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TABLE OF CONTENTS

5.7 Treatment of interstate effects............................................................................................... 3

5.7.1 State may claim the impact of a measure on CO2 emissions from affected EGUs 

within its borders.............................................................................................................. 3

5.7.2 State that implements the measure claims the emission effects..................................... 16

5.7.3 Cooperative multi-state accounting of interstate emission effects ................................ 36

5.7.4 Tradable regional EE/RE credit market ......................................................................... 42

5.7.5 Regional demonstration by states of emission performance.......................................... 81

5.7.6 Assessment of interstate effects by the EPA in the course of state plan review........... 93

5.7.7 Other ................................................................................................................................... 98

5.8 Projecting EGU CO2 Emission Performance .................................................................. 123

5.8.1 Electricity System Modeling Approaches for Projecting EGU CO2 Emissions........ 123

5.8.1a National-scale capacity expansion and dispatch planning models............................ 135

5.8.1b Utility-Scale Capacity Expansion and Dispatch Planning Models............................ 135

5.8.1c Electricity System Dispatch Simulation Model ........................................................... 135

5.8.1d Multi-Sector Models...................................................................................................... 137

5.8.2 Growth Tools for Projecting EGU Utilization and CO2 Emissions............................ 139

5.8.3 Translating from a rate-based emission performance goal to a mass-based emission 

performance goal .......................................................................................................... 140

5.8.3a Reference Case Scenario ............................................................................................... 145

5.8.3b Mass-Based CO2 Emission Goal Policy Scenario....................................................... 147

5.8.3c State Plan Policy Scenario............................................................................................. 147

5.8.4 Projecting CO2 emission performance under a state plan .......................................... 147

5.8.5 Applied Considerations for Different Types of State Plans......................................... 148

5.8.5a Approaches for Estimating the Future Effects of State Energy Efficiency 

Requirements, Programs, and Measures.................................................................... 149

5.8.5b Potential Uses of Energy Efficiency Projections for State Plan Emission Projections

......................................................................................................................................... 149

5.8.5c Data Issues and Considerations for Using and Developing Energy Efficiency 

Projections..................................................................................................................... 150

5.8.5e Renewable Portfolio Standards .................................................................................... 152

5.8.5f RPS as an Input to Electricity Sector Modeling .......................................................... 153

5.8.5g Data Needs for Estimating Generation Resulting from State RPS ........................... 154

5.8.5h Feed-In Tariff................................................................................................................. 154

5.8.5i Data Needs for Estimating Generation Resulting from Feed-In Tariff and 

Performance-Based Tax Incentives............................................................................. 155

5.8.5j Emission Budget Trading Programs............................................................................. 155

5.8.5.k Addressing the Sectoral Scope of Emission Budget Trading Programs.................. 155

5.8.5l Addressing Multi-Sector Emission Trading................................................................. 155

5.8.5m Addressing Emission Offsets....................................................................................... 156

5.8.5n Multi-State Emission Trading Programs .................................................................... 174

5.8.6 Process Considerations for conducting EGU CO2 emission projections ................... 176

5.8.6a Provision of the EPA Guidance .................................................................................... 178

5.8.6b Party that Translates the Rate-Based Goal to a Mass-Based Goal........................... 178
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5.8.7 Other ................................................................................................................................. 182

5.9 Treatment of existing state regulations and programs.................................................... 193

5.10 Treatment of New Fossil Fuel-fired EGUs ..................................................................... 228

5.11 Consideration of a facility's "remaining useful life" in applying standards of 

performance................................................................................................................... 236

5.12 Design, Equipment, Work Practice, or Operational Standards................................... 274

5.13 Emissions averaging and trading .................................................................................... 276

5.14 State-specific Implementation Considerations............................................................... 306

5.15 Other .................................................................................................................................. 326
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5.7 TREATMENT OF INTERSTATE EFFECTS

This section addresses programs and measures in a state plan that may affect the emission 

performance of the interconnected electricity system beyond a state border. In addition, many 

state measures allow for actions in neighboring states to meet the in-state requirement, or 

explicitly address CO2 emissions in neighboring states. We have organized the comments in this 

section under 8 subsections, 5.7.0 to 5.7.7. Responses to the comment topics of these subsections 

are discussed below, along with summaries of the specific public comments.

5.7.1 State may claim the impact of a measure on CO2 emissions from affected EGUs 

within its borders

This section contains comments on the proposed method for accounting EE emission reduction 

measures.

Commenters have raised a number of issues related to this subsection which are organized by 

topics (comments) below. Responses are provided for these topics. 

Comment 1: Comments disagreeing with proposed method for accounting for EE emission 

reduction measures; tracking energy savings to a specific utility; and symmetry between goal 

calculation and compliance measures, especially for EE.

Response 1: The treatment of EE has changed from the proposed approach. In the final rule, to 

the extent demand-side EE measures are tied to a state plan, the full quantified and verified 

MWh impacts of the measures may be used by an affected EGU or state to adjust a CO2 emission 

rate, regardless of whether the demand-side EE savings occur inside or outside the state or 

territory. Discounting is not required. For more information about the treatment of in-state and 

out-of-state energy efficiency impacts, see section VIII.K and VIII.L of the preamble to the final 

rule. 

The EPA revised the methodology used to calculate CO2 emission performance rates and state 

rate-based CO2 goals from the one used in the proposal. In order to ensure consistency with the 

calculation of CO2 performance rates and state rate-based CO2 goals in the final emission 

guidelines, and to avoid double-counting or inconsistent adjustment approaches across states, the 

final rule prescribes a general accounting approach states must use to adjust the CO2 emission 

rate of an affected source to reflect the MWh impacts of zero-emitting and low-emitting 

resource. Quantified and verified MWh impacts of qualifying zero-emitting and low-emitting 

resources tied to a state plan may be used by an affected EGU or state to adjust a CO2 emission 

rate, regardless of whether the renewable generation or demand-side EE savings occur inside or 

outside the state or territory. This ensures that affected EGUs receive full recognition for their 

investments, even if the impacts occur elsewhere, removing the need to determine exactly which 

EGUs reduced and changed power generation in response to the zero-emitting or low-emitting 

resource and removing what commenters below called the energy efficiency penalty described.
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Consistent with the EPA’s calculation of the CO2 emission performance rates and state ratebased CO2 goals in the final emission guidelines, the quantified and verified MWhs impacts are 

added to the denominator of an affected EGU’s reported CO2 emission rate, resulting in a lower, 

adjusted CO2 emission rate. The reported CO2 emissions reflect the actual emission reductions 

from the deployment of qualifying non-emitting and low-emitting resources across the regional 

grid. Further adjustment of CO2 emissions, such as through the subtraction of emissions 

estimated by applying an emissions factor to the MWhs, would double count CO2 emissions 

impacts across the grid. For more information about specific methods to adjust the CO2 emission 

rate of an affected EGU to reflect demand-side EE, including specific geographic eligibility 

requirements and limitations, see section VIII.K.1.a of the preamble to the final rule.

In this final rule, while the EPA allows the use of eligible EE measures to meet the emissions 

guidelines, demand-side EE is no longer incorporated into the BSER. For more detail on BSER, 

refer to section V of the preamble to the final rule.

The final rule allows for both rate-based and mass-based trading systems. Because of the 

separate accounting of MWhs and CO2 emissions, with emission impacts inherent in reported 

stack CO2 emissions and zero-emitting MWh impacts requiring explicit adjustments, the MWh 

accounting method corresponds with the use of MWh-denominated Emission Rate Credits 

(ERCs) in the rate-based emission trading framework as specified in this rule. 

The specific methods to adjust the CO2 emission rate of an affected EGU to reflect RE and 

demand-side EE are described in section VIII.K.1 of the preamble to the final rule. The same 

section also describes the eligibility requirements and conditions for resources to be used to 

adjust a CO2 emission rate. The preamble to the proposed Federal Plan describes the provisions

related to proper quantification and verification of MWhs from renewable electricity generation 

or demand-side EE savings in Section IV.D.8 of the preamble to the proposed Federal Plan.

Information about the requirements for rate-based emission trading programs and the issuance 

and tracking of ERCs are described in Sections VIII.C and VIII.K.2 of the preamble to the final

rule. The final rule also allows for mass-based trading systems, as described in Sections VIII.C 

and VIII.J of the preamble.

The following are summaries of the specific public comments under this comment:

Multiple commenters had significant concerns about the proposed approach for crediting energy 

efficiency in state compliance plans. Commenters disagreed with the proposed method for taking 

into account EE measures by discounting the emissions savings by the proportion of electricity 

imported and assumed to result in emission reductions that occur in exporting state. Commenters 

thought there should be equitable requirements with respect to both energy-exporting and 

energy-importing states. Commenters felt the EPA’s method of accounting for EE was inherently 

arbitrary and serves no valid purpose. Commenters stated states that generate the most coal 

power, such as Wyoming, Montana, West Virginia and Kentucky, tend to be states that are small 

in population and, therefore, export a great deal of the coal power they generate. Commenters

stated there is therefore little connection between the amount by which these states may reduce 

their electricity consumption and the amount of coal power these states will generate.
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Multiple commenters supported including 100 percent of the EE savings in the state, rather than 

the EPA proposal to devalue those savings by multiplying them by the in-state generation 

percentage. Commenters argued that the full benefit of ratepayer investment in energy efficiency 

projects should accrue to the state implementing the programs. Commenters stated that as 

currently proposed, the full benefit of energy efficiency projects is not credited in a net importer 

state, nor is it accounted for in any other state, thereby eliminating a portion of these measures as 

a compliance mechanism.

Commenters indicated that pro-rating also creates a new problem by failing to give states that are 

net importers of electricity full credit for their EE measures, and this disparate treatment 

increases the burden on states that are net importers electricity in meeting their state goals. 

Rather than incorporating emissions reductions from EE into state goals differently based on 

whether the state imports electricity, commenters stated that the EPA should eliminate EE from 

the state goals.

Commentersfelt that it is important that net importers get full credit for their investments in 

energy efficiency where such investments are reducing generation from fossil-fired resources. 

Commenters added that failing to provide full credit for EE investments will mean that a 

significant amount of energy efficiency is not recognized as a compliance option, even when 

they are having the practical effect of displacing in-state generation. Commenters noted that 

Georgia (a net importer of electricity) would receive only 88% of the emissions reductions from 

EE investments under the proposed rule. Commenters stated that this would act as a disincentive 

for net importing states such as New Jersey to utilize cost effective EE as a compliance tool. 

Commenters asserted that a state that is willing to fund EE should be able to take full credit for 

that investment and noted this approach is consistent with the proposed compliance rules for 

Building Block 3 which would allow a state to take credit for RE purchased by the state, even if 

the resource is out-of-state. Commenters noted that if the EPA only credits Wisconsin with 

83.97% of its savings as proposed, then the state is not being credited for $15 million in 

investments in 2012 alone. Commenters stated that the EPA should grant the full credit for 

avoided emissions due to the EE measures to the state that instituted and paid for the measure, 

which is consistent with the proposed compliance rules for Building Block 3. Commenters

stated that if Virginia were to receive credit for the full 100 percent of its energy efficiency, the 

reduction would increase from 9 lbs/MWh to 14 lbs/MWh. Commenters stated that the proposal 

essentially reduces North Carolina's EE savings credit by 13.88% even though North Carolina 

electricity consumers have been implementing and paying for 100% of the utility-sponsored EE 

and DSM programs implemented in the state. Commenters stated that the "net importer" 

adjustment improperly shifts a portion of these benefits to other states and leaves the 

corresponding costs of EE in the state producing EE savings. Commenters supported a consistent 

compliance approach where the state that implements energy efficiency measures claims 

equivalent emissions reduction benefits in its state compliance plan. Commenters stated 

allowing the state that implemented the EE program to claim the savings and emissions 

reductions benefit is consistent with the approach the EPA took when it calculated building block 

4 savings. Commenters stated a significant portion of Washington's investor-owned utilities 

import fossil fuel generation from outside state borders. Commenters stated that dispatch of those 

out-of-state plants is dependent upon the load demand in Washington. Commenters stated if the 

state is unable to claim out-of-state efficiency savings, it distorts the value of energy efficiency 

implemented within the state. Commenters stated if the final rule only allows a state to claim the 
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in-state emissions reductions of energy efficiency, the EPA would need to symmetrically adjust 

the building block 4 target to reflect the diminished energy efficiency savings.

Commenters noted that, as proposed, about 30 percent of California's EE benefits would not be 

credited to any state. Commenters also noted that determining which EE savings displace 

generation inside and outside of California would entail complex modeling and an analysis of 

error and uncertainty; as such, it would be very difficult to determine where the reductions 

occurred. Commenters noted that under the current approach, RE would count 100 percent 

towards compliance while EE would only count a fraction of that which places EE at a 

disadvantage even though both resources are expected to have the same effect on dispatch of inor out-of-state resources. Commenters recommended that the EPA should use the same approach 

for EE and RE: the state that pays for the new resource (RE or EE programs) counts 100 percent 

of the new resource for compliance. Commenters stated that California's total EE savings are 

being devalued by approximately 30 percent before being applied to the BSER goal, therefore 

California utilities believe that the EPA should include 100 percent of California's modeled EE 

savings in the goal-setting process, and symmetrically include 100 percent of EE savings during 

compliance.

Commenters stated that in estimating emission reductions from building block 4, the EPA should 

make no adjustment for either net electricity-importing or net electricity-exporting states, and 

instead base estimated emission reductions on the "avoided net generation value." Commenters

stated the opportunity for a state to reduce the amount of greenhouse gases emitted using 

demand-side energy efficiency improvements depends on the size and composition of electricity 

loads in the state. Commenters stated that the EPA should recognize this in applying Building 

Block 4 to set state goals: estimating the amount of annual incremental reductions in the state's 

electricity usage solely by applying an annual percentage savings rate to a state's baseline annual 

sales, accounting for transmission and distribution system losses. Commenters stated the EPA 

should not then reduce this amount by the portion of a state's load served by out-of-state 

generation, as proposed and as detailed in the Goal Computation TSD. Commenters stated this 

unbalanced adjustment does not reflect the load-based nature of the energy efficiency 

opportunity, unfairly deprives importing states the full greenhouse gas reducing impact of 

demand-side EE measures its electricity customers pay for, and leaves the excess efficiency in 

net-importing states unused in the target-setting process, even though this excess efficiency will 

actually decrease affected EGU emissions. Commenters stated making no adjustment in Step 5 

for either net electricity-importing or -exporting states would best reflect the actual potential for 

energy efficiency in each state. Commenters stated if the EPA chooses to retain an adjustment, 

the EPA should scale up the estimated reduction in generation by affected EGUs in net 

electricity-exporting states to reflect an expectation that a portion of the generation avoided in 

conjunction with the demand-side energy efficiency efforts of other, net electricity-importing 

states would occur at those EGUs. 

Commenters stated this adjustment also obviously creates wide disparities in setting state goals 

given that different states import and export different amounts of power. Commenters stated the 

adjustment requires states that consume all or most of the power they generate to reduce electric 

consumption more than states that import a greater amount of their power. Commenters stated 

yet, in an integrated grid, there is no reason why a state should wish to generate more or less 

power in-state; how much a state should rely on in-state power should depend on interstate 
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power economics. Commenters stated the entire thrust of federal electricity policy over the last 

two decades has been to break down artificial barriers and open up the power grid to the free 

movement of electrons so that consumers have the benefit of the lowest cost sources of 

electricity wherever those sources are located. Commenters stated that indeed, the EPA's policy 

of promoting renewable energy depends on promoting large-scale, long-distance electric 

transmission, as the areas richest in renewable resources (for instance in the Midwest wind belt) 

are not located near to the nation's major metropolitan areas. Commenters stated it therefore 

makes no sense to set state goals in part based on their percentage of in-state generation or to 

create an incentive for states to increase their use of in-state generation.

In addition, commenters stated the EPA's adjustment is arbitrary because it fails to account for 

all of the CO2 emissions reductions that will be created by the enormous amount of energy 

efficiency that the EPA is assuming. Commenters stated that in the EPA's Ohio example, for 

instance, 14.03 percent of Ohio's saved electricity is not counted against any state's goal, yet all 

of Ohio's reduced consumption would avoid electric generation (and thus presumably CO2

emissions) somewhere. Commenters stated that presumably, that 14.03 percent savings should be 

credited to the states which purchase power from Ohio, but the EPA never performs that 

calculation nor would it be feasible to do so on a 50-state basis given the dynamics of the 

interstate electricity market. Commenters stated in the end, the EPA's attempt to superimpose 

state-by-state energy efficiency targets on the interstate grid thus cannot help being arbitrary.

Several commenters had concerns about disincentivizing EE measures. Commenters stated that 

requirements must be easy to understand and not discourage energy importing states from 

funding and implementing EE programs. Commenters stated that this provision of the Proposed 

Rule risks diminishing the incentive for cost-effective, feasible emission reductions from EE 

measures, leaving significant EE on the table. 

Commenters believed that the EPA should base efficiency goals on electricity use, not 

generation, to avoid penalizing electricity-exporting states since the EPA's approach, as currently 

proposed, would make states' ability to achieve efficiency targets dependent on efficiency 

measures implemented in other states and would also impose higher efficiency savings 

requirements on electricity-exporting states as compared to electricity-importing states. 

Commenters also wondered how the EPA expects an electricity exporting state to effect demandside reductions in states to which it exports electricity (Is a state expected to add renewable 

generation that is not needed to meet in-state demand? Will it receive credit if, for example, an 

importing state installs renewable generation and thus reduces demand from the exporting 

state?)

Commenters stated that the proposal would only allow credit of a small portion of EE measures 

for some states. Commenters stated that only 12 percent of their state's load is served by in-state, 

investor-owned, fossil-fuel EGUs in part because much of the remaining load is served by fossil 

generation imported from EGUs in other states. Commenters stated that this approach would 

affect the cost-effectiveness and overall continued use of EE in their state. Commenters stated 

that if they could only claim 12 percent of the resulting emission reductions from their EE 

investment, then demonstrating cost-effectiveness of that EE investment would not be viable. 

Commenters stated that in their state, this approach would likely result in EE no longer being 
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considered a cost-effective emissions reduction strategy because only a small fraction of the 

energy savings can be attributed to reduction of emissions at in-state EGUs. 

