With rapid technological innovation and various state and federal financial incentives, electric utilities and their customers are increasingly integrating distributed generation into existing systems. State and localities are in the best position to determine how to promote these technologies and ensure that rates paid for distributed generation take into account the costs of maintaining and operating the distribution network. The federal government should not seek to impose a one-size-fits-all approach to rate design or adopt policies that favor distributed energy over other resources.
Benefits and Challenges
Distributed energy resources include solar photovoltaic, small wind turbines, combined heat and power, fuel cells, and micro-turbines. These resources can provide numerous benefits. For example, utilities could reduce their avoided costs — with less need to build new generation to meet growing demand — and transmission costs. DERs help utilities meet environmental goals and reduce air pollution caused by fossil fuel generation sources. Utilities may also improve reliability by using DERs as a backup during widespread outages.
However, there are several operational challenges in using DG. For example, too much DG may result in too much power entering a substation, causing power to flow from the substation to the transmission grid, which could result in high voltage power swings. DERs may cause lineworker safety issues such as islanding — when the DG continuously energizes a feeder even though the utility is no longer supplying power due to an outage or other cause. DG is difficult to monitor and forecast, and may place increased strain on distribution systems as these customers use the transmission and distribution systems more than non-DG customers.
There are also economic issues associated with increased DG. For example, utilities will have to make capital investments to address potential strains on the system, and the costs may be borne by both DG-owning and non-DG-owning electric customers. Many electric utilities pay DER owners for excess energy produced by their systems using net metering — the utility credits customers for their sales to the grid, charging them the net difference between how much they use and how much they produce. Utilities and other users are left to shoulder capital, operating costs, and the higher price of DG.
States and non-regulated utilities are working to design alternative compensation schemes to appropriately value the full costs associated with DG production. Examples of alternatives being considered are fixed charges for all utility customers, declining block energy charges based on usage, residential demand charges according to peak kW usage, time-based pricing, and standby rates. Regardless, the price of electric generation is a matter of state and local concern, and decisions about purchasing and pricing should be left there.
Community solar projects may be a good compromise for public power utilities and their communities to realize the benefits of DG, while mitigating issues. Community solar allows users to apportion costs fairly and reduce fluctuations in power flow.
In 2015 and 2016, energy legislation was introduced in the House and Senate that addressed DER, including solar.
The North American Energy Security and Infrastructure Act, H.R. 8, would have created a new federal standard under Section 111(d) of the Public Utilities Regulatory Policies Act to require states and non-regulated utilities to consider mandatory interconnection and billing for community solar. The American Public Power Association and others in the electric industry opposed this provision because it was duplicative of other PURPA standards, didn't require community solar facilities to pay to use the power grid, and ignored retail electric laws in states without retail competition.
The Energy Policy Modernization Act, S. 2012, included language directing the Department of Energy to undertake net metering studies. Our Association was concerned that studies could lay the groundwork for future federal net metering policy.
Congress did not pass comprehensive energy reform legislation, but the federal government has attempted to exercise jurisdiction over issues typically left to states and municipalities under the Federal Power Act. The FPA, the statute that governs the bulk power system, gives the Federal Energy Regulatory Commission the authority to regulate the interstate sale of energy and reserves for the states the power to regulate the sale of power within the state.
PURPA imposed on each public utility, with certain exceptions, the requirement to purchase capacity and energy from certain generators at the avoided cost and to sell needed power services to the generator. Since 2005, FERC has issued several orders to regulate distribution and intrastate power sales. During this time, the U.S. Supreme Court has issued several major decisions suggesting that the limits on FERC's jurisdiction may extend beyond interstate wholesale sales of electricity and into the sphere of local retail energy sales.
DG can provide many benefits for public power utilities and its customers, as long as the technology is implemented thoughtfully and rate structures are designed to reflect and fairly apportion costs. As confirmed by Congress in previous legislation and by the courts in multiple lawsuits since Congress passed the FPA, states and localities are in the best position to value the retail sale of energy and should continue to have jurisdiction to do so.