How to manage the green revolution.
Gordon van Welie is president and CEO of ISO New England Inc.
The introduction of competitive markets a decade ago triggered remarkable changes in an electric industry that had been conducting business in essentially the same manner for more than 70 years. These markets have fostered tens of billions of dollars of investment in generation and transmission, and have inspired entrepreneurs to develop novel technologies to modernize the system and make it more efficient.
In the decades ahead, more dramatic changes can be expected. They likely will be sparked by a surge of renewable energy development and the transmission needed to deliver its power to customers, the rapid expansion of demand-side resources and conservation, and the emergence of smart technologies that promise greater efficiency, reliability, and controllability—for operators and customers alike.
Realizing the potential environmental and economic benefits of these impending changes will depend, however, on successfully integrating these resources into the power system reliably and in a cost-effective manner.
Ten to 20 years from now, the power grid will look considerably different from the way it looks today. Although large, centrally located power plants will remain at its core, the power system of the future likely will be more dependent on wind farms, biomass, small hydro, photovoltaics and other renewable sources across both the transmission and distribution networks. The grid and its operators also might rely more on distributed energy sources for capacity, demand-side resources to reduce electricity use, and storage devices such as flywheels, batteries and plug-in electric vehicles (PEVs) that can make use of economic off-peak energy to help satisfy on-peak demand. In addition, innovative technologies, such as advanced meters, smart appliances and intelligent thermostats, will be deployed in homes and businesses to allow consumers to adjust their electricity use and lower system demand in response to real-time price signals.
This new mix of resources will add a significant amount of intricacy to an already complex power system. Unlike conventional generating plants, these new renewable resources have variable operating characteristics and will be scattered across the region wherever conditions are best suited to the type of resource being implemented, with many located far from demand centers. The future system – and its operators – will need to adapt to the challenge of managing thousands more resources and processing an exponential increase in the volume of data on a day-ahead and real-time basis. New communications technologies will be needed to ensure that grid operators can see and forecast what is happening—or about to happen—on the grid to maintain control of the system. Grid operators will need to be trained in the new technologies that will allow them to reliably manage a system in which conditions can change the moment the wind stops blowing or a demand-side resource is unable to respond. Policymakers, regulators and grid planners will have to assess the need for hundreds, maybe thousands, of miles of new transmission lines to connect these new resources to the bulk power system, and ultimately decide where they will be sited and who will pay for them.
New England is fortunate to have already in place a long-term planning structure that has served the region well during the first decade of restructuring. The region’s stakeholders have extensive experience working together to produce annual assessments of the infrastructure needed to maintain a reliable bulk power system. And to stay ahead of the curve, stakeholders in New England already have launched several new, comprehensive planning initiatives to ensure the region’s power system adapts to anticipated changes.
Already underway, these studies and planning initiatives will:
• Model system behavior at various concentrations of wind power;
• Develop a conceptual analysis that looks at how much new transmission backbone may be needed to connect renewable facilities potentially scattered across the landscape, including order-of-magnitude cost estimates;
• Determine how to integrate demand-side resources effectively; and
• Facilitate the use of smart-grid technologies.
These planning initiatives will help ensure the region charts the right course as it prepares for the grid of the future.
Policies and Incentives
Over the past several years, new state and federal environmental policy initiatives have piqued industry and investor interest in developing renewable energy in New England.
Ten Northeast and Mid-Atlantic states have joined the Regional Greenhouse Gas Initiative (RGGI), the first market-based effort in the United States to reduce carbon dioxide (CO2) emissions from power plants. RGGI, which went into effect at the beginning of 2009, established a cap-and-trade system, imposing an immediate cap on larger power plants’ CO2 emissions and mandating a 10-percent reduction in the cap by 2018. RGGI auctions emission allowances for the states, which will use most of the proceeds to promote energy efficiency, renewable energy, and other clean-energy technologies.
Five of the six New England states also have enacted individual renewable portfolio standards (RPS) mandating that varying levels of electricity come from renewable sources and imposing different deadlines. Vermont has established goals, similar to RPS, for renewable energy growth. Combined, the states’ RPS and related targets call for 30 percent of New England’s projected total electric energy demand in 2020 to be met by renewables and energy efficiency.
Considerable momentum also is coming from Washington, where the president and Congress have made upgrading the nation’s power grid a priority. Billions of dollars in the initial federal stimulus bill are dedicated to modernizing the grid and providing grants, tax breaks and loan guarantees to ramp up the development and deployment of renewable power and smart-grid technology.
This potent combination of federal and state initiatives has increased regional activity in developing renewable energy, with most of it now focused on wind.
Integrating Wind Power
Over the course of 2008, wind power in New England grew from 20 MW in operation to nearly 100 MW by year’s end. Although wind energy today represents only a fraction of the region’s total capacity, this growth rate is expected to continue (see Figures 1 and 2).