Commenters stated that in the case where a mass-based system of compliance is utilized by a 

state importing power to their state, the remaining 88 percent of emission reductions may be 

surrendered to states whose ratepayers did not make that long-term investment in EE resulting in 

an unfair transfer of hundreds of millions of dollars of ratepayer investment. Commenters were 

also concerned about fairness. Some commenters stated that it would not be fair for neighboring 

states to take credit for EE savings from programs paid for and implemented in their state 

without a clear system for their reimbursement, while Commenters stated that this approach to 

calculate the impact of these savings would result in a very unfair outcome. Commenters

provided a table that commenters said showed the states that would be negatively impacted and 

the extent of that impact. Commenters stated that they estimate that this approach would result 

in approximately 41 million MWh of state energy savings that would go unclaimed. Commenters

stated that their state has seen EE measures to be the most sought after and least cost energy 

resource, under the EPA's base proposal, EE measures would be relegated to the least-sought 

after and most-costly resource.

Commenters had concerns about the ability of states to meet their goals under the CPP if the 

proposed EE approach was included in a final rule. Commenters asserted that, if their state's 

compliance plan included "only those carbon dioxide emission reductions occurring in the state 

that result from demand-side EE programs and measures implemented in the state," it would be 

extremely difficult and unnecessarily costly to meet the 2030 goal set by the EPA. Commenters 

stated that a net-exporting state would have limited in-state demand-side EE opportunities to 

offset the emissions at its affected EGUs relative to its in-state generation, while the state 

receiving the exporting state's generation could get credit only for efficiency that reduces in-state 

fossil generation, of which there may be relatively little. 

Commenters claimed that this proposal would mean that reductions stemming from EE programs 

in importing states could be "stranded," discouraging investment in EE measures. Commenters

stated that the EPA's asymmetrical approach to imports and exports means that electricity that 

can be avoided by Building Block 4's EE measures are effectively "stranded": the state targets 

simply do not account for these reductions. Commenters believed that the simplest and fairest 

"fix" to this problem is to avoid scaling down the obligations of importing states, and to 

recalibrate those states' targets to account for 100 percent of the demand reduction achieved 

through EE measures. Commenters noted that the EE targets specified in Building Block 4 do 

not include any assumptions about how the responsibility for implementing those measures 

should be distributed across the state's utilities or affected EGUs and it is therefore both feasible 

and fair to assign responsibility to in-state generators for achieving the level of EE savings 

specified in Building Block 4. Commenters stated that their fix would make the EPA's 

methodologies for RE and EE consistent. Commenters also stated that the EPA's approach relies 

too heavily on the net importation factor from a single year in setting state targets for 2030 as the 

percentage of energy that a state imports or exports can change significantly from year to year 

when units enter and exit the system and new transmission lines are built. Commenters stated 

that basing the state's target on its export-to-import ratio for one year could lead to targets that 

are either too high or too low. Commenters noted that the EPA is not proposing that neighboring 

states, including states that are net exporters would be allowed to claim credit for the portion of 
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EE emission reductions that presumably occur in those states; thus, the "discounted" amount of 

the EE credit is simply lost, and could not be double-counted.

Commenters stated that if the EPA were to finalize its proposal where EE measures in net 

importing states must be discounted, the rule would skew state incentives away from investments 

in EE and toward investments in RE, reductions from which can be fully counted toward state 

compliance regardless of the RE-producing state's status as a net importer or exporter, and 

regardless of whether the RE is generated in-state or out-of-state. Commenters added that the 

fact that net-importing states will have greater incentives to invest in RE than in EE is 

unreasonable given that each MWh of EE or RE is equally likely to reduce emissions by 

reducing the need for an extra MWh of generation from a fossil-fueled generator. Commenters

stated that because the potential emission reduction achievable by each MWh produced by an RE 

resource or saved by an EE investment is exactly the same, the EPA should treat these resources 

equivalently for compliance. Commenters urged that the EPA not require states to demonstrate 

that each MWh of EE saved in the state has reduced emissions in the state (as opposed to a 

neighboring or interconnected states) and noted that by allowing states to claim 100% of each 

MWh of energy saved in the state toward state plan compliance, the EPA could avoid 

disadvantaging EE relative to other forms of emission reductions while ensuring that RE and EE 

are treated the same for purposes of compliance. Commenters stated that if the EPA is unwilling 

to allow net importers to receive full credit for their EE investments, the EPA should allow states 

to submit approvable multi-state or modular agreements that apportion credit for EE among 

neighboring states.

Several commenters pointed out the different treatment in the proposal for EE and RE policies. 

Commenters asserted that this is not how the CPP treats any other emission reduction measure. 

Commenters stated that this accounting provision imposes a double standard, allowing full 

recognition for cross-state RE impacts, while denying full recognition to analogous EE actions.

Commenters stated that this strongly disincentivizes the use of EE as a compliance tool in power 

importing states and fails to reflect the carbon reduction benefits that are actually being achieved 

by statewide efficiency programs in such states when using a rate-based accounting approach. 

Commenters offered an example, comparing the treatment under the proposed CPP of a netimporting state installing solar panels and the installation of more efficient installation. 

Commenters stated that the solar panels could be given credit, regardless of where they were 

located; but the installation of the insulation would only generate credit for part of the actual 

MWh of energy savings (and therefore emission reductions) based on the proportion covered by 

in-state generation sold to that state's customers. Commenters stated that these analogous cases 

should not be treated differently. Commenters commented on the difficulty of determining how 

much EE displaces generation inside and outside a state. Several commenters stated that the 

EPA's approach attributing EE savings assumes that a state could trace exactly which affected 

units generate less electricity as a result of increased EE. Commenters contended that the nature 

of the interconnected electric system make it impossible to directly link certain EE measures 

with reduced utilization of specific units, let alone specific affected units. Commenters stated 

that the EPA is willing to accept a great deal of imprecision in determining the magnitude of 

reductions that result from EE measures, including assigning an average 10-year life to EE 

measures and allowing states to make assumptions to project the amount of electricity that will 

be saved. Yet, commenters stated, the EPA asks states to precisely assign "credit" for reductions 

associated with EE measures. Commenters stated that it would be arbitrary if the EPA allowed a 
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general level of imprecision when calculating the benefits of EE, but then penalized states by 

requiring precise attribution of these estimated benefits for compliance purposes. Commenters

stated that if the EPA thinks it is possible to link demand-side EE connected to a specific 

affected EGU, then the EPA should provide further information and guidance to states. 

Commenters noted that a utility would not know the value of potential energy efficiency 

measures until after the fact, since the emission reduction value of these energy efficiency 

measures might be discounted by a factor not known until the end of the compliance period and 

also that the utility generally has no control over this discount factor. Commenters stated the 

EPA's methodology of pro-rating EE savings based on the net importation of electricity fails to 

resolve the uncertainty in whether a state's EE measures actually lead to energy measures and 

emissions reductions in the state. 

Commenters added that an additional consideration is where a generating facility is located on 

the dispatch stack. Commenters provided an example of North Carolina and South Carolina; 

North Carolina is an electricity importing state, much of which comes from South 

Carolina. Commenters stated that South Carolina does not have any coal-fired EGUs and only 

has combustion turbines and nuclear units. Commenters stated that EE programs would never 

reduce the use of the nuclear units because they are at the bottom of the dispatch stack due to 

their low operating cost. Commenters stated that EE will affect the marginal generating unit, 

which will be a fossil unit in North Carolina, not the lowest cost nuclear unit. Commenters

concluded that it is not appropriate for the EPA to require that North Carolina, for example, 

discount the CO2 emission reductions related to EE undertaken in the state based on the amount 

of electricity the state imports because EE programs in NC will not reduce the amount of 

electricity imported from nuclear plants in South Carolina.

Commenters stated that the EPA should provide guidance for allowing states to take full credit 

for both EE and renewable or other low- and zero-carbon power resulting in interstate emissions 

avoidance. Commenters recommended that the guidance could suggest that such full crediting 

may be permitted if the importing and exporting states both have rate-based targets, if they have 

a memorandum of understanding to avoid multiple states counting the same savings, or if the 

energy savings are included in a registry that includes guards against double counting. 

Commenters stated that according to an analysis by the American Council on an Energy Efficient 

Economy, efficiency potential is undercounted in half the states and the EPA's described 

methodology would leave in excess of 41 million MWh out of computations for state targets. 

Commenters noted that several of these states are participating in the two existing carbon 

markets in the US and, as such, are using, and crediting, EE in full under those regulatory 

programs.

Commenters stated that imported electricity is more expensive and will be one of the first 

resources to be displaced; therefore, RE and EE only result in a small portion of in-state 

generation reductions. Commenters stated that this was confirmed using EIA 2013 data, which 

showed that electricity imports decreased from 18% in 2012 to 9% in 2013 in their state (North 

Carolina). Commenters stated that this was also confirmed using AVERT modeling of EPA's 

projected 2030 cumulative EE and RE impacts to generation. Commenters contended that the 

EPA's AVERT model predicted that only 5% of the avoided generation from North Carolina EE 

and RE programs will actually occur in North Carolina. Commenters stated that the results 
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indicate that most of the avoided generation from EE and RE will take place outside of North 

Carolina and the remainder of the avoided generation was spread out among the southeast 

states. Commenters contended that allowing a state to only take credit for in-state CO2 reductions 

occurring as a result of RE generation/EE measures creates a disincentive for implementing these 

building blocks within states that import electricity. Commenters stated that if the proposed rule 

is not revised, net importing states will not be able to achieve the required in-state CO2

reductions.

Commenters noted various concerns regarding EE credits, especially for states that are net 

importers of fossil generation yet are characterized in the BSER calculation as net exporters of 

electricity overall. While commenters agreed that EE measures provide an important and cost 

effective component of BSER, commenters contended that, under the proposed approach, they 

would be unable to develop a cost-effective compliance plan because the state would only be 

able to credit a small fraction of the investment in EE that can be tracked to fossil-fuel generation 

in the state. Therefore, commenters added, they would have to rely on much more expensive and 

potentially infeasible over-compliance with measures contemplated in the other three building 

blocks. In summary, commenters stated that it was of utmost importance for them to be allowed 

to take credit for the full breadth of emission reductions in their state compliance plan that are a 

result of EE investments.

Commenters noted that equity is an implicit element of cost considerations, and the rule makes 

no effort to ensure that it is geographically equitable. Commenters stated that interstate 

electricity sales are important to many states, but the building block is based only on in-state 

electricity generation, not consumption, while the state energy efficiency standards are based on 

retail sales (consumption) within the state and not on generation. Commenters noted that the 

EPA reduces the EE requirement in states when generation is less than consumption to apply 

only to its generation and but that the EPA makes no compensating adjustment for electricity 

exporting states.

Commenters stated the generation unit affected by a given energy efficiency measure may be 

located in a different State than the implemented measure. Commenters indicated that a State's 

inability to control the location of the impact of an efficiency measure on the GHG emissions 

within the State and the inability to address this issue without making arbitrary assumptions is 

indicative of the challenges associated with using end-use efficiency to control emissions and 

further indicates that it is not BSER.

Commenters stated that rewarding electricity-exporting states with a multiplier for energy 

efficiency achieved in-state carries with it an implication that neighboring electricity importing 

states are pursuing similar levels of energy efficiency; however, because of the potentially 

divergent incentives for pursuing energy efficiency as a means of compliance with the EPA's 

proposed 111(d) plan between electricity-importing and exporting states, such an assumption is 

potentially incorrect. Commenters stated that there is no guarantee that the additional energy 

efficiency credits an electricity-exporting state would get were actually being generated in other, 

electricity-importing states.

Commenters stated that the EPA's methodology of pro-rating EE savings based on the net 

importation of electricity not only fails to resolve the uncertainty surrounding whether a state's 
12

EE measures actually lead to emissions reductions in the state, but creates a new problem by 

failing to give states that are net importers of electricity full credit for their EE measures. 

Commenters stated that this increases the burden on states that are net importers of electricity in 

meeting their state goals. Commenters believed that the EPA should eliminate EE from the state 

goals.

Commenters stated that the impacts to the generators and utilities will be difficult to discern in 

regions where there is not a match of service boundaries to political boundaries (i.e., state 

borders). Commenters stated that the regulators likely will require a common approach with 

which all participants comply to allow for the summation of the results for the entire state.

Commenters stated that if the ISO's modeling expertise is deployed for developing the state's 

CO2 rate goal, adjustments in the energy efficiency impact due to whether or not a state is a 

power importer would be unnecessary. Commenters stated that the ISO modeling effort would 

account for the impact of the state's energy efficiency on the region's and states' fossil 

generation.

Commenters noted that even in states with vertically integrated utilities, there are some 

independent power producers (also known as merchant plants) that are not affiliated with loadserving utilities. Where there is not common ownership between the party currently 

implementing the EE program and the affected EGU, commenters believed the state will need to 

either administratively allocate or auction EE savings generated by those programs, or adopt a 

tradable credit mechanism to enable affected EGUs to acquire the credits needed to achieve their 

target emission rates. Commenters suggested that, if the EPA could not allow states to take full 

credit for in-state EE investments, then a possible solution would be for the EPA to revisit their 

Block 4 emissions reduction goal computation. Commenters added, though, that it would not be 

sufficient to simply adjust this goal to account for the small percentage of in-state energy that can 

be used for compliance, as this would provide a disincentive for further EE investment.

Multiple commenters believed that it is near impossible to trace energy savings, or megawatts, to 

a specific generating unit and that the Building Block 4 BSER would should be implemented in a 

manner which ensures that this level of tracking is not required.

Commenters stated Washington interprets the proposal to require states to track efficiency 

savings to specific in-state EGUs subject to the Clean Power Plan. Commenters believed this is 

an unnecessary and complicated step to the rule. Commenters stated it is inconsistent with the 

way the EPA established the emissions reduction goal, and it is inconsistent with the EPA 

proposal to allow states to count all energy efficiency achieved and claimed through program 

implementation despite the intricacies of inter-state electricity transmission. Commenters stated 

it would significantly diminish the efficacy of a state's energy efficiency programs.

Commenters stated that Washington has been a leader in energy efficiency since the late 1970s, 

and is nationally recognized for its programs, however, in 2012 only 10 percent of Washington's 

in-state generation came from affected electric generating units. Commenters stated 99 percent 

of the state's generation came from unaffected sources such as hydroelectric power, nuclear, and 

wind, and the investor-owned utilities receive a significant portion of their energy from out-ofstate EGUs. Commenters stated if Washington could only claim "those CO2 emission reductions 
13

occurring (or projected to occur) in the state that result from demand-side EE measures 

implemented in the state," Washington would only claim a fraction of the efficiency savings it 

actually achieved, yet the building block 4 target assumes Washington could claim 100 percent 

of its savings compared to the small proportion of that the proposal implies would be available 

for use in demonstrating compliance. Commenters stated under this approach it is reasonable to 

assume that compliance with the plan would be unnecessarily expensive and challenging. If the 

final rule insists upon tracking back efficiency savings to an affected EGU, commenters 

recommended that the EPA symmetrically adjust the process of setting the value for the building 

block 4 targets to account for the value of energy efficiency in reducing emissions from a state's 

fossil EGUs.

Commenters stated that it is impossible to trace energy savings, or megawatts, from EE to find 

out which generator would have run but for the EE savings. Commenters noted that the 

EPA assesses the impact of EE programs through reductions in electricity sales but estimates the 

impact of EE programs only at the statewide-level because, in many cases, it is impossible to 

determine whether a particular generator's electricity sales were reduced due to EE. Commenters 

stated that the EPA cannot assess whether the megawatts reduced through an EE measure 

displace fossil generation rather than RE or other zero-emitting generation and consequently, it is 

uncertain whether EE actually reduces CO2.

Commenters stated that it is not clear how the carbon reductions from EE will be attributed to a 

specific emitting generator, or to a utility that achieves the additional efficiency.

Commenters stated that there should be some symmetry between the goal calculation and the 

measures permitted for compliance. Commenters noted that the EPA currently calculates the 

contribution of EE measures to Alaska's target rate on the basis of statewide electric sales but 

believes that the EPA should calculate the amount generation is avoided due to EE measures as a 

percent of forecasted generation from affected EGUs or, in the alternative, allow statewide EE 

measures to count for compliance purposes.

Commenters said the guidance should provide states with needed clarity on the following items:

• Identify Remedies for the 111(d) State Energy Efficiency Penalty. The EPA 

should address and resolve the EE penalty created when EE projects are 

implemented in electricity-importing states. As proposed, the rule would leave 

stranded and uncounted the emission reductions created by energy efficiency in 

an importing state because neither the importing state, nor the generating state, 

could claim credit for emissions reductions equal to 100% of those created by the 

energy efficiency program or project. (Further detail provided on page 45 of the 

comment.)

• Encourage the Use of Tradable Credits. The EPA should support the development 

and use of single-state and multi-state credit programs and other market-based 

systems. This will encourage the use of the least-cost compliance options, which, 

in many cases, will involve comprehensive energy retrofits. 
14

Commenters stated the EPA should require that any state or states that include energy efficiency 

gains in multi-jurisdictional plans should be allowed to include the potential savings in their 

targets. Commenters add that the EPA could also determine that a target adjustment might not be 

necessary if the potential change in the targets is small enough, as it might be from areas with 

low energy consumption.

Comment 2: Comments suggesting that the rule does not state whether an exporting state can 

claim credit for EE gains in an importing state. 

Response 2: The treatment of EE has changed from the proposed approach. In the final rule, to 

the extent demand-side EE measures are tied to a state plan, the quantified and verified MWh 

impacts of the measures may be used by an affected EGU or state to adjust a CO2 emission rate, 

regardless of whether the demand-side EE savings occur inside or outside the state or territory.

For more information about the treatment of in-state and out-of-state energy efficiency impacts, 

see section VIII.L of the preamble to the final rule. The EPA revised the methodology used to 

calculate CO2 emission performance rates and state rate-based CO2 goals from the one used in 

the proposal. In order to ensure consistency with the calculation of CO2 performance rates and 

state rate-based CO2 goals in the final emission guidelines, and to avoid double-counting or 

inconsistent adjustment approaches across states, the final rule prescribes a general accounting 

approach states must use to adjust the CO2 emission rate of an affected source to reflect the MWh 

impacts of zero-emitting and low-emitting resource. Quantified and verified MWh impacts of 

qualifying zero-emitting and low-emitting resources tied to a state plan may be used by an 

affected EGU or state to adjust a CO2 emission rate, regardless of whether the renewable 

generation or demand-side EE savings occur inside or outside the state or territory. This ensures 

that affected EGUs receive full recognition for their investments, even if the impacts occur 

elsewhere, removing the need to determine exactly which EGUs reduced and changed power 

generation in response to the zero-emitting or low-emitting resource.

The following are summaries of the specific public comments under this comment:

Commenters stated that states can take credit only for the effects of EE programs associated with 

electricity generated within their borders. Commenters stated that this means that while EE in an 

importing state can benefit an exporting state by reducing the need for generation at higher 

carbon facilities serving the importer, the proposed rule does not explicitly state whether the 

exporting state may claim credit for the EE gains in their compliance plans. Commenters stated 

that, if it cannot, it appears that this credit may be lost and this would reduce the incentive for the 

importer to invest further in these programs. Commenters stated that the EPA support of modular 

multi-state plans that allow states to fairly claim credit for these lower cost compliance options 

may also incentivize new EE measures.

