The electric infrastructure faces a unique combination of transformative technology advances and unusually strong policy and market changes. This confluence presents the U.S. with the opportunity to strategically define a future power system that offers significant value in terms of reliability, resilience and economic competitiveness within the context of our aspirations for clean and secure energy systems. However, institutional and policy innovations will be required to capture the full opportunity before us. To achieve this, all stakeholders will need to work together systematically to define the objectives and 20- to 50-year national outcomes necessary to guide this important transformation.
Information technologies promise to substantially transform the electric power system and the way it serves consumers and the nation as a whole. From power plants to customers, digital technologies are triggering substantial innovation in monitoring, communications and control across the system. These innovations, collectively described as “smart grid,” have the potential to dramatically change the way we plan, build, and operate the electric system, from generation to end-user. They have the potential to enable a profound level of system transparency across entire interconnections, enabling operators to see actual system dynamics in real time and manage reliability and asset utilization with exceptional precision. And digitization of the distribution system, including smart metering, will provide transparency of demand and local operations that enable operators to treat demand as an actual tool in grid management rather than a simple boundary condition.
Beyond technology innovation, market and policy initiatives at the state and local levels to reduce emissions have launched a dramatic change in the generation portfolio that’s happening now and in the near future. Growth in intermittent generation from wind and solar has advanced significantly in the past five years. And emerging clean energy strategies are driving a move toward greater reliance on natural gas supplies, while some coal-fired power plants are being considered for closure. These shifts in the generation portfolio strongly influence grid planning and operations because they affect frequency response and voltage management, while balancing services become increasingly challenging to provide.
Another driver for change is the general pause in deregulation in the last five years. This—combined with continued innovation in new approaches for engaging demand, such as demand response and ancillary services markets—has left us with a variety of regulatory frameworks, within which regional and interconnection-scale operations must operate.
Finally, the progressive adoption of plug-in hybrids and electric vehicles to reduce oil imports in support of national energy security goals offers a new load for electricity that must be considered in transmission and distribution (T&D) system planning.
Important progress has been made in expanding clean generation and testing the benefits of digital innovations at the T&D level. Markets for ancillary services and demand response are emerging in some areas, and innovative approaches are emerging to offer ancillary services products in unstructured market areas. Overall, however, our regulatory environment has struggled to keep pace with advances in technology and alternate generation strategies.
Fundamentally, new tools and new expectations require reevaluation of the institutions and practices that have provided reliable and affordable electricity for the past century. Current technology and policy drivers require extraordinary collective action to: A) define the key attributes of a future grid that best serves historical and emerging societal objectives; and B) adapt our processes and institutions to align with the vision of desired grid attributes.
One example attribute that will dramatically increase in the future electric system is system flexibility, and in particular the capacity to optimize electric system operation across multiple electric operational and market domains. Another example could be new control paradigms based upon system-wide observability that are inherently more resilient and supportive of a generation portfolio with substantial intermittent resources and smaller, gas-fired generators. A third attribute might be transparency in pricing and system performance to engage end users and give them greater choice in their energy decisions.
Fundamentally, the U.S. needs to develop and adopt institutional processes that meet both the time-tested objectives of the past and also capture the potential new values offered by the sweeping technology and policy changes we are experiencing today and over the next 50 years.
Technology and policy often alternate being lead and lag forces as we progress toward future evolving societal objectives. Changes in these objectives, such as environmental quality, often necessitate the creation of policies that inspire the development of technology to enable these new societal goals. At other times, advances in technology, such as those related to energy efficiency and customer self-generation, lead to the transformation of policies to fulfill new societal objectives, such as low-cost electricity and improved environment. While both of these circumstances exist at all times to varying degrees, we are entering a time of concurrent change in both societal objectives and transformational technology capability, with the potential to dramatically advance the electric system infrastructure and its operation.
Specifically, smart grid innovations and the push for renewable generation are affecting both the transmission system and the distribution system.
