Utilities also will have to make extensive use of automated control and intelligence — evaluating, correlating and analyzing data from smart meters, supervisory control and data acquisition (SCADA) and many other systems to provide operational value for the utility and ratepayer. The result should be a new environment that differs from what most utilities may be accustomed to. It also is extremely dynamic, with new applications and use cases constantly emerging.

Distribution modernization programs are in full swing in virtually every state. The value drivers are compelling, namely, to improve reliability, operational efficiency and outage performance, support DER — including microgrids such as the one at Marine Corps Air Station Miramar in San Diego and rooftop solar — and provide a richer customer experience and new forms of engagement.

Perhaps most importantly, utilities are positioned for a new power ecosystem that is far different from when their grids were laid out decades ago, long before technology such as the internet and DER were conceived.

Achieving the desired outcomes, however, involves technologies with which utilities often have limited experience, including new communications and power distribution networks, data collection and analysis, and sophisticated automation to support new workflows. As utilities get started with these initiatives, they also recognize that distribution modernization involves more than operational technology. Two other elements play a crucial role: 

• New Business Models: DER and increased consumer control of energy consumption mean that people will use the power network in new and different ways. Utilities must look beyond their traditional business model of one-way power flow because their consumers may also be DER providers who expect compensation for the power they supply to the grid. Utilities will have to create new business models to ensure  that all stakeholders can participate and sustain investments.
• A New Regulatory Construct: Utility companies are moving from a protected position where their revenue was ensured to a competitive or quasi-competitive environment that requires them to open the grid to other entities that want to make money from it. At the same time, they are under pressure to increase their reliability, resilience and efficiency, both to meet regulator expectations and, ultimately, to ensure their survival in this new environment. 

As utilities strive to navigate these different layers to achieve business objectives, they will likely find themselves in new and different territory. For example, a major question is how to get started with DER. Utilities often have little idea of the required initial analysis and planning, how to value DER, how to integrate and manage them in the network and/or how to manage the number of applications from everyone who wants to put solar on their roof.

Leveraging the large quantity of data from the smart grid also is problematic. In general, utilities are uncertain how to structure that data, manage it, ensure accuracy and use it effectively. They are unlikely to have data scientists on staff who understand how to evaluate, correlate and analyze data to achieve desired value drivers, whether to determine when a meter needs replacing, predict the impact of DER in a particular region or provide management with strategic intelligence previously out of reach.

Most utilities lack the resources and knowledge to handle all this activity on their own. In fact, more than half of U.S. utilities (55 percent) have communications and telecommunications teams with fewer than 10 employees, according to results from the Black & Veatch 2018 Strategic Directions: Smart Cities & Utilities Report survey, suggesting that in the near term at least, significant outside assistance will be needed (Figure 1).

In their search for outside assistance, utilities generally prefer a partner that can manage the full lifecycle of investment, from initial analysis through planning and implementation, and then serve as an ongoing resource to ensure that the utility achieves the value it was seeking. In addition to effective project management at scale and appropriate cost structures, one of the most crucial partner attributes in these initiatives is the ability to successfully navigate the requirements of regulators, DER providers and internal stakeholders.

A variety of partner arrangements are possible as distribution modernization initiatives continue to take shape. These arrangements may include engagements to manage the modernization (or a specific segment of it) to completion on a project basis to provide insights on an advisory basis that help utility executives make key decisions, or to supplement in-house staff with specialized expertise. Transitional engagements provide a way to get a new process off the ground and gradually turn it over to utility staff as their knowledge and comfort level rises.

This includes the deployment of new or upgraded networks to handle the increase in data traffic to and from fixed “smart” devices in the revamped distribution network and mobile devices deployed in the field for work scheduling, asset maintenance and customer support. 

Utilities are also exploring new types of partner arrangements and taking advantage of the transition to solve traditional problems in more innovative and effective ways. For example, rather than each utility allocating staff to handle similar functions, in some cases, a collective engagement with an experienced third party that handles it for all of them could be more productive and costeffective.

Distribution modernization can be transformative for power utilities by affecting their operations, their customer relationships and their bottom line. With the right partner, the right skills and insights can be provided and delivered at the right time.