Comment 3: Comments suggesting that each state plan submitted must ensure that credit for 

emissions avoided through EE is awarded only to EE measures and programs undertaken within 

that state.
15

Response 3: In the final rule, to the extent demand-side EE measures are tied to a state plan, the 

quantified and verified MWh impacts of eligible measures may be used by an affected EGU or 

state to adjust a CO2 emission rate, regardless of whether the demand-side EE savings occur 

inside or outside the state or territory. For more information about the MWh accounting 

approach for adjusting a CO2 emission performance rate, and requirements related to geographic 

eligibility, see section VIII.K.1 of the preamble to the final rule. For more information about the 

treatment of in-state and out-of-state energy efficiency impacts, see section VIII.L of the 

preamble to the final rule. 

The following are summaries of the specific public comments under this comment:

Commenters stated that, in order to simplify administration of EE crediting and assure adequate 

state oversight, each state plan submitted must ensure that credit for emissions avoided through 

EE is awarded only to EE measures and programs undertaken within that state. Commenters

stated that a state plan may not provide for crediting of avoided emissions for EE programs and 

measures undertaken in other states. Commenters stated that as experience is gained with this 

program and systems for tracking the crediting of avoided CO2 emissions are developed, the EPA 

should review and consider the possibility of expanding the geography of acceptable EE 

investments.

Comment 4: Comments suggesting that the EPA allow approvable multi-state agreements. 

Response 4: The EPA’s approach has changed since proposal. In the final rule, to the extent 

demand-side EE measures are tied to a state plan, the MWh impacts of the measures may be used 

by an affected EGU or state to adjust a CO2 emission rate, regardless of whether the demand-side 

EE savings occur inside or outside the state or territory. For more information about the 

treatment of in-state and out-of-state energy efficiency impacts, see section VIII.L of the 

preamble to the final rule. The EPA is also allowing multi-state plans in the final emission 

guidelines, see section VIII.C.5 of the preamble to the final rule.

The following are summaries of the specific public comments under this comment:

Commenters stated that if the EPA is unwilling to allow net importers to receive full credit for 

their EE investments, the EPA should at least allow states to submit approvable multi-state 

agreements that apportion credit for EE among neighboring states. Commenters contended that 

under this approach, these multi-state agreements could ensure that no state receives "double" 

credit for emission reductions from EE while allowing states that have invested in EE to quantify 

and receive full credit for their investments.

Comment 5: Comments requesting clarification regarding the treatment of EE by states that 

export electricity
16

Response 5: The EPA’s approach has changed since proposal. In the final rule, to the extent 

demand-side EE measures are tied to a state plan, the quantified and verified MWh impacts of 

the measures may be used by an affected EGU or state to adjust a CO2 emission rate, regardless 

of whether the demand-side EE savings occur inside or outside the state or territory. For more 

information about the treatment of in-state and out-of-state energy efficiency impacts, see section 

VIII.L of the preamble to the final rule. There are a range of ways states can engage in multistate coordination, as described in Section VIII.C.5 of the preamble to the final rule.

The following are summaries of the specific public comments under this comment:

Commenters asked the following questions regarding treatment of EE for states that 

import/export electricity: 

• Would it be possible for the EPA to apportion a state's excluded EE savings to the 

exporting states? 

• Could states enter into bilateral or multi-state agreements to apportion credit for 

EE? 

• Can you explain how the EPA determined the level of each state's electricity 

imports/exports and which sales year they used? What if these levels change over 

time?

5.7.2 State that implements the measure claims the emission effects

This section contains comments on the proposed method for accounting RE projects and a 

method recommended by some commenters for accounting for EE emission reduction measures.

Commenters have raised a number of issues related to this subsection which are organized by 

topics (comments) below. Responses are provided for these topics. 

Comment 1: Comments supporting the EPA's proposal for claiming RE.

Response 1: In the final rule, to the extent qualifying RE generation measures are tied to a state 

plan, the quantified and verified MWh impacts of the measures may be used by an affected EGU 

or state to adjust a CO2 emission rate, regardless of whether the RE generation occurs inside or 

outside the state or territory. For more information about specific methods to adjust the CO2

emission rate of an affected EGU to reflect RE and demand-side EE, the timing and the 

eligibility requirements for resources used to adjust a CO2 emission rate, including renewable 

resources, see section VIII.K.1 of the final rule preamble. The rule describes requirements and 

criteria related to proper quantification and verification of MWhs from renewable electricity 

generation or demand-side EE savings in section VIII. K.3 of the final rule preamble. For more 

information about how the BSER RE assumptions in the final rule address concerns about 
17

crediting and about the treatment of in-state and out-of-state renewable energy impacts and the 

avoidance of double-counting, see also section VIII.L of the preamble to the final rule.

The following are summaries of the specific public comments under this comment:

Several commenters agreed that a state should be able to take into account all of the carbon 

emission reductions from RE measures implemented by the state, regardless of where the energy 

is generated. Commenters stated that this should only be allowed when the environmental 

attributes of the energy are retired in that state, while other commenters stated that this should be 

allowed as long as the generation is not double-counted. Commenters stated that this should be 

allowed as long as there is a credible REC tracking system or they can demonstrate entities in the 

state have submitted environmental attributes (i.e., credits) for those MWhs. Commenters stated 

that the ability to sell the environmental attributes of renewable power to buyers that will retire 

the attributes for compliance or other purposes is a critical component of the business model of 

RE developers. Commenters recommended that any asset or PPA that is recognized, approved 

and paid for by utility customers be given credit to customers' state when accounting for CPP 

compliance. Commenters stated that the principles of cost causation and fiscal responsibility are 

long-standing in the utility industry, and it is consistent with those principles that states that pay 

for RE should get credit for that RE for compliance.

Commenters stated that the CPP, when finalized, should not disrupt current and expanding 

interstate markets for RE and associated environmental attributes or credits. Commenters stated 

that the simplest, fairest, most reliable, and most environmentally beneficial way to account for 

RE is to treat the credit for RE as a property right that accrues first to the entity that owns the 

right to sell or use the RE itself and that entity could then use that right to meet its obligations 

under any state or multi-state plan, or alternatively sell or grant that right to another entity to use

in meeting its obligations. Commenters stated that states should have flexibility to enter into 

bilateral agreements regarding use of credits much like they would with a multi-state compliance 

option. Commenters stated that a state should not take credit for any existing RE programs that 

were included in another state's baseline and used to set that state's interim and final goals.

Commenters stated that the EPA should explicitly prohibit double counting, without providing a 

suggestion on which state should bear the burden of demonstrating that the reductions were not 

double counted; while commenters stated that the state receiving the credit must demonstrate that 

there had not been double counting. Commenters also stated that the EPA should require that 

every state that wishes to use RE MWh to demonstrate compliance with its state goal 

demonstrate that the zero-carbon attributes of that RE are dedicated to that state; commenters 

asserted that this would minimize double counting and avoid disruptive uncertainty in the 

underlying commercial markets. 

Several commenters stated that the proposed approach is consistent with the requirements of 

most state's RPS by allowing a state to take credit for RE generated in another state and it 

recognizes that RECs can be used for interstate trading. Commenters stated that they believe that 

RECs can be a useful tracking mechanism, but the ownership of RECs should not take 

precedence over the fundamental principle that the state whose customers are paying for RE 

should receive compliance credit. Commenters stated that, in the event that the customers who 
18

paid for the energy did not acquire or no longer hold ownership of RECs, those who paid for the

energy should receive compliance credit.

Commenters stated that allocating RECs in the final rule based solely on where the electricity is 

generated would work a manifest injustice on states and companies that have invested in the 

development of out-of-state RE. Commenters stated that the proposed approach will help to 

ensure the development of the most cost-effective renewable resources. Commenters stated that 

limiting compliance to RE located within a given state could result in less efficient placement of 

RE resources. Commenters stated that if the rule only allowed for REC in the state where the 

generation occurred, use of prime locations would be artificially constrained, resulting in higher 

costs and potentially less technically sound and efficient RE systems, which would create an 

unnecessary disincentive that could ultimately reduce the amount of RE developed in the longterm. Commenters also stated that limiting credit to the state of generation could unjustly reward 

owners and operators of affected EGUs that have not invested in developing RE resources, but 

happen to be located in a state where another operator has built such resources. Commenters

stated that under these circumstances, the owner or operator of an EGU with a high emission rate 

might avoid any responsibility to reduce emissions while the developer of the renewable 

resources might be unable to take any advantage of its investment in complying with the rule.

Commenters clarified that this approach means that in cases where one state has an RPS and 

purchases RE from another state that has a production tax credit, the EPA must consider the 

purchasing state to have the "enforceable measure" and give that state the credit for the RE. 

Commenters stated that doing otherwise would directly conflict with how RE has been treated 

for years under existing tracking systems.

Commenters stated that states should only be allowed to take credit for RE generated in another 

state if they participate in an environmental crediting accounting system for RE. 

Commenters stated that states should also be allowed to take credit for reductions in energy 

demand due to any local or municipal government's RE program. Commenters provided an 

example of reductions in energy demand resulting from RE programs in New Orleans, stating 

that these should be credited to Louisiana's compliance with its state target. Commenters stated 

that similarly, where another state curtails generation that serves New Orleans, the costs imposed 

on New Orleans ratepayers should be shared in some manner. Commenters stated that if credits 

and costs are not shared across state borders in an equitable manner, states will have a powerful 

incentive to design their programs in a manner that shifts as much of the cost impact of the 

program to the other state as possible, rather than designing programs in a regionally cooperative 

manner. Commenters suggested that, to address these issues, states should be able to work with 

one another to determine the best method for the accounting of interstate credits from RE 

programs and that states should be able to determine how to allocate the credits and costs, and 

ensure there is no double counting of reductions among states.

Commenters stated that, in order to avoid double counting, states be prohibited from counting 

RE generation within their borders for compliance, if the associated RECs are used for 

compliance with out-of-state policies. Commenters stated that because the District of Columbia 

does not have any fossil fuel power plants, they are not subject to the CPP; however, they urged 

EPA to prohibit a state from counting any RE power or RECs purchased by the District toward 
19

that state's compliance. Commenters stated that it is essential that the EPA recognize existing 

contracts that allocated environmental attributes to particular counter parties in particular states.

Commenters stated that RECs are not the only way in which compliance with RES programs is 

measured and the EPA should not limit compliance credit to only RE represented by RECs.

Commenters also stated that the EPA should not limit RES programs as the only mechanism for 

including renewable generation. Commenters stated that the final guidelines should clarify that 

states can pursue a range of options to increase RE deployment and that RECs are not necessarily 

the best or only way for states to credit or trade RE across state lines.

Commenters believed that entities owning out of state RECs should get credit for those RECs in 

the states in which they are headquartered, regardless of whether they are in a multistate 

compliance arrangement with the state that generates the energy.

Commenters stated that export and import of both unbundled and bundled RE and the 

corresponding greenhouse gas compliance value should be unencumbered and should not be 

limited to contiguous states or ISO regions.

Commenters stated that if a state could only take credit for RE generation that displaced in-state 

units, unanticipated new generation or retirements over the ten-year compliance period could 

change which fossil unit is displaced by RE generation, such that a wind farm for which a state 

could previously take credit is no longer available to the state as a compliance 

measure. Commenters stated that this uncertainty would make it less likely for a state to include 

significant RE measures as part of its plan in comparison to measures that would carry less 

uncertainty, such as increased gas dispatch of existing NGCCs. Commenters stated that the 

proposed accounting method of allowing states to take credit for RE regardless of where 

displacement occurs will minimize this uncertainty and promote the use of RE in state plans.

Commenters stated the Proposal presents insurmountable challenges for states like Oregon that 

are net importers of fossil generation yet are characterized in the EPA's BSER calculation as net 

exporters of electricity overall. Commenters provided an overview of EE in Oregon and stated 

that Oregon would not be able to develop a cost-effective compliance plan because the state 

would only be able to credit a small fraction of the investment in energy efficiency that can be 

tracked to fossil-fuel generation in the state. Commenters stated this would effectively render as 

unusable otherwise cost-effective investments in energy efficiency that were assumed in setting 

the BSER, and force Oregon to rely on much more expensive and potentially infeasible overcompliance with measures contemplated in the other three building blocks. Commenters stated it 

is of utmost importance that the EPA allows Oregon to take credit for the full breadth of 

emission reductions resulting from energy efficiency investments in its state compliance 

plan. Commenters recommended the EPA should adopt a consistent compliance approach 

requirement where the state that implements energy efficiency measures will claim the resulting 

emission reductions in its state compliance plan.

Comment 2: Comments suggesting disparity between how state goals and credits were derived.
20

Response 2: In the final rule, the EPA adopted the denominator approach, not the numerator 

approach recommended by the reviewers that commented on the proposed approach. The EPA 

revised the methodology used to calculate CO2 emission performance rates and state rate-based 

CO2 goals from the one used in the proposal. In order to ensure consistency with the calculation 

of CO2 performance rates and state rate-based CO2 goals in the final emission guidelines, and to 

avoid double-counting or inconsistent adjustment approaches across states, the final rule 

prescribes a general accounting approach states must use to adjust the CO2emission rate of an 

affected source to reflect the MWh impacts of zero-emitting and low-emitting resource.

Quantified and verified MWh impacts of qualifying zero-emitting and low-emitting resources, 

including eligible renewable energy resources, tied to a state plan may be used by an affected 

EGU or state to adjust a CO2 emission rate, regardless of whether the renewable generation occur

inside or outside the state or territory. Consistent with the EPA’s calculation of the CO2 emission 

performance rates and state rate-based CO2 goals in the final emission guidelines, the MWh 

impacts are added to the denominator of an affected EGU’s reported CO2 emission rate, resulting 

in a lower, adjusted CO2 emission rate. For more information about how the BSER RE 

assumptions in the final rule address concerns about crediting, see section V of the preamble. For 

more information about the treatment of in-state and out-of-state renewable energy impacts and 

the avoidance of double-counting, see section VIII.L of the preamble to the final rule.

The following are summaries of the specific public comments under this comment:

Several commenters stated that the final rule should assign compliance credit to the state that 

produces the RE, no matter where the energy is used. Commenters did not express a preference 

for how RE is counted, but discussed compliance challenges given the proposed accounting 

method. Commenters stated that renewable generation should be counted with the state that 

generates the electricity both for purposes of determining carbon dioxide intensity and for 

establishing compliance with the goal. Commenters stated that the EPA should adopt an 

approach that is consistent with regard to goal setting and compliance, while allowing states 

flexibility to establish agreements to utilize out-of-state renewable generation for compliance 

purposes. Commenters urged the EPA to adopt an approach that consistently and adequately 

addresses the legal, economic and technical implications of the RE compliance option.

Several commenters had concerns about RE exporting states. Commenters stated that the EPA's 

proposed approach for counting out-of-state RE for compliance could create significant 

compliance challenges for certain states that produce more RE than they consume. However,

commenters stated that RE generation from these states is used by others to satisfy current 

demand or RES requirements, reducing the amount of RE generation that these states could rely 

upon for compliance with the state goals. Further, commenters contended that these states have 

little control over whether and to whom the RE generation is sold (or whether and to whom the 

renewable attributes are sold). Commenters stated that these states have ambitious goals, but 

limited tools with which to comply with them. Commenters stated that these "source" states, like 

Idaho, New Mexico or Wyoming, have RE targets predicated, in part, on their high levels of RE 

generation in 2012. Commenters stated that these states are faced with a dilemma of having their 

targets established on the basis of RE to which they do not have access, creating a conflict 

between the energy on which the goal is based versus the energy which is available for 
21

compliance with that state goal. Commenters stated that the EPA should re-calculate the state 

goals for source states accordingly.

Commenters stated that given the disparity between their state's (Wyoming) exports and 

consumption, the differences between how the goal was derived and credits for future renewable 

development eviscerate the EPA's growth assumptions. Commenters provided an example of 

energy produced from a 1,000 MW wind farm in Wyoming, which transmits all of its electricity 

to California. Commenters noted that this generation will be used to determine California's 

compliance with section 111(d), not Wyoming's. Commenters stated that they see an analogue in 

the EPA's decision to exclude hydroelectric power from setting goals because no states are 

expected to develop any new large facilities. Commenters concluded that in the context of new 

renewables on a scale that would make it possible to reach Wyoming's Block 3 goal, there is no 

reason to expect new export facilities to be credited to Wyoming.

Commenters stated that for Montana to accomplish the reductions, within the time frame allowed 

that all low and no carbon emission sources of electricity generation within the state of Montana 

must be included in the calculations to meet the assigned goals/standards. Commenters stated 

that if the proposed method for accounting for RE becomes final, then CO2 emissions from 

EGUs within the State of Montana must be excluded from the calculations on an equal basis; 

MWh per MWh. Commenters concluded that this is the only equitable avenue for accurately 

calculating and determining the achievement of the goals/standards. Commenters stated that 

there is no feasible way for Montana to reach its goal using the building blocks unless credit for 

renewables that are built in Montana, but whose energy would flow out of state, is given to 

Montana. 

Commenters stated that if another state is allowed to make claim to RE sources physically 

located outside their state, for determining carbon dioxide intensity and compliance, then they 

must also be required to account for the carbon dioxide emitted by power plants located outside 

their borders, whose sole purpose is to provide energy to that State.

Commenters stated that if the method for calculating state goals does not change and the EPA 

decides, for compliance, to credit a state for only the RE consumed in the state, then the EPA 

should provide symmetrical treatment for carbon emissions and count only the carbon associated 

with fossil-fuel generated electricity consumed in a state. Commenters stated that, if the final 

CPP allows states to take credit for RE consumed in their state, but generated in another state, 

then those states should also be required to take credit for the power and carbon emissions 

produced by the RE exporting state's fossil fuel power plants. Commenters stated that allowing 

other states to take credit for RE production without also taking credit for the carbon emissions 

only makes it more certain that the RE Exporting state will not meet the EPA' s carbon goal.