For transmission, the major advance is in the area of wide area measurement and control. The introduction of new sensor and monitoring technologies, principally the deployment of synchro-phasor monitoring equipment, will enable grid operators to have unprecedented, real-time visibility into the state of the grid at virtually any location. In the wake of major outages of the past, DOE, NERC and the utilities have worked together to both refine and deploy phasor monitoring units (PMU). The North American Synchro-Phasor Initiative (NASPI), launched by DOE and now led by NERC with support from DOE, is in the process of deploying hundreds of these PMUs throughout the three major interconnections in North America (see Figure 1).
By the end of 2012, with previous industry investment and the recent co-investment by industry and federal ARRA funds, the deployed U.S. PMU inventory is expected to exceed 1,000 devices. This fleet of smart grid devices has tremendous potential to transform monitoring and operations at the interconnection, regional and local levels. These monitors will provide precise time-stamped1 electric power status at monitor locations 30 to 60 times a second. By collecting and sharing this information in real-time, the condition of the entire grid can be observed, and operations can be coordinated to ensure reliability is maintained.
While wide-area coordination has occurred in the past, it has primarily been within limits established by off-line studies, lengthy analyses (typical focusing on worst-case scenarios), and embodied in regional agreements. The advent of wide-area, real-time monitoring as enabled by NASPI will dramatically increase the coordinative potential, perhaps even creating the opportunity for near-real-time operation and control of major grid functions throughout an entire interconnect. At a minimum, it will enable more coordinated control, sharing of reliability assets, reduction of aggregate reserve requirements, and better utilization of both existing grid assets, as well as optimized deployment of new assets.
Research is underway to craft new tools that leverage phasor data to improve system control and ultimately test the value of real-time control. Research in the Western Interconnect is comparing the benefits of adaptive islanding based upon real-time phasor data to determine its performance relative to traditional, predefined protection schemes. And utilities in the U.S. and China are designing real-time controls for select portions of their systems to improve resilience and reliability.
These advances in situational awareness and real-time monitoring and control of system dynamics offer the promise to improve both system reliability and asset utilization across the transmission system. Many major corridors today are rated on a seasonal basis, often leaving significant amounts of assets underutilized for significant periods of time. Ultimately, real-time high-resolution monitoring and operations enabled with phasor technology should provide more precise asset utilization, increased potential for renewable integration, improved reliability and high resilience.
Smart grid technologies at the distribution system level are focused on achieving better electrical service at lower cost through the use of ubiquitous, distributed communications and controls. Smart grid is envisioned as a means to enable loads (customers) to be full participants in delivery of electric service. Distribution system automation is also considered an important element of a smart grid.
These concepts, when linked to smart meters and premise gateways, are enabling a range of integrated, interactive load-control efforts that have the potential to enhance consumer engagement in energy options and add demand to the tool kit we use to manage the grid of the future. One previous test bed project on the Olympic Peninsula in Washington state employed a transactive-control approach to smart grid implementation at the consumer level. For this project, they observed peak load reductions of approximately 15 percent and successfully utilized “Grid Friendly” appliances for under-frequency load shedding, when needed. Aspects of this previous project will be broadened and more comprehensively tested during one of the new ARRA-funded smart grid demonstration projects, the Pacific Northwest Smart Grid Demonstration, with 11 utilities and 60,000 customers participating. In total, 14 regional smart grid demos are underway around the country, providing an emerging resource for understanding the benefits of a range of smart grid concepts at the distribution level.
The capacity for load to provide reliability support has long been in the operator’s toolbox, but usually as utility-controlled unscheduled or emergency load shedding. The potential for distribution smart grid concepts to provide grid reliability benefits in a less intrusive—and presumably less expensive—manner, implies that it could complement as well as compete with other methods for providing reliability services—i.e., load following, frequency management, etc.
One example is the use of customer storage for providing grid regulation services. Perhaps the most intriguing prospect for use of customer storage for grid support is associated with deployment of plug-in hybrid electric vehicles (PHEV) and electric vehicles (EV). While vehicle to grid (V2G) services have been suggested and analyzed2 for providing grid services, concerns over voiding vehicle warrantees—due to deep discharge—suggests caution with this approach. An alternative version, V2G½, allows the utility to vary charging to provide grid regulation service.3 Analysis of this approach suggests that significant regulation service could be provided even when confined to the charging cycle for PHEVs and EVs.4 As with some grid support options, such as frequency support, the location of the asset isn’t a vital attribute; what is vital is that it’s available, dispatchable, and reliable. Smart grid assets can provide both local and wide-area grid support, if institutionally enabled.
