Grid congestion occurs when transmission lines can’t carry enough power to meet customer demand, posing challenges for regional grid managers throughout the US. Recently in Texas, the transmission system has been experiencing congestion more frequently. During periods of peak demand when system-wide load reaches 55 GW or more, congestion occurs over 90 percent of the time. The New York independent system operator projects that over a ten-year period, congestion will increase in almost all constrained areas. In New England, the regional grid manager is curtailing wind power generation due to local transmission constraints. From coast to coast, congestion in the US adds billions of dollars to the cost of transmission while threatening grid reliability. Meanwhile, the distribution system is facing its own set of grid stability challenges as rooftop solar and other distributed energy resources (DERs) alter grid voltage and frequency profiles. It has become very clear that the existing grid is an overused and outdated infrastructure.
Utilities, state regulators, regional grid managers and national policymakers all rely on planning procedures to guide them along the way towards modernizing a hundred-year-old electromechanical grid so it can serve the needs of customers in these data-driven times. Quite often, technology innovation and changes in consumption habits happen too fast for industry leaders to sit down and revise the latest roadmaps. Even if increasing transmission capacity was the only solution, construction couldn’t happen fast enough to stave off further constraints. But capacity expansion is not the only solution. New grid-side and customer-side technologies backed by an up-to-date regulatory framework can vastly reduce the distance to a smarter, more flexible grid. Knowing the impacts that DERs have on T&D infrastructure, regulators can proactively address power quality concerns, such as by encouraging solar-plus-storage to help manage resource intermittency at the point of interconnection. This paper, CIGRÉ’s Roadmap to a Smarter, More Flexible Grid, looks at key market and regulatory developments affecting the rollout of such a smarter, more flexible grid.
Smart Grid Implementation T rends
Over the past five years, the utility industry has made significant progress in the development and commercial deployment of smart grid technologies, moving at an unexpectedly rapid pace even by the most enthusiastic forecasts. The accelerated adoption of DERs has paved the way for electric service providers to configure virtual power plants (VPP) that perform all the roles of a major power station. The industry continues to see increased market penetration
for advanced metering infrastructure on both sides of the meter, providing real-time information that unlocks new opportunities, such as operating demand response as a dispatchable resource. New markets, meanwhile, can disappear as quickly as they emerge, as we’ve seen with rooftop solar in Nevada. These changes demand a reassessment of short- and longterm plans.
Virtual Power Plant Deployment
Following the leadership of electric companies in Western Europe, the US is beginning to see electricity providers integrate DERs on a large scale, operating many small units as a single entity, a virtual power plant. DERs on their own—including rooftop solar, energy storage, plug-in electric vehicles, and demand response systems—can raise grid stability issues at the distribution level and introduce challenges to the utility business model. Virtual power plants provide the ability to control generation and load. Using demand response to scale back consumption, VPPs can optimize load reduction in response to day-ahead forecasts and real-time power consumption.
France’s Provence-Alps-Côte d’Azur (PACA) region has local generating capacity to supply less than half of the region’s demand, requiring imports from other regions via a double-circuit 400 kV transmission line. The only alternative to meet regional load requirements is a 225 kV line that already experiences heavy usage. During periods of high demand, the transmission system operator may limit load transfers across the 400 kV line and ask local generating facilities to help make up the shortfall by increasing output. In the winter of 2010-11, the PACA region helped launch the PREMIO smart grid demonstration project, one of the first such projects in France, to support DER product
development, testing and analysis. After a partial launch, the project has been running all DERs since the winter of 2011-12, achieving service reliability improvements, DER regulation and system analysis, and France is carrying lessons learned into bigger smart grid projects.