Because the state targets are based on generation in a state and not consumption, commenters 

wanted to know how the EPA expects an electricity exporting state to effect demand side 

reductions in states to which it exports electricity and asked if an exporting state is expected to 

add renewable generation that is not needed to meet in-state demand. Commenters also asked if 

an exporting state will get credit if an importing state installs renewable generation and thus 

reduces demand from the exporting state.
22

Commenters stated that the proposed method for accounting for RE is directly contradictory to 

the method the EPA used to calculate Maine's base rate and goal rate of CO2 production, which 

includes all of Maine's wind-generated RE in the total generation for the state, without regard for 

existing out-of-state PPAs. Commenters contended that the EPA cannot have it both ways and 

stated that if the EPA considers RE generation with an out-of-state PPA to be part of Maine's 

existing energy generation mix, then the EPA must allow new RE in Maine to be used as a 

compliance mechanism, regardless of any PPAs or RECs. Commenters stated that if this is not 

addressed in the final rule, it will de-incentivize development of wind power projects in Maine 

and other states. Commenters stated that local impacts from RE developments are borne directly 

and primarily by local residents, and residents have a right to expect benefits from a project to 

counter the effects of any negative impacts. Commenters stated that the host state bears the 

burden of any environmental impacts from these projects, and has invested time and effort in 

reviewing and permitting these projects and ongoing compliance. Commenters stated that it is 

inappropriate that the impacted resources should be devalued further through the loss of any 

benefit the host state might otherwise gain by using the projects as a compliance mechanism. 

Commenters stated that excess RE generation should then be allowed for compliance in states 

where the power is sold by PPA or credited through REC ownership.

Commenters stated that the EPA must credit RE for determining compliance consistent with the 

framework of counting all in-state EGU emissions for goal setting regardless of where the 

electricity is consumed. Commenters stated that if their state (Idaho) received credit for all RE 

generation within its borders, Idaho would have the flexibility to share its RE generation with 

states that export energy to Idaho. Commenters also noted that this would be consistent with the 

way EPA considered in-state RE generation potential in setting each state's RE goal. 

Commenters stated that the proposal to ultimately give credit to consuming states is inconsistent 

with this methodology. Commenters urged that Idaho must be credited for generation that occurs 

within its borders.

Commenters stated that it was unfortunate that the proposal would not grant any emission 

reduction credits to Kansas for the zero emission wind energy produced. Commenters stated that 

to capture credit for the RECs, Kansas will likely have to participate in some form of interstate 

program that would include states receiving Kansas wind energy. Commenters stated that an 

interstate program would require new statutory authority, significant groundwork in determining 

which states would participate, resources to develop interstate agreements to create the entity that 

would administer the trading program, and time to create parallel regulations in each state to 

implement a program that would allow for Kansas to receive benefit from the zero carbon 

emissions associated with future wind energy development. Commenters stated that states like 

Kansas should have the opportunity to develop a state plan that promotes the build-out of Kansas 

wind resources, for Kansas utilities as well as out of state utilities. Commenters encouraged the 

EPA to offer a solution to this issue in the final rule that gives Kansas the flexibility to provide 

for wind energy expansion that allows neighboring states as well as Kansas to develop plans that 

can meet their respective CO2 emission reduction goals.

Commenters stated that RE should be credited to the state where it is generated, regardless of 

where it is consumed. Commenters noted that this is consistent with the way CO2 emissions from 

affected EGUs, EE (credit only for demand-side EE measures implemented in the state), and 

nuclear electricity are counted. Commenters specifically commented on not using the same 
23

accounting method for nuclear electricity and RE and stated that this creates a distortion within 

the proposed rule's carbon accounting that would unfairly penalize states that export renewable 

electricity. Similarly, commenters stated that renewable and nuclear resources should be counted 

towards compliance only in the state in which they are located, (renewable and nuclear energy 

should be counted consistently). Commenters stated that this approach would better reflect the 

manner in which the EPA set the goals, would be simpler, would eliminate the need to address 

the possibility of double-counting, eliminate many inter-state conflicts that are likely to arise 

under the proposed RE crediting provisions, and it would remove a disincentive for multi-state 

plans under the proposed CPP. Commenters stated that multi-state plans, under the proposed 

CPP, allows states to claim compliance credit for another state's renewable resources without 

having to share that credit. Commenters stated that crediting the state that generates the RE 

would lower New Mexico's compliance gap from a "base case" of 211 lb/MWh to 83 lb/MWh 

and provides a better representation of the emission reductions that New Mexico would be able 

to achieve.

Comment 3: Comments suggesting that state plans should be utility-driven portfolios.

Response 3: In the final rule, to the extent qualifying RE generation measures are tied to a state 

plan, the quantified and verified MWh impacts of the measures may be used by an affected EGU 

or state to adjust a CO2 emission rate, regardless of whether the RE generation occurs inside or 

outside the state or territory. For more information about how the BSER RE assumptions in the 

final rule address concerns about crediting see section V of the preamble to the final rule. For 

more information about the treatment of in-state and out-of-state renewable energy impacts, see 

section VIII.L of the preamble to the final rule. 

The following are summaries of the specific public comments under this comment:

Commenters stated that the provisions of the CPP proposal are not suited to a situation where 

load is remote from generation, a characteristic that affect small municipal entities like Missouri

River Energy Services (MRES) and its members. Commenters stated that the building blocks all 

presume that load and generation are located in the same state. Commenters stated that this 

means MRES' renewable wind energy resources in Iowa, Minnesota and North Dakota, as well 

as their nuclear resource, do not fall within the boundaries of the state of Wyoming where their 

only fossil fuel EGUs emit CO2. Commenters stated that their EE and demand-side management 

programs in their member states generate CO2 savings outside of Wyoming, in states where they 

have no affected units that emit CO2 under the CPP.

Commenters stated that renewables have to be constructed where the resources exist (and where 

there is adequate transmission), and those resources are not necessarily located in the same state 

where all CO2 emitting affected units are located. Commenters contended that this fact also 

demands that utilities that acquire renewable resources should be entitled to use the credits where 

the utility's system needs them for compliance purposes. Commenters stated that portability 

ensures that utilities pursue those resources that fit best with their system at the lowest cost, and 

promote a more efficient and economical generation portfolio and electric grid. Commenters

stated that state plans should employ a utility-driven portfolio approach that recognizes the clean 

energy and EE (the non- CO2 resources) owned by each utility, as well as the other building 
24

blocks. Commenters stated that in the event that a utility has non-emitting credits, that utility 

should be entitled to use those non-emitting credits it owns to offset its CO2 emissions in any 

state. Commenters stated that it is only fair that the customers who paid for the RE resource and 

the EE measures be entitled to take credit for them to offset their own emissions. Commenters

stated that ratepayers are entitled to portability of their non-emitting resources in interstate 

commerce to use them for compliance against the CO2 emissions from their resource located 

remote from their home state.

Commenters provided an example of the potential inequity. Commenters stated that the example 

involves the Minnesota RES, as well its 1.5 percent EE goal. Commenters stated that both instate and out-of-state wholesale utilities serve the load in Minnesota, and they do so with both 

renewable and fossil generation that are based in-state and outside of Minnesota. Commenters

noted that Minnesota's CO2 reduction goal is based on the generation located only in the state and 

stated that it would be unjust for Minnesota to count all of the RE and EE used in the state by 

out-of-state entities towards CPP compliance. Commenters stated that MRES has no generation 

contributing to the CO2 emissions located in the state of Minnesota, but it does provide RE and 

EE based on the state's mandates. Commenters noted that the RE and EE has been paid for by 

MRES members in MN, IA, ND and SD and is generated in Iowa, Minnesota and North 

Dakota. Commenters stated that the state of Minnesota should not be entitled to offset the 

emissions of its in-state EGUs with RE and EE from a utility that does not even emit any CO2 in 

the state. Commenters contended that to reduce emissions at an affected EGU by requiring 

utilities that do not own, operate, or otherwise purchase power from the EGU to invest in RE or 

EE flies in the face of fairness. Commenters stated that they may have an RES compliance 

obligation in Minnesota, but that does not entitle the state of Minnesota to take the RE paid for 

by MRES members and their customers to meet its state CO2 reduction goal. Instead, 

commenters stated it is only fair that ratepayers get the full benefit of their investments by 

allowing the utility owning the RECs to use those credits for its own benefit to offset its own 

CO2 emissions.

Comment 4: Comments expressing concerns that RE cannot be created out of state.

Response 4: In the final rule, to the extent qualifying renewable energy generation is tied to a 

state plan, the quantified and verified MWh impacts of the renewable energy measures may be 

used by an affected EGU or state to adjust a CO2 emission rate, regardless of whether the 

generation occurs inside or outside the state or territory. For more information about the 

treatment of in-state and out-of-state renewable energy impacts, see section VIII.L of the 

preamble to the final rule.

Regarding double counting, it is proposed that EM&V plans must address how double counting 

will be avoided through the use of tracking and accounting procedures to ensure that two or more 

programs do not separately claim savings from the same EE project or measure (for example, 

two EGUs claiming savings from the same lighting retrofit). Other types of double counting 

must likewise be considered and avoided. For more details on EM&V provisions, see section 

VIII.K.3 of the preamble to the final rule, section IV.D.8 of the preamble to the proposed Federal 

Plan, and the draft guidance document.
25

The following are summaries of the specific public comments under this comment:

Commenters stated that the proposed guidelines appear to say that credit for RE projects can 

only go to the state where the project is located, even though RE may help reduce emissions in 

another state. Commenters suggested that the RE should be credited to the state that uses the RE 

and that verified RECs be used as evidence of emission reductions in those cases where the RE 

generation took place in another state. Commenters stated that RECs should eliminate the 

potential for double counting of generation offsets.

Commenters were concerned that there are no provisions to allow for the interstate use of RE for 

compliance with the rule, and that the Red Rock Hydroelectric Project which is under 

construction in Iowa may be limited to the state of Iowa only. Commenters said they have an 

exclusive power purchase agreement with a private wind developer in another state which is a 

significant investment that their company chose to take proactively to augment its resource with 

a certain amount of renewable energy.

Commenters stated that under the proposed approach the credit for existing RE projects would 

accrue to the state that hosts them rather than the states that bankrolled them through binding 

purchased power agreements. Commenters contended that this is clearly inequitable and must be 

addressed in the architecture of any rule that entails beyond-the-fence line mandates.

Comment 5: Comments suggesting that the EPA must avoid double-counting, regardless of the 

method for crediting RE.

Response 5: The EPA agrees that it is important to minimize the risk of double-counting of 

emission impacts of measures, particularly across state plans, and has incorporated elements into 

the rule that seek to minimize it. It is proposed in the Federal Plan that EM&V plans must 

address how double counting will be avoided through the use of tracking and accounting 

procedures to ensure that two or more programs do not separately claim savings from the same 

EE project or measure. Other types of double counting must likewise be considered and avoided. 

For more details on EM&V provisions, see section VIII.K.3 of the preamble to the final rule, 

section IV.D.8 of the preamble to the proposed Federal Plan, and the draft guidance document.

States have the option to adopt multi-state plans, for either rate-based or mass-based plans, that 

reflect regional interactions. These plans engage multiple states in the same system for purposes 

of tracking mass-based allowances or issuing and trading unique rate-based Emission Rate 

Credits (ERCs) as described below. 

Mass-based plans rely exclusively on reported stack emissions for determining whether a massbased CO2 emission goal is achieved and avoids concerns about counting the same mass 

reductions in two different mass-based states.

For rate-based plan compliance, the final rule specifies a general accounting approach that 

inherently acts to minimize state rate differences that may influence distortionary investments 

and ensures that quantified and verified MWh impacts of qualifying zero-emitting and lowemitting resources are applied consistently across all affected EGUs. The EPA revised the 
26

methodology used to calculate CO2 emission performance rates and state rate-based CO2 goals 

from the one used in the proposal to better reflect the regional nature of the grid among other 

things. Consistent with the calculation of CO2 performance rates and state rate-based CO2 goals 

in the final emission guidelines quantified and verified MWh impacts of qualifying zero-emitting 

and low-emitting resources tied to a state plan may be used by an affected EGU or state to adjust 

a CO2 emission rate, regardless of whether the renewable generation or demand-side EE savings 

occur inside or outside the state or territory. Double-counting of CO2 emission reductions is 

prevented, however, because the reported emissions from each unit are represented in the 

numerator of each of those unit’s emission rates and the method disallows any adjustment to any 

EGU’s reported emissions. 

Because of the separate accounting of MWhs and CO2 emissions, with emission impacts inherent 

in reported stack CO2 emissions and zero-emitting MWh impacts requiring explicit adjustments, 

the accounting method corresponds with the use of MWh-denominated ERCs in the rate-based 

emission trading framework specified in this rule. This MWh accounting method creates a 

crediting system or rate adjustment process that is indifferent to the rate-based CO2 emission 

goals of individual states, or the specific CO2 emission rate standards that states may apply, and 

the relative stringency of those goals or standards. 

An ERC is issued separately from any other instruments that may be issued for a MWh of energy 

generation or energy savings from a qualifying measure, such as a renewable energy certificate 

(REC). An ERC may be issued, however, based on the same data and verification requirements 

used by existing REC tracking systems for issuance of RECs that are used to meet state 

renewable portfolio standards. The EPA is aware of the potential for interactions between ERCs 

and RECs and encourages the states to consider, when developing their state plan, how existing 

instruments that are used to meet other regulatory requirements or in voluntary markets may 

interact with ERCs.

The EPA acknowledges in the final rule that there may be interactions between mass-based and 

rate-based plans regarding counting measures, specifically where measures that provide 

substitute or avoided generation, such as RE and demand-side EE, are located in a mass-based 

state and can also be used by a rate-based state in meeting the CO2 performance rates or state 

goals. The EPA has determined that, in the context of interactions among rate-based and massbased plans, there is not explicit double-counting of the CO2 emission reductions associated with 

counting measures located in mass-based states, considering the accounting methods outlined in 

this final rule. Though there is no risk of double-counting emissions, in response to commenter 

concern that overall CO2 emissions reductions would be foregone in situations where a source in 

a rate-based state counts the MWh from measures in a mass-based state, but the generation from 

that measure acts solely to serve load in the mass-based state, the EPA is restricting the ability of 

rate-based state to claim emission reduction measures, such as RE and demand-side EE, located 

in mass-based states. In order to avoid cutting some states off from regional RE supplies that are 

assumed in the BSER building block 3 and incorporated in the CO2 emission performance rates 

or state rate-based CO2 goals in the emission guidelines, the EPA has determined that it is 

appropriate for rate-based states to count MWhs from RE located in mass-based states, subject to 

the condition that the generation in question was intended to meet electricity load in a state with 

a rate-based plan. 
27

For a discussion about the elements incorporated into the final rule to minimize double-counting, 

see section VIII.L of the final rule preamble. For more information about specific methods to 

adjust the CO2 emission rate of an affected EGU to reflect demand-side EE and renewable 

energy, including eligibility dates and the types of EE savings and RE MWhs that are eligible, 

see section VIII.K.1 of the final rule preamble. Requirements for rate-based emission trading 

programs and the issuance and tracking of ERCs, including qualifying measures, programs or 

projects, addressing the potential for interactions between ERCs and RECs or EECs, are 

addressed in section VIII.K.2 of the final rule preamble. Section IV.D.8 of the preamble to the 

proposed Federal Plan describes the provisions related to proper ex post quantification and 

verification of MWhs from renewable electricity generation or demand-side EE savings to avoid 

overestimation as suggested by commenters. For information about mass-based emission 

standards with a market-based emission budget trading program, see section VIII.J.2.d of the 

preamble to the final rule. 

The following are summaries of the specific public comments under this comment:

Commenters, in response to the EPA's request for comment on whether RE-based emission 

reductions should be credited to the state where the energy is generated rather than the state 

where the energy is used, stated that the EPA must avoid all incentives to double-count emission 

reductions or otherwise game the system. Commenters also stated that the EPA should design its 

state-based targets so that RE generation (rather than importation) is incentivized wherever such 

generation is physically feasible, so that maximum RE capacity is fostered.

Comment 6: Comments suggesting that states exporting renewable energy may not receive 

credit for these exports without further agreements with importing states. 

Response 6: In the final rule, to the extent qualifying renewable energy measures are tied to a 

state plan, the quantified and verified MWh impacts of the measures may be used by an affected 

EGU or state to adjust a CO2 emission rate, regardless of whether the generation occurs inside or 

outside the state or territory. For more information about the treatment of in-state and out-ofstate renewable energy impacts, see section VIII.L of the preamble to the final rule. 

The following are summaries of the specific public comments under this comment:

Commenters stated that states can claim credit only for RE they consume and that is accounted 

for under their renewable policies; as a result, states exporting RE may not receive credit for 

these exports without further agreements with importing states. Commenters stated that, at the 

same time, energy exporting states may not be able to claim credit for these emission reductions 

either. Commenters concluded that the proposed accounting method for RE may not capture all 

incentives for RE development in areas, like the West, with many large export and import 

relationships.

Commenters stated that these import/export relationships are particularly important in the West 

because there are numerous long distance power transfers in the region and that California is 

particularly interested in working with regional partners to explore joint compliance options and 

ensure that RE is accounted for across state lines to strongly encourage further investments.
28

Comment 7: Comments recommending that customer-sited distributed renewable generation 

within a state be credited like EE. 

Response 7: In the final rule, the EPA recognizes the value of renewable energy as part of the 

Best System of Emission Reduction. Renewable energy measures installed after 2012, including 

distributed renewable energy generation, that are tied to a state plan and achieve quantified and 

verified MWh savings may be used to adjust a CO2 emission rate, provided they meet the general 

and specific eligibility requirements for resources used to adjust a CO2 emission rate, in the same 

way that eligible EE resources may be used, described in section VIII.K.1 of the preamble to the 

final rule. The measures must also meet the eligibility requirements and provisions related to 

proper quantification and verification of MWhs from RE generation, as described in Ssection 

IV.D.8 of the preamble to the proposed Federal Plan

The following are summaries of the specific public comments under this comment:

Although commenters agreed that RE be credited based on out-of-state PPAs, commenters 

recommended that EPA should credit increased, customer-sited distributed renewable generation 

within a state, which is implemented after the date of the publication of the Proposed Rule, 

similarly to its proposed treatment of end-use EE.

Comment 8: Comments suggesting that states should be able to take credit for emission 

reductions achieved out of state due to in-state energy efficiency policies. 

Response 8: In the final rule, to the extent demand-side EE measures are tied to a state plan, the 

quantified and verified MWh impacts of the measures may be used by an affected EGU or state 

to adjust a CO2 emission rate, regardless of whether the demand-side EE savings occur inside or 

outside the state or territory. For more information about the treatment of in-state and out-ofstate energy efficiency impacts, see section VIII.L, Treatment of Interstate Effects, in the final 

rule preamble. 

