agricultural data. By combining large agricultural data sets with advanced analysis techniques, IAA seeks to catalyze agricultural research, leading to improved agricultural productivity and stability. IAA has constructed a platform that combines Jupyterhub web notebooks for interactive data analysis, relational databases for storage of crop genetic and geospatial data, and the Globus file transfer system for efficient data transfer and authentication. The platform uses a data permissions system that allows users to share data with collaborators. The central platform is located at the Minnesota Supercomputing Institute, at the University of Minnesota, which allows access to the large storage and compute resources required for advanced agroinformatics analysis pipelines.

Author(s): Palchak, D; Cochran, J; Deshmukh, R; Ehlen, A; Soonee, S; Narasimhan, S; Joshi, M; McBennett, B; Milligan, M; Sreedharan, P; Chernyakhovskiy, I; Abhyankar, N | Abstract: The use of renewable energy (RE) sources, primarily wind and solar generation, is poised to grow significantly within the Indian power system. The Government of India has established an installed capacity target of 175 gigawatts (GW) RE by 2022 that includes 60 GW of wind and 100 GW of solar, up from current capacities of 29 GW wind and 9 GW solar. India’s contribution to global efforts on climate mitigation extends this ambition to 40% non-fossil-based generation capacity by 2030. Global experience demonstrates that power systems can integrate wind and solar at this scale; however, evidence-based planning is important to achieve wind and solar integration at least cost. The purpose of this analysis is to evaluate the operation of India’s power grid with 175 GW of RE in order to identify potential cost and operational concerns and actions needed to efficiently integrate this level of wind and solar generation.

Author(s): Palchak, D; Cochran, J; Deshmukh, R; Ehlen, A; Soonee, R; Narasimhan, S; Joshi, M; McBennett, B; Milligan, M; Sreedharan, P; Chernyakhovskiy, I; Abhyankar, N | Abstract: The use of renewable energy (RE) sources, primarily wind and solar generation, is poised to grow significantly within the Indian power system. The Government of India has established a target of 175 gigawatts (GW) of installed RE capacity by 2022, including 60 GW of wind and 100 GW of solar, up from 29 GW wind and 9 GW solar at the beginning of 2017. Using advanced weather and power system modeling made for this project, the study team is able to explore operational impacts of meeting India’s RE targets and identify actions that may be favorable for integration. Our primary tool is a detailed production cost model, which simulates optimal scheduling and dispatch of available generation in a future year (2022) by minimizing total production costs subject to physical, operational, and market constraints. Our team comprises a core group from the Power System Operation Corporation, Ltd. (POSOCO), which is the national grid operator (with representation from the National, Southern, and Western Regional Load Dispatch Centers) under Ministry of Power, National Renewable Energy Laboratory (NREL), and Lawrence Berkeley National Laboratory (Berkeley Lab), and a broader modeling team that includes Central Electricity Authority (CEA), POWERGRID (the central transmission utility, CTU), and State Load Dispatch Centers in Maharashtra, Gujarat, Tamil Nadu, Karnataka, Rajasthan, and Andhra Pradesh. Our model includes high-resolution wind and solar data (forecasts and actuals), unique properties for each generator, CEA/CTU’s anticipated buildout of the power system, and enforced state-to-state transmission flows. Assuming the fulfillment of current efforts to provide better access to the physical flexibility of the power system, we find that power system balancing with 100 GW of solar and 60 GW of wind is achievable at 15-minute operational timescales with minimal RE curtailment. This RE capacity meets 22% of total projected 2022 electricity consumption in India with annual RE curtailment of 1.4%, in line with experiences in other countries with significant RE penetrations (Bird et al. 2016). Changes to operational practice can further reduce the cost of operating the power system and reduce RE curtailment. Coordinating scheduling and dispatch over a broader area is the largest driver to reduce costs, saving INR 6300 crore (USD 980 million) annually when optimized regionally. Lowering minimum operating levels of coal plants (from 70% to 40%) is the biggest driver to reduce RE curtailment—from 3.5% down to 0.76%. In fact, this operating property is more influential than faster thermal generation ramp rates in lowering the projected levels of curtailment. While this study does not answer every question relevant to planning for India’s 2022 RE targets, it is an important step toward analyzing operational challenges and cost saving opportunities using state-of-the-art power system planning tools. Further analysis can build upon this basis to explore optimal renewable resource and intrastate transmission siting, system stability during contingencies, and the influence of total power system investment costs on customer tariffs.

