|Use of distributed energy resources (DERs) can provide significant benefits but may also create operational and economic issues for electric utilities, which should be addressed at the local and state level.|
|APPA supports federal programs that help public power utilities continue to invest in new and innovative DER technologies.|
|APPA supports federal regulatory policies under which DERs cannot participate in wholesale electric markets without the consent of state and local regulators.|
In a shift from the traditional electric power paradigm, utilities and utility customers are installing DERs, including distributed generation (DG) facilities that employ small-scale technologies to produce or dispatch electricity closer to the end use of power. DERs include demand-side management tools, such as demand response and efficiency programs, and DG resources, such as solar photovoltaic installations, small wind turbines, combined heat and power, fuel cells, micro-turbines, and storage devices (e.g., large lithium batteries or grid-connected electric vehicles (EVs)).
Use of DERs may benefit utilities and their customers by reducing the need for new utility generation assets and ancillary services, allowing utilities to avoid higher transmission costs by reducing peak demand, diminishing air pollution emitted by traditional fossil fuel-fired generation, and assisting utilities in hedging against widespread power outages.
Despite these potential benefits, DERs may also present significant challenges for electric utilities and power customers. DG resources may introduce operational complexities for transmission, distribution, and generation systems. For example, too much DG can create excess demand at a substation, causing power to flow from the substation to the transmission grid and increasing the likelihood for high voltage swings and other stresses on electric equipment.
Increased DG use may cause economic issues as well. Utilities may have to make capital investments to address potential strains on the system caused by DG deployment, and these costs may be borne by both DG-owning and non-DG-owning electric customers. Designing rates for DG customers can also present challenges. For example, subject to applicable state or local laws, most electric utilities compensate DG producers through net metering, under which customers with on-site generation are credited for their kilowatt-hour (kWh) sales back to the grid and charged for periods when their electricity consumption from the grid exceeds their DG output. Under many net-metering programs, the customer is both charged and credited at the utility’s full retail rate of electricity, thus potentially over-compensating DGs with a value of generation that is higher than the utility’s avoided cost (since the full retail rate includes expenses other than the cost of the power itself). Some, but not all, regulators have adopted alternative compensation schemes to appropriately value the full costs associated with DG production. These economic issues may also arise in the future with the growth of storage and EVs.
These reliability, operational, and economic challenges may be even more severe if DERs are permitted to participate in wholesale electric markets without the consent of state and local regulators. APPA raised this concern in response to the Federal Energy Regulatory Commission’s (FERC) 2018 rule allowing electric storage resources located on the distribution network or even behind a retail customer meter to participate in organized wholesale electricity markets without the consent of state and local regulators. The rule was ultimately upheld by a federal appeals court, which concluded that state and local regulators cannot use their authority over local distribution systems to broadly prohibit storage resources from accessing wholesale markets. The court did recognize that state and local regulators retain broad authority over the distribution system, which might be legitimately used to restrict wholesale market access in certain cases, including for safety or reliability purposes.
In its Order No. 2222 issued in September 2020, FERC adopted additional rule changes to facilitate DER participation in organized wholesale markets. While the new rules raise jurisdictional and practical concerns arising from such wholesale market participation, FERC significantly mitigated these concerns for most APPA member utilities by establishing an “opt-in” mechanism for small utilities under which DERs located on small utility systems may not participate in organized wholesale markets without the consent of the state or local regulator.
Congressional and Agency Action
Congress has passed several bills relating to DERs in recent years, including several provisions included in the Energy Act of 2020 designed to support research, development, and deployment of DERs. The Infrastructure Investment and Jobs Act (IIJA)(P.L. 117-58), which was signed into law in November 2021, authorized and appropriated additional funding for several Energy Act of 2020 programs, including appropriating $355 million for energy storage demonstration grants and $150 million for long-duration storage demonstration. It also reauthorized and appropriated $3 billion annually for fiscal years (FY) 2022-2026 for the Department of Energy Smart Grid Investment Grant Program, which provides grant funding for utilities to deploy various grid technologies, including investments that enable the integration of DERs and electric vehicle-to-grid technologies. APPA supports these programs that will help public power utilities continue to invest in new and innovative technologies.
The Inflation Reduction Act (IRA)(P.L. 117-169), signed into law in August 2022, made significant changes to energy tax credits, making the existing production tax credit (PTC) and the investment tax credit (ITC) available to tax-exempt entities, including public power utilities, as a direct pay, refundable credit. It also expanded the ITC to make the credit available to energy storage projects. These changes will enable public power utilities to receive tax parity for their investments in DG, as well as for utility-scale investments in clean energy technologies.
FERC is currently considering filings by regional grid operators to implement FERC Order No. 2222. The Commission approved filings by grid operators in California and New York, and proposals by ISO New England, the Midcontinent Independent System Operator, PJM Interconnection, and Southwest Power Pool remain pending before the agency. In addition to these market-related issues, FERC and the North American Electric Reliability Corporation (NERC), are pursuing a number of initiatives to address reliability concerns associated with inverter-based resources (including solar PV resources) connected to transmission and distribution systems. FERC and NERC are focusing, for example, on the need to ensure that such inverter-based resources can adequately “ride through” grid disturbances rather than going offline in large numbers and threatening grid stability.