The following are summaries of the specific public comments under this comment:

Several commenters stated that a state should be able to take credit for emission reductions 

achieved out of state due to in-state EE policies. Commenters stated that the credit should only 

be taken as long as the reductions will not be double-counted. Commenters stated that the credit 

should only be taken as long as both the importing and exporting state select rate-based goals; 

and commenters added that states should not be required to track savings back to the actual 

power plants or determine CO2 emissions reductions due to electricity savings. Commenters

stated that a state should not take credit any existing efficiency programs that were included in 

another state's baseline and used to set that state's interim and final goals. Commenters stated that 

as long as both the emissions and the energy output from the energy resources are allocated only 

to the state that imports the energy, these sources will not be double counted, and the technical 

potential for leakage is reduced
29

Several commenters believed that the state that funds the incentives and related program 

expenses incurred by the utility, should receive full credit for savings realized at out-state EGUs 

under 111(d). Commenters stated that such treatment of EE savings would be consistent with 

expected treatment of out-of-state RE generation compelled by the state. Commenters stated 

that this approach would accurately credit and incentivize EE investment in states that import 

fossil-fuel energy, thereby allowing the state to use its EE infrastructure as a tool for compliance.

Commenters stated that this approach would be compatible with their existing state laws. 

Commenters stated that this approach also provides parity between the mechanisms used to 

develop the BSER Block Four goal and compliance mechanisms available to importers. 

Several commenters stated that this approach would encourage energy importing states from 

funding and implementing EE programs and maximize the impact of the most cost-effective 

resource available for reducing carbon emissions.

Commenters asked that the EPA recognize that EE measures in hydropower-based utility 

territory reduces GHG emissions and award credit for that without requiring EE mandates or 

other encumberments on utilities with de minimis GHG emissions of their own. 

Commenters stated that states should have the ability to work with one another to determine the 

best method for accounting of such credits and costs, without having to be in a regional program, 

ensuring there is no double counting of reductions among states.

Commenters stated that, in addition to changing the rule to allow EE measures to be claimed no 

matter where the emission reductions occur, the EPA should allow a state to use the marginal 

emissions rate of the region's net system mix or its own average marginal emissions rate. 

Commenters claimed that this will allow each state to count the full value of its EE investments. 

Commenters stated that the EPA should allow each state to assign the avoided emission rate as 

the emissions rate of the marginal resources in the power pool.

Commenters stated that if the CPP is to achieve the degree of cost-effective carbon reductions 

that the RGGI model demonstrates are achievable, the rules under which state compliance is 

enforced must allow for the full crediting of EE impacts.

Commenters recommended that the EPA appropriately account for voluntary EE actions by 

private actors not covered by the rule, so that such actions are not double counted by reducing 

any state's obligations under the rule.

Commenters requested that the EPA recognize the existing deployment process for EE in 

consumer-owned utilities (COUs) in the Pacific Northwest. Commenters described the process 

for bringing EE projects onboard. Commenters stated that significant EE acquisitions have come 

about due to collaboration with the NWPPC and the Bonneville Power Administration (BPA).

Commenters stated that every successive regional power plan adopted by the NWPPC is an 

overall 20 year forecast that offers resource guidance accomplished through rigorous analysis 

and stakeholder involvement. Commenters stated that EE goals are a part of that resource 

guidance prioritized along with renewables and cogeneration. Commenters explained that BPA's 

power rate case sets the agency's budget, including budgeting for EE goals, informed by the 

Regional Technical Forum (RTF) which evaluates the cost effectiveness of EE measures. 
30

Commenters stated that COUs fund BPA EE programs through their power rates and many 

COUs supplement their EE programs by budgeting additional incentives in addition to 

contributions made through BPA programs.

Comment 9: Comments requesting additional guidance.

Response 9: In the final rule, to the extent qualifying RE generation and demand-side EE 

measures are tied to a state plan, the quantified and verified MWh impacts of the measures may 

be used by an affected EGU or state to adjust a CO2 emission rate under a rate-based approach, 

regardless of whether the RE generation or demand-side EE savings occur inside or outside the 

state or territory. The EPA will work with states using the rate-based approach that are interested 

in allowing the use of RE from outside the U.S. to adjust CO2 emission rates as described in 

section VIII.K.1.a.(2)(c)(iii). Descriptions of the types of qualifying generation that is eligible, 

including hydropower, is described in section VIII.K.1.a.(3). For more information about 

specific methods to adjust the CO2 emission rate of an affected EGU to reflect RE and demandside EE, including specific geographic eligibility requirements and limitations and measurement 

and verification requirements to ensure that the MWhs are unique and creditable, see sections

VIII.K.1 and VIII.K.3 of the preamble to the final rule. For more information on the treatment of 

in-state and out-of-state renewable energy and energy efficiency impacts, see section VIII.L of 

the preamble to the final rule. 

The MWh accounting method corresponds with the use of MWh-denominated Emission Rate 

Credits (ERCs) in the rate-based emission trading framework specified in this rule. An ERC is 

issued separately from any other instruments that may be issued for a MWh of energy generation 

or energy savings from a qualifying measure, such as a renewable energy certificate (REC). An 

ERC may be issued, however, based on the same data and verification requirements used by 

existing REC tracking systems for issuance of RECs and EECs that are used to meet state 

renewable portfolio standards or energy efficiency resources standards. The EPA is aware of the 

potential for interactions between ERCs and RECs or EECs and encourages the states to 

consider, when developing their state plan, how existing instruments that are used to meet other 

regulatory requirements or in voluntary markets may interact with ERCs. Requirements for ratebased emission trading programs and the issuance and tracking of ERCs, including qualifying 

measures, programs or projects and addressing the potential for interactions between ERCs and 

RECs, are in section VIII.K.2 of the preamble to the final rule.

The following are summaries of the specific public comments under this comment:

Several commenters believed that additional consideration, clarity and/or guidance was needed 

with respect to quantifying, assigning, or crediting electricity generation that crosses state or 

regional boundaries.

Several commenters requested clarification on how RE is to be credited when RE is generated in 

one state but financed and/or used in another. Commenters were unsure whether renewable 

generation imported from Canada could count towards 111(d) compliance. Commenters stated 

that the EPA should specifically address the manner in which interstate REC markets will be 

assessed for the purpose of compliance with the CPP. Commenters requested guidance on 
31

determining the beneficiary of RE and EE programs where the implementing state imports power 

from an EGU located in another state.

Commenters recommended the EPA allow states to take credit for international sources of RE 

and EE where the following conditions are met: 1. the new international resources used for 

crediting will result in reduced emissions from fossil-fuel generation in the United States; and 2.

the international resources are not double-counted as a non-emitting or low-emitting resource for 

a regulatory obligation of both the source country and Clean Power Plan compliance. 

Commenters expressed concern about the potential for leakage between states and between new 

and existing generation and recommended the EPA should ensure that generation shifts across 

borders does not allow power plants in the U.S. to comply with the clean power plan without 

actually achieving the anticipated reduction in carbon pollution.

Commenters believed states should be able to include import of Canadian low- and non-emitting 

electric generation in a state-driven portfolio plan. Commenters also suggested that the 

requirements to use Canadian low- and non-emitting electric generation could be part of a state 

commitment approach in which the requirements would be only enforceable by the state.

Commenters noted that electricity flows across state and international boundaries, and that load 

centers in U.S. states are often supplied in part by resources in neighboring Canadian provinces, 

and vice versa. Commenters stated that the same accounting systems used for interstate tracking 

systems can be used to track emission effects and to avoid double counting of emission 

reductions in the U.S.-Canada context. Commenters noted the following examples of tracking 

systems currently used: Midwest Renewable Energy Tracking System (or "M-RETS") (used to 

track renewable energy in U.S. Midwestern states and the province of Manitoba); Western 

Renewable Energy Generation Information System (or "WREGIS") (renewable energy registry 

and tracking system for the Western Interconnection, including the provinces of Alberta and 

BC); and New England Power Pool Generation Information System ("NEPOOL GIS") (tracks 

renewable energy credits ("RECs") for both renewable generation sourced within the ISO-NE 

control area and for generation imported from adjacent control areas, including provinces in 

eastern Canada).

Commenters noted that the Regional Greenhouse Gas Initiative ("RGGI") program has used the 

importation of electricity from Canada to reduce the utilization of fossil fuel-fired units in the 

RGGI region and thereby decrease the CO2 emissions at covered EGUs and noted that several 

states include Canadian RECs in their RPS programs. Commenters recommended states be 

allowed to include these RECs in their state plans. 

Commenters stated that clear accounting rules to award credit for RE to the appropriate parties is 

needed. Commenters stated that the EPA also did not adequately address the issue of increased 

demand or competition for such out-of-state credits, which will affect availability and price of 

those credits. Commenters specifically requested the EPA to provide guidance on avoiding

double-counting. Commenters requested that the EPA include more discrete provisions in the 

CPP governing the quantification and credit of electricity generation. Commenters asked for 

guidance on what the EPA considers effective ways to identify, allocate and ensure the integrity 

of out-of-state reductions caused by in-state RE programs.
32

Commenters asked how hydropower assets should be counted and specifically how they should 

be counted when two states each want to count the same hydropower generation toward their 

goal. Commenters asked whether the owner of the hydropower asset or output gets to pick the 

highest bidder, or is it based on load (contract path) following.

Commenters asked for clarification on the following questions: who gets the credit when RE is 

developed in one state using that state's tax credits and other incentives, but then exported to 

another state for consumption; and how does this differ in a multi-state arrangement. 

Commenters stated that the Proposed Rule is unclear whether the transfer of REC count toward 

the recipient state's compliance efforts in the absence of a formal multi-state plan between those 

two states.

Commenters urged the EPA to work collaboratively with states in developing definitive guidance 

that establishes a clear and workable framework on how states can account for and use RECs or 

RE generated from out-of-state resources.

Several comments stated that the EPA must clarify that the state paying for the RE generation 

may claim credit for that generation regardless of where the generation physically occurs.

Commenters requested that this clarification be made in rule language. Commenters stated that 

the owner should be able to sell or grant the right to another entity to use in meeting its 

obligations. Commenters also stated that if the EPA does not clarify that the state that owes the 

RE claims the credit, that there is a risk that the state hosting the RE production could also try to 

claim the compliance credit, which could lead to double counting of emissions reductions, and 

therefore a failure to meet the emissions reductions targeted by CPP. 

Commenters suggested that the EPA clearly state that renewable generation based upon out-ofstate PPAs are also creditable and they are credited in a manner that does not require importing 

states to negotiate agreements with exporting states. Commenters asked that the EPA clarify that 

bundled REC purchases from other states may count for compliance.

Commenters claimed that failure to specify acceptable and unacceptable attribution approaches 

for out-of-state RE introduces significant uncertainty, risk of double-counting emissions 

reductions and RECs, and potential for serious damage to existing RE markets. 

Commenters requested that the EPA provide guidance on affordable methods by which any state

may quantify emissions occurring outside of state boundaries when electricity or credits are 

being imported or exported, if the final CPP requires such quantification be included in State 

Plans.

Commenters stated that new hydroelectric power must be available for compliance for the state 

that owns the energy, regardless of where the energy is generated.

Commenters stated that the EPA should clarify that existing and future contracts that include 

RECs or other environment attributes also convey the associated emissions reductions relevant to 

state CPP implementation plans while preserving flexibility for regional and bilateral 

arrangements between states. Commenters contended that a lack of clarity will restrict utilities' 

ability to contract for renewable power across state lines, increasing compliance costs and 

artificially restricting the development of cost-effective renewable projects.
33

Commenters stated that the EPA should provide guidance to states for assessing the relative 

contribution of different state policies to a particular RE project. Commenters presented issues 

that required guidance, including: whether credit could be apportioned based on financial 

analysis of the contributions of each state's policy to the viability of a RE project; or, credit could 

go solely to the holder of the REC associated with the RE generation. Commenters stated that 

this may be worked out through multi-state accounting agreements, but some form of guidance 

or default allocations would provide more certainty for states, utilities, and RE developers. 

Commenters encouraged the EPA to further develop and describe what it means for a state to 

have "implemented" a RE measure in light of the interactive nature of state and federal policies 

promoting clean energy. 

Commenters stated that having the EPA be the final arbiter of whether a state has properly 

included RE emission reductions in a compliance plan creates great uncertainty for individual 

states, which would not know until after the EPA assessed all submitted state compliance plans 

whether they could count all of the RE included in a particular plan. Commenters were

concerned that this could undermine a state's ability to demonstrate that a plan would achieve the 

target emission rate goal, and could result in time-consuming and expensive plan revisions that 

delay the start of compliance. Commenters suggested to avoid plan revisions related to possible 

RE double counting and to ensure against double counting in the first instance, the EPA should 

provide clear guidance as to how states should attribute RE.

Commenters stated that the EPA should provide states with guidance on how to allocate RE built 

by electric utilities to serve customers in multiple states. Commenters gave an example of 

KCP&L which serves customers in Kansas and Missouri. Commenters stated that most of 

KCP&L's fossil generation owned by the company is located in Missouri, but most of the wind 

generation that has been built and is expected to be built in the coming years is in Kansas. 

Commenters stated that wind resources are allocated to each state, based on customer demand, 

without any need to transfer RECs. Commenters contended that in such situations, the state that 

consumes the RE should be able to use it for compliance. Commenters stated that the final

guidelines should address how utilities can allocate RE generation to different states, consistent 

with customer consumption patterns.

Commenters stated that the proposed guidelines do not specify how a state would demonstrate 

RE reductions included in a plan will not be double counted, but, in the absence of clear 

guidance from the EPA, it would seem to presuppose that states with potentially competing 

claims agree on how to apportion credit for RE reductions. Commenters stated that it appears 

that the EPA may intend to foreclose the use of some RE emission reductions for compliance if 

states cannot agree on attribution. Commenters stated that this would be unfair to states (and the 

owners of RE generation) as it could increase compliance costs by rendering some valid 

emission reductions unusable for compliance purposes simply because states could not agree. 

Commenters asserted that the EPA should not disallow the use of RE generation because it may 

have been double counted. Instead, Commenters stated, the EPA should articulate clearly how 

RE generation will be credited to states to prevent against double counting and ensure that all 

reductions can be used for compliance.

Commenters stated that the proposal fails to establish a workable regulatory framework for 

addressing the accounting of electricity resources generated in one state but used in another.
34

Commenters stated that our electricity system is interconnected with many cross-state purchase 

agreements. 

Commenters stated that the EPA should clarify how EE measures should be credited. 

Commenters urged the EPA to clarify EE measures are counted on a load-basis rather than a 

geographical basis.

Commenters stated that it will be important that the guidance provided to the states in the final 

rule, clearly recognizes the strength of mass-based approaches in avoiding accounting 

difficulties.

Commenters stated that the proposed rule is vague and the final rule should be unmistakably 

clear that all RE produced in a state is also credited entirely to that state.

Commenters stated that Wyoming exports about 60% of its block 1 generation and asked if block 

3 and 4 savings from other states can be applied to Wyoming's Block 1 exported production. 

Commenters also asked for clarification on whether block 3 and 4 savings only apply to 

Wyoming generation related to intrastate retail sales and asked for guidance on how block 3 and 

4 savings would be allocated among block 1 generators.

Comment 10: Comments requesting clarification on how RE should be credited; lack of 

clarification is costing Navajo Nation jobs and revenue. 

Response 10: In the final rule, to the extent qualifying RE generation are tied to a state plan, the 

quantified and verified MWh impacts of the measures may be used by an affected EGU or state 

to adjust a CO2 emission rate, regardless of whether the RE generation occurs inside or outside 

the state or territory. For more information about specific geographic and other eligibility 

requirements for resources that can used to adjust a CO2 emission rate, see section VIII.K.1 of 

the preamble to the final rule.

States, including areas of the Indian country, that do not have any affected EGUs within their 

borders may be providers of credits to adjust CO2 emission rates, as discussed in Section 

VIII.K.1.a.(2)(c). 

The accounting method corresponds with the use of MWh-denominated Emission Rate Credits 

(ERCs) in the rate-based emission trading framework specified in this rule. An ERC is issued 

separately from any other instruments that may be issued for a MWh of energy generation or 

energy savings from a qualifying measure, such as a renewable energy certificate (REC). An 

ERC may be issued, however, based on the same data and verification requirements used by 

existing REC tracking systems for issuance of RECs and EECs that are used to meet state 

renewable portfolio standards or energy efficiency resources standards. The EPA is aware of the 

potential for interactions between ERCs and RECs or EECs and encourages the states to 

consider, when developing their state plan, how existing instruments that are used to meet other 

regulatory requirements or in voluntary markets may interact with ERCs.
35

For more information about specific methods to adjust the CO2 emission rate of an affected EGU 

to reflect renewable energy generation and eligibility requirements for resources that can be used 

to adjust a CO2 emission rate, including eligibility dates and the types of RE MWhs that are 

eligible, see section VIII.K.1 of the final rule preamble of the CPP. Requirements for rate-based 

emission trading programs and the issuance and tracking of ERCs, including qualifying 

measures, programs or projects and addressing the potential for interactions between ERCs and 

RECs, are in section VIII.K.2 of the final rule preamble. For requirements related to the 

measurement and verification of eligible and unique MWhs, see Section VIII.K.3 of the 

preamble to the final rule.

The following are summaries of the specific public comments under this comment:

Commenters commenting on the Tribal and Territories Supplemental Notice, provided 

comments on counting RE. Commenters stated that RE generated within a state should be 

credited toward meeting that states carbon reduction rate. Commenters stated that the EPA 

should clarify that credits for RE should be assigned to the entity that is purchasing the output, 

including the RECs (or merely the RECs from that resource), unless an alternate arrangement is 

specified through contract. Commenters urged the EPA to make an immediate clarification 

without waiting for the issuance of a final rule.

Commenters stated that they have repeatedly asked the EPA to make this clarification and listed 

6 different meetings or documents where commenters asked the EPA for 

clarification. Commenters stated that the EPA's action, and subsequent inaction by not clarifying 

its ambiguous statements, has created and continues to create direct and irreversible economic 

harm to the Navajo Nation economy and its citizens. Commenters explained that because of the 

ambiguity of whether RE development on tribal lands will count toward a state's emission 

reduction goal, one project is currently on hold in the Navajo Nation. Commenters contended 

that this project has the potential to be the first of many utility-scale RE projects developed 

within the Navajo Nation and that several hundred construction jobs that the project would 

provide are on hold and in jeopardy. Commenters stated that absent an immediate clarification 

adopting the Navajo Nation's position, the Navajo Nation will likely lose all of the jobs and the 

direct and indirect economic growth associated with the project. Commenters stated that based 

on standard economic factors, the resulting lack of investment will cost the Navajo Nation 

economy over the life of the RE resource over $50 million in tax revenue alone. Commenters 

stated that the EPA should not engage in any behavior that would limit the use of tribal RE 

resources in any state and should refrain in its final rule from questioning the existing RE 

marketplace, which currently allows for interstate and inter-territorial sales and exchanges of 

RECs produced by RE projects.

