As consumers, we take for granted the ability to access electricity at the flick of a switch. Grid reliability is presumed, and blackouts or brownouts result in customer dissatisfaction and bad publicity for utilities. Similarly, some utilities are subject to reliability mandates and tied to rates. This raises the stakes of the challenge to utilities, who consumers expect to continue to supply electricity reliably – even as power sources shift from conventional sources to a mix of conventional and distributed generation (DG) sources, and as consumption patterns change based on adoption of electric vehicles, energy storage and energy efficiency.

The challenge: distribution planning with different energy generation sources

The Solar Energy Industries Association recently reported that currently 645,000 US homes and businesses have installed solar power, with 195,000 of those installations occurring in 2014. Further increases in consumer demand for PV are expected as solar prices continue to decline and, more generally, increases in other DG energy sources are anticipated, driven by recent regulatory efforts to reduce CO2 emissions (Clean Air Act), and implementation of new state policies including distributed resource plans.

This poses a challenge: what must utilities do to sustain grid reliability as PV and other DG energy supplies increase?

Analysis and tools: the building blocks

Utility distribution planners are currently assessing how to adapt to the new scenario that they know is inevitable: a future in which there will be increased DG – including increased PV – and grid reliability needs to be maintained. The distribution planning process requires both considerations of the fine-scale spatial variations in the grid, with feeder-level characteristics key factors, as well as the temporal variations on diurnal and seasonal timescales.

The current analysis of the challenge suggests that the solutions are within reach: studies indicate that existing tools and existing data can be used to assess future scenarios. An upcoming study by Jeff Smith and Nadav Enbar of EPRI indicates both the complexity of maintaining grid reliability, and the potential for existing tools to be deployed to analyse the challenges and identify effective solutions. The study is a bottom up analysis at the feeder level, and assesses 12 attributes of any individual feeder to review the implications of adding varying amounts of PV to that feeder. Broadly, the 12 attributes considered are technical and economic metrics relating to the transformer capacity, feeder losses, energy consumption, feeder voltage and feeder protection.

As suggested by the number of feeder attributes analysed, the variability at the feeder level is significant since distribution systems are unique in their response to distributed energy resources, and the costs and benefits vary significantly. This is reflected in the report analysis of three different feeders: one of which can host PV anywhere on the feeder, one of which can host PV at some, but not all, locations on the feeder and one of which cannot host PV anywhere on the feeder. Therefore analysis must be conducted at the local feeder scale: there are not “representative feeders” that can be used broadly since location and other feeder attributes matter in determining how much PV can be added.

A notable result of the EPRI study is the determination that the local feeder level analyses can be aggregated to a substation or system level, incorporating results from thousands of feeders for distribution planning.

Utility organisational structures: new emerging needs

While there is some work to be done in gathering and maintaining the necessary distribution system data and in ensuring that the distribution planning models are accurate, the biggest challenges to utilities relate to how to integrate software and IT systems to enable accurate distributed energy resource planning, and how to ensure that utility staffing and internal organisation are aligned with the future needs.

In another upcoming study, Daisy Chung of the Solar Electric Power Assication (SEPA) and Andy Coleman of Black and Veatch, have analysed different utilities’ approaches to distribution planning to assess the extent to which utilities’ existing processes and structures are aligned with future needs. Interviews with utilities indicated that many have a siloed structure that reflects past needs, with some degree of coordination to address emerging distributed energy resource planning needs. The pressure of meeting day-by-day – even minute-by-minute – operational needs and also comply with regulations can make it difficult for utilities to find the bandwidth to develop medium or long-term planning processes.

Developing good distributed energy resource forecasting tools relies on integrating distribution infrastructure data, distribution modelling software, interval metering data, and real-time management systems, but these have traditionally been supported separately. The conventional approach to interconnection involves consideration of applications received using general principles that in some cases may be simple rules of thumb. As DG increases, some utilities are proactively seeking interconnection in specific areas and are expediting certain applications accordingly. This approach relies on running a distribution grid model, which allows the utilities to plan with precision.

Such process changes mean that the responsibilities of distribution engineers become more complex, and utilities are not necessarily currently staffed to meet these needs. Therefore utilities may need to consider not only their processes and the structures that support them, but also the expertise of the relevant utility staff.

Connecting the dots

The momentum for change in the way the grid operates is considerable – for example, the package of twelve bills passed by the California Senate last week includes legislation to make California’s energy generation use 50% renewables by 2030. Such policy drivers will force utilities to plan for a different future with a substantially larger source of DG in addition to changes in energy consumption.

The future of utility distribution planning involves models that work at the local feeder level and aggregate the results to the system level, allowing data to inform a substantially more precise decision-making process. As is so often the case, the analyses and tools that enable a new approach to distribution planning and maintenance of grid reliability in this future scenario are at our fingertips, and the speed of the transition to that new approach is primarily governed by how rapidly our human-based systems and organisations adapt.

Utilities must adapt to the growing amount of distributed solar and other renewables coming on to the grid. Image: SDG&E.

Utilities must adapt to the growing amount of distributed solar and other renewables coming on to the grid. Image: SDG&E.

The DNV GL survey of 200 energy leaders (2014) identified interconnection of DG as the most significant challenge facing the utility industry in the next five years. Source:

The DNV GL survey of 200 energy leaders (2014) identified interconnection of DG as the most significant challenge facing the utility industry in the next five years. Source: