Blog Post

Electricity Distribution and Distributed Generation: What Do We Need to Know?

Dec 15, 2015 | Timothy J. Brennan

The standard practice for getting electricity to those who use it, particularly residential and commercial customers, has been through regulated monopoly electric utilities. These utilities cover the cost of distribution by incorporating it into the price charged for each kilowatt-hour (kWh) of electricity used by those customers.

Expansion of distributed generation (DG)—the production of electricity at the customer’s location, primarily from solar cells—threatens this standard practice. DG is expanding because the cost of producing solar is falling while policies to reduce fossil fuel use are getting stronger. By reducing demand for utility-delivered electricity, DG is leading utilities to consider how to grow their business in other ways, including taking a larger role in energy management and DG itself.

Because distribution cost is recovered based on use, DG exacerbates these effects. The price utilities get for each kWh of electricity used must exceed the cost of delivery to cover fixed costs, that is, costs unrelated to use, such as the wires going to homes and businesses. When demand falls, the utility loses that profit margin for each kWh of electricity it no longer delivers.

Making matters worse for the utilities is that most who install solar panels maintain their connections to the grid. If these households pay for the grid connections only on the basis of net use—what they take from the grid less what they supply into the grid from their solar panels—they have these connections effectively subsidized by either the utility or non-DG customers who have to pay higher rates to cover the utility’s costs.

Regulators across the country are struggling with how utilities should adapt to potential growth in DG. Answers to two questions will be important in making good decisions.

1. How big are economies of scope between distribution and competitive services? 

Utilities want to play in nontraditional markets such as solar energy provision or energy management. However, a hallmark of regulatory policy for the last three decades has been that regulated firms should not be involved in competitive businesses. Otherwise, the regulated firms have incentives to impede competition and raise prices to ratepayers by cross-subsidizing competitive affiliates or discriminating against unaffiliated competitors in access to their services. These concerns led to the breakup of the “Ma Bell” telephone monopoly in the 1980s and “independent system operator” rules limiting electric generator control over regulated transmission following the opening of bulk power markets to competition in the 1990s.

This, however, may not be all to the story. Allowing utilities to participate in these markets may have some benefits as well—so-called economies of scope. The merits of having utilities supply DG and energy management to efficiently operate the grid could outweigh the risks presented by having utilities potentially distort competition. In balancing these possible merits against the costs, regulators should demand solid evidence and not just utility assertions that they need to be able to grow in the face of declining demand for traditional services.

2. How much of utility costs are fixed?

In thinking about electricity economics, I and others often assume that distribution costs are essentially all fixed. Once delivery capacity is in place, the incremental costs of distributing an additional kWh are negligible. Although some industry sources more or less support this, others have told me that up to 75 percent of distribution costs vary with the amount of electricity that is used.

This is a wide range of possibilities. Why does the answer matter?  Pricing of the grid should follow its costs. If most costs are fixed, customers should pay a fixed fee regardless of how much electricity they use. This includes DG customers billed on a “net use” basis, who may pay little or nothing toward the fixed cost of staying connected to the grid.

But if much of the utility’s costs vary with output, expanding DG can reduce distribution costs. This will be especially so in regions where electricity use is expanding, as DG could reduce the need to spend money on new transformers or larger substations. Paying a fixed fee for distribution would keep potential DG users from incorporating these cost savings into deciding whether to install solar panels.

Understanding how much of a utility’s costs would be avoided with DG installation is thus crucial to sound regulation. Knowing this might require a great deal of data on the costs of providing distribution by service area. Statewide average total costs per kWh delivered will not suffice.

Meeting the challenges of distributed generation requires that regulators can answer these questions regarding economies of scope and the portion of fixed costs. Informing those answers should be a high priority for research.