by Phil Davis, Schneider Electric
Large, rotating masses are the unsung heroes of reliability on the electric grid. Loads come and go, but our Newtonian friends, Momentum and Inertia, make order from chaos. They provide precious seconds for dispatch to react to large load excursions while smaller ones disappear as noise, swallowed by the flywheel effect and some really smart automated controls.
With the prospect of strong Environmental Protection Agency action under section 111(d) of the Clean Air Act, nuclear issues and renewable sources’ growing at an unanticipated rate, Newton’s safety net is crumbling as new power sources with little to no mass become significant.
The result? Software is replacing rotating mass.
Inconveniently, software cannot produce electrons, so it must use synthetic equivalents. Key among these is demand response. Demand response started as a fairly straightforward method of adding capacity by inciting many customers to curtail load when asked. Then it became a strategy to extend existing energy sources (energy markets); and lately, demand response has gained some currency as spinning reserves and frequency regulation resources (fast demand response)-all fine, but not breakthrough stuff, or even mainstream, in professional energy circles. It’s even become fashionable to refer to this just like software (i.e., v1, v2, etc.).
That habit has spread to nearly every corner: Utility 2.0, Smart Grid 3.0-not the best analogy. As Silicon Valley investors discovered, advancements have been more organic, project-based and heavily risk-managed. Thus, the real advancements in demand response come from smart evolution of existing practices. Demand response has created a vocabulary that is common to electric providers and their customers. This vocabulary is accelerating technology. For example, demand response has produced tools that grid operators use to maintain balance and that customers have learned can help them avoid demand charges. Same tool, different purposes; however, that combination of activity and others similar have focused industry energy on the grid edge.
The D.C. District Court’s decision vacating Federal Energy Regulatory Commission (FERC) order 745, if left standing, will accelerate demand response programs within local utility franchises. Already this was underway, arguably since the early days of interruptible rates, load control switches and time of use. Utility experience with demand response has awakened a review of business processes where the solutions to new problems happen between the control rooms and customers rather than upstream to the bulk energy systems and balancing authorities.
A larger view of demand response exists today; not as a customer-reactive program, but as a coordinated virtual power plant (VPP). This VPP provides portfolio management capability that stratifies resources according to energy characteristics, thus giving the dispatcher all the buttons to press for reliability, economy, safety and environmental impact. As utilities break apart silos, demand response becomes the generic name for the discipline of managing control center to customer.
As technology advances, so do the business processes that depend on it. Demand response has become active load management. Just as demand response before it, active load management has distinct applications.
Closest to home and most appealing is volt-VAR control (V-VC) and its offshoot, conservation voltage reduction. Utilities can use these tools, which have the same impact as fast-acting demand response, but they require no customer engagement. The combination of better data from sensors and meters with advanced distribution management systems (ADMS) allows fine tuning dispatch to better match true load. There have been many successful uses in Europe. Recently the Electric Power Research Institute (EPRI) published a study confirming surprisingly good results in U.S. pilots.
V-VC serves two purposes: It can perform similarly to peak reduction programs of traditional demand response, and it can make major contributions to energy efficiency by avoiding generation except when absolutely necessary.
A precedential impact of active load management is the increased understanding that the meter is a node, but not a boundary, on a smart grid. This paves the way for customer-sited distributed generation, even under utility maintenance, serving the twin needs of the customer and critical loads during major outages. Hardware can organize these resources into microgrids for resiliency while software can create virtual microgrids for efficiency. Thus, active load management provides building blocks to a new understanding of resilience, sometimes called a “fractal grid.”
Next? At DistribuTECH Conference & Exhibition in February, a leading ADMS vendor demonstrated the ability to dispatch home HVAC thermostats directly from the control room. Distributed intelligence efforts are moving the focal point of automated decision-making from central systems to substations and beyond to reduce latency and overcome the lack of those rotating masses. Perhaps this is the precursor to widespread utility microgrid development. Standards development is focused across the board at enabling these interactions. Is this activity practical?
