As evidenced by the 27 states that are suing the EPA, the agency’s recently-finalized Clean Power Plan(CPP) is controversial to say the least. In addition to the legal challenges facing the rule, there are also concerns over grid reliability posed by the large number of coal-fired generator retirements anticipated in the near term. Although much ink has been spilled on analyzing the Clean Power Plan, aside from discussions over grid reliability, little attention has been paid to other potential interstate effects posed by intra-state CPP compliance efforts, and vice versa. Despite the pitfalls posed by discordant state implementation plans within a region, the CPP nonetheless does not require regional collaboration. As argued in this essay, however, by failing to collaborate, states may not only put their own and neighboring states’ CPP compliance plans at risk, but also jeopardize existing and future regional electric system planning efforts.
Finalized on October 23, 2015, EPA’s Clean Power Plan seeks to reduce carbon dioxide emissions (CO2) from power plants 32 percent below 2005 levels by 2030. Through section 111(d) of the Clean Air Act, the agency established state-specific fossil-fuel electric generating unit CO2 emission performance rates. Referred to as the “best system of emissions reduction . . . adequately demonstrated” (BSER) in CAA parlance, the final rule breaks down the performance rates into equivalently expressed rate-based or mass-based goals that states can choose between as a means of achieving compliance. To reach the nation-wide 32 percent CO2 reduction goal, the individual state performance rate reductions range from 7 percent in Connecticut to 47 percent in Montana.
The rule gives states flexibility in achieving their emission performance rates, and one of the first questions state implementers must decide is whether to pursue a rate-based or mass-based approach. Under a rate-based approach, fossil-fuel generators would be prohibited from exceeding a certain amount of carbon per unit of produced power, usually expressed in megawatt hours. A mass-based plan, on the other hand, would set a state-wide cap on total carbon dioxide emissions from the electric power sector. To further facilitate state and regional compliance, the final CPP allows states to enter into trading schemes with other states that implement the same rate- or mass-based approach.
Absent an order to stay the rule while pending litigation proceeds, states will have untilSeptember 6, 2016 to submit their implementation plans to EPA, with a possible 2-year extension. A federal implementation plan will await any state that fails to submit a plan, or submits an inadequate plan.
A legal victory for EPA is by no means assured; the legal challenges cover the gamut, from whether EPA is impermissibly regulating beyond the “fence line” to whether the agency even has the authority to regulate carbon dioxide emissions under CAA section 111(d) at all. Aside from these law suits, another long-standing concern is whether the projected wave of coal-fired plant retirements will threaten the reliability of the nation’s electric grid. The most prominent voice of this criticism has been the North American Electric Reliability Corporation (NERC), the nation’s Electric Reliability Organization, which highlighted its concerns in a report in November 2014, prompting NERC’s oversight body, the Federal Energy Regulatory Commission, to solicit feedback from stakeholders through a series of meetings and technical conferences. In a resultingletter to EPA from the Commission, FERC noted that although “existing processes for identifying and addressing reliability issues . . . are generally adequate,” any lingering reliability concerns could be allayed through, for example, including a backstop “safety valve” to prevent closure of critical grid assets during unanticipated reliability events. EPA adopted FERC’s “reliability safety valve” suggestion for the final rule, andpromised to coordinate with FERC and DOE to ensure grid stability throughout the rule’s multi-year implementation.
But stabilizing the grid is not the same as modernizing it, and when it comes to Clean Power Plan compliance, EPA’s concern (along with FERC and NERC) is the former, not the latter. States, on the other hand, are at the forefront of CPP compliance as well as grid-modernization reforms — as exemplified by ongoing proceedings in states like New York, Minnesota, Hawaii, Maryland, Massachusetts, and California, as well as the District of Columbia.
It remains up to the states, therefore, to consider what effect their CPP implementation — and that of their neighboring states — will have not only on reliability but also on existing and future efforts to modernize their regional systems. As a result of the interconnected nature of the electric grid, failing to consider the interstate effects of individual state CPP-compliance could spell trouble in numerous ways. As states continue crafting their implementation plans, here are some questions they should ask themselves…and their neighbors.
- Is our electric resource mix vulnerable to likely generator closures in neighboring states? One almost-certain effect of CPP compliance will be continued coal plant closures, a trend already underway due to competition from renewables, cheap natural gas, and other factors. According to a May 2015 analysis by the EIA, coal plant retirements could total 90 GW under the CPP — with most closures occurring by 2020 — as opposed to 40 GW of coal-fired retirements without the Plan. In its April 2015 Phase I report on the CPP’s grid reliability impact, NERC projects that the regions facing the most coal and natural gas retirements will be ERCOT, SPP, NPCC, and MISO, with about 10, 7, 11, and 9 GW of closures, respectively between 2016-2020. Although considerable attention has been paid to the reliability impacts of such closures, little analysis has yet been done on the effect that they may pose to a neighboring state’s own CPP compliance or resource procurement. For example, if one state’s implementation plan and electricity resource mix both depend on receiving power from another state’s coal-fired plant, how would the closure of that plant affect the importing state’s CPP compliance and electricity resource needs? Furthermore, according to NERC’s Phase I report, CPP implementation will result in significant shifts in regional power transfers. It is up to the states themselves to ensure that these shifts and prospective plant closures will not disrupt their own resource procurement needs, CPP compliance options, and future regional system planning goals.