In Germany, Siemens has partnered with two utilities, RWE Deutschland and Stadtwerke München, the municipal utility in Munich, to initiate two VPP pilot projects. The RWE project built upon an earlier test run of hydropower plants linked up with combined heat and power units and emergency power systems, a demonstration that showed the VPP concept’s technical and economic maturity. Since 2012, VPP energy output has been traded at the Leipzig Energy
Exchange (EEX) in Leipzig as a participant in the German Renewable Energy Sources Act (EEG). The Stadtwerke München project was created to improve regional DER planning and forecasting. The first stage includes 8 megawatts (MW) of cogeneration integrated with 12 MW of hydropower and wind power. These plants can operate more efficiently as a VPP than as separate plants.In 2011, Tennessee Valley Authority started looking for a demand response management system to deploy demand response as a VPP but found that systems were designed for day-ahead programs. TVA developed a custom solution to help grid managers deploy resources effectively. Though the system
does not include generation, TVA considers it a VPP because, operated as a single entity, aggregated demand response is a dispatchable resource that is integrated into the daily resource plan. TVA dispatches resources from least expensive to most expensive according to load requirements, providing grid managers with an overview of resources to adjust as load rises and falls. Units with low operating costs, such as hydroelectric and nuclear resources, usually come first. More expensive coal power and combustion turbines come last. As a VPP, demand response resources are deployed as load increases. This brings demand response into the real-time operational picture. So far, system development milestones include a near real-time view of current load, the ability to calculate curtailable load, recording of participant performance, telephony notification, and mobile view of system and products. Grid managers
need a near real-time view of load available for curtailment for the VPP to work. They obtain data from four sources: SCADA, ICCP, meter data management systems (MDMS) and load forecast.
Adoption Of Advanced Metering Infrastructure
One of the greatest challenges of smart grid adoption is the degree of organizational transformation that is required to take full advantage of new technologies. Procurement is only one step in the process, preceded by a commitment to breaking down organizational silos and followed by system integration, process management overhaul and recruiting to fill gaps in data management, analytics and reporting. Organizational challenges increase as companies move past lowhanging fruit like metering and billing automation to try to capture more value by integrating systems and data across organizational boundaries. For many US utilities, the operational benefits of advanced meteringinfrastructure (AMI)—including reliability and efficiency improvements and cost reductions—have outweighedthe initial cost of change. The evidence can be seen in a major milestone achieved in 2013, when the number of two-way smart meters surpassed the number of one-way meters, according to the Federal Energy Regulatory Commission’s 2015 Assessment of Demand Response and Advanced Metering. A utility survey presented at the CIGRE US National Committee’s 2015 Grid of the Future provides further insight about AMI deployment from a subset of companies that are generally ahead of the curve by national adoption standards. Most of these companies have reached AMI deployment of 75 percent or more. Among grid-side technologies, the most widely deployed systems are two-way SCADA, outage management systems (OMS), and MDMS. The majority had no deployment or plans for microgrids, utility-owned DERs, distribution management systems (DMS) or phasor measurement units (PMUs). An important next step is integrating systems with each other and with existing systems, enabling utilities to share data among different parts of the organization and to coordinate processes that reach across internal boundaries. The most commonly integrated systems are AMI with MDMS, and AMI with OMS. This is consistent with the utilities’ leading motivations for adoption, which are improving reliability and efficiency. On the customer side of the meter, web portals and distributed generation have been most widely adopted. Behind-the-meter technologies such as home area networks (HAN) and in-home displays are not widely deployed, as the utility’s reach usually stops at the meter. Other companies have begun to sell in-home products such as smart thermostats and
smart appliances that can be connected to wireless networks, and controlled by customer devices such as smart phones.
Nevada Solar Reversal
A hallmark of US policy in the development of rooftop solar as a customer-owned distributed energy resource is state-level legislative and regulatory control. Unlike top solar markets of Western Europe and Asia, where deployment tends to follow national priorities, all 50 US states can fine-tune their own market fundamentals through a combination of financial incentives, rate-setting for utility service, and grid interconnection rules. By and large, this has led
to deliberate growth in the market, a stark contrast to Spain, Italy, France, and the United Kingdom, countries that have gone through dramatic boomand-bust cycles driven by changes in feed-in tariffs for solar energy exports to the grid. The state of Nevada began incentivizing the DER market like many other US states by providing legislative support for net metering, an agreement that allows utility customers with qualifying onsite generation to receive bill credits valued at the retail electricity rate. In 2015, the Nevada legislature determined that growth in the rooftop solar market necessitated an end to net metering and instructed state regulators to phase the program out. By January
2016, the regulatory commission had eliminated net metering for all customers, substantially reducing the value of solar energy generation for thousands of customers.Several rooftop solar companies responded by closing sales offices in Nevada, and the solar industry is now backing challenges to the net metering policy reversal in court and at the ballot box. New residential solar market activity has vanished, and customers who generate solar energy are facing a substantially lower return on investment. In effect, the elimination of net metering without a policy alternative has diverted resources away from smart grid technology deployment.