This article describes some of the recent research into the capacity value of wind power. With the worldwide increase in wind power during the past several years, there is increasing interest and significance regarding its capacity value because this has a direct influence on the amount of other (nonwind) capacity that is needed. We build on previous reviews from IEEE and IEA Wind Task 25a and examine recent work that evaluates the impact of multiple-year data sets and the impact of interconnected systems on resource adequacy. We also provide examples that explore the use of alternative reliability metrics for wind capacity value calculations. We show how multiple-year data sets significantly increase the robustness of results compared to single-year assessments. Assumptions regarding the transmission interconnections play a significant role. To date, results regarding which reliability metric to use for probabilistic capacity valuation show little sensitivity to the metric.

The integration of large amounts of variable renewable generation can increase the demand on flexible resources in the power system. Conventional hydropower can be an important asset for managing variability and uncertainty in the power system, but multi-purpose reservoirs are often limited by non-power constraints. Previous large-scale variable generation integration studies have simulated the operation of the electric system under different penetration levels but often with simplified representations of hydropower to avoid complex non-power constraints. This paper illustrates the value of bridging the gap between power system models and detailed hydropower models with a demonstration case. The United States Western Interconnection is modeled with PLEXOS, and ten large reservoirs on the Columbia River are modeled with RiverWare. The results show the effect of detailed hydropower modeling on the power system and its benefits to the power system, such as the decrease in overall production cost and the reduction of variable generation curtailment.

The first part of this two-paper series discusses the motivation of implementing a primary frequency response (PFR) market in restructured pool-based power markets, as well as the market design that would create the right incentives to provide the response reliably. PFR is the immediate, autonomous response of generation and demand to system frequency deviations. It is the critical response required to avoid triggering under- and over- frequency relays or instability that could lead to machine damage, load-shedding, and in the extreme case, blackouts. Currently, in many restructured power systems throughout the world, ancillary services markets have been developed to incent technologies to provide the services to support power system reliability. However, few ancillary services markets include a market explicitly incentivizing the provision of PFR. Historically, PFR was an inherent feature available in conventional generating technologies, and in most systems, more was available than needed. Yet, recent trends in declining frequency response, the introduction of emerging technologies, and market behavior may soon require innovative market designs to incent resources to provide this valuable service.

The paper discusses the general wind power forecast error curve and how several power systems have exploited the shape of this curve to successfully incorporate significant amounts of wind energy at very low cost. The paper examined some of these systems in more detail to better understand how wind variability and wind forecast uncertainty are efficiently handled through these approaches. The paper also show that these elegant approaches for integrating wind into dispatch, although quite simple from a weather forecasting point of view, actually clarify the requirements and increase the value of sophisticated wind power forecasts in other time frames and for additional users. Taken together, these approaches can efficiently and reliably incorporate wind energy in power system operations and power markets.

Wind and solar generation may consequently be difficult to predict over some time scales. Large penetrations of variable generation (VG) lead to increases in the variability and uncertainty in the system's generation output, driving a need for greater flexibility. This flexibility will need to come either from flexible generation technologies or from alternative sources of flexibility such as flexible demand and storage. This article will discuss the additional flexibility needs introduced by variable generation from wind and solar power and will describe general approaches to analyzing the need for and provision of additional flexibility in the power system in both the operational and planning time frames.

Greening the Grid provides technical assistance to energy system planners, regulators, and grid operators to overcome challenges associated with integrating variable renewable energy into the grid. This document, part of the Greening the Grid introduces the evolution of power system planning with high levels of variable renewable generation.

Increased competition in the electricity sector and the integration of variable renewable energy sources is resulting in more frequent cycling of thermal plant. Thus, the wear-and-tear to generator components and the related costs are a growing concern for plant owners and system operators alike. This paper presents a formulation that can be implemented in a MIP dispatch model to dynamically model cycling costs based on unit operation. When implemented for a test system, the results show that dynamically modeling cycling costs reduces cycling operation and tends to change the merit order over time. This leads to the burden of cycling operation being more evenly distributed over the plant portfolio and reduces the total system costs relative to the case when cycling costs are not modeled. Science Foundation Ireland Deposited by bulk import

Wind integration studies are now routinely undertaken by utilities and system operators to investigate the operational impacts of the variability and uncertainty of wind power on the grid. There are widely adopted techniques and assumptions that are used to model the wind data used in these studies. As wind penetration levels increase, some of the assumptions and methodologies are no longer valid and new methodologies have been devised. Based on involvement in conducting studies, reviewing studies, and/or developing datasets for studies in the Western Interconnect, the Eastern Interconnect, Hawaii, and other regions, the authors report on the evolution of techniques to better model the wind power output for cases with high penetrations of wind energy.

