by Chuck Hornbrook, Itron
Distributed energy generation, particularly solar photovoltaic (PV), has evolved significantly during the past 10-15 years. As recently as 2000, off-grid PV installations for commercial and residential applications were 70 percent of the cumulative installed megawatts of PV systems. By 2010, off-grid had shrunk to 17 percent, while grid-connected centralized and distributed PV systems represented 15 and 68 percent of the installed PV, respectively.
Forecasts indicate a continuation of this trend to meet state renewable portfolio standards (RPSs).
Behind the meter, or customer-owned, generation is a major part of this rapid growth. Using California as the proxy for national growth, among the three major investor-owned utilities (IOUs) alone—Pacific Gas & Electric Co., Southern California Edison and San Diego Gas & Electric Co.—more than 72,000 customer-owned systems and more than 705 MW have been installed.
Nearly 18,000 solar PV systems representing more than 150 MW were interconnected in California on the customer side of the meter in 2010. It is estimated that more than 100,000 solar systems representing 1,000 MW—residential, commercial and industrial—will be installed on the customer side of the meter in California by mid-2012.
Financial and business factors are encouraging growth in utility customer-owned solar. Several states, including California, have established utility subsidies that reduce the upfront cost of the solar system or provide an incentive tied to the performance of the system. Net energy metering benefits exist in many states where utilities provide a credit for energy exported to the grid.
The federal government provides a 30 percent investment tax credit (ITC) on the cost of solar systems. The federal government also has included an accelerated depreciation schedule for commercial installations to help encourage investment for projects seeking tax equity financing.
Furthermore, the cost of solar PV has decreased more than 30 percent in the past 10 years. To reinforce the financial payback on the investment in solar, an April 2011 Lawrence Berkeley National Laboratory study found that the average sales price premiums of California homes with solar PV systems were comparable to the investment homeowners made to install the systems, enabling most homeowners to recoup much of their original capital investment.
Solar PV systems generate electricity in direct current (DC). As a result, a solid-state piece of equipment called an inverter is required to convert DC to a usable, alternating current (AC). Thus, inverters have become the key equipment to control and regulate the system’s output. These grid-tied solar systems also typically will stop operating when the inverters sense a spike or a drop in voltage below a specified acceptable range. These operating parameters are set up for safety to avoid the export of potential generation to a distribution feeder or prevent negatively impacting other equipment on the distribution grid.
Challenges and Progress
Monitoring, measuring and possibly controlling distributed generation systems on the customer side of the meter or those systems less than 2 MW were not a major operating concern of electric utilities in the past.
With few systems installed, the grid was large enough to absorb their presence. Today, with increased penetration of solar PV and clustering of systems on specific distribution feeders, a need is emerging for the local distribution company to have viability and communication with these smaller systems. This high fluctuation, or intermittency, combined with a high penetration might impact the local distribution circuits, potentially adversely, when the utility has no visibility into what is going on with the circuit or the load center where the solar PV system is sited.
Recently in Hawaii, which, like California is experiencing a massive increase in installed solar PV, local electric distribution company Hawaiian Electric established that any new systems being installed on circuits with 15 percent of the circuit under peak load undergo a study to determine if the system can even be interconnected.
In response to the increasing likelihood of high penetration of solar PV and its impacts, the Department of Energy (DOE), California Public Utilities Commission (CPUC) and Electric Power Research Institute (EPRI) are all engaged in studies, demonstration projects and standard committees to understand the impacts of high penetration and how to mitigate them effectively.
High Penetration and Grid Awareness—A Confluence
In the past, utilities facing the increased penetration of solar on their distribution grid had little visibility, with the exception of costly studies that were not real-time and used expensive utility resources. With advanced metering infrastructure (AMI) and additional grid situational awareness through sensors on distribution circuits and transformers, utilities have more tools for monitoring and studying solar PV impacts on their grid. At the grid’s edge, though, what intelligence or functions must reside in the inverters and what mechanism do stakeholders have to communicate to the inverters?
To address the smartness of the inverters, smart solid-state inverters are being developed that will provide low-voltage ride through support, reactive power and, in the future, storage to offset the impact of intermittency. For communication, some utilities have started to discuss having supervisory control and data acquisition manage the distributed resources less than 2 MW and provide grid stability through the inverter, similar to what is required for large solar systems greater than 2 MW, which typically are interconnected under Federal Energy Regulatory Commission interconnection rules. It is unclear, however, what requirements are needed for the communication—latency, bandwidth and quality of service—and what is the best solution for smooth operation. Many efforts are underway, but a consensus and set standards are not finalized.
One possible solution might be the use of an existing AMI system to provide updates on the performance of solar systems and provide set point commands to the inverters to operate in a particular fashion. One challenge is that inverters and solar PV systems are different than a reporting device such as an in-home display owned by a customer or an air conditioning unit that is part of a direct load control (DLC) solution, both of which are part of a smart grid ecosystem. In addition, the inverter and solar PV system are not utility-owned distribution automation or sensing devices. As a result, protocols, regulations and stakeholder understanding on when and what kind of controls and commands are feasible are still in their infancy.
The transformation of the distribution grid through the development of open standard Internet Protocol-based AMI networks, integration with distribution automation and the increased installations of solar PV systems is a confluence of grid advancements that will bring more smart to the smart grid. AMI and the related meters, open standard multiservice networks and capabilities for grid situational awareness provide utilities with improved grid awareness. By adding smart inverters to the edge of the distribution network and communicating with these utility resources through open standards, more value will be created for all stakeholders. How this communication occurs with these inverters is developing. The goal, as with other smart grid efforts, should embrace open standards to increase the number of available applications and continue the development of the smart grid ecosystem.
Chuck Hornbrook is a senior product manager for smart grid solutions at Itron. Reach him at email@example.com.