Forbes.com

Can Utilities Profit from Distributed Energy Resources?

Distributed energy resources can help utilities deal with peak demand and perhaps even become a source of new revenue for energy companies.

By Aaron Denman and Hubert Shen

Published on May 01, 2017
min read


This article originally appeared on Forbes.com. For more than a century, people plugged their electrical appliances and machines into an outlet and were content to have the power flow from some far-off, unseen location. Electricity arrived from a power 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. All this 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 acquire. By installing rooftop solar panels or purchasing backup generators and storage units, some consumers began taking greater responsibility for their own electricity—whether they were pursuing better reliability, more favorable economics or environmental benefits. But for the utilities that manage the electric system, these distributed energy resources (DERs) are a mixed bag. Utility executives are already dealing with a demand curve that is leveling off, due to greater energy efficiency. Now they must find ways to integrate electricity from new sources onto the grid. If unplanned, DERs can represent an unreliable supply of electricity that requires significant 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 first step is identifying where and how DERs can create value in the grid and for customers. Utilities typically have two broad options to meet peak electricity demand: Supply more electricity to meet demand, or constrain demand by encouraging conservation during peak periods. DERs offer additional options. If they can take up some of the load during peak periods, then utilities can put off investing in new “peaker” plants that supply extra electricity at times of greatest demand. Over time, if DERs result in fewer electrons flowing across the grid, utilities can put off adding substations and extend maintenance schedules. Utilities will still need to make investments in a smarter grid that can handle two-way traffic and integrate flows from many more sources. 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). And a smarter grid may bring new opportunities for utilities to generate revenue, beyond infrastructure investments. New rules are coming into play will allow utilities to treat the procuring of electricity from DERs as a regulatory asset, which would in turn allow them 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. Finally, 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. Energy services are becoming a more attractive part of the business, and some of the business models rely heavily on analytics and data gleaned from a smarter grid system. 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.

This article originally appeared on Forbes.com.

For more than a century, people plugged their electrical appliances and machines into an outlet and were content to have the power flow from some far-off, unseen location. Electricity arrived from a power 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.

All this 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 acquire. By installing rooftop solar panels or purchasing backup generators and storage units, some consumers began taking greater responsibility for their own electricity—whether they were pursuing better reliability, more favorable economics or environmental benefits.

But for the utilities that manage the electric system, these distributed energy resources (DERs) are a mixed bag. Utility executives are already dealing with a demand curve that is leveling off, due to greater energy efficiency. Now they must find ways to integrate electricity from new sources onto the grid. If unplanned, DERs can represent an unreliable supply of electricity that requires significant 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 first step is identifying where and how DERs can create value in the grid and for customers. Utilities typically have two broad options to meet peak electricity demand: Supply more electricity to meet demand, or constrain demand by encouraging conservation during peak periods. DERs offer additional options. If they can take up some of the load during peak periods, then utilities can put off investing in new “peaker” plants that supply extra electricity at times of greatest demand. Over time, if DERs result in fewer electrons flowing across the grid, utilities can put off adding substations and extend maintenance schedules.

Utilities will still need to make investments in a smarter grid that can handle two-way traffic and integrate flows from many more sources. 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).

And a smarter grid may bring new opportunities for utilities to generate revenue, beyond infrastructure investments. New rules are coming into play will allow utilities to treat the procuring of electricity from DERs as a regulatory asset, which would in turn allow them 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.

Finally, 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. Energy services are becoming a more attractive part of the business, and some of the business models rely heavily on analytics and data gleaned from a smarter grid system.

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.