Commenters contended that because the EPA asked for comment on whether states should only 

count RE generated in their state, the proposal is ambiguous about whether RE projects 

constructed on tribal lands will have to be included in either a regional trading program or a 

multi-state plan in order for RECs from such projects to be distributed across multiple 

jurisdictions. Commenters stated that developers must be allowed to freely negotiate the sale 

and delivery of electricity and RECs across jurisdictions (including state and tribal boundaries) 

through various contractual mechanisms, such as PPAs, without fear that the value of those 
36

projects will be severely limited by an inability to transfer the RECs for use to address 

CO2 emission reductions under any state plan.

Commenters stated that the EPA is also mistaken that the Supplemental Proposed Rule will 

result in no additional costs to the Navajo Nation. Commenters provided the example of the 

utility-scale RE project that is currently on hold. Commenters stated that the Navajo Nation is 

currently losing out on $100 million worth of investments in RE resources on the Navajo Nation 

because of the ambiguity of whether RE development on tribal lands will count toward a state's 

emission reduction goal.

Commenters stated that in an environment that suffers from over 50% unemployment, the 

continued delay in job creation is unconscionable and should not be allowed to continue merely 

because of the ambiguity created by the CPP. Commenters stated that the delay could also cause 

the project to not qualify for Federal tax credits and would lead to increasing the cost of the 

project. Commenters asserted that without immediate clarification by the EPA, additional project 

partners could have the same concerns, thereby stifling the Navajo Nation's economic growth 

and jeopardizing its pursuit of a green economy. Commenters stated that the EPA should issue an 

immediate clarification and statement supporting the current RE marketplace and the existing 

practice under which the use of RE and application of RECs is not bound by territorial 

restrictions. Commenters stated that this clarification should include that EPA has no interest in 

modifying the current RE development marketplace and supports without conditions or questions 

multi-jurisdictional development of RE resources and that such development can be contracted 

for use to meet compliance requirements for any state under the Proposed Rule for the States.

Commenters stated that the EPA should not interfere with RE project development in Indian 

Country. Commenters stated that the EPA should allow Indian tribes to receive credits for RE 

projects the tribes develop and use on their lands. Commenters stated that the EPA should 

immediately state that its intent is not to hinder the development of RE projects on tribal lands 

and further clarify that the EPA explicitly rejects any prohibition against a state utilizing RE 

projects that occur outside its boundaries. Commenters stated that the EPA should continue to 

leave the methodology for coordination for the sale and purchase of RECs and RE to the market 

and not attempt to dictate that methodology.

Commenters stated under the Energy Policy Act of 2005, the federal government committed to 

support the development of energy resources, and in particular RE resources, on tribal lands.

Commenters concluded that the EPA is contravening the clear mandates of the EPA by creating 

a barrier to the development of RE on tribal lands in a manner that is discriminatory as compared 

to the states.

5.7.3 Cooperative multi-state accounting of interstate emission effects

This section includes comments associated with multi-state agreements. 

Commenters have raised a number of issues related to this subsection which are organized by 

topics (comments) below. Responses are also provided for these topics.
37

Comment 1: The EPA should provide guidance on how to attribute reductions associated with 

RE before states submit compliance plans. EPA should serve as the third party verifier. 

Response 1: In the final rule, to the extent RE generation and demand-side EE measures are tied 

to a state plan, the MWh impacts of the measures may be used by an affected EGU or state to 

adjust a CO2 emission rate, regardless of whether the RE generation or demand-side EE savings 

occur inside or outside the state or territory. The accounting method corresponds with the use of 

MWh-denominated Emission Rate Credits (ERCs) in the rate-based emission trading framework 

specified in this rule. An ERC is issued separately from any other instruments that may be issued 

for a MWh of energy generation or energy savings from a qualifying measure, such as a 

renewable energy certificate (REC). An ERC may be issued, however, based on the same data 

and verification requirements used by existing REC tracking systems for issuance of RECs and 

EECs that are used to meet state renewable portfolio standards or energy efficiency resources 

standards. The EPA is aware of the potential for interactions between ERCs and RECs or EECs 

and encourages the states to consider, when developing their state plan, how existing instruments 

that are used to meet other regulatory requirements or in voluntary markets may interact with 

ERCs.

For more information about specific methods to adjust the CO2 emission rate of an affected EGU 

to reflect RE and demand-side EE, including specific geographic eligibility requirements and 

limitations, see section VIII.K.1 of the preamble to the final rule. Requirements for rate-based 

emission trading programs and the issuance and tracking of ERCs, including qualifying 

measures, programs or projects and addressing the potential for interactions between ERCs and 

RECs, are in section VIII.K.2 of the final rule preamble. For requirements related to the 

measurement and verification of eligible and unique MWhs, see Section VIII.K.3 of the 

preamble to the final rule. For more information on the treatment of in-state and out-of-state 

renewable energy and energy efficiency impacts, see section VIII.L of the preamble to the final 

rule, Treatment of Interstate Effects.

The following are summaries of the specific public comments under this comment:

Commenters supported the use of cooperative agreements between states, but requested that EPA 

provide clear guidance as to how to attribute reductions associated with RE and EE before states 

submit their compliance plans. Commenters raised questions about how to address compliance in 

the case of generation resources located in one state, but serving customers in another state or 

multiple states. Commenters provided an example where utilities located in one state that have 

ownership in generation stations in another state may be interested in using EE measures adopted 

in the "home" state to offset the CO2 emissions from generating stations in the other state, but 

would be unable to do so unless a multi-state plan is adopted. Commenters also pointed out a 

potential scenario in which one state may impose a CO2 reduction obligation on a non-emitting 

utility in that state, and another state (where the utility has generation that emits CO2) may 

require only CO2 emitters to reduce CO2, which would effectively require utility to pay twice for 

reducing the same CO2 emissions. Commenters also asked how an agreement could be reached 

when a state wants to claim credit for renewable generation built outside its borders, based on an 
38

assertion that the renewable project was built pursuant to that state's renewable policies.

Commenters suggested that the proposed rule should be adjusted to provide incentives for 

developing cross-state energy efficiency and renewable energy to encourage these collaborative 

regional plans. 

Commenters urged that EPA develop guidance on these issues. Commenters stated that there are 

many existing state and federal laws that already focus on generation and use of energy, 

including renewable resources and energy efficiency, in the Northwest region. Commenters 

stated the proposed EPA rule raises questions about the general construct, timing, and interaction 

with these existing laws. Commenters stated it is unclear how renewable energy credits (or actual 

energy) that comes into a state from a neighboring state would be accounted for in individual 

state implementation of the goals. Commenters noted that clear guidance may be useful to 

helping incentivize states to develop cooperative approaches and avoid scenarios were states may 

not be able to design multi-state plans prior to the due date for compliance plans. Commenters 

also called on EPA regional support to design joint compliance options and provide the data 

needed to support those options. Commenters suggested that states incorporate existing 

measurement and verification processes for determining the avoided MWh and emissions 

reductions from EE into regional protocols that can measure the impacts of EE at a regional 

level.

Commenters agreed that states must adopt a measurement and verification (M&V) program to 

accompany any plan elements beyond Building Blocks 1 and 2 in the final rule. Commenters 

stated the M&V program would also allow a state to take credit for reductions of emissions in 

another state where the implementing state now obtains transmitted power, and ensure that two 

states do not claim the same reduction.

Commenters stated that EPA's approach of requiring a state to determine where the avoided 

generation has/will occur and only giving credit for in-state reductions is going to be burdensome 

to states in terms of planning, record keeping, and ensuring no double counting. Commenters

stated that in order to prevent legal issues between states and utilities, EPA should serve as the 

third party to examine how to handle the tracking of avoided generation to prevent double 

counting where the EE/RE is paid for by one state, implemented by a second state, and the 

generation is avoided in a third state. Commenters also indicated that EPA needs to provide the 

states with a more concrete methodology for this accounting/ modeling, a nation-wide reporting 

system, and third party verification of which unit avoided generation due to EE/RE in which 

state.

Comment 2: Comments stating that the EPA should promote regional cooperation to prevent 

perverse incentives that could result in negative economic impacts between states. Additionally, 

costs to customers in DC will be affected by decisions made by other states. 

Response 2: The final rule allows for multi-state coordination through a joint emission goal and 

among states retaining individual state goals, including via trading programs, as well as multistate plans that address a subset of EGUs in a state. For more information, see section VIII.C.5 of 

the preamble to the final rule. 
39

The following are summaries of the specific public comments under this comment:

Commenters noted the potential cost impacts associated with the rule. Commenters expressed 

concerns that the proposed rule could have potential deleterious effects where regulated utilities 

provide customers with energy generated by facilities outside the state. Commenters noted that if 

a state's emission goals under the Proposed Rule created a perverse incentive to close an electric 

utility, it could result in economic costs to customers in outside states. Commenters urged that 

EPA should promote consideration in working towards the common goal of carbon reduction 

among states. Commenters stated that although the District of Columbia would not have to 

submit a state plan because it imports nearly all of its electricity via the regional transmission 

grid managed by PJM, it will be affected by the actions states within its region take to comply 

with their emissions guidelines. Commenters noted that decisions made by states throughout the 

PJM RTO region will ultimately affect District residents and ratepayers.

Comment 3: Comments suggesting a cooperative accounting agreement would not address 

double-counting concerns.

Response 3: The EPA agrees that it must minimize the potential for double-counting. The final 

rule acknowledges the interactions between rate and mass states and includes elements that 

minimize the risk of double-counting as described in section VIII.L of the preamble to the final 

rule. 

It is proposed in the Federal Plan that EM&V plans must address how double counting will be 

avoided through the use of tracking and accounting procedures to ensure that two or more 

programs do not separately claim savings from the same EE project or measure (for example, 

two EGUs claiming savings from the same lighting retrofit). Other types of double counting 

must likewise be considered and avoided. For more details on EM&V provisions, see section 

VIII.K.3 of the preamble to the final rule, section IV.D.8 of the preamble to the proposed Federal 

Plan, and the draft guidance document.

The following are summaries of the specific public comments under this comment:

Commenters requested assurances that EPA will confirm that double counting does not occur. 

Commenters expressed concerns that a cooperative accounting agreement would not address 

double-counting concerns. Commenters noted that although the proposal suggests that a massbased state could adjust the overall CO2 emissions from the affected fleet to account for the 

"export" of avoided CO2 emission credits, RE and EE benefits are already automatically 

accounted for under a mass-based program as the existence of RE/EE measures, or "megawatts," 

displaces the state's or region's reliance on fossil fuel-fired generation. Commenters argued that it 

is difficult to unravel the location and type of fossil fuel-fired generation the specific unit of RE 

or EE has displaced, therefore, any adjustment to the overall CO2 emissions from the mass-based 

state's affected fleet would be derived from assumptions (e.g., estimates of the magnitude by 

which to offset the emissions of the mass-based state's affected fleet). Commenters expressed 

concern that if an adjacent state that relies on a rate-based approach attempted to claim credit for 

RE produced in a mass-based state, this would result in unavoidable double-counting. 

Commenters stated they support the level of emission reductions in the proposed rule, but urged 
40

EPA to ensure that flexibility in the rule does not result in double counting of emission 

reductions.

Commenters supported EPA's proposal giving states the ability to take credits for renewables for 

compliance purposes as well as state renewable portfolio standard requirements without 

duplicating compliance credit. Commenters noted that a crediting and tracking system will be

needed to ensure that 111(d) compliance credit is not double counted between states. 

Commenters stressed that implementation of the Clean Power Plan hinges on EPA's ability to 

accept or reject state proposals in order for the Plan to be effective. Commenters stated the EPA 

must disapprove a state's implementation plan if the plan is deemed "unsatisfactory" or double 

counts RECs or avoided emissions already accounted for in other state implementation plans. 

Comment 4: Comments regarding the duplication of emission reductions between state plans.

Response 4: In the final rule, to the extent RE generation and demand-side EE measures are tied 

to a state plan, the MWh impacts of the measures may be used by an affected EGU or state to 

adjust a CO2 emission rate, regardless of whether the RE generation or demand-side EE savings 

occur inside or outside the state or territory. For more information about specific methods to 

adjust the CO2 emission rate of an affected EGU to reflect RE, see section VIII.K.1 of the 

preamble to the final rule.

The following are summaries of the specific public comments under this comment:

Commenters responded to EPA's request for comments concerning duplicative emission 

reductions between state plans. Commenters stated that EPA should defer to states that agree on 

an alternate formula for allocating reductions between or among themselves, as long as doublecounting is avoided. Commenters stated that the final rule should clearly provide that it is up to 

the owners of renewable generation to indicate which entity gets credit for the renewable 

generation. Commenters indicated that the affected state plans will include and track these 

agreements, and EPA must respect these agreements as long as there is no double-counting of the 

renewable generation for 111(d) compliance. Commenters stated that EPA should provide 

flexibility in the final rule to not strand existing utility pollution control assets, while providing 

for wind energy expansion that allows the host state as well as neighboring states to develop 

plans that can meet their respective CO2 emission reduction goals.

Commenters noted that EPA requested comment on whether an emission reduction becomes 

duplicative (and therefore cannot be used for demonstrating performance in a plan) if it is used as 

part of another State's demonstration of emission performance under its CAA section 111(d) plan 

(79 FR 34913). Commenters stated that avoidance of double counting is an accounting issue for 

States to resolve and EPA's involvement should only be as a last resort. Commenters suggested 

that, upon resolution, state goals should be modified as appropriate but the credits should not be 

voided resulting in no state benefit.
41

Comment 5: Comments suggesting that the EPA should use certification tracking system to 

track emissions.

Response 5: The final rule allows for multi-state coordination through a joint emission goal and 

among states retaining individual state goals, including via trading programs, as well as multistate plans that address a subset of EGUs in a state, as described in section VIII.C.5 of the 

preamble to the final rule. The final rule also includes requirements for tracking systems used by 

states issuing emission rate credits under rate-based emission trading approaches. For more 

information, see section VIII.K.2 of the preamble to the final rule.

The following are summaries of the specific public comments under this comment:

Commenters stated that EPA should encourage states participating in a multi-state plan to use 

existing all-generation certificate tracking systems, where they exist, or work with existing RE 

tracking systems to track emissions from affected EGUs. Commenters noted that projects often 

receive numerous tax credits and other incentives in the state in which they are located, and that 

EPA should be receptive to state plans that cooperatively allocate credit for such resources 

through mutual agreement between states that generate and use renewable electricity. 

Commenters stated that EPA must treat renewables consistently in state carbon emission 

baselines and targets.

Comment 6: States shouldn't have to join a multi-state compact to share RE credits. The EPA 

should give deference to states' ongoing resource planning measures as a means for sustainable 

electricity supply planning and delivery.

Response 6: In the final emission guidelines, the EPA provides for multiple multi-state plan 

approaches that states may take to meet the emission guidelines. This includes multi-state plans 

with joint multi-state rate- or mass-based goals and the ability to collaborate with other states in 

the implementation of rate- or mass-based emission trading programs though a single-state plan. 

These multi-state approaches are described in sections VIII.C.5, VIII.J.3, and VIII.K.4 of the 

preamble to the final rule.

Regarding renewable energy, the final rule bases the Best System of Emission Reductions upon 

resources within a regional, not a state’s border. In the final rule, to the extent RE generation 

measures are tied to a state plan, the MWh impacts of the measures may be used by an affected 

EGU or state to adjust a CO2 emission rate, regardless of whether the RE generation occurs 

inside or outside the state or territory. For more information about specific methods to adjust the 

CO2 emission rate of an affected EGU to reflect RE, see section VIII.K.1 of the final rule 

preamble. The final rule allows for multi-state coordination among states retaining individual 

state goals under rate-based and mass-based emission trading programs. Details can be found 

under section VIII.C.5 of the final rule preamble.

The following are summaries of the specific public comments under this comment:
42

Several commenters stated that states should not have to join a multi-state compact in order to 

effectively share the renewable resource credit. Commenters stated that EPA should not impose 

measures within the CPP that would compel Minnesota to cease the importing and exporting of 

energy resources needed to reliably and cost effectively serve the energy needs of Minnesotans 

as part of CPP state target compliance requirements, and noted that EPA's proposed 

determination of a Best System of Emission Reductions is based upon resources within a state's 

borders. Commenters stated that EPA should give deference to Minnesota's ongoing resource 

planning measures as a means for sustainable electricity supply planning and delivery, and if 

necessary, demonstrating Minnesota compliance with the EPA proposed CPP. Commenters 

stated that EPA should permit states to allow regulated sources to use tradable mass-based 

emissions credits purchased from sources in other states, without any formal multistate plan, so 

long as any ton of emissions allowance can only be used in one state. For states that use the ratebased emissions approach, EPA should clarify that renewable energy generated in one state can 

be included in another state's compliance formula. Commenters agreed that multi-state 

cooperation is most likely to arise among states that have individual state plans that recognize 

reductions or credits from other states, but indicated EPA must clarify that states can cooperate 

without blending state goals into a multi-state goal. Commenters stated that this approach should 

qualify as a multi-state approach eligible for an additional one year extension.

Comment 7: Comments regarding the practical implication of not considering energy 

cooperative’s electric systems. 

Response 7: The treatment of EE has changed from the proposed approach. In the final rule, to 

the extent demand-side EE measures are tied to a state plan, the full MWh impacts of the 

measures may be used by an affected EGU or state to adjust a CO2 emission rate, regardless of 

whether the demand-side EE savings occur inside or outside the state or territory.

The following are summaries of the specific public comments under this comment:

Commenters stated that the proposal fails to consider the practical implications of an energy 

cooperative's electric system that crosses state boundaries, particularly in the case of crediting 

reductions due to energy efficiency projects.

5.7.4 Tradable regional EE/RE credit market

This section addresses comments on tradable credit markets as a method of implementation and 

compliance with CPP.

Commenters have raised a number of issues related to this subsection which are organized by 

topics (comments) below. Responses are also provided for these topics.

Comment 1: Comments supporting tradable credit markets.
43

Response 1: In the final rule, quantified and verified MWh impacts of qualifying zero-emitting 

and low-emitting resources tied to a state plan may be used by an affected EGU or state to adjust 

a CO2 emission rate, regardless of whether the renewable generation or demand-side EE savings 

occur inside or outside the state or territory. Consistent with the EPA’s calculation of the CO2

emission performance rates and state rate-based CO2 goals in the final emission guidelines, the 

MWh impacts are added to the denominator of an affected EGU’s reported CO2 emission rate, 

resulting in a lower, adjusted CO2 emission rate.

Because of the separate accounting of MWhs and CO2 emissions, with emission impacts inherent 

in reported stack CO2 emissions and zero-emitting MWh impacts requiring explicit adjustments, 

the accounting method corresponds with the use of MWh-denominated Emission Rate Credits 

(ERCs) in the rate-based emission trading framework specified in this rule. 

