by Rodger Smith, Oracle Utilities
As distributed renewable energy generation-particularly customer-owned rooftop solar photovoltaics (PV)-continues to proliferate, the challenges it presents to the utility distribution network also are mounting.
Recent regulatory challenges to utilities’ traditional business model include those proposed by the New York Department of Public Service (DPS) and the Hawaii Public Utilities Commission (PUC). Both states have particularly high penetrations of rooftop solar PV being installed by consumers-for more control over their electricity costs, in the case of Hawaii, or for more grid independency, in the case of New York.
Hawaii led the nation in the percentage of utility customers with PV systems in 2013, according to the Solar Electric Power Association (SEPA).
This growing penetration of rooftop solar PV also is causing utility operational system challenges, posing issues for the utility in matching load with generation and keeping voltage levels within allowable limits.
Solar PV is intermittent: Clouds reduce PV output, and connected voltage drops. In neighborhoods with high penetrations of renewable generation, intermittency can affect the entire areas by causing lights to flicker because of voltage fluctuations and cause violations in the American National Standard for Electric Power Systems and Equipment (ANSI) C84.1 voltage limits of 120 volts +/- 5 percent. Flickering lights aren’t the only issue. The types of voltage fluctuations caused by these intermittencies also cause consumer electronics to fail faster because of additional heating of the electronics’ circuits.
Solar PV intermittency also disrupts conservation voltage reduction (CVR) solutions employed by many electric utilities over the years to optimize voltage on feeder lines from substations to customers. This requires more capacitor and transformer tap operations. As a result, CVR schemes must model the forecasts of the renewables on the grid to proactively set the voltages-not for where they are at the moment, but where they will be-and avoid excessive capacitor, regulator and transformer tap operations throughout the day.
These aren’t the only issues utilities face as a result of an increased penetration of rooftop solar PV. Other operational issues include reverse power flow, reduced switching flexibility, lack of visibility of actual circuit loads caused by net energy metering, increased O&M for voltage regulation equipment, and transmission-level aggregation issues.
But challenges also offer opportunities, and an increasing number of utilities are moving to ameliorate the challenges of customer-based rooftop solar PV, as well as other push-pull customer disruptive forces such as electric vehicles by using data analytics, load aggregation, load shape modeling, and more.
Turn Challenges Into Opportunities
It all begins with data, whether it’s data aggregation, data modeling or data analytics.
One way utilities handle the new solar influx is by learning more about customer time-of-day load shapes. By aggregating meter-level consumption, customer load shapes can be modeled at particular points in the day to determine more accurately likely stress points in a solar intermittency situation.
Further, aggregating distributed generation separate from the load can provide more accurate power flow simulations, as well as more accurate advanced distribution management system optimization functions. Knowing locations of rooftop solar generation throughout the utility’s distribution area makes it possible to moderate or smooth the effects of cloud-caused intermittencies over the short term through geographic dispersion. In other words, every solar panel in a utility’s distribution area is unlikely to be affected at the same time by cloud cover, barring a massive storm.
Finally, utilities are beginning to use big data analytics to forecast location-based growth of renewables within their distribution territories based on specific load policies, census data and econometric growth models.
Utilities can use this kind of spatial forecasting analysis to improve their long-term infrastructure planning requirements and more fully define the expected mitigation measures needed for the continued growth of distributed energy resources.
Utilities are adopting mitigation measures that include location-specific energy storage (for grid balancing because of intermittency issues) and integrated demand response to meet a broader range of distribution system needs. The coordinated scheduling and dispatch of demand response, for example, can help mitigate new energy demand patterns and phase balancing issues.
Prepare for Changes
A need exists within the industry to provide more advanced modeling of the distributed energy resources (DER) in play. This modeling would assume a standard output based on the size of the resource, its location and the day of the year to calculate expected solar incidence of that specific location. Then, it would overlay the cloud cover forecast (e.g., Doppler radar) to predict intermittency of that location by time of day.
But beyond this and other operational changes necessary to manage a more customer-powered grid, utilities’ business model also will need to change. This kind of change will require a new, wider definition of the utility’s role, as well as a major regulatory overhaul.
Earlier this year, the New York DPS and the Hawaii PUC took major steps to do just that. In New York, the plan calls for distribution utilities to be what DPS Chair Audrey Ziebelman described as “economically advantaged” to drive greater energy efficiencies. In Hawaii, the PUC is focused on building a grid that will integrate distributed resources in a manner that benefits customers and the electric system equally.
The efforts of these two states will be watched closely as others struggle to define the optimum balance. The transformation is occurring in step changes. It will be the redefinition of the role of the utility, however, that will mark the ultimate change.
Rodger Smith is senior vice president and general manager of Oracle Utilities.