This post is part of our ongoing series on the Clean Power Plan. Each report focuses on a different aspect of the administration’s Clean Power Plan rule and its impact on the energy sector. For more information on how your facility may be affected by the new rule, please contact us at firstname.lastname@example.org or at (281) 333-3339.
The heart of the Clean Power Plan lies in two new emission performance rates for fossil fuel electric generating units (EGUs) developed based on the three building blocks determined by the EPA to be the best system of emission reductions (BSER). These performance rates serve as the technical and legal backbone to the current CPP and the basis for the each state’s rate-based (lbs/ New MWh) and mass-based (short tons) emission goals.
What facilities are impacted?
Before the EPA could set state emission goals, an emission standard that was achievable solely through the efforts of specific existing sources had to be established. Having specific existing sources, labeled “affected units”, as the foundation for the state goals is important not only because of its influence on the development of state-level implementation plans, but because these sources will be the only ones required to participate in the federal trading program if a state fails to develop its own plan.
|Affected Fossil Fuel-Fired EGUs|
|Affected Units||Excluded Units|
|Fossil Fuel-Fired Electric Steam Generating UnitsAll fossil fuel-fired electric utility steam generating unit with:a generator capacity >25 MW; anda base load rating >250 MMBtu/h heat input (HHV) of fossil fuel (either alone or in combination with any other fuel).||New, modified or reconstructed fossil-fuel EGUs that had not commenced construction as of January 8, 2014Simple cycle turbinesNon-fossil fuel units (i.e., units that are capable of combusting 50 percent or more non-fossil fuel) using fossil fuels in 10 percent or less of the annual capacity factorStationary combustion turbines that are not capable of combusting natural gasSteam generating units or IGCC units that are subject to a federally enforceable permit limiting net-electric sales to one-third or less of its potential electric output or 219,000 MWh or less on an annual basisCombined heat and power units that are subject to a federally enforceable permit limiting, or have historically limited, annual net electric sales to a utility power distribution system to the product of the design efficiency and the potential electric output or 219,000 MWh (whichever is greater) or lessUnits that serve a generator along with other steam generating unit(s), IGCC(s), or stationary combustion turbine(s) where the effective generation capacity is 25 MW or lessNote: An excluded or unidentified unit may still be regulated by its respective state to meet that state’s emissions goal.|
|Stationary Combustion TurbinesCombined cycle turbines and combined heat and power combustion turbines with:a generator capacity >25 MW; anda base load rating of greater than >250 MMBtu/h.|
What are the emission performance rates?
After determining which sources would be subject to the new rule, the EPA went on to calculate the performance standard based on what it found to be (i) achievable by the source categories, (ii) adequately demonstrated in practice, and (iii) most effective at reducing emissions while considering, cost, energy impact, and ancillary health and environmental impacts. The agency ultimately settled on emission performance rates comprised of three “building blocks”:
From these building blocks, the EPA developed emission performance rates based on the carbon intensity of each subcategory of affected units (see below).
Emission Performance Rates
(Adjusted Output-Weighted-Average Pounds of CO2 Per Net MWh from All Affected Fossil Fuel-Fired EGUs)
|Subcategory||Interim Rate||Final Rate|
|Fossil Fuel-Fired Electric Steam Generating Units||1,534||1,305|
|Stationary Combustion Turbines||832||771|
Determining the state goals
The EPA developed both rate-based and mass-based goals for each state. The rate-based goal weights the two emission performance rates according to the generation mix of each state to determine the composite goal. As a result, coal heavy states, like Colorado, have a higher rate-based goal (i.e., 1,174 lbs of CO2/Net MWh) while others, like Massachusetts, have a much lower goal (i.e., 824 lbs of CO2/Net MWh). A higher state-level goal is indicative of a greater concentration of fossil fuel steam EGUs within the state versus stationary combustion turbines.
In addition to the rate-based goal for each state, the EPA calculated mass-based goals measured in total short tons of CO2. Mass-based goals are particularly important because they represent an alternative to the rate-based goals and are the only means a state can use to demonstrate compliance under a “state measures plan”, the most flexible of the state implementation tools available.
The state rate- and mass-based goals are established for each of three interim periods, 2022-2024, 2025-2027, and 2028-2029. The goal is not required to be met every year within a discrete interim period, so long as the average performance within the given interim period meets that interim period goal (i.e., all emission reductions can occur in the last year of the interim period, provided they are steep enough to offset earlier emissions). This gradual implementation culminates in 2030 when a state is required to meet its final performance goal. Beginning in 2030, states must meet their final goal for every two year successive period. The CPP is designed so that the post-2030 goals can easily be made more stringent if deemed appropriate.
What is the impact?
The EPA estimates that coal will still provide about 27 percent of the projected generation in 2030, with natural gas providing about 33 percent of the mix. To put that in perspective, this past May, the U.S. Energy Information Agency (“EIA”) forecast that, without a Clean Power Plan, coal would make up approximately 37% of the U.S. electric generation mix in 2030, with natural gas composing 29%. When the EIA considered a more abundant natural gas supply and more efficient extraction methods in their forecast, the projected mix shifted to 30% of the total for coal and 38% coming from natural gas.
In our next installment, we will discuss how state implementation of the new rule will affect individual operating units.