An ERC is issued separately from any other instruments that may be issued for a MWh of energy 

generation or energy savings from a qualifying measure, such as a renewable energy certificate 

(REC). An ERC may be issued, however, based on the same data and verification requirements 

used by existing REC tracking systems for issuance of RECs and EECs that are used to meet 

state renewable portfolio standards or energy efficiency resources standards. The EPA is aware 

of the potential for interactions between ERCs and RECs or EECs and encourages the states to 

consider, when developing their state plan, how existing instruments that are used to meet other 

regulatory requirements or in voluntary markets may interact with ERCs.

For more information about specific methods to adjust the CO2 emission rate of an affected EGU 

to reflect renewable energy generation and eligibility requirements for resources that can be used 

to adjust a CO2 emission rate, including eligibility dates and the types of RE MWhs that are 

eligible, see section VIII.K.1 of the final rule preamble of the CPP. Requirements for rate-based 

emission trading programs and the issuance and tracking of ERCs, including qualifying 

measures, programs or projects and addressing the potential for interactions between ERCs and 

RECs, are in section VIII.K.2 of the final rule preamble. Section IV.D.8 of the preamble to 

proposed Federal Plan describes the provisions related to proper quantification and verification 

of MWhs from renewable electricity generation. 

The following are summaries of the specific public comments under this comment:

Multiple commenters stated they believe that states should be able to take advantage of existing 

REC markets to track and take credit for renewable energy generated out-of-state; these 

commenters noted that a renewable energy certificate (REC) issued by a tracking system would 

be a viable, effective, efficient option that would allow affected EGUs and other entities to 

demonstrate compliance with a renewable energy standard. Commenters noted that the use of 

regional REC markets is consistent with EPA's approach of determining state renewable targets 

based on the regional availability of renewable power resources. Commenters stated that 

allowing states to continue to use demonstrated and effective regional tracking systems to track 

RE will be the most efficient way to demonstrate CPP compliance. Commenters recommended 

that states be required (or strongly encouraged) to use current tracking systems in place for REC 

generation and tracking to avoid double counting (e.g. PJM-EIS GATS). Commenters stated that 

such tracking systems help states comply with renewable portfolio standard (RPS) obligations; 

other commenters stated that each state has the discretion to choose what level of RPS 
44

compliance it will allow through out-of-state RECs. Commenters noted that RECs convey RE 

attributes, the name and location of the generating unit, the fuel used to produce electricity, the 

use of renewable electricity to individual grid users, the date the generation unit went online, and 

avoided grid emissions associated with renewable generation. Multiple commenters supported 

states developing, expanding or participating in an environmental crediting accounting system 

for renewable energy that utilizes RECs. Commenters supported RECs from a utility perspective, 

and stated that the final rule should allow utilities the ability to utilize RECs to demonstrate 

compliance by surrendering or selling the RECs to entities or states needing additional 

environmental attributes. Commenters noted that the problem of double counting is minimized 

when RECs are properly issued, tracked, and retired. Commenters asserted that the benefit of 

tracking systems is the ability to identify the location of certificate use and whether the 

certificate is used for compliance with a state RPS in the state where the generator is located, an 

adjoining state, or a state across the country. Commenters also noted that interstate trading 

programs would ensure reliability and reduce customer rate impacts. Commenters stated that the 

use of markets would also help utilities determine how much renewable energy capacity they 

needed to install or have under contract. Commenters also noted that reliance on the renewable 

energy market would provide greater RE generation opportunities at lower cost and lower 

emissions; commenters asserted that the interstate trading of RECs is an integral component of 

the financing and deployment of RE generation. Commenters also noted that a recent UCS report 

discussed the benefits of regional grid coordination and highlighted several recent studies by grid 

operators showing that renewable energy can significantly lower CO2 emissions while 

maintaining reliable and affordable electricity. Commenters believed that allowing nationwide 

trading of RECs for compliance RE targets would lower compliance costs.

Commenters supported a trading mechanism as a means for states to accommodate utilities that 

do not have mechanisms to reduce emissions - e.g., NGCC units (which can be redispatched) or 

electrical load (to which energy efficiency measures can be applied) - in all states where it has 

generation. Commenters urged that state plans must have some way for utilities to comply 

without the possibility of energy efficiency or demand reduction measures in that state to offset 

generation. 

Commenters recommended the EPA not modify the current renewable energy development 

marketplace and recommended that any state by allowed to use renewable energy resource

contracts to meet their compliance requirements without requiring multi-jurisdictional 

agreements. 

Comment 2: Comments requesting recommendations on how to track the crediting of RE use.

Response 2: The EPA agrees that it is important to ensure that emission rate credits (ERCs) for 

qualifying measures, including RE MWh generation projects and programs, are properly issued 

and tracked to avoid duplication or double claims. The final rule describes specific requirements 

and assurances states must include in their plan submittal, including tracking system 

requirements, to assure the integrity of a rate-based emission trading approach. For more 

information, see section VIII.K.2 of the preamble to the final rule.
45

In the final rule, to the extent RE generation measures are tied to a state plan, the MWh impacts 

of the measures may be used by an affected EGU or state to adjust a CO2 emission rate, 

regardless of whether the RE generation occurs inside or outside the state or territory.

Because of the separate accounting of MWhs and CO2 emissions, with emission impacts inherent 

in reported stack CO2 emissions and zero-emitting MWh impacts requiring explicit adjustments, 

the accounting method corresponds with the use of MWh-denominated Emission Rate Credits 

(ERCs) in the rate-based emission trading framework specified in this rule. 

An ERC is issued separately from any other instruments that may be issued for a MWh of energy 

generation or energy savings from a qualifying measure, such as a renewable energy certificate 

(REC). An ERC may be issued, however, based on the same data and verification requirements 

used by existing REC tracking systems for issuance of RECs that are used to meet state 

renewable portfolio standards. The EPA is aware of the potential for interactions between ERCs 

and RECs or EECs and encourages the states to consider, when developing their state plan, how 

existing instruments that are used to meet other regulatory requirements or in voluntary markets 

may interact with ERCs.

Multi-state plans, where multiple states submit a plan to meet a joint rate-based or mass-based 

CO2 goal, must meet all of the same requirements as a single state plan to be approvable. State 

plan requirements are addressed at section VIII.D.2 of the preamble to the final rule. In 

particular, a state plan must describe the plan approach and geographic scope, as discussed in 

section VIII.D.2.a.(1) of the preamble to the final rule. In addition, states may collaborate in the 

implementation of single-state rate-based and mass-based emission trading programs, through 

the interstate transfer of ERCs and emission allowances, as discussed at section VIII.C.5.c. of the 

preamble to the final rule. RECs may not be used as a compliance unit under a rate-based 

emission standards plan type, as discussed at section VIII.K.2.f of the preamble to the final rule. 

However, RECs could be used as a compliance instrument under a state measure, such as a state 

RPS, addressed in the supporting material for a state measures plan type.

For more information about specific methods to adjust the CO2 emission rate of an affected EGU 

to reflect renewable energy generation and eligibility requirements for resources that can be used 

to adjust a CO2 emission rate, including eligibility dates and the types of RE MWhs that are 

eligible, see section VIII.K.1 of the preamble to the final rule. Requirements for rate-based 

emission trading programs and the issuance and tracking of ERCs, including qualifying 

measures, programs or projects and the potential for interactions between ERCs and RECs, are in 

section VIII.K.2 of the preamble to the final rule.

The following are summaries of the specific public comments under this comment:

Several commenters provided recommendations on how to track the crediting of RE use. 

Commenters recommended EPA leverage the infrastructure for REC tracking that is in place in 

many states and regions. Commenters supported the use of established REC tracking systems 

and believe they are a viable tool that affected EGUS, regulators, and other entities can employ 

to help ensure compliance with an RE standard. Commenters stated that the existing REC 

tracking systems would not likely need any major modifications in order to be used to account 

for and verify out-of-state purchases of RE. For example, commenters recommended the use of 
46

the existing M-RETs tracking system; commenters specifically listed procedures for review used 

in M-RETs to prevent double-counting. Commenters stated that M-RETS tracks the amount of 

RE delivered to the interstate transmission system and the amount of RE that the utility retires 

for each state, and RECs may be used only once. Commenters provided that processes are in 

place to prevent double counting both for generation tracked within M-RETS and between MRETS and other tracking systems. Commenters also supported the use of tracking systems such 

as WREGIS to expand the procurement of RE options for states, and other commenters also 

pointed to the New England Power Pool Generation Information System. Commenters supported 

the use of RGGI, stating that RGGI states have successfully implemented emissions limits within 

existing power markets without distortions, disruptions, or reliability issues. Commenters urged 

EPA to simplify the manner in which RGGI states can craft state plans to comply with the ESPS. 

Commenters noted that states would benefit from the ability to purchase more competitively 

priced RE as well as the ability to sell RECs to other states. Commenters pointed to North 

Carolina as a state with an established entity which verifies, tracks, and banks both RE 

generation and EE avoided generation. Commenters pointed to the Generation Attribution 

Tracking System (GATS) as a viable system for tracking RECs. Commenters noted that GATS 

has validations built into the tracking system to provide as a basis of certificate ownership and to 

prevent double counting from system registration through retirement of the certificates. 

Commenters asserted that incorporating a tradable-REC program into a rate-based compliance 

mechanism would take advantage of existing tools and resources and minimize a state's need to 

develop new mechanisms to demonstrate compliance. Commenters gave examples of existing 

programs that could be used and referenced a document for more information on the existing 

programs: Jan Hamrin, Clean Energy States Alliance, REC Definitions and Tracking 

Mechanisms Used by State RPS Programs (Jun. 2014), available at 

http://www.cesa.org/assets/2014-Files/RECs-Attribute- Definitions-Hamrin-June-2014. 

Commenters suggested that EPA be clear that existing REC and environmental attribute 

crediting platforms (including voluntary REC tracking systems) are acceptable tools for 

approvable state plans to use, and that for any existing or newly developed system to be 

approvable it must ensure that the same renewable MWh do not generate or use credits that can 

be double counted. 

Commenters pointed to a recent independent report (see "Tracking Renewable Energy for the 

U.S. EPA's Clean Power Plan", June 25, 2014) that concluded that the current tracking 

infrastructure is sound and the risk of double counting renewables for the purposes of RPS

compliance is remote. Commenters noted that most REC tracking systems require that a facility 

be registered only in one tracking system, which ensures that claims are not being made for 

certificates over multiple tracking systems. Commenters also noted that for most tracking 

systems, including GATS, there registry administrators also have the ability to identify 

duplication or double claims, that the registries provide public reports that are very similar to 

ensure comprehensive checks to prevent double counting; and that the registries allow regulators 

access to centralized on-demand and current reports about retired certificates, account-holder 

information, and state, regional, or market-wide data. Commenters urged that similar reports 

could be designed and created based on the rules for 111(d) compliance; Commenters stated that 

the tracking systems have implemented many enhancements and changes to accommodate the 

changing needs of the States and could also accommodate the changes needed to support 111(d) 

compliance.
47

Commenters noted that for state renewable policies that do not currently involve the transfer of 

RECs, states will need to incorporate accounting using RECs in order for the renewable energy 

to be assigned to different policies and counted under 111(d). Commenters supported allowing 

RE regulations and programs that meet Evaluation, Measurement, and Verification (EM&V) 

requirements to generate RECs based on of the quantity of energy savings or renewable energy 

generation. Commenters asserted that these states would not need to require the transfer of 

RECs, provided the RECs are retired in state and are not counted towards another mechanism 

being used for 111(d) compliance. Commenters recommended that EPA provide guidance to 

states regarding the acceptable RE that would count towards compliance, and requested as well 

specific guidance on how states could reconcile existing RE policy and generation sources with 

the RE targets and generation sources indicated in the proposed rule.

Commenters expressed concern that some states lack infrastructure capable of planning and 

implementing RE measures on a state-specific basis, or have time to develop a joint 

implementation plan. Commenters recommended that as long as there is a basic level of 

consistency between state programs (e.g., similar currencies), any two or more states should be 

able to trade emission credits on a bilateral basis without a formal multistate compliance plan. 

Commenters pointed out that interstate REC trading would require coordinated regional action. 

Commenters also asked EPA to allow the use of greenhouse gas reductions secured outside of 

the power sector, as long as the reduction is made by facilities that are tied to the grid. As an 

example, commenters suggested that a Waste-to-Energy facility that sells renewable energy to 

the grid could generate an offset in a state or regional trading system based on the avoided 

landfill methane emissions. Commenters specifically requested that RECs not be limited to 

utility scale projects, but be allowed to come from commercial and residential distributed solar 

systems. 

Comment 3: Comments suggesting that the EPA should/should not mandate interstate trading.

Response 3: The final emission guidelines allow for, but do not require, multi-state plans. The 

final emission guidelines also provide for coordination among states in the implementation of 

single-state plans. The final emission guidelines provide for multiple multi-state plan approaches 

that states may take to meet the emission guidelines. This includes multi-state plans with joint 

multi-state rate- or mass-based goals, and the ability to collaborate with other states in the 

implementation of rate- or mass-based emission trading programs though a single-state plan. 

These multi-state approaches are described in sections VIII.C.5, VIII.J.3, and VIII.K.4 of the 

preamble to the final rule.

The following are summaries of the specific public comments under this comment:

Commenters recommended that the EPA mandate interstate trading of CO2 credits. Commenters

urged that although the proposed rule provides flexibility to each state to make their own 

determination regarding regional CO2 markets, it also allows for each state to "go it alone" and 

does not require cooperative planning and stakeholder processes. Commenters asked that at a 
48

minimum, the EPA mandate that states perform comprehensive analysis of multistate and 

regionals CO2 reductions plans before defaulting to a state only program. 

Commenters asserted that the EPA cannot and should not mandate interstate trading programs. 

Commenters asserted that the Clean Air Act does not anticipate or define RECs, and that the 

inclusion of RECs is not workable in a regime where the state has obligations related to emitting 

units located in the state. Commenters further noted that because RECs are based on state laws, 

the definition of what fuel can be used to produce a REC may vary among the states.

Comment 4: Comments requesting the EPA to allow flexibility in credit trading, e.g. allow 

states to account for RE using options other than RECs.

Response 4: The EPA agrees that it is important to ensure that emission rate credits for 

qualifying measures, including RE MWh generation projects and programs, are properly issued 

and tracked to avoid duplication or double claims. The final rule describes specific requirements 

and assurances states must include in their plan submittal, including tracking system 

requirements, to assure the integrity of a rate-based emission trading approach. For more 

information, see section VIII.K.2 of the preamble to the final rule.

In the final rule, to the extent qualifying RE generation measures are tied to a state plan, the 

MWh impacts of the measures may be used by an affected EGU or state to adjust a CO2 emission 

rate, regardless of whether the RE generation occurs inside or outside the state or territory.

Because of the separate accounting of MWhs and CO2 emissions, with emission impacts inherent 

in reported stack CO2 emissions and zero-emitting MWh impacts requiring explicit adjustments, 

the accounting method corresponds with the use of MWh-denominated Emission Rate Credits 

(ERCs) in the rate-based emission trading framework specified in this rule. 

An ERC is issued separately from any other instruments that may be issued for a MWh of energy 

generation or energy savings from a qualifying measure, such as a renewable energy certificate 

(REC). An ERC may be issued, however, based on the same data and verification requirements 

used by existing REC tracking systems for issuance of RECs that are used to meet state 

renewable portfolio standards. The EPA is aware of the potential for interactions between ERCs 

and RECs or EECs and encourages the states to consider, when developing their state plan, how 

existing instruments that are used to meet other regulatory requirements or in voluntary markets 

may interact with ERCs.

Multi-state plans, where multiple states submit a plan to meet a joint rate-based or mass-based 

CO2 goal, must meet all of the same requirements as a single state plan to be approvable. State 

plan requirements are addressed at section VIII.D.2 of the preamble to the final rule. In 

particular, a state plan must describe the plan approach and geographic scope, as discussed in 

section VIII.D.2.a.(1) of the preamble to the final rule. In addition, states may collaborate in the 

implementation of single-state rate-based and mass-based emission trading programs, through 

the interstate transfer of ERCs and emission allowances, as discussed at section VIII.C.5.c of the 

preamble to the final rule. RECs may not be used as a compliance unit under a rate-based 
49

emission standards plan type, as discussed at section VIII.K.2.f of the preamble to the final rule. 

However, RECs could be used as a compliance instrument under a state measure, such as a state 

RPS, addressed in the supporting material for a state measures plan type.

For more information about specific methods to adjust the CO2 emission rate of an affected EGU 

to reflect renewable energy generation and eligibility requirements for resources that can be used 

to adjust a CO2 emission rate, including eligibility dates and the types of RE MWhs that are 

eligible, see section VIII.K.1 of the preamble to the final rule. Requirements for rate-based 

emission trading programs and the issuance and tracking of ERCs, including qualifying 

measures, programs or projects and the potential for interactions between ERCs and RECs, are in 

section VIII.K.2 of the preamble to the final rule.

The following are summaries of the specific public comments under this comment:

Several commenters requested that EPA allow flexibility in the types of trading agreements 

allowed between states. Commenters stated that RE and EE credit trading among states should 

support compliance even in the absence of a comprehensive regional plan. Commenters asked 

EPA to support approaches that allow states flexibility to allocate credits for RE an EE, as well 

as approaches which allow states to reach agreements on the allocation of carbon liabilities. 

Commenters suggested that this would allow existing tracking mechanisms, such as WREGIS, to 

be compatible with the final rule.

Commenters requested that EPA not limit states' ability to include RE in state plans to RE that is 

represented by RECs. Commenters argued that RECs are not the best or only means of crediting 

or trading RE across state lines, and provided as examples both the use of bilateral contracts for 

RE as well as allowing accounting for the use of utility-owned in-state and out-of-state RE 

without the generation of a REC. Commenters also asserted that EPA should not limit states to 

RES programs as the only means of including RE in a compliance plan, and recommended that 

states could also consider performance-based incentives, financial assistance programs, state 

integrated resource plans, or other regulatory programs. 

Commenters requested EPA consider allowing or implementing alternative trading 

platforms/registries. Commenters requested that EPA be open to state proposals to rely on 

alternative approaches for allocating RE, including through existing voluntary REC platforms or 

through a new section 111(d) platform or registry. Commenters also noted that other generation 

tracking systems can be used to calculate interstate emissions from affected EGUs and help 

avoid double-counting. Commenters recommended allowing states to approve carbon credit 

exchanges that allow facilities using renewable or other tools to sell their surplus emission 

reductions to other facilities; commenters urged that such an exchange could also serve as a 

finance mechanism for technological upgrades and worker/community transition programs and 

work on either a single state or a regional basis. Commenters urged EPA to provide guidance for 

states or regions wishing to implement their own programs.