In a very short time span, wind has become the dominant choice for renewable energy among developers, and as of Sept. 1, 2009, represented almost 85 percent of the proposed renewable projects in ISO New England’s generation interconnection queue (see Figure 3). More than 2,800 MW of wind projects are currently in the pipeline: more than 800 MW of proposed offshore projects and 2,000 MW of proposed onshore projects. The level of nameplate wind capacity in New England could triple by the end of 2010, to 300 MW or more.
With zero emissions, wind resource development will help achieve the states’ environmental goals and lessen the region’s reliance on fossil fuels to produce electricity.
But integrating a large portfolio of wind power poses several challenges for grid operators. Since wind turbines produce power only when the wind blows and wind speed is variable and difficult to predict, forecasting output from wind resources is an inexact science. This uncertainty can lead to an over- or under-commitment of other resources on the system. In real time, a sudden change in wind speed or direction can lead to a change in output that would require corrective action by system operators. In addition, the wind blows longer and faster at night, while peak demand occurs during the day, thus making electricity storage a desirable future resource.
Earlier this year, ISO New England initiated the New England Wind Integration Study (NEWIS) to take a comprehensive look at how onshore and offshore wind energy, demand resources, traditional generation, and transmission will interact once operational. The study will model numerous scenarios of wind development and identify operating issues created or exacerbated by the variability and unpredictability of wind power output.
NEWIS is developing an accurate and flexible forecasting model based on three years of historical wind speed and directional data (2004 through 2006) and the possible location of onshore and offshore wind resources. This model will be used to run hypothetical scenarios of power system and wind generation interaction based on various levels of potential wind development, from 1,200 MW to 12,000 MW, representing 2.5 percent to 20 percent of projected consumption. The impact of each scenario on wind power forecasting, unit commitment, reserve requirements, automatic generation control, emissions, carbon costs, and locational marginal prices will be analyzed.
NEWIS also will evaluate the ability of wind facilities to provide grid support functions, such as regulation, and analyze potential reliability issues related to maintenance and scheduling requirements and the loss of energy output when wind speeds reach levels too high to operate turbines.
The results of the study, expected to become available next year, will be used to assess whether modifications will be needed in operating requirements, guidelines or standards, and whether new market rules would help to reliably integrate new wind generation.
New Transmission Needed
As the amount of renewable resources increases—in particular large amounts of wind power—new transmission lines will be needed to deliver these resources to market. In early 2009, the governors of the six New England states asked the ISO for technical assistance in creating a regional blueprint for integrating large-scale onshore and offshore renewable energy sources—mostly wind—into the region’s electric power grid. The technical analysis also looks beyond New England to include possible increased imports from New York and Canada where large-scale generation facilities are under study and development, including wind, hydro, and zero-emission nuclear power.
The technical analysis for the governors evaluates the economic and environmental impacts of numerous scenarios of resource and conceptual transmission development between now and 2030. The results are intended to inform the governors’ and other state policymakers’ decisions about how to meet their stated goals of providing cost-effective, low-carbon, secure electric energy to New England consumers.
The analysis shows that higher concentrations of renewable energy would result in lower wholesale electric energy prices and a significant reduction in emissions compared to conventional fossil fuel generation. It also identifies the conceptual transmission development and estimated costs to integrate the resources envisioned in each scenario.
Because the region’s population centers generally are located far from the remote areas with the best potential for wind development, it’s possible that new backbone transmission facilities will be required to connect wind to demand centers. How large a backbone is needed will depend on how much wind is developed and where it’s sited.
The ISO’s study team evaluated various options and its analysis was presented to the region’s governors for review in September 2009. The 2,000-MW scenario of new offshore wind resources identified conceptual transmission development of about 1,000 miles of new extra-high voltage (EHV) lines (345 kV) and a submarine cable from Maine to Massachusetts. If the region were to fully develop 12,000 MW of wind, the conceptual study indicated more than 4,000 miles of new EHV (500 kV or 765 kV) lines could be needed. The cost estimates for developing the potential transmission configurations range from about $1.6 billion to just over $25 billion.
These conceptual findings will require considerable additional economic and technical analysis before it will be possible to decide how much transmission ultimately may be needed, where it would be built and who would pay for it. New England’s long history of coordinated regional planning will be crucial as the region moves to address the transmission requirements of integrating renewable power.
The Role of Demand Resources
The policies related to renewable portfolio standards require load-serving entities to show electric energy savings through reductions in demand. In New England, demand response already is an important tool used to manage the region’s power system during heavy demand periods. Since 2003, New England has seen a tenfold increase in the amount of available demand resources (DR), due in large part to the region’s forward capacity market (FCM), which has allowed demand response, energy efficiency, and distributed generation to compete on a level playing field with generation in New England’s annual capacity auctions. By 2011, DR is projected to account for nearly 10 percent (3,000 MW) of the region’s capacity—the highest percentage of any region in the nation (see Figure 4).
