This article originally appeared on Energy Today.

For more than a century, most people plugged their electrical appliances and machines into an outlet and were content to have the power flow from some far-off, unseen location, from a generation plant managed by a rather faceless utility company that most customers didn’t think about for more than a few minutes a month, as they wrote their monthly checks.

That pattern began to change over the past decade as technologies for generating electricity from renewable sources—solar panels in particular—became more affordable and easier to have installed. By installing rooftop solar panels or purchasing backup generators and storage units, some consumers began to take greater responsibility for generating a portion of their own electricity—whether they were pursuing better reliability, more favorable economics or environmental benefits.

But the rise of these distributed energy resources (DERs) creates a challenge—and just maybe an opportunity—for utilities. Utility executives are already dealing with a growth curve that is levelling off. Now they have to find ways to integrate a growing influx of electricity onto the grid from a wide variety of sources. If unplanned, DERs can represent an unreliable supply of electrons that require big investments to accommodate in the grid system. However, when planned, DERs can help utilities deal with peak demand and perhaps even become a source of new revenue for energy companies—if they can find a role in the evolving economics of electricity.

The grid will continue to connect the system elements, from large central power generation through DERs and customers at every level. For utilities, successfully navigating the integration of these resources will require a well-measured approach to understanding the impact of DERs on the system, reinforcing the grid to accommodate and take advantage of the electricity DERs can supply and investigating growth opportunities stemming from the popularity of distributed energy.

Bringing distributed resources into the system

The first step for utility executives is to figure out where and how DERs can create value in the grid and for customers. The value of any electricity that DERs contribute to the system may be outweighed by the costs of upgrading the grid to accommodate new inputs. Doing this requires better communication and automation, accommodation of two-way energy flows and the reinforcement of grid infrastructure.

Well-planned DERs can be a useful tool to help meet a region’s electricity demand. Utilities typically have two broad options to meet peak electricity demand within an area: Supply the extra electrons necessary to meet demand, or constrain demand by encouraging conservation during peak periods. DERs offer a viable third option. If fewer electrons are flowing across the grid to electricity consumers during peak load times, utilities can put off adding substations and extending maintenance schedules.

To weigh the costs against the financial gains and other benefits, executives should:

• Identify the value in DERs and consider them as a capacity resource in system planning.
• Decide how to integrate them—for example, do you acquire some distributed resources or just encourage them by sending appropriate price signals?
• Determine how to compensate the DER owners for the electricity they contribute to the system.

Since all this will be new for most utilities, they should work with regulators to set up pilot programs, so they can try out different models and learn what works best. They can use what they learn to help weigh the trade-offs of integrating DERs compared to their traditional methods of upgrading their own generating capacity.

DERs as a growth opportunity

While the rise of DERs is often seen as a growing headwind, digging deeper suggests there are three ways DERs can serve as a growth opportunity, either within the regulated utility or at the parent company level.

First, as previously noted, the proliferation of DERs and the need to connect them to the larger distribution system will create demand for more infrastructure investments to modernize the grid. These investments are in addition to utilities’ existing maintenance and capex obligations, and the shorter lives of DER assets also contribute to attractive returns. Several states have approved grid modernization programs that ensure such returns, including California (where San Diego Gas & Electric will invest $3.5 billion over 15 years) and Illinois (where Commonwealth Edison will invest $2.6 billion over 10 years).

Second, while the addition of DER capacity may delay or even replace the need for some traditional distribution assets such as feeder or substation upgrades, there is growing precedent to treat the procuring of DER capacity as a regulatory asset. Doing so allows utilities to consider the costs of rebates or other DER investments in their rates and make a return on their investment. For example, Con Edison’s Brooklyn Queens Demand Management (BQDM) program uses a range of DER technologies (including storage, demand response and energy efficiency) to solve some distribution needs. The analysis included an unquantifiable societal value that, when factored into the cost of procuring DERs, allowed Con Ed to earn a return on its DER investment.

Third, customers’ enthusiasm for generating and managing their own electricity suggests a demand for new and competitive businesses that can help customers—particularly commercial and industrial ones—meet those needs. Technological advances, favorable legislation and financial innovation are all moving in a direction that makes energy services more attractive, and DERs could act as the core service offering to build on. Utilities are exploring opportunities to provide these services, and there are already some good examples of businesses generating value from cross-selling to customers of their parent company, or through innovative use of financial securitization and tax credits. For example, Cofely, the energy services company developed by Engie, has succeeded by focusing on scale projects in fast-growing parts of the world.

Some utilities are exploring models that require less capital than a typical energy services company, relying more heavily on data and analytical services, a low-cost customer-acquisition model and potentially a securitization component. This lowers the investment required to enter the market and focuses the business on higher-margin portions of the value chain. Regardless of the model, limited existing capabilities and speed of change in the market should push utilities to consider acquisitions around a core foundation that they can use to build a services platform.

Whether utilities consider DERs primarily as an additional resource for planning electricity consumption—or they explore new revenue opportunities in developing grids or launching new energy service businesses—the arrival of DERs on a massive scale calls for proactive engagement. Utility executives who move assertively to understand and assess the evolving conditions can position their organizations to make the most of the opportunity.

Aaron Denman is a partner with Bain & Company in Chicago, and Hubert Shen is a Bain partner in Los Angeles. Both work with Bain’s Global Utilities practice. Joseph Scalise is a partner in San Francisco and he leads Bain’s Global Utilities practice in the Americas.