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As our power grids transition toward a decarbonized energy mix, ensuring reliability and provision of grid services remains paramount. The power system has always been heavily influenced by the weather—extreme temperatures determine the timing of peak demand, winter cold snaps can limit natural gas supply, gas turbine reliability and output are affected by ambient conditions, and hydro output varies seasonally and annually. However, as the grid increasingly relies on variable renewable energy (VRE), like wind and solar, the attention to reliability and weather conditions is increasingly important. The implications of changing reliability are large. The Electric Reliability Council of Texas (ERCOT) rolling blackouts from earlier this year impacted millions of people across the state and could be seen from space ( Figure 1 ).

The bulk power system is undergoing a digital revolution. With the recent and continuing growth of inverter-based generation, primarily wind and solar energy, the industry has begun exploring the implication of these new resources on power system reliability and resilience. This paper provides an overview and description of grid services that key resource types are able to provide, showing that new resources can provide many of the required grid reliability services.

This paper discusses the importance and challenges of incentivizing flexibility during short-term operations of the bulk power system due to the increasing variability and uncertainty from growing penetrations of variable generation (VG). Operational flexibility can refer to many aspects of a resource’s capability to support the power system, such as the speed, range, and duration of power output, as well as the ability to autonomously respond to frequency or voltage changes. Inefficient utilization of existing flexibility, or unwillingness of resources to provide flexibility, can compromise system reliability by not meeting the changing net load, and it can also lead to higher costs when an inefficient use of flexibility resources occurs. There are many existing characteristics of market design that incentivize flexibility in some manner. How they incentivize the provision of flexibility as well as the level of flexibility is still debated. We explore some of these existing market designs, as well as new market mechanisms, such as pay-for-performance regulating reserve and flexible ramping products, that aim to explicitly incentivize the provision of more flexibility to the system, particularly as a result of increasing VG penetration levels.

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 ...

Defining flexibility has been a challenge that a number of industry members and researchers have attempted to address in recent years. With increased variability and uncertainty of variable generation (VG), the resources on the system will have to be more flexible to adjust output, so that power output ranges, power ramp rates, and energy duration sustainability are sufficient to meet the needs of balancing supply with demand at various operational timescales. This chapter discusses whether existing market designs provide adequate incentives for resources to offer their flexibility into the market to meet the increased levels of variability and uncertainty introduced by VG in the short-term operational time frame. It presents a definition of flexibility and discusses how increased levels of VG require increased needs for flexibility on power systems. Following this introductory material, the chapter examines how existing market designs ensure that resources have the right incentives to provide increased flexibility, and then discusses a number of emerging market design elements that impact flexibility incentives.

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.

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.

Renewable technologies are often characterized as being somewhat different to ‘conventional’ generating technologies in three ways, each with different implications for electricity markets. Firstly, some have highly variable and somewhat uncertain availability, meaning that electricity markets must be designed to elicit adequate flexibility. Secondly, many have very low short-run marginal costs (operating costs), meaning that the mechanisms for managing resource adequacy must be carefully considered. Thirdly, some are nonsynchronous, meaning that grid codes and regulatory requirements must be appropriately designed. Access to flexibility can be enhanced by a range of market design choices, such as short dispatch intervals, short delays from gate closure to dispatch, large balancing areas, high demand side participation, and exposing renewable technologies to market price signals commensurate with other technologies. The design of markets for frequency control ancillary services (FCAS) also provides opportunities to increase access to flexibility, by creating active real-time markets for a wide range of FCAS, allowing renewable technologies to provide FCAS, and determining FCAS reserve requirements dynamically in real time. Mechanisms for managing resource adequacy are a source of ongoing debate, with many of the key issues having been exacerbated by the entry of renewables. Rapid market change makes investment decisions difficult, regardless of the market model applied. Ultimately, given the existence of arguably successful examples of both energy-only and capacity market designs, the choice of market model may be less important than the quality of governance with which it is implemented and maintained. WIREs Energy Environ 2015, 4:279–289. doi: 10.1002/wene.137 For further resources related to this article, please visit the WIREs website. Conflict of interest: The authors have declared no conflicts of interest for this article.

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.

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.

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.