Ideation And Brainstorming To Reset The Regulatory Framework
The regulatory process, whereby stakeholders continually look back at performance metrics to set benchmarks for future results, is designed for continuity. This practice has long excelled at managing transmission and distribution system assets and ensuring that electric service providers maintain resource adequacy. On the other hand, when the task is to transform energy networks, established regulatory processes can hinder participants in a fast-moving market. The current pace of technology change requires flexibility to introduce or modify proposals without undue overhead, whether the goal is setting minimum technical requirements for wind and solar projects in Puerto Rico or fine-tuning retail service tariffs to balance infrastructure costs between customers who operate DERs and those who do not.
National Grid, a British utility company with operations in the Northeastern US, was ahead of the curve when it rolled out an end-to-end smart grid pilot project for the city of Worcester, Massachusetts. Looking back at US Department of Energy smart grid grants funded by the American Reinvestment and Recovery Act, many US utilities were focused on certain aspects of smart grid technology, but not end-to-end solutions. National Grid used a 2010-11 Smart Grid Roadmap to inform and articulate planning and investments required to deliver a grid modernization plan over a period of 5 to 10 years. By paying close attention to technology development, National Grid continues to revisit parts of the plan. For example, further product advances within advanced metering are allowing for distributed processing of meter data rather than pulling meter data back to a control center for processing. It is also preparing for an inevitable shift in workforce training and education needs through an investment in strategic workforce planning. Years ago, it might have been sufficient to revisit the solutions in the plans over a 2- to 5-year horizon. Now, with the rate of change in technology and capabilities, utilities should reassess the solutions on an annual basis and be flexible enough to go after opportunities as they present themselves.
In deregulated markets, utility efforts to optimize DER assets have been at times constrained by regulatory obstacles making it difficult to achieve cost sharing between customers with and without rooftop solar or to own and operate generation. As utility costs related to rooftop solar escalate, attempts to increase fixed charges have been met with steadfast opposition on the grounds that they undercut the value of rooftop solar and energy efficiency for customers. The effect has been to allocate more infrastructure costs to customers without solar and deny utilities a more stable source of revenue for grid improvements. Utility ownership of DER assets could be an alternative solution, as it would enable better management of peak load. But again regulatory barriers can stand in the way, preventing utilities from recovering costs for generation that affects the wholesale electricity market. Around the world, however, there are numerous examples of a paradigm shift in regulatory decision making.The Puerto Rico Electric Power Authority has directed solar and wind energy project developers to incorporate energy storage with minimum technical requirements that improve grid stability while facilitating the adoption of DERs. One requirement says storage must provide 45 percent of maximum generating capacity for one minute to smooth the ramp rate of power that would otherwise be affected by resource intermittency. Another requirement says storage must be able to output 30 percent of a project’s rated capacity for about 10 minutes to help regulate grid frequency.
