Achieving Clean Air Act Section 111(D) Carbon Regulation Compliance via Nuclear Load-Following in the Southeastern United States

Abstract

As the effects of climate change loom nearer and threaten the global community at large, it is imperative that major emitters of greenhouse gasses (GHGs) begin to curb their rates of emission to limit and mitigate those impacts. Carbon dioxide (CO2) is the largest single component of GHGs in the atmosphere comprising roughly 400 ppm, according to the National Oceanic and Atmospheric Administration (NOAA) 1. In 2012, just over 82% of GHG emissions in the United States were embodied as CO2 with methane (CH4) as the second highest form of GHG emissions at just under 9%. According to the United States Environment Protection Agency’s (EPA) GHG Inventory, the power sector comprised just over 31.6% of all GHG emissions across the nation2. Power systems are operated such that the lowest cost non-variable resources are generally brought online to meet demand and more expensive, non-variable sources of generation are brought online subsequently as demand increases in real time and more online generation capacity is necessitated. Most often, this lowest cost resource comes in the form of nuclear and coal-fired power. Compared to other non-variable, non-renewable fuel sources (i.e. natural gas & nuclear fuel rods), coal is particularly carbon-intensive and poses a number of other associated health and atmospheric risks 3. In response to the growing threats of climate change and in an attempt to de-carbonize the power sector the EPA began to field comments on CO2 regulation in 2013, and moved forward with publication of its proposed ‘Clean Power Plan’ (CPP) in 2014 4. The EPA derived its rulemaking authority from section 111(d) of the federal Clean Air Act. A year-long comment period followed, and, on 3 August 2015, the EPA released its final rule, which was subsequently published in the Federal Register on 23 October of the same year 5. While many states have internal goals for the power sector via Renewable Portfolio Standards (RPS) and other state-level tax incentives for renewable generation to complement the existing federal Investment Tax Credit (ITC) and Production Tax Credit (PTC), the CPP represents the first federal regulation on CO2 as an air pollutant. Section 111(d) of the Clean Air Act pertains to the regulation of harmful pollutants resulting from existing stationary sources of pollution and excludes those 187 hazardous air pollutants (HAPS) specifically mentioned and regulated under section 112 of the same statute 6. The proposed and final rule both require a reduction in CO2 emissions from all existing electrical generating units (EGUs) greater than 25 MW in generating capacity by 2030 on a state-by-state or region-by-region basis 7. This allows for states to comply by achieving CO2 emission reductions alone or in conjunction with partner states, requiring associated states to coordinate amongst themselves. Emission reduction compliance can either be achieved through a mass-based system, meaning that annual emissions (in tons CO2/year) from EGUs in a state or collection of states will be the benchmark of compliance, or a rate-based scale which looks at average emissions across the entire fleet of regulated EGUs within a state or partnered group of states as measured in lbs CO2/MWh 7.Existing generation sources under the EPA’s final rule pertain to all units that are online prior to 2020. States attempting compliance must submit a compliance plan, often called a ‘state implementation plan’ (SIP) by 2016, while those states working in tandem must submit their SIPs to the EPA for approval by 2018. In general, the EPA requires a 30% mass reduction in annual emissions or a 30% reduction in rate of CO2 emissions by 2030 based on 2005 emissions levels 6. The EPA recommends three building blocks for compliance: 1) improving heat rates at existing facilities, 2) switching coal units to natural gas units, and 3) developing emission-free resources 6. In addition, it should be noted that energy efficiency will also likely play a critical role in achieving targets at the state level. A fourth block for demand-side management and end-user energy efficiency was initially included in draft released for public comments in 2014. It has since been removed, but remains a viable compliance strategy that states are likely to include as part of their emissions compliance strategies 8. While renewable energy in the form of wind and solar technology, is often touted as a means of achieving the needed reductions in power sector GHG emissions, it should be noted that such power is variable and cannot reliably serve as baseload capacity to meet energy demand. Such power sources often prove effective for shaving a system’s demand profile and curbing the probability that smaller, generally more carbon intensive ‘peaking’ plants need to come online. This is not to say that there is no value derived from the generation that occurs during off-peak hours and mitigates emissions by allowing for baseload capacity to ramp down. These sources are particularly dependent on tax credit subsidies which expire and require relatively frequent renewal 9, 10. These resources are also highly geographically dependent. Siting the same 100 MW of solar PV generation capacity in two different geographic locations can have wildly different implications for the greater grid to which this generation is interconnected 11. In addition, hour-to-hour generation can vary differently as well at a given site 12. Non-variable renewable energy (i.e. biomass generation) often requires feedstock with competing value chains, and the means by which feedstock is processed and delivered is not as streamlined or viable at the same scale as natural gas and coal.As energy companies in the United States begin to extract natural gas resources that were previously untapped via hydraulic fracturing (‘fracking’), pipeline natural gas, which is less carbon intensive than coal and results in fewer particulate matter-related health issues, has become cheaper and is becoming more cost-effective at larger scales than has previously been the case (see Figure 1) 13. In addition, compared to bituminous coal, combustion of natural gas results in a 43% reduction of CO2 emissions when compared with bituminous coal per MMBtu of fuel combusted 14.