The use of smart grid as a means of providing regional or even extra-regional reliability services will require means of incenting and rewarding such use. To the degree this can be accommodated within existing markets and regional and extra-regional agreements, no further institutional or regulatory action is needed. However, it’s more likely that the institutional underpinning for wide-area utilization of smart grid assets hasn’t yet reached a state that it would enable such utilization.
Deployment of renewable generation is growing rapidly, in part as a response to financial opportunities to receive state renewable energy credits (legislated by renewable portfolio standards) and federal production tax credits. Over 63 percent of the total electric generation additions in 2009 were wind power.5 While wind power additions were lower in 2010 (estimated to be about 40 percent of new generation), wind and growing solar electric generation will continue to be a significant source of new generation additions, at least as long as state and federal subsidies encourage development. The prospect of continued low natural gas prices entices development of gas-fired generation, but if concerns over greenhouse gas emissions remain strong, our future will include substantial amounts of new renewable generation.
One major challenge with variable renewable generation—namely wind and solar—is its stochastic nature, and potential for sudden ramps, both up and down. Wind ramp rates exceeding 100 MW per minute have been observed at the control area level, even at the relatively modest levels of wind power penetration today. Such variability causes significant challenges for grid operators, as they seek to balance electricity generation to meet load.
Grid operators are developing improved tools to manage this higher level of generation uncertainty, using improved forecasting, better understanding of the probabilities of high ramp rates (and associated reserve requirements), and increasing the use of existing assets capable of rapid load following and spinning reserve. However, here too, the potential to tap into dynamic resources outside the control area in a highly coordinated, near real-time basis is a very attractive option. A certain amount of this is enabled now, but not at the scale or temporal granularity that will be desired in the future.
A number of studies are underway to explore the potential for greater coordination among various control areas. In the Pacific Northwest, this is partly motivated by the relatively high penetration of wind generation (see Figure 2). In the case of the Bonneville Power Administration (BPA) control area, current wind power capacity exceeds half of average load, and is projected by 2015 to be 40 percent greater than average load and more than 80 percent of peak load. Most of this wind power serves load outside of the BPA control area.
Despite the significant transmission capacity to major load centers in California, managing such high penetrations of variable renewable generation will be difficult within a single control area. Therefore, it’s important to increase coordination of operations with neighboring balancing areas, particularly for reliability services. Beginning in 2008, system operators in the Pacific Northwest formed a joint initiative that would, in part, explore a range of measures aimed at improving flexibility to address high ramp rates, and stochastic uncertainty in regional grid operations. Efforts are leveraging development of an efficient dispatch toolkit and an intra-hour transaction accelerator platform. However, major issues exist, such as differing operating regimes and criteria, schedule flexibility, ability to adequately address economics and reliability, and improving transmission access for non-firm transmission transactions.
Other studies are looking at potential benefits of increasing coordination of control areas in the Western Interconnect.6 One major study,7 to be completed next year, has reported interim results that suggest economic advantages exceeding $250 million from greater coordination and consolidation, and it’s expected that additional financial benefits will be identified as the study progresses. In another study,8 the potential for wide-area coordinated dispatch of fast and slow storage resources in distant locations for providing grid regulation has suggested considerable advantage in sharing of such resources. Additional studies9,10 either assume or require substantial control area coordination to accommodate the substantial penetration of wind power.
The key attribute of these studies is that closer coordination—perhaps even consolidation—of grid control areas, will be necessary to integrate such variable generation and take advantage of potential generation diversity, and to access available, under-committed assets in a neighboring control area. Because of the variable nature of these renewable generation sources, reliability will largely be associated with various ancillary services, which aren’t treated equally in various markets, and in many cases can be addressed optimally by reaching across multiple institutional jurisdictions.