Frequency responsive reserve is the autonomous response of generators and demand response to deviations of system frequency, usually as a result of the instantaneous outage of a large supplier. This article discusses the issues that can occur without proper incentives and even disincentives, and proposes alternatives to introduce incentives for resources to provide frequency responsive reserve to ensure an efficient and reliable power system.

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).

Greater penetrations of variable renewable generation on some electric grids have resulted in increased levels of curtailment in recent years. Studies of renewable energy grid integration have found that curtailment levels may grow as the penetration of wind and solar energy generation increases. This paper reviews international experience with curtailment of wind and solar energy on bulk power systems in recent years, with a focus on eleven countries in Europe, North America, and Asia. It examines levels of curtailment, the causes of curtailment, curtailment methods and use of market-based dispatch, as well as operational, institutional, and other changes that are being made to reduce renewable energy curtailment. European Commission - European Regional Development Fund Ministerio de Economía y Competitividad

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.

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.

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.

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.

Flexibility of operation--the ability of a power system to respond to change in demand and supply--is a characteristic of all power systems. Flexibility is especially prized in twenty-first century power systems, with higher levels of grid-connected variable renewable energy (primarily, wind and solar). This paper summarizes the analytic frameworks that have emerged to measure this characteristic and distills key principles of flexibility for policy makers.

In the U.S., a number of utilities are adopting higher penetrations of renewables, driven in part by state policies. While power systems have been designed to handle the variable nature of loads, the additional supply-side variability and uncertainty can pose new challenges for utilities and system operators. However, a variety of operational and technical solutions exist to help integrate higher penetrations of wind and solar generation. This paper explores renewable energy integration challenges and mitigation strategies that have been implemented in the U.S. and internationally, including forecasting, demand response, flexible generation, larger balancing areas or balancing area cooperation, and operational practices such as fast scheduling and dispatch.

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.

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.

Examples of the different events affecting wind power fluctuations are shown.The behaviors and the responses of the Spanish power system and wind power plants experiencing such events were analyzed. Examples presented in this chapter show that some of the wind power integration issues are related to low-voltage ride-through. They are solved through strict grid code enforcement. Other solutions to manage the reserve power generation and the wind power fluctuations are also very important in order to achieve high levels of wind power penetration. In the Spanish case, this could require increasing the availability of dispatchable and fast-start power plants, as well as increasing wind power plant participation on supporting the power system by providing voltage control, inertial emulation, frequency control, oscillation damping, or updated voltage ride-through capabilities.

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.

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.

This paper considers several alternative forms of an energy imbalance market (EIM) proposed in the nonmarket areas of the Western Interconnection. The proposed EIM includes two changes in operating practices that independently reduce variability and increase access to responsive resources: balancing authority cooperation and sub-hourly dispatch. As the penetration of variable generation increases on the power system, additional interest in coordination would likely occur. Several alternative approaches could be used, but consideration of any form of coordinated unit commitment is beyond the scope of this analysis. 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.

Power systems are planned such that they have adequate generation capacity to meet the load, according to a defined reliability target. The increase in the penetration of wind generation in recent years has led to a number of challenges for the planning and operation of power systems. A key metric for generation system adequacy is the capacity value of generation. The capacity value of a generator is the contribution that a given generator makes to generation system adequacy. The variable and stochastic nature of wind sets it apart from conventional energy sources. As a result, the modeling of wind generation in the same manner as conventional generation for capacity value calculations is inappropriate. In this paper a preferred method for calculation of the capacity value of wind is described and a discussion of the pertinent issues surrounding it is given. Approximate methods for the calculation are also described with their limitations highlighted. The outcome of recent wind capacity value analyses in Europe and North America, along with some new analysis are highlighted with a discussion of relevant issues also given. Science Foundation Ireland Charles Parsons Energy Research Awards Charles Parson au, ti, pe, la, ke, ab - kpw10/11/11

As integration of variable generation continues to grow rapidly in power systems globally, system planners are seeking new tools to understand the role of variable output generators and the challenges experienced with their integration. The North American Electric Reliability Corporation (NERC) has established a task force to examine the integration of variable generation. This paper details the achievements to date and outlines ongoing efforts from Task 1.2 on the capacity value of variable generation and from Task 1.4 on the concept of flexibility in power systems and options for its definition. Arising from international collaboration with the International Energy Agency, a discussion on the definition of flexible resources is presented. A potential metric for flexibility offered by conventional plant is developed and applied to a test system.

