Evolving Role Of Distribution Network

Self-generation, as this newsletter has repeatedly argued, is on the rise in jurisdictions where one or more of the following applies: High retail rates, abundance of sunshine across the year and prevalence of customers living in single family dwellings with big roofs. Supportive policy – or at least lack of restrictive policies that hamper distributed generation – are also helpful as are the falling cost of batteries and electric vehicles (EVs) especially those with bi-directional capabilities (photo below). The combination of these factors allows single-family households to self-generate some or most of the electricity they annually consume by installing sufficient number of solar panels on the roof. Batteries and a bi-directional EV makes it easy to store the excess energy to be used after the sun goes down.

This phenomenon, already prevalent in certain places, is gradually spreading elsewhere as the cost of purchasing electricity from the network continues to rise while the cost of self-generation and storage continues to decline.

Against this background some analysts claim that solar and solar + storage customers are net positive since they reduce the need for the distribution utilities and/or retailers to invest in additional generation and distribution capacity. Others argue that these customers are free-riders who avoid paying their fair share for the upkeep of the distribution network. Worse yet, some say that they are net negative because they cause a cost-shift – from solar to non-solar customers – arguments that have been repeated in prior issues of this newsletter.

Cost-shifters, free riders, net positive or something in between depends on many variables and the methodology used to arrive at the results, the topic of numerous value-of-solar (VoS) studies that come up with different conclusions.

The arguments include how much customers should pay for a kWh taken from or fed into the distribution network and whether the value should change for each hour of the day and depending on the direction of the flow as the prevailing conditions change.

Pricing arguments aside, it has become evident that the time has arrived to recognize the evolving role of the distribution network. It is no longer a one-way conduit delivering kWhs to customers but a critical conduit offering two-way transfer of electricity plus a myriad of related services – such as the inherent reliability of being connected – that are poorly understood and frequently under-appreciated.

The critical function of the distribution network was at the center of Reforming the Energy Vision (REV), a multi-year regulatory proceeding and policy initiative started in 2014 by the New York’s Public Service Commission (NYPSC) intended to transform the way electricity is produced, bought and sold and how services can be provided and priced.

Among the REV’s main intentions were to enable the integration of more renewable energy – both utility-scale and distributed – and smart grid technologies in the grid. The NYPSC said that REV was as an ongoing regulatory proceeding with no pre-defined end date and subject to modifications as it progressed with the aim of serving the best interests of utilities and customers.

REV encompasses numerous policies and proceedings as well as proposals to restructure utility ratemaking and revenue models. Among its unique features was the recognition of the changing role of the utility delivery network especially at the distribution level. It envisioned, in principle, the distribution network as an open access platform on which variety of services could be delivered to customers.

In March 2017, based on recommendations from an extensive stakeholder process, the NYPSC adopted the Value of Distributed Energy Resources (VDER) as a new compensation mechanism to more accurately and efficiently value DERs.

The two key pillars of REV were (and still are),

• The recognition that the critical distribution network should be treated as an open access asset in similar fashion to how transmission networks are treated in competitive markets; and
• The idea that distributed energy resources (DERs) should be properly valued and integrated into the planning, financing, upgrading, operation and maintenance of the distribution system, the concept of integrated DERs or iDERs.

An analogy for the former would be to implement a “distribution delivery charge” paid by the recipient of the electricity exactly as Amazon’s customers pay a “shipping and handling” charge for anything delivered from Amazon’s warehouse.

In a post on the Electricity Brain Trust (EBT) Bryan Hannegan the CEO of Holy Cross Energy (HCE), a small distribution company in Colorado, described the concept, 

“With this simple (open access) construct, the commodity electricity (and related grid services, such as capacity) can be bought and sold to one’s heart’s delight, safe in knowing that the distribution network operator has sufficient revenue to maintain the network on which those transactions will be able to occur.”

Implementing the scheme, however, turned out to be problematic, to put it mildly.

“Holy Cross Energy tried to implement this (scheme) starting in 2023 but naturally ran into objections from the solar industry in Colorado. I still believe that there is ‘no such thing as a bad idea, just bad timing’ and this may be one of them.”

If not HCE, perhaps someone else will introduce open access pricing for the distribution network and demonstrate the benefits of the scheme to all stakeholders.

The second issue central to the future of any distribution network is how best to encourage more DERs and to integrate their many valuable attributes into the planning, expansion and operation of the network.

As noted by Lorenzo Kristov, another frequent contributor to the EBT, a key component of a well-functioning distribution network with high penetration of DERs is to separate the costs and charges for operating the distribution network from the price of the energy moved over the network.

There are different ways to ensure a viable revenue stream for the open-access distribution system operator or DSO either by charging the recipients of energy, the producers or both.

CAISO, California’s grid operator, has a grid management charge (GMC) on a per-MWh for energy injected into or withdrawn from the system — i.e., wholesale suppliers and buyers both pay to cover the cost of operating the system. Central to the idea is the separation of delivery charges from the price of the energy itself.

Regarding the cost shift, Kristov argues that it is merely the outcome of the current regulatory construct, the traditional retail regulation, which goes back over a century and did not foresee self-generation, let alone customers feeding excess generation into the network. Kristov says,

“If self-production causes a shortfall in utility revenues to cover system costs, recovering those costs by raising rates for other customers is one possible policy choice. The policy makers’ job is to figure out the best way to deal with declining network revenues without suppressing the growth of DERs or unfairly shifting costs.”

He says, “… it’s pretty clear that the emerging revolution in DER technologies, particularly their continuously improving cost and performance, constitute a threat to the continued captivity of ratepayers to centrally planned and owned capital-intensive infrastructure.”

“In this context the “cost shift” framing of self-production supports the interests of the incumbents who want to keep ratepayers captive to the 20th century electricity business architecture.”

“But the technology and the economics no longer favor the 20th century top-down, centrally planned, operated and owned, large-scale capital-intensive electricity system architecture.”

As another un-named observer noted, as time goes on a sub-class of customers emerge who rely infrequently and little on the distribution network, using it only at times of extreme conditions, e.g., when they are imbalanced while others continue to always rely on it for all their needs.

This is precisely the problem that needs to be addressed. As your editor has argued in the past, the diversification of consumers into prosumers, prosumagers and nonsumers plus other variations such as flexumers means that each requires different services from and can provide different services to the network and should be charged or paid according to the costs imposed and the values derived or provided. Of course, those who go off-grid need not pay for the network at all.

While the current debate among the experts has not resulted in an agreed specification of the problem nor a solution, a consensus is emerging that we need a new rate structure to provide adequate revenues for the critical distribution networks. The future of DERs, the well-being of the networks and the viability of many distribution network operators depends on it.

This article originally appeared in the May 2025 issue of EEnergy Informer, a monthly newsletter edited by Fereidoon Sioshansi who may be reached at [email protected]"