An important consideration in wind power integration studies is the role that wind power forecasting will play in simulated high-penetration system operations. As no wind power forecast is perfect, an understanding of the forecast error distributions that are observed in current system operations is important for modeling the forecast errors that can be expected in future scenarios. In this work, we statistically characterize and model the wind power forecast errors from three different operational forecasting systems at multiple timescales. Comparisons are made with two methods that are commonly used in wind integration studies to represent wind power forecasting: the persistence model, and an assumed normal distribution of forecasting errors. A number of model distributions are fit to the operational system forecast errors and the accuracy of the model fits to extreme events is examined in detail.

Power systems with high wind penetration experience increased variability and uncertainty, such that determination of the required additional operating reserve is attracting a significant amount of attention and research. This paper presents methods used in recent wind integration analyses and operating practice, with key results that compare different methods or data. Wind integration analysis over the past several years has shown that wind variability need not be seen as a contingency event. The impact of wind will be seen in the reserves for non-event operation (normal operation dealing with deviations from schedules). Wind power will also result in some events of larger variability and large forecast errors that could be categorized as slow events. The level of operating reserve that is induced by wind is not constant during all hours of the year, so that dynamic allocation of reserves will reduce the amount of reserves needed in the system for most hours. The paper concludes with recent emerging trends.

Wind integration studies are increasingly important tools to estimate the impacts that the addition of large amounts of variable and uncertain generation will have on the electricity grid. As the number of these studies has increased in recent years, the sophistication of the methods and assumptions utilized has also increased. These methods have had to evolve with increasing penetration rates and to study changing research questions. In this work, the authors report on the state of the art in this area and make suggestions for improving the methods and assumptions used for cases with high levels of wind power.

This article examines how wind and solar integration studies have evolved, what analysis techniques work, what common mistakes are still made, and what and why calculating integration costs is such a difficult problem that should be undertaken carefully, if at all. Examples of integration costs for other generation technologies are examined to help illuminate underlying cost causation principles.

Wind integration will not be accomplished successfully by doing “more of the same.” It will require significant changes in grid planning and operations, continued technical evolution in the design and operation of wind turbines, further adoption and implementation of wind forecasting in the control room, and incorporation of market and policy initiatives to encourage more flexible generation.

When wind plants serve load within the balancing area, no additional capacity required to integrate wind power into the system. We present some thought experiments to illustrate some implications for wind integration studies.

The variability inherent in wind power production will require increased flexibility in the power system, when a significant amount of load is covered with wind power. Standard deviation (σ) of variability in load and net load (load net of wind) has been used when estimating the effect of wind power on the short term reserves of the power system. This method is straightforward and easy to use when data on wind power and load exist. In this paper, the use of standard deviation as a measure of reserve requirement is studied. The confidence level given by ±3–6 times σ is compared to other means of deriving the extra reserve requirements over different operating time scales. Also taking into account the total variability of load and wind generation and only the unpredicted part of the variability of load and wind is compared. Using an exceedence level can provide an alternative approach to confidence level by standard deviation that provides the same level of risk. The results from US indicate that the number of σ that result in 99% exceedence in load following time scale is between 2.3–2.5 and the number of σ for 99.7% exceedence is 3.4. For regulation time scale the number of σ for 99.7 % exceedence is 5.6. The results from the Nordic countries indicate that the number of σ should be increased by 67–100% if better load predictability is taken into account (combining wind variability with load forecast errors).

Balancing area reserve sharing2 may significantly reduce wind integration costs. It also reduces utility costs without wind. Some recent studies indicate that large balancing areas can integrate wind more easily than small ones. The “hockey stick” pattern of dramatically increasing wind integration cost above some threshold wind penetration may not be as pronounced as expected. The existence and location of this threshold could have important implications regarding the cost of integrating significant wind penetrations. We examine wind integration impacts as a function of balancing area size to determine if the larger system size mitigates wind integration impacts at high penetrations. Using data from Minnesota, we show that ramping requirements can be reduced by balancing area consolidation. In a companion paper3, we examine electricity market data in the United States that show how ramping capability is provided at low or no cost, and discuss its relevance to wind integration.