Three decades of geographically diverse and sometimes contentious deregulation, policy adaptation, and exploration of alternative electric system enterprises have given rise to an array of different institutional environments for utility services. Beginning with deregulation of power generation and establishment of markets—first for power supply, then for other grid services—and on to recent FERC NOPRs on demand response for reliability services, we have witnessed progressive—if geographically uneven—maturation of power and energy markets. In the next three decades we will be witnessing the seamless confluence of information technology and grid evolution—providing utilities, industry and consumers with the tools to build the power grid of the future. Yet geographically diverse system conditions and development forecasts, combined with diversity and disparate sophistication of markets, create seams in the system that frustrate and complicate the optimal development of the electric grid. While such seams issues might have been most obvious in energy markets, grid reliability could be the next challenge associated with these jurisdictional seams.
The Pacific Northwest might be the testing ground for resolving some of these issues. The high degree of wind generation and its projected growth, along with the absence of intra-hour and reliability markets, and heavy export of wind generation to meet RPS goals outside of the BPA control area, begs for attention—not just in the Northwest, but in the entire Western Interconnect. For example, the California goal of 33 percent RPS will stimulate a considerable addition of renewable generation. Thus development of the necessary institutional vehicles that enable wide-area reliability support is in the best interests of all. In the absence of such coordinated attention, issues such as the excess generation currently facing BPA and the wind industry in the Northwest; cross subsidization of reliability services; transmission planning and access; and, ultimately, the addition of common resources (such as central storage) will be potentially contentious, slow and fragmented.
There is incredible activity across the electric infrastructure environment today. Technology innovations in the smart grid, RPS-driven renewable generation and recent growth in new natural gas generation are visible in all geographic regions and types of utilities in North America. Regulators at the state and federal level are evaluating the benefits of new technologies and encouraging local demonstrations and, in some cases, state-wide adoption. Congress in the Energy Independence and Security Act (EISA) of 2007 established the first legislation for smart grid that provided a blueprint for the subsequent public (ARRA) and private investment in more than $16 billion of smart grid infrastructure and demonstration.
These are just a few of the broad and productive activities currently underway across the electric infrastructure landscape. Progress is being made, and lessons are being learned. The challenge is how to complement this productive but mostly bottom-up, diverse effort with a higher level, systematic approach across all grid stakeholders that addresses the questions that reflect national and regional imperatives, such as:
• Beyond improving current grid paradigms of operation and protection, how can the digitization revolution in the grid deliver new value to consumers and help deliver national energy, security and economic objectives?
• Given that we have revolutionary new tools with unheard precision and speed, what new paradigms of power system operation and control might we strive toward in 2050 and 2100?
• What policy innovations are needed to align grid planning and regulatory environments to the natural 50+ year infrastructure investment horizons that are necessary for the U.S. to have a competitive, digital economy in 2050 and 2100?
• How can the nation best achieve public objectives of clean energy and energy security in ways that are technology neutral and environmentally certain?
• How do we ensure inherently secure and resilient power systems as they become increasingly digital?
• What levels of transportation electrification are required to meet national objectives for reduced oil imports and energy security, and what power system adjustments are needed to accommodate these goals?
• What ratios of baseload, intermittent and distributed local generation are required to ensure adequate reliability, resilience, security and asset utilization for the system we want in 2050? How do those ratios change under different paradigms for control or national emissions policy?
The following next steps represent suggested efforts to raise the strategic guidance of our investment and energies currently directed towards the grid—hopefully helping better guide long-term success in choosing the grid that we want for our future. This is by no means an exhaustive or complete grid transformation agenda, but reflects important opportunities to substantially augment the current good works underway.
1) Establish a systematic, national review of existing methods and constructs involved in reliability management to identify innovations that reflect emerging technical capabilities and new energy policy aspirations. Each of the four North American interconnections are comprised of balancing areas and control areas with long-established approaches for cooperatively assuring grid reliability. With the advent of significant intermittent renewables transforming the need for balancing services comes the promise of innovations in how balancing areas interact and cooperate, which will help utilities integrate the growing share of renewable power. Various studies are underway across the country. A coordinated national approach would help to identify optimal innovations that support renewables but retain reliability and security.
2) Examine how best to provide ancillary services in a future where smart grid technologies enable wide system transparency, where state RPS initiatives drive significant increases in intermittent, renewable generation, and where consumers have real-time observability of energy use and options. We need regulatory innovation that provides a level playing field for all technology options for ancillary services and unleashes the innovation that’s possible in our current and emerging technology assets.