- Do we rely on imported nuclear power from a state that is considering a rate-based Clean Power Plan compliance option?
This is primarily a concern for states in competitive markets that are home for financially struggling commercial nuclear power generators. As noted in the NEI’s recent Status and Outlook for Nuclear Energy in the United States, and explained more comprehensively in an article co-authored by GW Law’s Professor Hammond, various market-related factors have led to the closure, or announced closures, of seven nuclear reactors in the United States. These early retirements not only affect grid reliability but also threaten to stall, if not completely derail, the nation’s existing carbon emission reduction progress. Nuclear energy advocates urge states to consider EPA’s proposed mass-based CPP compliance option, because it looks at total emissions output, thereby inherently valuing the emissions-free characteristics of nuclear generation. The rate-based compliance option disadvantages existing nuclear generation, the argument goes, because it only considers emissions from existing fossil fuel-powered plants. As a result, a state like Illinois could replace any or all of its several financially struggling nuclear generators with low-emissions natural gas units and still be in compliance with the CPP, notwithstanding that CO2 emissions would increase. In addition to potentially impacting grid reliability and our national CO2 emissions goals, nuclear plant closures affect the states and regions relying on that nuclear power to meet their resource needs. In that sense, then, it should matter to states whether their neighbors are choosing a CPP compliance option that may put significant amounts of base load generation at risk.
- Is our rate-based or mass-based compliance approach compatible with that of our neighbors?
In the final rule, EPA recognized the value of using regional emissions trading schemes to ensure compliance. Through a rate-based or mass-based trading program, generators can purchase compliance credits — either, respectively, an “Emission Rate Credit” (ERC) representing one MWh of electric generation (or reduced electricity use) with zero associated CO2 emissions, or an Emission Allowance representing one ton of CO2 emissions. A major catch, however, is that states can only enter into regional trading schemes with states that implement the same rate-based or mass-based approach. Policy arguments for adopting each type of scheme will vary by state, so if participating in a regional trading scheme, or keeping that option open, is important for state regulators, it would behoove them to collaborate with their neighboring counterparts to ensure that their respective compliance approaches are not incompatible.
- Does our compliance strategy depend on building new multi-state financed transmission infrastructure?
Another potential conflict may arise when states consider what infrastructure will be necessary to facilitate their CPP compliance, as well as to implement their broader intra- and interstate electric system planning goals. By EPA’s own estimation, the final CPP will result in 706,000 GWh of new renewable generation by 2030 (an increase from the proposed rule’s 305,000-335,000 GWh estimate). Some of this new renewable energy may be already grid-accessible, but more likely, a significant portion will require transmission system expansions to be harnessed, as acknowledged in the final rule and confirmed through separate analyses by organizations like EIA and ICF. Although some utilities like Xcel Energy are expanding their transmission networks to reach remote renewable resources in states like Colorado, Minnesota, and the Dakotas, many others are biding their time. This is an understandable reaction, considering the protracted siting battles, cost allocation disputes, and multi-year commitments involved in taking a transmission project from concept to completion. For these and other policy reasons, some states may opt for intra-state distributed generation projects, as opposed to participating in a multi-state financed transmission upgrade. Because interstate transmission projects are so expensive, the economics of such an endeavor would be negatively affected if a previously-committed or interested state opted for a non-transmission alternative instead. If a neighboring state relied on that infrastructure project to meet its own CPP or electric system planning goals, it could suddenly find itself walking a very lonely road. Without extensive conversations about electric system planning goals and CPP compliance options, state regulators may inadvertently affect their neighbors’ own policy objectives.
The significance of these questions goes beyond simply ensuring regional grid reliability. Indeed, EPA’s final rule included FERC’s suggestions that were designed to keep the lights on, and the agency has furthermore committed to cooperating with FERC and DOE toward that end as well. Rather, the point here is to illustrate the wide-reaching effects that an individual state’s Clean Power Plan compliance may have on its neighbors and vice versa. Intra-state clean power plan compliance may be sufficient to satisfy the EPA and forestall blackouts, but without considering the inter-state implications, states risk misaligning their policy goals and stunting existing and future regional electric system planning efforts.
TransMissives 