Integration of wind-power plants into the electric power system presents challenges to power-system planners and operators. These challenges stem primarily from the natural characteristics of wind plants, which differ in some respects from conventional plants. Wind plants operate when the wind blows, and their power levels vary with the strength of the wind. Hence, they are not dispatchable in the traditional sense, which lessens the ability of system operators to control them while maintaining the system's balance between load and generation.

This report summarizes some of the issues discussed during the engagement on power system flexibility. By design, the focus is on flexibility options used in the United States. Exploration of whether and how U.S. experiences can inform Chinese energy planning will be part of the continuing project, and will benefit from the knowledge base provided by this report. We believe the initial stage of collaboration represented in this report has successfully started a process of mutual understanding, helping Chinese researchers to begin evaluating how lessons learned in other countries might translate to China's unique geographic, economic, social, and political contexts.

This paper introduces a production cost modeling approach for evaluating the benefits of intra-hour scheduling among Balancing Authorities (BAs). System operation is modeled in a three-stage sequential manner: day ahead (DA)-hour ahead (HA)?real time (RT). In addition to contingency reserve, each BA will need to carry out “up” and “down” load following and regulation reserve capacity requirements in the DA and HA time frames. In the RT simulation, only contingency and regulation reserves are carried out as load following is deployed. To model current RT operation with hourly schedules, a new constraint was introduced to force each BA net exchange schedule deviation from HA schedules to be within North American Electric Reliability Corporation (NERC) area control error (ACE) limits. Case studies that investigate the benefits of moving from hourly exchange schedules between Western Electricity Coordinating Council (WECC) BAs into 10-minute exchange schedules under two different levels of wind and solar penetration (11% and 33%) are presented.

The purpose of this paper is to describe multiple studies of wind and solar integration that have found CO2 reductions of approximately 30%. These studies can be viewed in several ways, including as viable paths to compliance with the EPA rule, alternative ''bookend cases'' to compare to compliance based largely on natural gas, or something in between. The studies in this paper represent a body of work that can help inform the public discussion surrounding the cost and reliability impacts of complying with the proposed EPA CPP.

As more wind energy capacity is added in the nation, the question of wind's capacity value is raised. This article shows how the capacity value of wind is determined, both in theory and in practice.

This paper discusses the key issues that confront power system planners and operators when integrating wind power plants into the electric power system. A key question is how the variations in wind plant outputs affect the operation of the power system on a daily basis and what the associated costs are. These costs are lower than initially expected by some utility engineers. The main reason for this is that wind tends to behave more like negative load than traditional firm-block generation, and the power system has been designed to handle significant load variations on a routine basis. This paper summarizes the key results of wind integration studies conducted to date and provides insights from individual studies. The studies present simulations of system operations that employ well-established production-costing and unit-commitment computational tools.

Several detailed technical investigations of grid ancillary service impacts of wind power plants in the United States have recently been performed. These studies were applied to Xcel Energy (in Minnesota) and PacifiCorp and the Bonneville Power Administration (both in the northwestern United States). Although the approaches vary, three utility time frames appear to be most at issue: regulation, load following and unit commitment. This article describes and compares the analytic frameworks from recent analysis and discusses the implications and cost estimates of wind integration. The findings of these studies indicate that relatively large-scale wind generation will have an impact on power system operation and costs, but these impacts and costs are relatively low at penetration rates that are expected over the next several years. Published in 2004 by John Wiley & Sons, Ltd.

The National Renewable Energy Laboratory (NREL) started a project in 2000 to record long-term, high-frequency (1-Hz) wind power data from large commercial wind power plants in the Midwestern United States. Outputs from about 330 MW of installed wind generating capacity from wind power plants in Lake Benton, MN, and Storm Lake, Iowa, are being recorded. Analysis of the collected data shows that although very short-term wind power fluctuations are stochastic, the persistent nature of wind and the large number of turbines in a wind power plant tend to limit the magnitude of fluctuations and rate of change in wind power production. Analyses of power data confirms that spatial separation of turbines greatly reduces variations in their combined wind power output when compared to the output of a single wind power plant. Data show that high-frequency variations of wind power from two wind power plants 200 km apart are independent of each other, but low-frequency power changes can be highly correlated. This fact suggests that time-synchronized power data and meteorological data can aid in the development of statistical models for wind power forecasting.