The Puerto Rico Electric Power Authority has directed solar and wind energy project developers to incorporate energy storage with minimum technical requirements that improve grid stability while facilitating the adoption of DERs. One requirement says storage must provide 45 percent of maximum generating capacity for one minute to smooth the ramp rate of power that would otherwise be affected by resource intermittency. Another requirement says storage must be able to output 30 percent of a project’s rated capacity for about 10 minutes to help regulate grid frequency. In Germany, the federal government has established clear priorities to reduce fossil fuel generation and eliminate nuclear power production. The policy of Energiewende (Energy Transition) has disrupted business as usual, driving down electricity prices as the grid has been flooded with subsidized solar and wind energy. Utilities are adapting by modifying business models to optimize energy resources for customers.In the United Kingdom, the national Office of Gas and Electricity Markets has backed a policy of price controls for electric companies known as the RIIO Model, aligning revenues with incentives, innovation, and output. (R=I+I+O) The purpose is to double the rate of investment in grid infrastructure while reducing grid access costs for consumers. Companies set performance targets in collaboration with consumers, and results help determine revenue.In South Korea, the utility KEPCO has effectively created an energy storage market as it attempts to procure 500 MW of storage capacity for frequency regulation. KEPCO’s plan is to reduce energy costs using lithium-ion battery-based storage systems to displace thermal generation.In New York, the state government is facilitating a program called Reforming the Energy Vision (REV), aligning utility earnings with optimization of DERs so they begin to function more as distribution system operators than electricity service providers. Under the REV framework, all six investor-owned utilities in New York have partnered with SolarCity, a leading rooftop solar company, in Solar Progress Partnership, an organization that will advocate for shared interests in regulations affecting community solar and residential solar.In California, the legislature sent early market signals for smart grid priorities, requiring utilities to disclose reliability metrics publicly on company websites and requiring state regulators to establish a plan for improving efficiency, reliability, and cost-effectiveness of the electrical system. California has also become the first state in the US to mandate 1.3 GW of energy storage by the end of the decade, which might well be a harbinger of similar regulations in other jurisdictions.
Technology Penetration Beyond The Meter
Achieving some of the goals of smart grid and smart meter deployment requires customer participation. For instance, demand response programs rely on customers to act on price or load information that is provided by the utility, or to allow the utility to automatically control the customer’s usage during peak events. Customers can manage their energy use better when they have access to detailed usage information with frequent readings and information on usage by specific appliances. In order to get customers to participate, they must see the value of participation and also feel comfortable that the collection, analysis and sharing of this data does not invade their privacy too much.Research has identified four characteristics of individuals that affect their willingness to participate in programs that require detailed data to be collected, analyzed and shared:
1. perceived risk of data sharing
2. perceived ability to control the collection and
use of data
3. perceived value of data sharing
4. value of privacy
Some customers see little danger in having their energy usage data being shared with utilities, other companies, or authorities, while others fear that their data can be used in harmful ways. Some feel that they can protect their data by using passwords, privacy settings or other controls, while others feel that “they” (hackers, companies, authorities) will get whatever data they want. Some see value in sharing their data with the utility and receiving detailed usage data,
e.g., through lower energy bills or helping to prevent outages, while others feel they already are doing all they can to save electricity and the data wouldn’t be helpful. Finally, some customers value their privacy more highly than others, sometimes stated as “It’s none of their business” versus “I’ve got nothing to hide”. The willingness of customers to participate in programs depends largely on where they fall in terms of these four measures.
Obstacles And Pathways To Data Sharing
Before addressing customer attitudes towards smart grid technology adoption, utilities themselves have to recognize the value that increased data collection and analysis can have on operations. The 2015 utility survey invited company leaders to rank the most important factors standing in the way of smart grid investment. The two biggest factors were the perceived immaturity of smart grid technologies, and the lack of funds to implement smart grid. The
concern about technology maturity is consistent with the preference for proven technology investments and a generally conservative approach to investment in the utility industry. Lack of funds reflects the funding process for utilities. Investor-owned utilities must ask regulators to add investments to their rate base after the money has been spent, and must satisfy shareholders who often seek a reliable return from utility stocks. Municipals and coops must use
operating cash or sell bonds to invest, and must be concerned with financial responsibility as well as adopting technologies that provide value to citizens or coop members. Another obstacle identified by utilities is lack of internal expertise. Smart grid technologies require knowledge of IT, systems integration, network design and management and data science, while utilities report that their weakest areas of expertise are in data management, analysis and reporting. These processes are critical if utilities are to achieve the potential benefits associated with smart grid. Smart grid technologies have many potential benefits to utilities, such as improved operational efficiency, resilience, safety, cost savings, avoided investments, and integration of intermittent renewables. The utility survey asked company leaders to rank their companies’ top three motivations for smart grid adoption. The most widely mentioned were improved reliability and operational efficiency, followed by cost reduction and outage recovery. These are tangible and predictable benefits, whose adoption can be justified to regulators, investors, city governments or coop owners, all of whom tend to favor “proved and prudent” investments. More long-term motivations such as accommodating distributed generation and centralized renewables were rarely mentioned.
