As talk about the “utility of the future” moves from conferences and white papers into the realm of action, a number of critical philosophical issues have emerged.

Distributed energy resources offer a drastically different way of delivering energy and grid services that have until now been the purview of electric utilities. Now grid-edge technologies are enabling customers not only to generate their own power, but also to participate in grid operations. 

Regulatory proceedings at state utility commissions are the primary venue for these discussions, as regulators consider changes to rate designs, to cost recovery and profits for regulated utilities, and to rules governing access to the grid. A number of states have active debates ongoing about net metering, distribution system planning, “smart rates” to go with smart grids, third-party ownership models for distributed generation, access to customer data and a host of other issues.

A new paper for GTM Research’s Grid Edge Executive Council, Regulating the Utility of the Future: Implications for the Grid Edge, goes in depth on the developments in five states that are leading the charge, addressing these issues through active dockets.

  • New York’s well-known docket, Reforming the Energy Vision (REV), is seeking to reinvent distribution utilities as “platforms” for distributed technologies. 
  • California is pursuing 80 percent carbon reductions by 2050 through ever greater levels of renewable energy and energy efficiency, promoted by a comprehensive set of dockets.
  • Hawaii, weighed down by sky-high electric rates, wants to capture the benefits of distributed energy to reduce costs and bolster the state economy.
  • Massachusetts is undertaking a grid modernization effort, building a 21st century grid and designing new rates to make the most of it.
  • Minnesota has begun to explore performance-based ratemaking for Xcel Energy through a collaborative process.

Regulators in these states have uncovered some fundamental philosophical issues that will have to be resolved. If distributed technologies provide grid services, who should own them: the utility or the customer? 

How should the owners be compensated? Who decides what investments get made and where? Should utilities be able to prevent customers from making investments? If utilities are going to make less money selling electrons, then what should they do instead, and how should they get paid?

One fundamental issue in all of these proceedings, and all similar proceedings yet to come, will be determining which entities will play the gatekeeper role for the grid. In a traditional paradigm, the distribution utility is the gatekeeper, permitting grid-edge technologies to interconnect (or not) through regulated procedures and prices.

While everyone agrees that safety is an imperative, distributed technologies can have big implications for utility revenues. Utilities and their regulators can put up roadblocks to new technologies and services, especially when they threaten the financial health of the utility.

This issue has been addressed in the New York REV proceeding, which aims to make utilities into a “platform” for grid-edge competition. While the PUC staff and utilities favor continuing their dominant role, with safeguards that would promote fair access, a number of other parties are opposed. They instead call for an independent distribution system operator (IDSO), similar to the wholesale-level NYISO.

Access is a contentious issue in Hawaii as well, where hundreds of distributedsolarprojects have been held up for months by the utility due to technical concerns about overloading local feeder lines. With ongoing growth in solar, plus the potential for more demand response, energy storage, and other grid-edge technologies, the gatekeeper role is a centerpiece in the docket on Hawaiian Electric’s distributed generation interconnection plans.

Related to the gatekeeper issue is the question of who decides which grid-edge investments get made, and who gets to own those assets.

Regulated utilities have shown interest in owning behind-the-meter DERs, like storage, and providing demand response (which is just an evolution of their traditional curtailment function).

But third-party vendors object strongly, noting the conflict of interest that this poses with the gatekeeper role of distribution utilities. If the distribution utility is to be a neutral platform for DERs, it cannot also be a competitor in providing them.

“Allowing utilities in New York to rate-base DER investments will be incredibly corrosive to the DER marketplace and set innovation in New York’s distribution system back immeasurably,” wrote NRG in a filing.

Competing interests

This debate is the latest incarnation of the decades-old discussion of whether regulated utilities should be allowed to offer home appliance sales and service, home security systems and other services that are also offered by the private sector. In most cases, regulators have prohibited these business lines, since utilities' unique monopoly protections would give them an unfair advantage.

In addition to competing with vendors in the grid edge space, utilities are also increasingly in competition with their customers. One unresolved, and yet fundamental, issue is that customers have different motivations for investment than do distribution utilities.

Grid-edge technologies offer benefits to grid operations, such as increasing efficiency, reliability and visibility. But they also offer benefits to individual consumers by lowering costs or reducing environmental footprints.These motivations can sometimes conflict.

Many customers in Hawaii, for example, are investing in solar to reduce costs -- thus overloading distribution feeders and creating additional costs for the distribution utility. To solve the issue, HECO has proposed investing in utility-side grid upgrades like grounding transformers. But these issues can also be solved by consumer investments in things like advanced inverters and battery storage.

This problem is exacerbated by revenue models that give distribution utilities a strong incentive to invest in DERs. If their customers invest in grid solutions, utilities lose out on the opportunity to profit by making their own DER investments. If the utility also has the power to be the gatekeeper, it will be motivated to prevent their customers from investing in DERs, to save the opportunity for itself.

Changing utility profit motives could minimize this conflict. Of all the dockets and proceedings in the five states, those focused on incentive- or performance-based ratemaking will have the biggest role in defining the business model of the future utility.

All of the five states in this review have adopted policies that reduce the impact of lost energy sales on utility profits. Three primary methods are used: decoupling, lost-revenue adjustment mechanisms (LRAMs), and incentive rates of return.

Decoupling provides a rate of return for utilities based on something other than the amount of kilowatt-hours sold, such as revenues per customer. This “decouples” profits from energy throughput, rendering the utilities agnostic about losing sales in the short term. Of the states considering changes to utilities, only Minnesota has not already adopted electric-sector decoupling.

An LRAM calculates the profits that the utilities are losing out on and adjusts revenues accordingly. Likewise, incentive rates of return provide a bonus for meeting or exceeding energy reduction goals, helping to make up for the lost revenues.

One persistent criticism of this approach is that these lost-revenue models do not remove the incentive for utilities to build and own more infrastructure, such as power plants and T&D systems. Utilities also earn a rate of return on money invested in new capital projects, and anything that reduces energy sales also reduces the need for new infrastructure. So despite these lost-revenue policies, utilities can still have a long-term antagonism to efficiency and customer-owned generation.

Hawaii has an open docket on incentive-based (or performance-based) ratemaking that would put an end to this, rewarding utilities for meeting certain goals rather than for increasing their own capital investments.

Likewise, the e21 Initiative in Minnesota points out that the current approach to ratemaking is a “cost-by-cost accounting to determine whether we are paying the right amount for what utilities delivered.” The group recommends moving to a “more forward-looking regulatory framework that determines what we should pay to achieve the outcomes society wants.”

No single state has yet definitively and clearly answered the ultimate question of what the utility system of the future will look like. Most of the proceedings are active now, with critical rulings still months away. Moreover, the grid edge transition will be an ongoing and iterative process, adapting as events unfold over the coming years.

These dockets are the best indications of where things are headed. How regulators resolve these difficult philosophical questions will determine the business opportunities of tomorrow, next year and beyond.

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Want to learn more about how each state is evolving? Ben Paulos breaks them down in Regulating the Utility of the Future: Implications for the Grid Edge, an 89-page report that analyzes the five states that are paving the way toward new business models.