Energy imbalance provisions in open access transmission tariffs pose a formidable obstacle for commercial wind energy development in the U.S. To allow wind project development to proceed, some ISOs have adopted provisions reflecting the variable nature of wind energy resources.

The first part of this two-paper series discusses the motivation of implementing a primary frequency response (PFR) market in restructured pool-based power markets, as well as the market design that would create the right incentives to provide the response reliably. PFR is the immediate, autonomous response of generation and demand to system frequency deviations. It is the critical response required to avoid triggering under- and over-frequency relays or instability that could lead to machine damage, load-shedding, and in the extreme case, blackouts. Currently, in many restructured power systems throughout the world, ancillary services markets have been developed to incent technologies to provide the services to support power system reliability. However, few ancillary services markets include a market explicitly incentivizing the provision of PFR. Historically, PFR was an inherent feature available in conventional generating technologies, and in most systems, more was available than needed. Yet, recent trends in declining frequency response, the introduction of emerging technologies, and market behavior may soon require innovative market designs to incent resources to provide this valuable service.

Many wind integration studies have been performed in recent years, with evolving methodologies. Since power systems and data availability vary significantly, the results and methodologies used in these studies have varied accordingly. This paper presents the main findings from the IEA WIND Recommended Practices for Wind Integration studies. An overview of a complete wind integration study is presented as a flow chart. The main simulation steps are presented with recommendations on methodologies: an increase in reserve requirements, estimating impacts on other generation and balancing, capacity value of wind power and transmission expansion due to wind power. The study set-up and the main assumptions are outlined, as they can have a critical impact on the results. The recommendations are applicable for other variable renewable sources, including photovoltaics.

Determining the additional reserves required to maintain reliability when significant quintiles of VER are added to a power system is complicated by the nonlinear nature of reserves as well as by the lack of data and experience. Dealing with variability and uncertainty is not new for power system operators; generation and load have always been both variable and uncertain. While large amounts of wind and solar generation do not typically fail instantaneously the available energy does vary and is only somewhat predictable. Power system operators compensate for the variability and uncertainty of aggregate load and generation (including wind and solar) by maintaining a series of reserves: additional capacity (generation, responsive load, and storage) above that needed to meet the current net load. This chapter examines reserve types and requirements in general and addresses how VER impacts are determined.

As the worldwide use of wind turbine generators in utility-scale applications continues to increase, it will become increasingly important to assess the economic and reliability impact of these intermittent resources. Although the utility industry appears to be moving towards a restructured environment, basic economic and reliability issues will continue to be relevant to companies involved with electricity generation. This article is the second in a two-part series that addresses modelling approaches and results that were obtained in several case studies and research projects at the National Renewable Energy Laboratory (NREL). This second article focuses on wind plant capacity credit as measured with power system reliability indices. Reliability-based methods of measuring capacity credit are compared with wind plant capacity factor. The relationship between capacity credit and accurate wind forecasting is also explored. Published in 2000 by John Wiley & Sons, Ltd.

By the end of June 1999, 250 MW of wind generation had been dedicated in the State of Iowa. This represents the beginning of what is likely to be significant wind capacity development during the next 20 years in the State as a result of possible governmental mandates and consumers' desire for sustainable sources of energy. After accounting for predicted load growth over the next 15 years, we estimate Iowa's potential wind energy portfolio through to the year 2015. Winds in the Midwest are primarily generated by fronts moving through the region. The purpose of this study is to find the best way to distribute wind-generating capacity among several sites by using an electricity-production, cost and reliability model. We calculate this benefit in terms of reduction in the fuel cost of conventional generators. We also consider system reliability in terms of energy not served (ENS). Our findings indicate that it is beneficial to develop wind power plants at several sites, and that there are many possible combinations of wind locations that can be chosen to obtain diversity benefits. We also calculate capacity credit for the composite wind power plants using two different methods, and calculate a trade-off curve between the economically optimal and the most reliable solutions. The methods we use to find the best geographical locations and sizes of wind power plant are based on a dynamic fuzzy search algorithm and a genetic algorithm. Each procedure produces a solution set that can be analyzed further in other contexts, such as voltage and land use constraints. We illustrate the sensitivity of the fuzzy economic benefit solutions to small perturbations of the capacity selections at each wind site. We find that small changes in site capacity and/or location have small effects on the economic benefit provided by wind power plants.