The growth of wind power as an electrical power generation resource has produced great benefits with reductions in emissions and the supply of zero cost fuel. It also has created challenges for the operation of power systems arising from the increased variability and uncertainty it has introduced. A number of studies have been performed over the past decade to analyze the operational impacts that can occur at high penetrations of wind. One of the most crucial impacts is the amount of incremental operating reserves required due to the variability and uncertainty of wind generation. This paper describes different assumptions and methods utilized to calculate the amount of different types of reserves carried, and how these methods have evolved as more studies have been performed.

This paper discusses key results that had emerged at the time from two studies, the Western Wind and Solar Integration Study (covers the footprint of WestConnect, a group of transmission owners that covers most of Colorado, New Mexico, Arizona, Nevada, and Wyoming) and the Eastern Wind Integration and Transmission Study (covers a large part of the Eastern Interconnection). Results from both studies showed that high wind penetrations could be successfully integrated into the power system, but were dependant on sufficient transmission and significant changes in operations.

Paper examines the capacity requirements that arise as wind generation is integrated into the power system and how those requirements change depending on where the wind energy is delivered.

This paper attempts to evaluate which balancing area (BA) characteristics best accommodate wind energy.

The rapid growth of wind power as a generation resource in the past decade has given many utilities and Regional Transmission Organizations (RTO) concerns due to its unconventional characteristics. Because of these concerns, many of these entities have initiated studies that evaluate the feasibility of large amounts of wind power onto their system and the operational impacts present. This paper will discuss some of the past major studies, mostly focusing on the United States, and the basic methodologies that were used during these studies. The paper will also review many of the different results and conclusions of the studies and discuss how they have helped the power industry as a whole. Lastly, the authors will attempt to share their ideas on some of the limitations of the current and past integration studies, and some insight on how these may be evolving in the future.

The natural variability of wind power makes it different from other generating technologies, which can give rise to questions about how wind power can be integrated into the grid successfully. This article aims to answer several important questions that can be raised with regard to wind power. Although wind is a variable resource, grid operators have experience with managing variability that comes from handling the variability of load. As a result, in many instances the power system is equipped to handle variability. Wind power is not expensive to integrate, nor does it require dedicated backup generation or storage. Developments in tools such as wind forecasting also aid in integrating wind power. Integrating wind can be aided by enlarging balancing areas and moving to subhourly scheduling, which enable grid operators to access a deeper stack of generating resources and take advantage of the smoothing of wind output due to geographic diversity. Continued improvements in new conventional-generation technologies and the emergence of demand response, smart grids, and new technologies such as plug-in hybrids will also help with wind integration.

Power systems must have enough generation to meet demand at each moment of the day. In addition, they must also have enough reserve to deal with unexpected contingencies. The increase in the penetration of wind generation in recent years has led to a number of challenges in the calculations required to facilitate wind generation while maintaining the existing level of security of supply. A key calculation in this process is the capacity credit or value of wind generation. Capacity credit/value of wind generation can be broadly defined as the amount of firm conventional generation capacity that can be replaced with wind generation capacity, while maintaining the existing levels of security of supply. This topic has been the subject of much study and debate in recent times. The aim of this paper is to give an overview of the state of the art in this area, in particular with regard to the work of IEA WIND Task 25 and the work detailed in its state of the art report on the design and operation of power systems with large amounts of wind power.

Wind power plant output depends on wind speed. Such speeds cannot be accurately predicted over daily periods because the wind fluctuates from minute-to-minute and hour-to-hour. Consequently, electric utility system planners and operators are concerned that variations in wind plant output may increase the operating costs of the system. This concern arises because the system must maintain balance between the aggregate demand for electric power and the total power generated by all power plants feeding the system. The operators' concerns are compounded because unlike conventional power plants that are generally under their control and thus are dispatchable, the wind plants are controlled by nature. It should be understood that the key issue is not whether a system with a significant amount of wind capacity can be operated reliably, but rather to what extent the system operating costs are increased by the variability of the wind.