As modernization of our nation’s electric grid moves forward, the potential efficiency and emissions benefits of distributed energy resources and advanced grid technologies are often cited. As state regulators and stakeholders evaluate implementation options for the Clean Power Plan, they should consider the role that these resources might play in achieving compliance with the rule. This post provides a summary of the Environmental Protection Agency’s (EPA) treatment of distributed resources and advanced grid technologies—in particular, distributed generation, demand response, transmission and distribution investments, and energy storage—in the final rule. It explores the role that these resources might play in attaining the Clean Power Plan’s goals, discusses the incentives that they might face under rate-and mass-based programs, and discusses some of the specific considerations that these resources raise for regulators and stakeholders.
EPA’s final Clean Power Plan, released on August 3, places CO2 emission standards on existing fossil-fuel fired electric generating units. EPA’s final rule establishes separate CO2 emissions rate limits for fossil fuel-fired steam generating units and natural gas combined cycle units, but allows states to choose an alternative equivalent state rate or state mass goal. Each state must submit a plan to EPA outlining how it intends to comply with EPA’s guidelines. The final targets of the rule are derived from three building blocks: potential heat rate improvements at existing coal-fired plants, shifting coal-fired generation to natural gas, and increasing renewable generation. However, EPA makes clear that measures outside of these three building blocks may also be used to comply with these requirements.
A state’s choice of a mass-based or rate-based approach will influence how investments in distributed resources and advanced technologies are affected by the Clean Power Plan. Under a mass-based program, allowances for each ton of the mass emissions limit are allocated or auctioned. Each affected source must then hold one allowance for each ton of CO2 emissions. Distributed resources or advanced grid technologies can help to achieve compliance by reducing the demand for generation from affected sources, and lowering the CO2 allowance price from what it otherwise would be. As discussed below, state regulators and stakeholders will need to consider how the CO2 price under a mass-based approach will impact the economics of these investments, and whether additional incentives or complementary policies are necessary to realize cost-effective CO2 emissions reductions from these resources. For example, allowances (or allowance revenue if allowances are auctioned) could be set aside to reward investments in advanced grid technologies that reduce demand.
In a rate-based program, affected sources must comply with a designated CO2 emissions rate. A source with an emissions rate higher than its rate goal may purchase emission reduction credits (ERCs) (denominated in MWh) to adjust its emission rate. For resources eligible to generate ERCs, the potential to sell ERCs to generators with a compliance obligation provides a built-in incentive to increase activity.
EPA provides clear guidance on how certain distributed resources and advanced grid technologies can be used to generate ERCs for compliance in a state using a rate-based goal. In order to be eligible to generate ERCs, measures must meet three general requirements, as well as any other process requirements and protocols identified by the crediting state.
- Measures must be installed after 2012. ERCs can be generated beginning in 2022.
- Eligible measures must be grid-connected, and capable of substituting for electric generation on the grid.
- Measures must be located in a state with a rate-based plan. However, renewable energy measures in states with a mass-based plan may eligible for ERCs if they can be explicitly demonstrated to serve load in a state with a rate-based plan, for example, through a purchase power agreement.
Specific considerations relevant to distributed generation, demand response, transmission and distribution investments, and energy storage, follow.
Distributed Generation: In the final rule, EPA notes that distributed generation was excluded from calculations of the “best system of emission reduction” because of unique data and technical challenges that complicate identifying a technically feasible and cost-effective level of generation from these resources. However, the final rule clarifies that distributed generation resources that meet the eligibility criteria described above may generate ERCs that can be used for compliance under a rate-based approach. EPA further notes that analysis by the Department of Energy (DOE) and the National Renewable Energy Laboratory (NREL) indicates there may be sufficient cost-effective opportunities for distributed generation to satisfy one-third to over one-half of the stringency associated with building block 3. ERCs would be awarded to eligible generation based on net output to the grid. For distributed generation that serves onsite loads, EPA’s proposed model rule indicates that avoided transmission and distribution losses can be credited. EPA also provides additional criteria for crediting generation from biomass, including the biogenic portion of waste-to-energy generation, combined heat and power (CHP) that is not an affected source under the rule, and waste heat to power (WHP). For resources using biomass, a state must propose eligible biomass feedstocks and their treatment of biogenic CO2 emissions in its state plan.
Eligibility to earn ERCs under a rate-based approach provides a direct incentive for distributed generation. Growth in distributed generation, particularly solar, since 2012 means that there is a significant quantity of distributed generation resources that is potentially eligible for ERCs, particularly in California, the southwest and east coast. The potential for distributed generation to earn ERCs would encourage additional distributed generation in states implementing a rate-based approach.
Under a mass-based system, an increase in generation from behind-the-meter distributed resources that reduces demand from fossil fuel-fired generation will serve to lower emissions and the CO2 allowance price faced by affected sources. The extent to which the CO2 allowance price encourages additional distributed generation from retail customers will depend on how regulators adjust retail rates in response to the Clean Power Plan, as well as a state’s compensation rules for distributed generation. For example, in states where distributed solar is compensated through net metering, higher retail prices under a mass-based system would be expected to encourage additional distributed solar. States wishing to encourage additional distributed generation could also set aside allowances to provide a more direct incentive.
Utilities and state regulators in many states have been working to address how to manage the increasing power flows from distributed resources. The potential for the Clean Power Plan to encourage additional distributed generation increases the importance of these conversations.