As the worldwide use of wind turbine generators continues to increase in utility-scale applications, it will become increasingly important to assess the economic and reliability impact of these intermittent resources. Although the utility industry in the United States appears to be moving towards a restructured environment, basic economic and reliability issues will continue to be relevant to companies involved with electricity generation. This paper is the first of two that address modeling approaches and results obtained in several case studies and research projects at the National Renewable Energy Laboratory (NREL). This first paper addresses the basic economic issues associated with electricity production from several generators that include large-scale wind power plants. An important part of this discussion is the role of unit commitment and economic dispatch in production-cost models. This paper includes overviews and comparisons of the prevalent production-cost modeling met hods, including several case studies applied to a variety of electric utilities. The second paper discusses various methods of assessing capacity credit and results from several reliability-based studies performed at NREL.

Load forecasting at the day-ahead timescale is a critical aspect of power system operations in the unit commitment process. It is also an important factor in renewable energy integration studies, where the combination of load and wind or solar forecasting techniques create the net load uncertainty that must be managed by the economic dispatch process or with suitable reserves. An understanding of the load forecasting errors that may occur in this process can lead to better decisions about the amount of reserves necessary to compensate for the errors that do occur. In this work, we performed a statistical analysis of the day-ahead (and two-day-ahead) load forecasting errors observed in two independent system operators for a one-year period. Comparisons were made with the normal distribution commonly assumed in power system operation simulations used for renewable power integration studies. Further analysis identified time periods when the load is more likely to be under- or overforecast.

The overall objective of this study was to understand, on an Interconnection-wide basis, the effects intra-hour scheduling compared to hourly scheduling. Moreover, the study sought to understand how the benefits of intra-hour scheduling would change by altering the input assumptions in different scenarios. This report describes results of three separate scenarios with differing key assumptions and comparing the production costs between hourly scheduling and 10-minute scheduling performance. The different scenarios were chosen to provide insight into how the estimated benefits might change by altering input assumptions. Several key assumptions were different in the three scenarios, however most assumptions were similar and/or unchanged among the scenarios.

Hydro power is one of the most flexible sources of electricity production. Power systems with considerable amounts of flexible hydro power potentially offer easier integration of variable generation, e.g., wind and solar. However, there exist operational constraints to ensure mid-/long-term security of supply while keeping river flows and reservoirs levels within permitted limits. In order to properly assess the effective available hydro power flexibility and its value for storage, a detailed assessment of hydro power is essential. Due to the inherent uncertainty of the weather-dependent hydrological cycle, regulation constraints on the hydro system, and uncertainty of internal load as well as variable generation (wind and solar), this assessment is complex. Hence, it requires proper modeling of all the underlying interactions between hydro power and the power system, with a large share of other variable renewables. A summary of existing experience of wind integration in hydro-dominated power systems clearly points to strict simulation methodologies. Recommendations include requirements for techno-economic models to correctly assess strategies for hydro power and pumped storage dispatch. These models are based not only on seasonal water inflow variations but also on variable generation, and all these are in time horizons from very short term up to multiple years, depending on the studied system. Another important recommendation is to include a geographically detailed description of hydro power systems, rivers' flows, and reservoirs as well as grid topology and congestion.

Variable generation is on track to become a significant contributor to electric power systems worldwide. Thus, it is important to analyze the effect that renewables will have on the reliability of systems. In this paper we present a new tool being implemented at the National Renewable Energy Laboratory, which allows the inclusion of variable generation in the power system resource adequacy. The tool is used to quantify a first estimate of the potential contribution of transmission to reliability in highly interconnected systems and an example is provided using the Western Interconnection footprint.

Evaluating the capacity value of renewable energy sources can pose significant challenges due to their variable and uncertain nature. In this paper the capacity value of solar power is investigated. Solar capacity value metrics and their associated calculation methodologies are reviewed and several solar capacity studies are summarized. The differences between wind and solar power are examined, the economic importance of solar capacity value is discussed and other assessments and recommendations are presented.