The New York REV process takes this further in its efforts to formalize a concept of distribution service platform (DSP), which speeds the process of these bits’ and pieces’ coming together in a common framework managed by the local distribution utility. One key element is potential third-party participation. Customer engagement is hot with utilities, and the New York REV design might prove a catalyst. As building management companies, neighborhoods and campuses recognize there is new flexibility possible in service quality and economy, new players will arise who are willing to do the organizational and management work on customers’ behalf. This improves customer engagement while shielding underlying complexity from those who choose not to learn the rules of electricity.
“Prosumer” typically refers to a producer-consumer of energy. One example is the grid-connected homeowner with rooftop solar. The term also should include the concept of a professional consumer: one so deeply involved in managing a lifestyle or business that learning sophisticated tools does not pose barriers. Both benefit from advancements in transactive energy and transactive controls.
Transactive energy is a market mechanism that allows producers to offer and consumers to buy energy on mutually agreeable terms. It can include long-term to spot market needs, but the key element is that it replaces an unwieldy rate making process that has not been able to keep pace with technology or societal demands. Better, it elevates regulators to an oversight process similar to that the Securities and Exchange Commission has over more established commodities markets. This improves the potential for energy products to fit closely the needs of narrowly defined customer sets and even individuals.
Transactive controls provides the support infrastructure for transactive energy. Electricity is a volatile and fast-paced market. It is impractical for customers to keep track of or even manage this volatility without automated support. In an idealized future, the customer will specify energy attributes (cost, reliability, flexibility, etc.), and transactive controls with sophisticated capabilities will do the detail work that makes it so. This transactive energy plus transactive controls energy framework serves the needs of sophisticated industrial energy managers, as well as indifferent individuals with an interesting implication for service levels.
The U.S. has a social contract in which utilities agree to regulation in exchange for monopoly status for exclusive geographies. Part of this contract is universal service; everywhere, every load, all the time. To achieve this, our industry has developed a planning process that allows for major failures plus absolute peaks plus a safety margin. In the current time and near future, this might be overkill and it might not meet our needs as well. The social contract might need amending.
Reliability has a cost, but not every customer needs it. Today, we expect all the electricity we need to be there all hours of the day, and in as much quantity as necessary. Would the Customer of the Future need the same? Conceivably not. With local solar, battery backup (even in the form of an EV) or even just a tolerance for outages, tomorrow’s customer might trade absolute reliability for a dramatic discount. This might even serve remote customers better than the current system? Co-gen customers? Hardy souls with a thrifty bent?
Transactive energy constructs allow for pricing infrastructure apart from energy and thus to charge a premium for six nines. This also requires accelerating advancements in customer perceptions. Customers will see rate increases, putting the industry in the awkward position of explaining the costs of new regulations and how rates aren’t rising as fast as they might have. It’s a difficult public relations problem.
Almost no one outside energy understands the change coming. It is the one area that lags behind others, and it could derail progress made to date. Anyone remembering the stakeholder working groups in the early days of demand response knows how difficult it is to manage these changes. Maybe some of the R&D and grant money going to technology needs to fund social pilots on change management.
Demand response is the language of smart grid; the language of customer engagement. Locations with strong demand response programs have more sophisticated customers. In turn, demand response has spawned an understanding that distributed energy resources, new ways of circuit design and management, more sophisticated grid tools, and new business processes provide a great framework for integrating renewables, right-sizing grid deployments and serving customers. Rapid advancements in open standards support these efforts, as does the increasing link between information and operations technologies. Again, the customer-facing front office needs to keep pace.
We cannot meet new goals in emissions, renewables and more with traditional systems. The relationships between customers and utilities will change.
Phil Davis is senior manager, Demand Resource Center, for Schneider Electric, where he develops grid-connected energy efficiency and demand resource strategies for large energy users. Before joining Schneider Electric via an acquisition, he was chief operating officer for RETX Energy Services, where he also ran market operations to monetize client energy positions. Trained in economics, Davis has an extensive background in applying efficient energy strategies to support the disparate goals of energy stakeholders.