Prioritizing Low-Cost, Safe, Reliable Solutions
Utilities have historically observed a line of demarcation between the grid side and the customer side of the meter. But the global mandate now is for utilities to provide low-cost, safe, reliable solutions, and many of those are behind the meter. Device manufacturers and mobile app developers have transformed society by designing intuitive interfaces that give users real-time visibility and control over routine tasks. Utilities can sit by and watch technology insurgents provide user-friendly solutions for homes, commercial buildings and automobiles, or they can do the job themselves and do it better by tapping enterprise data for customer and network optimization.
Preparing For The Unpredictable
There’s no way to futureproof a smart grid roadmap, no way to peer into a crystal ball and see when the next big shift will occur in the electricity market. Anyone who has recently completed a survey of the utility landscape may want to go back and reassess their projections for DER penetration in light of Tesla Motors announcement that the Model 3, a $35,000 electric vehicle (EV) that can travel at least 215 miles on a single charge, may begin shipments by the end of 2017. If the next generation of EVs is the one that enters the mainstream, distribution networks will soon see a proliferation of transportable energy storage systems that will have a profound effect on supply and demand. Widespread EV deployment is just one change that is likely to take place in the very near future, whether the grid is ready or not. Other factors to account for include price volatility, global warming, cyber security, and shifts in consumer behavior.
The pace of DER technology deployment is driven by pricing for commodities like natural gas and the rate that buyers pay for DER assets themselves. Not long ago, a shale gas boom pushed gas prices to historical lows, leading to a drop in wholesale electricity prices and by extension a more challenging market for wind and solar energy projects. Gas will continue to influence DER adoption as the No. 1 source of electricity generation in the US. By the same token, regulation and policy will continue to play a significant role based on the terms and conditions of system ownership and the availability of financial incentives. Also, prices for solar and wind power can be locked in for up to 20 years, while the price of natural gas is unpredictable, so DER can serve as a hedge against volatile gas prices.
Grid congestion is worst during periods of peak demand, such as hot summer days when utility customers are running air conditioning units to cool their homes and places of business. Extreme heat has the potential to damage large-scale generation and transmission assets, triggering wildfires or drought conditions that may compromise access to water for power plant cooling. An effective roadmap should place a high priority on technology and process improvements that increase grid reliability and resiliency.
At least since the discovery six years ago of the Stuxnet malicious worm, cyber security has been a top priority for all utilities and policymakers. At a 2015 House Energy and Commerce Committee hearing on grid security, one industry leader called cyber security “the 800-pound gorilla in the room.” Secure communications protocols and other security measures are essential for maintaining public safety and the integrity of the electric system.
For consumer product and service developers, the barriers to entry into the utility space have never been lower. The Nest smart thermostat has attracted public interest in connected home technologies, opening the floodgates for other new entrants into the market. In January 2016, the annual CES consumer electronics show in Las Vegas featured new products including a Wi-Fi enabled water leak detector, smart floodlights, and a platform using facial recognition software to automatically customize lighting, cooking surface configurations and espresso machines according to individual preferences. Meanwhile, the solar industry has surpassed one million installations in the US, providing a readymade market for the rollout of derivative technologies like solar plus storage.
The electric grid, once recognized as the 20th Century’s greatest feat of engineering, now stands at a historical crossroads as utilities and key stakeholders begin the process of grid transformation. Careful planning is required to stay at the forefront of technology change. While the US has surpassed many Western European nations in solar energy deployment, for example, it lags behind in the development of virtual power plants. The role of the utility has changed
to such an extent that traditional regulatory decision making, designed for long-term asset management and near-universal access to low-cost electricity, must adapt to incentivize optimization of energy resources for customers. It’s important to pay close attention to utility and customer attitudes about smart grid adoption, because full participation by both parties will be needed to obtain full value from the grid. Each year brings new challenges and opportunities to the utility landscape, calling for constant attention and regular recalibration to the roadmap to make sure the dream of a fully flexible and smart grid is achievable.
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