From a daily operational perspective, a potential 10-percent reduction in electricity use during peak-use periods or unforeseen system events has obvious benefits. In the long term, DR can defer the need to build additional transmission, generation and distribution facilities, reduce emissions that contribute to air, land and ground pollution as well as atmospheric changes, and reduce the region’s reliance on imported fuel supplies. In addition, demand-response resources may facilitate the integration of wind resources by reducing demand when the wind stops blowing. To achieve these benefits, the region must prepare to effectively integrate this high level of demand resources into power system operations.
In 2008, the ISO initiated a two-year demand-resource integration project to identify potential barriers to participation and develop solutions. The project already has produced an initial analysis of how these resources would respond under varying conditions and, through collaboration with stakeholders, developed modifications to operational procedures and FCM rules to address issues that the analysis revealed.
To avoid fatigue that could develop among demand-response providers that are called upon too frequently, new dispatch rules scheduled to go into effect next summer divide the region into dispatch zones to allow operators to call on active DR resources precisely where, when, and how often they are needed, rather than calling on all of them every time demand-side reductions are required.
In addition, improvements to the current active DR software and communications infrastructure will be implemented, ensuring that system operators and DR resources can communicate with each other in real time.
The ISO has revised its emergency operating procedures to more effectively employ demand-response resources as reserves. Efforts also are underway to integrate the dispatch of active DR resources alongside conventional supply resources, using a common, standard communications platform.
To improve coordination between the ISO and demand-resource aggregators, the region is creating demand-designated entities (DDEs), which will be responsible for receiving and acting on dispatch instructions from the ISO. DDEs will be the only entities the ISO will communicate with to dispatch instructions for demand resources, thereby streamlining and expediting dispatch of DR.
Stakeholders are continuing to study other issues related to the coordination of, and communication with, demand-response providers to ensure they are used as efficiently as possible to lower demand on the system when needed. Additional changes in procedures or market rules will be made if necessary.
A Smarter System
As the region prepares to embrace large amounts of demand-side and renewable resources, ISO New England is preparing the foundation to improve efficiency and enable the addition and reliable dispatch of these alternative resources.
For New England, the smart grid is the integration of three different types of infrastructure: power system, communications, and information technology infrastructure. Integration of these three components will give grid operators better visibility and control over the system and provide consumers with new tools to manage their own electricity consumption and costs. The ISO actively is implementing several smart-grid projects to better manage computer networks and power system resources, and several smart technologies successfully have been integrated into the transmission system.
The remote intelligent gateway (RIG) master communications equipment, which is based on an older, proprietary technology and is used to dispatch and collect data from generators, is being replaced with more widely available, industry-standard equipment and more efficient processes.
The ISO has installed two phasor measurement units (PMU) as part of the Eastern Interconnection phasor project, a national effort by the U.S. Department of Energy to create a robust and secure synchronized data-measurement infrastructure for the interconnected North American electric power system. PMUs help control-room operators to understand system dynamics in real time.
In addition, an online decision-support tool is being assessed to help operators restore the power grid in real time after a blackout. Currently, system restoration primarily is based on offline planning and manual work by control-room operators.
The region also is closely following the emergence of energy-storage technologies to boost reserves, including PEVs, which can be charged overnight and used as a supply-side source of electricity during the day. How to harness that potential source of reserve energy is being evaluated. Additionally, to help keep the system’s frequency regulated, a pilot project is being implemented to evaluate the capability of non-generating resources, such as flywheels, to perform this function in the regulation market.
In August, the ISO submitted two proposals to the DOE to fund investments in technologies that would significantly advance the development of the smart grid across the region. One application seeks to expand the base of synchrophasors to accurately monitor the performance of the power grid, and the other incorporates several smart-grid demonstration projects, including wide-area monitoring and development of software that would automate the selection of the mechanisms grid operators use to coordinate and adjust voltage profiles across New England.
The ISO also is conducting or involved in a number of other activities related to smart-grid research, education, standards development, and planning. These activities aim to enhance the understanding of smart-grid technologies; educate market participants, regulators, legislators, and others in New England and across the industry about the smart grid; and develop uniform standards to ensure compatible technologies.
New England’s power system is entering a period of tremendous change. Many of the processes and procedures that have achieved a high level of grid reliability in New England must be adapted to reliably accommodate new types of supply and demand resources, as well as the expanded use of electricity for transportation and other purposes. While the integration of renewable resources will take transmission planning and siting to new levels in New England, developing the ability to use new, often scattered resources such as variable wind or demand-response resources will accelerate the advances in technology that will comprise the smart grid. There is a convergence occurring in New England among new smart-grid and renewable technologies, public policy, and power system planning and operations. It’s vitally important that New England policy makers, industry participants, and the ISO continue to work closely together to fully realize the potential of these new resources and technologies.