Demand response: While EPA said little about demand response in the proposal, the final rule allows demand response to generate ERCs in a rate-based program under two conditions. First, the demand response measure must result in a net reduction in load. In other words, it must actually lead to total lower demand, thereby directly reducing emissions, rather than simply shifting demand from peak to off-peak hours. Indirect emissions reductions may occur under the latter scenario if marginal generation from relatively high-emitting peaking units is replaced with off-peak generation from lower and potentially zero-emitting generation. However, under that scenario, the incremental off-peak generation, if eligible, would be credited under EPA’s approach. Second, demand response must also be zero-emitting. Demand response activities that substitute emitting on-site generation for generation from the grid are not eligible to generate ERCs.
The extent to which demand response in its current forms might meet the criteria outlined above is somewhat unclear. A recent study by Navigant Consulting, commissioned by the Advanced Energy Management Alliance and submitted with their comments to EPA, estimates that demand response could provide about a 1 percent reduction in direct CO2 power sector emissions in the markets of PJM, the Midcontinent Independent System Operator (MISO), and the Electric Reliability Council of Texas (ERCOT), though that result assumes that peak shifting is inconsequential and there is no on-site generation.
For states implementing a rate-based program wishing to include demand response, state regulators, market operators, and demand response providers will need to determine acceptable accounting practices for determining whether a demand response resource is actually reducing, rather than shifting, load. Separately, the nature of participation by demand response in wholesale markets going forward remains in question as the Supreme Court reviews the D.C. Circuit’s decision to vacate FERC Order No. 745, which set compensation rules for demand response participation in real-time and day-ahead wholesale electricity markets. This creates some additional uncertainty for regulators and stakeholders as they consider the role that demand response might play in state plans.
In a mass-based program, the impact of the CO2 price on demand response will depend on whether demand response is competing with generation in wholesale markets. If demand response is competing in wholesale markets, the impact of the CO2 allowance on wholesale electricity prices would be expected to provide an incentive for additional demand response. However, as noted above, uncertainty over the fate of FERC Order No. 745 creates uncertainty over the future of demand response participation in wholesale markets. Policymakers interested in encouraging cost-effective reductions from demand response under mass-based plans will have to grapple with the uncertainty over market rules for demand response, and should consider how these reductions might be achieved under different scenarios and the role that complementary policies might play.
Transmission and Distribution Investments: Transmission and distribution system upgrades that improve efficiency or reduce electricity use at the end user are eligible to generate ERCs under a rate-based program. For example, advances in sensors and monitoring devices are enabling utilities to reduce losses through Volt/VAR Optimization (VVO) by enabling them to optimize voltage levels across distribution systems in real time. These technologies can be used in applications such as conservation voltage reduction (CVR), which reduces voltage at distribution feeder lines, and thus can lower end-use energy consumption and improve system efficiency and resilience. Load reductions that can be attributed to these investments can be used to generate ERCs. DOE’s assessment of investments in advanced VVO technologies made under the American Recovery and Reinvestment Act of 2009’s Smart Grid Investment Grant program found that CVR projects indicated a potential for peak demand reductions of between 1 percent and 2.5 percent.
How state regulators view investments in advanced transmission and distribution technologies will likely determine their relevance as a tool for Clean Power Plan compliance. As BPC’s Electric Grid Initiative noted in its 2013 report, for many smart grid technologies, insufficient information on performance, particularly under a range of system conditions, has deterred investment by utilities and acceptance by state regulators. Therefore, absent clear support from regulators, it is not clear that the incentives provided by ERCs will be sufficient to encourage utilities to make such investments. Separately, to enable confidence in ERCs from transmission and distribution investments, utilities and regulators will have to work to develop best practices for assessing the load reductions from these measures.
Under a mass-based program, the incentives for transmission and distribution investments will vary depending on the regulatory structure of the state. Vertically integrated utilities, for example, have the ability to compare the economics (and likely regulatory treatment) of potential emission reduction opportunities across their entire system. In deregulated states where generation participates in competitive wholesale electricity markets, however, there is no built-in incentive for transmission and distribution investments as an emission reductions option, because the CO2 price is reflected in the wholesale markets. In such states, regulators that view transmission and distribution investments as a cost-effective strategy for Clean Power Plan compliance would need to factor in the potential emissions benefits into their review of such investments, and—as discussed above—would need to consider regulatory policies in support of these investments, as well as whether allowance allocations might also be used to encourage such investments.
Energy storage: In the final rule, EPA recognizes the role that energy storage can play in increasing the efficiency of the system and enabling the integration of zero-emissions renewable energy. However, energy storage is not eligible to generate ERCs under a rate-based program because it does not directly substitute for electric generation from the grid or avoid electricity use from the grid. Rather, any increased renewable generation enabled by energy storage would be eligible to generate ERCs. Similarly, a mass-based approach would not inherently provide a direct incentive for energy storage. States that wish to encourage energy storage in order to facilitate renewable energy integration or improve system efficiency under either type of program could attempt to do so through complementary polices (and, in the case of a mass-based program, distribution of allowances).
Looking forward, as states consider how to implement the Clean Power Plan, they will have to consider a multitude of economic and political factors, as well as the ease with which different options can be implemented. Understanding how implementation choices interact with existing market and regulatory structures, and what this means for potential emission reduction strategies, is one piece of this discussion. Stay tuned for additional analysis of other key issues facing state policymakers as they evaluate implementation options.