3) Innovate the delivery of energy services across wider regional areas as monitoring and communications technologies improve and state RPSs call for increased renewable generation that is far removed from load centers. New information tools enable new concepts for inter-regional cooperation that will improve asset utilization and lower balancing costs.
4) Develop interconnection-scale operational and dynamics models for the Eastern Interconnection (EI), spanning the current five reliability councils, to boost the coordinated utilization of emerging smart grid infrastructure across the EI. Such tools exist in the other three North American interconnections (WECC (western U.S.), ERCOT (Texas) and Quebec) primarily because they are served by a single reliability council. Having such models would significantly accelerate the ability of EI utilities to validate new smart grid tools and concepts that would support situational awareness, enhanced voltage and frequency management, enhanced integration of renewables and improved system protection and restoration.
5) Update macro energy policy analysis tools to reflect the role of the electric power system in overall energy policy analyses. The current tools (National Energy Modeling System, NEMS) have very limited ability to reflect the impact of power system investments, thus hindering the national grid policy debate on how best to deliver the grid we want in 2050 and beyond.
6) Answer the question, “How can we best conduct the debate on defining the grid we want in 2050?” Concurrent forces of smart grid innovation and clean energy policy combine to offer the possibility for shaping the answer. One potentially constructive approach would be for the nation to complement today’s broad local and regional efforts to modernize the grid with a structured, transparent discussion across all stakeholders to define the power system that we want and can have with the new tools that are emerging.
This discussion should be centered on a set of long-term, national outcomes and key questions, and informed by a robust set of energy scenarios that provide a basis for planning, investment and innovation by all stakeholders. This is a substantial body of work that is likely to take years to complete. The objective would be to ultimately provide a long-term set of targets for investment and transformation that fit the time horizon of major infrastructure investments, and to inform where institutional and regulatory innovations are required to complement technology and business advances to maximize the overall effectiveness of our collective national investment in our future power system.
The future is bright with opportunity to dramatically improve our current system and create bold new approaches that are enabled by smart grid innovations and the nation’s push for a clean energy future. Now is the time to enhance our systematic approach to making long-term, meaningful transformation a reality.
1. Global positioning satellite timing signals are ubiquitous, precise and accurate, enabling determination of local voltage and current—and associated phasor—at a rate of 30 times per second or faster, compared with supervisory control and data acquisition readings, which occur at a rate of once every 4 seconds.
2. Assessment of Future Vehicle Transportation Options and Their Impact on the Electric Grid, DOE-NETL-2010/1466, National Energy Technology Laboratory, Jan. 10, 2011.
3. Kintner-Meyer, M., “Smart Charger Technology for Customer Convenience and Grid Reliability,” Electric Vehicle Symposium 24, Proceedings, Stavanger, Norway, May 15-17, 2009.
4. Tuffner, F. K. and M. C. W. Kintner-Meyer, “Using Electric Vehicles to Mitigate Imbalance Requirements Associated with an Increased Penetration of Wind Generation,” in Proceedings of the 2011 IEEE PES General Meeting, Detroit, Mich., July 24-28, 2011 (forthcoming).
5. Electric Power Industry 2009: Year in Review, Energy Information Agency, Issued November 2010, updated January and April 2011.
6. Y. V. Makarov, et al., “Analysis of Balancing Authorities’ Cooperation Methods with High Variable Generation Penetration,” Proc. 9th International Workshop on Large-Scale Integration of Wind Power into Power Systems as well as on Transmission Networks for Offshore Wind Power Plants, Québec City, Québec, Canada, Oct. 18 and 19, 2010.
7. N. Samaan et al., Evaluation of Potential Benefits of Leveraging Diversity of Variable Resources, Loads and Conventional Generation Across the Western Interconnection, PNNL, NREL and WECC, July 2010.
8. N. Lu, et al., The Wide-area Energy Storage and Management System Phase II Final Report – Flywheel Field Tests, PNNL-19669, 2010, PNNL, Richland, Wash.
9. Eastern Wind Integration and Transmission Study, EnerNex Corp., Revised Feb. 2011.
10. Western Wind and Solar Integration Study, GE Energy, May 2010.