The ever increasing level of wind power penetration in Spain has a remarkable impact on power system operation and costs. Furthermore, the Iberian Peninsula Power System is considered to be a weak systems. With a weak interconnections, wind power fluctuations could affect the security, reliability and stability of power system. There are times when a combination of several events or several actions taken (coincidence or coordinated) may lead to the worst condition of power system. An evolution of procedures and regulations related to power system have been performed and developed by Spanish Transmission System Operator (TSO) to tackle these extreme events; thus, improving the overall wind power integration. This paper analyzes the wind power events and the evolution of procedures during past several years implemented by Spanish TSO. Events are analyzed from TSO perspective as well as from the wind farm and wind turbines point aspects. Operational decisions and techniques developed and performed by Spanish TSO to resolve these events are also described in this paper.

The development of large amounts of wind and/or solar energy will have an impact on bulk electricity markets. These variable generation sources increase the level of variability and uncertainty that the power system operator must manage. In this paper we discuss the impact that electricity markets have on the wind producer, using examples from the Nordic system. We also describe two market structures that will help induce both the needed flexibility, whether from generation or load, and sufficient capacity. We also provide some general guidelines for market design and simple tests that can help identify how a proposed market would function. We close with suggestions for future research.

The anticipated increase in variable generation in the Western Interconnection (WI) over the next several years has raised concerns about how to maintain system balance, especially in smaller Balancing Areas (BAs). Given renewable portfolio standards in the West, it is possible that more than 50 gigawatts (GW) of wind capacity will be installed by 2020. Significant quantities of solar generation are likely to be added as well. The consequent increase in variability and uncertainty that must be managed by the conventional generation fleet and responsive load make it attractive to consider ways in which Balancing Area Authorities (BAAs) can pool their variability and response resources, thus taking advantage of geographic and temporal diversity to increase overall operational efficiency. Our analysis considers several alternative forms of an Energy Imbalance Market (EIM) that have been proposed in the non-market areas of the WI. The proposed EIM includes two changes in operating practices that independently reduce variability and increase access to responsive resources: BAA cooperation and sub-hourly dispatch. As proposed, the EIM does not consider any form of coordinated unit commitment; however, over time it is possible that BAAs would develop formal or informal coordination plans. This report examines the benefits of several possible EIM implementations, both separately and in concert.

This report tries to first generalize the requirements of the power system as it relates to the needs of operating reserves. It also includes a survey of operating reserves and how they are managed internationally in system operations today and then how new studies and research are proposing they may be managed in the future with higher penetrations of variable generation.

With the advent of wind power generation on worldwide power systems, many operators and researchers are analyzing the impacts that higher future amounts may have on system operations. Many of the tools are analyzing longer term impacts on the steady-state operations of power systems and are primarily using cost as a metric. They are also using tools that are often inflexible to accommodating different market designs or operational structures. In this paper a model was developed to mimic operator behavior using a combination of security-constrained unit commitment, security-constrained economic dispatch, and automatic generation control programs. New metrics are used to compare reliability in terms of energy imbalance for different systems or different market and operational structures at very high time resolution. Finally an example application of the tool and results for a test system are shown.

During the past few years, there has been significant interest in alternative ways to manage power systems over a larger effective electrical footprint. Large regional transmission organizations in the Eastern Interconnection have effectively consolidated balancing areas, achieving significant economies of scale that result in a reduction in required reserves. Conversely, in the Western Interconnection there are many balancing areas, which will result in challenges if there is significant wind and solar energy development in the region. A recent proposal to the Western Electricity Coordinating Council suggests a regional energy imbalance service (EIS). To evaluate this EIS, a number of analyses are in process or are planned. This paper describes one part of an analysis of the EIS's implication on operating reserves under several alternative scenarios of the market footprint and participation. We improve on the operating reserves method utilized in the Eastern Wind Integration and Transmission Study and apply this modified approach to data from the Western Wind and Solar Integration Study.

Wind forecasting is an important consideration in integrating large amounts of wind power into the electricity grid. The wind power forecast error distribution assumed can have a large impact on the confidence intervals produced in wind power forecasting. In this work we examine the shape of the persistence model error distribution for ten different wind plants in the ERCOT system over multiple timescales. Comparisons are made between the experimental distribution shape and that of the normal distribution. The shape of the distribution is found to change significantly with the length of the forecasting timescale. The Cauchy distribution is proposed as a model distribution for the forecast errors and model parameters are fitted. Finally, the differences in confidence intervals obtained using the Cauchy distribution and the normal distribution are compared.