Commenters noted that since renewable energy may be used both to comply with RPS and Clean 

Power Plan requirements, the ability to track renewable and carbon attributes separately for use 

in different regulatory programs should be considered. Commenters assured that the final rules 
50

should provide as much flexibility as possible and should not exclude certain types of credits or 

trading programs.

Comment 5: Comments suggesting the EPA separate the CPP from state RPS programs by 

establishing a Renewable Energy Carbon Attribute (RECA) certificate.

Response 5: The final rule allows interested states to participate in interstate trading programs 

depending upon the type of approach the state selects and specifies a unique acceptable unit of 

trading under a rate-based approach, the emission rate credit (ERC), a tradable compliance unit 

representing one MWh of electric generation (or reduced electricity use) with zero associated 

CO2 emissions. Requirements for rate-based emission trading programs, including those related 

to issuance of ERCs based on RE generation and demand-side EE MWh savings, and tracking 

systems. For specific requirements under rate-based emission trading approaches, see section 

VIII.K.2 of the preamble to the final rule.

In section VIII.K.3.b of the preamble to the final rule, the EPA clarified that for energy 

generating resources, including RE, states may leverage the programs and infrastructure they 

have in place for achievement of their RPS and take advantage of registries in place for the 

issuance and tracking of RECs. Many existing REC tracking systems already include wellestablished safeguards, documentation requirements, and procedures for registry operations that 

could be adapted to serve similar functions in relation to the final emission guidelines.

The following are summaries of the specific public comments under this comment:

Commenters argued that reliance on a state RPS REC tracking system as a basis for compliance 

with the Clean Power Plan is problematic because most states do not have a mandatory RPS and 

do not issue or use RECs. Commenters provided examples of numerous definitions and practices 

among the state RPSs that may contradict or be incompatible. For example, commenters

provided that some, but not all, state RPSs may allow non-zero emitting resources such as 

biomass and coal wastes to be used for compliance, may allow RECs to be banked for varying 

amounts of time, or may define RECs as including environmental attributes or not. Commenters

urged that the conflicting definitions and practices of jurisdictional RPSs that use state RPS 

RECs would lead to duplication or use of ineligible resources (e.g., if a state claimed credit for a 

REC that has already been accounted for in a separate state plan). 

Commenters recommended that EPA separate the CPP from state RPS programs by establishing 

a Renewable Energy Carbon Attribute (RECA) certificate or similar instrument that represents 

the CO2 reduction attribute of one megawatt-hour of electricity generated by a zero-emitting 

renewable resource. Commenters suggested that a RECA certificate could be created for each 

megawatt-hour of eligible renewable energy and granted to the renewable resource owner, who 

could then surrender the RECA certificate as part of the state's Clean Power Plan compliance or 

trade the RECA certificate to another entity for their compliance obligation. Commenters

recommended the state to provide documentation that it possesses and has retired an equivalent 

amount of RECA certificates. Commenters asserted that under this approach, there would be no 

possibility of duplicate counting. 
51

Commenters noted that if a RECA approach is adopted, an eligible renewable resource would 

receive a RECA certificate and could also receive a REC separately for state RPS compliance 

purposes. Commenters explained that the RECA certificate and the REC generated could be 

owned by separate entities and retired for separate purposes, or they could travel together under 

common ownership and be traded and retired together. Commenters further explained that 

retirement of the RECA certificate would determine which state may count the renewable energy 

in its state emission rate calculation. 

Commenters further recommended that EPA permit the interstate trade of RECA certificates 

with or without the associated energy and irrespective of electrical boundaries; commenters 

explained that this would not result in double-counting because a state may only count renewable 

energy in its state emissions calculation if it owns and retires the RECA certificate. Commenters

warned that if importation of renewable energy from out-of-state is prohibited, this would cause 

the unintended effect of inhibiting growth in the renewable energy industry.

Comment 6: Comments stating that the EPA should provide the infrastructure necessary to 

facilitate basic tracking of allowances for intrastate and interstate trading for any state that does 

not currently have a registry system, such as through a default, opt-in national trading program.

Response 6: States participating in a trading program must include in their state plan regulatory 

provisions that address the tracking of ERCs or emission allowances through the use of a joint 

tracking system, interoperable tracking systems, or an EPA-administered (or approved) tracking 

system, as described in section VIII.C.5.c of the preamble to the final rule. As described in 

subsection VIII.K.2, the EPA is exploring options for providing an EPA-administered tracking 

system and is conducting an initial scoping assessment of tracking system support needs and 

functionality. The final rule also includes specific requirements for tracking systems under ratebased emission trading approaches in section VIII.K.2 of the preamble to the final rule.

Regarding the proposal of a national registry, the EPA’s approach provides flexibility to the 

states on how to design their registries and therefore will not require states to submit to a national 

registry. To ensure the credibility of state registries for trading programs, the EPA provides 

recommended criteria in the draft EM&V guidance document.

The following are summaries of the specific public comments under this comment:

Several commenters recommended that EPA provide the infrastructure necessary to facilitate 

basic tracking of allowances for intrastate and interstate trading for any state that does not 

currently have a registry system, such as through a default, opt-in national trading program.

Commenters noted that EPA has established similar programs for other pollutants, such as under 

the Acid Rain Program and the NOx Budget program. Commenters recommended that EPA 

could provide a platform, support a third party to provide a platform, or work with states to build 

on existing platforms to alleviate the administrative and cost burden of developing a trading 

program for states. Commenters urged that EPA consider such standardized credit trading or 

agreements to minimize "perverse market incentives or disincentives" that may result from state 

programs with difference compliance requirements. Commenters stated that the national program 
52

should allow for the participation of states that are using either rate-based or mass-based 

compliance plans, and should provide the infrastructure for states to accomplish multi-state 

approaches, such as providing or approving credit-tracking systems for states that wish to 

implement trading programs or accept credits from other states for compliance. 

Commenters also recommended that the EPA could assist the states by establishing a standard 

for credits and trading that can be used for compliance purposes. Commenters stated that it 

would be appropriate to have trading systems for both emissions (pounds or tons of CO2) and 

energy (megawatt-hours) from renewables and demand-side savings for rate-based programs and 

trading systems for emissions (pounds or tons of CO2) for a mass-based program. Commenters

stated that the EPA or some other agreed upon entity could manage the trading systems, and an 

optional credit tracking system for emissions and energy could be provided for states.

Comment 7: Comments suggesting that the EPA encourage expansion/linking of current 

tracking systems and/or consider guidance for development of tracking mechanisms.

Response 7: As described in subsection VIII.K.2 of the preamble to the final rule, the EPA is 

exploring options for providing an EPA-administered tracking system and is conducting an 

initial scoping assessment of tracking system support needs and functionality. The final rule 

includes specific requirements for issuance, use and tracking of ERCs under rate-based emission 

trading approaches in section VIII.K.2 of the preamble to the final rule. The final rule further 

provides eligibility requirements for resources that can be used to adjust a CO2 emission rate in 

section VIII.K.1 of the preamble to the final rule.

The following are summaries of the specific public comments under this comment:

Commenters requested that EPA encourage the expansion of the existing framework for the 

tracking/crediting renewable energy to allow for further verification and quantification of 

emissions reductions from renewable energy. Commenters recommended that current REC 

tracking systems be linked to reduce the possibility for double counting; commenters asserted 

that the existing tracking systems were written by APX and linking the systems should be 

relatively straightforward. Commenters recommended the use of single-state and multi-state 

credit programs and other market-based systems, as well as the use of emission reductions that 

are secured outside of the power sector, provided the reductions are made by facilities tied to the 

grid. Commenters recommended that REC system operators collaborate to make a unified webbased tool available to stakeholders and EPA to verify the origin and trading history of a 

particular REC using the serial number. Commenters supported development of a regional 

trading system for the Southeastern states that will allow for tracking of renewable energy 

generated in the region for purposes of compliance with the Clean Power Plan. Commenters

asserted that this database could be used to track renewable energy that is generated in-state and 

used by load-serving entities in that state for compliance, as well as renewable energy generated 

out-of-state and transferred to a load-serving entity within the state. Commenters requested that 

the final rule should allow for both interstate and international trading, including the purchase of 

RECs from other nations such as Canada, which could be tracked using WREGIS, M-RETS, and 

NEPOOL GIS. Commenters also noted that power purchase agreements (PPAs) could be used 
53

for importing RE from Canada. Commenters supported the inclusion of RPS standards and 

climate programs into state plans as an option to allow states to import Canadian RECs. 

Commenters recommended guidance for development of tracking mechanisms. Commenters

suggested that EPA consider its January 2001 "Improving Air Quality through Economic 

Incentive Programs (EIP)" draft guidance to provide clarity to states regarding the creation of 

and tracking of EE and RE credits. Commenters argued that the EIPs contain elements to ensure 

their integrity; include adequate monitoring, record keeping, and reporting; recommend tracking 

mechanisms; and prevent double counting. Commenters noted that in some cases, the EIP 

principles would need to be amended or clarified to satisfy CPP requirements. 

Commenters requested that the EPA consider how non-ratepayer funded solutions to energy 

savings could be incorporated into EE trading mechanisms. Commenters stated that private 

sector actors have played a driving role in developing a market for residential solar energy 

installations. Commenters believed that the private sector could play a similar role in residential 

energy efficiency installations if appropriate incentives were provided. However, commenters 

stated that to realize the potential of the private market to contribute to the creation of residential 

energy efficiency savings, EPA must:

• Permit states to set up market mechanisms that allow private parties to develop 

and sell energy efficiency projects into such markets;

• Provide specific guidance to allow states to encourage private-sector undertaking 

or catalyzing the installation of residential energy efficiency measures;

• Provide details in 111(d) guidance on specifics of crediting and enforcement 

mechanisms and program implementation models that would be acceptable from 

an EPA perspective for purposes of meeting compliance requirements; and

• Support the creation of energy efficiency registries to ensure that the carbon 

dioxide emission reductions from energy efficiency measures is first registered 

and then retired (i.e. is not counted twice.) Presumably, such a registry will be 

necessary for the savings that result from ratepayer funded programs; we ask that 

the registry be designed to register and retire savings from all recognized sources, 

not only ratepayer-funded programs.

Comment 8: Comments suggesting the EPA should clarify how REC trading works between 

states.

Response 8: In the final rule, quantified and verified MWh impacts of qualifying zero-emitting 

and low-emitting resources tied to a state plan may be used by an affected EGU or state to adjust 

a CO2 emission rate, regardless of whether the renewable generation or demand-side EE savings 

occur inside or outside the state or territory. Consistent with the EPA’s calculation of the CO2

emission performance rates and state rate-based CO2 goals in the final emission guidelines, the 
54

MWhs impacts are added to the denominator of an affected EGU’s reported CO2 emission rate, 

resulting in a lower, adjusted CO2 emission rate.

Because of the separate accounting of MWhs and CO2 emissions, with emission impacts inherent 

in reported stack CO2 emissions and zero-emitting MWh impacts requiring explicit adjustments, 

the accounting method corresponds with the use of MWh-denominated Emission Rate Credits 

(ERCs) in the rate-based emission trading framework specified in this rule. 

An ERC is issued separately from any other instruments that may be issued for a MWh of energy

generation from a qualifying measure, such as a renewable energy certificate (REC). An ERC 

may be issued, however, based on the same data and verification requirements used by existing 

REC tracking systems for issuance of RECs that are used to meet state renewable portfolio 

standards. The EPA is aware of the potential for interactions between ERCs and RECs and 

encourages the states to consider, when developing their state plan, how existing instruments that 

are used to meet other regulatory requirements or in voluntary markets may interact with ERCs.

For more information about specific methods to adjust the CO2 emission rate of an affected EGU 

to reflect renewable energy generation and eligibility requirements for resources that can be used 

to adjust a CO2 emission rate, including eligibility dates and the types of RE MWhs that are 

eligible, see section VIII.K.1 of the preamble to the final rule. Requirements for rate-based 

emission trading programs and the issuance and tracking of ERCs, including qualifying

measures, programs or projects, and a discussion of addressing the potential for interactions 

between ERCs and RECs, are in section VIII.K.2 of the preamble to the final rule. Section 

VIII.K.3 of the preamble to the final rule describes the requirements and criteria related to proper 

quantification and verification of MWhs from renewable electricity generation.

The following are summaries of the specific public comments under this comment:

Commenters believed the rule should provide more specific details on how REC trading and 

crediting would work between states. Commenters stated that the proposed rule is unclear as to 

how EPA will credit RE generation. Commenters asserted the proposed rule only treats RE and 

EE by requiring the quantification of CO2 reductions, but does not clearly explain how RECs 

will be treated. Commenters urged that it is unclear whether a state can comply through longterm power purchase agreements of out-state-power or RECs. 

Several commenters stated that EPA should issue clear and certain crediting guidelines to reduce 

uncertainty, avoid double-counting, and avoid conflict between states regarding how renewable 

energy generation should be allocated. Commenters stated that EPA's approach should reinforce 

incentives for states to fully leverage their programmatic and regulatory tools (e.g., tax credits; 

codes and standards), and for utilities and their regulators to be willing to invest ratepayer dollars 

in RE measures and projects. Commenters specifically wanted to know which state would get 

credit for renewable generation, for instance, if a renewable generator in one state sells RECs out 

of state, or if RE is generated outside of a state but meets in-state purchase agreements. 

Commenters stated the proposal is uncertain as to whether EPA will only approve state plans that 

allow for the interstate transfer of renewable attributes, or whether states may develop plans that 

mandate that the environmental attributes of renewable generation within the state be used for 

that state's compliance. Commenters stated that it is unclear whether a developer that owns the 
55

RECs from a project located in the state has the ability to sell them outside of the state and 

whether or not the RECs would count solely for projects located within the state. Commenters 

questioned how renewable resources will be treated if those resources are used for RPS 

requirements in another state and if the RPS is part of the other State's compliance plan (State 

Plan). Commenters specifically asked about the case of a multi-state power company, and 

whether the power company which owns or purchases the renewable energy would be able to 

choose which state receives credit. Commenters specifically requested that EPA mandate that 

each SIP permit the use of RECs from out of state. Commenters expressed concerns that the 

proposed rule does not tell states to cooperate in the use, purchase, or sale of RECs, which may 

result in some states keeping all RECs generated in the state. Commenters specifically 

requested that EPA allow excess renewable generation or credits to be sold to utilities in other 

states. Commenters were also concerned that the uncertainties in the rule, as written, would 

subject retail electric providers to enforcement by the EPA and citizen lawsuits. 

Commenters made multiple recommendations regarding the accounting of and treatment of 

credits for renewable energy. Commenters noted that the state limits were based assuming the 

renewable energy generated in a particular state would get the full credit for that generation. If a 

state that receives the renewable energy gets to claim credit for it, Commenters believed they 

would also have to claim the CO2 from fossil fueled units designated to generate power for that 

state. Commenters also believed the simplest approach is for states to claim all of the renewable 

energy within their borders and the CO2 produced within their state regardless of the ownership 

of the energy. Commenters argued that allowing states to use renewable energy generated in 

other states for compliance could place significant compliance burdens on states that have 

historically been the source of renewable generation but are not large consumers of this 

generation; specifically, a generating state may not be able to benefit from renewable energy 

generation it incentivized. Commenters requested that EPA should provide guidance clarifying 

that unless a contract specifies that the environmental attributes of a REC follows the purchaser, 

the compliance credit under 111(d) stays with the generating state. 

Commenters suggested that credits be issued for all avoided carbon emissions resulting from 

state measures, regardless of where the avoided emissions occurred. Commenters noted that 

because the tradable credit system would be limited to affected EGUs, use of credits by these 

entities when complying with rate-based emission limits would apply the avoided carbon 

emissions to the state that was responsible for the measure. Commenters recommended that EPA 

consider renewable resources on a load served basis for credit rather than based on geography. 

Commenters referred to Washington State's Energy Independence Act (RCW 19.285), which 

allows utilities to purchase renewable resources or RECs from out of state to comply. 

Commenters reiterated that the decision should be based on REC ownership to avoid double 

counting between states wherever RECs and electricity are not in the same place. Commenters 

recommended that EPA provide states direction on determining REC ownership and that such 

ownership be tracked in REC accounting systems. 

Commenters argued that entities that own out of state RECs should get credit for those RECs in 

the states in which they are headquartered in order to ensure that the entity that invested in the 

RE asset receives the value of that asset. Commenters expressed doubt that multi-state 

compliance arrangements are a feasible means for utilities to receive credit for out of state RECs. 

Commenters asserted that allowing purchases of credits from out of state will broaden the market 
56

of renewable resources and encourage construction of new projects. Commenters wanted that 

limiting the transfer of renewable attributes within state boundaries would hold renewable 

generation captive within state lines and be disruptive to wholesale renewable markets and 

power producers. 

Commenters stated that the rule should require that compliance credit goes to the states where 

the purchasers of renewable energy generation or credits reside, whether the state plan is massbased or rate-based. Commenters stated that credit for RE should follow the renewable funding 

source (e.g., energy certificates (RECs) obtained from those resources and/or power purchase 

instruments that directly led to the development or continued operation of those resources.) 

Commenters stated that EPA should include a mechanism to insure that ratepayer investments 

accrue to their goals, similar to how RECs apply today. Commenters stated that for the small 

number of RE generation projects for which ownership of the environmental attributes are not 

apparent from the contract or REC, the EPA should clarify that the off-taker of the energy from 

such projects is entitled to claim credit for the emission reductions attributable to the project. 

Commenters urged that a state should be able to take credit for reductions provided that RECs 

are the required tracking mechanism and that RECs are not counted for multiple states' 111(d) 

compliance (e.g. in multiple state RPSs), under multiple state programs within a state plan, or by 

multiple compliance entities within a state. Commenters stated that EPA should strongly 

encourage states to use an environmental attribute accounting system when demonstrating that 

the zero-carbon attributes of that RE are dedicated to that state. Commenters stated that REC 

programs that allow a utility to allocate RECs to states should be used to determine which state 

gets credit for the renewable energy generation in its compliance calculation. Commenters also 

specified that any state wishing to use renewable energy MWhs to demonstrate compliance 

should establish an environmental attribute credit accounting system wherein the state where that 

credit is ultimately retired is the state able to count the credit towards demonstration of 

compliance. 

Several commenters also supported applying the credit only to the state where the REC is retired. 

Commenters reiterated that it is the consumption and not the generation of renewable electricity 

that qualifies for 111(d) compliance credit. Commenters asserted that RECs represent all the 

environmental attributes associated with the renewable generation and are the primary 

mechanism for state RPS compliance, and noted that several states are already dependent on outof-state renewables to meet their RPS. Commenters iterated that states would need to 

demonstrate to EPA sufficient REC retirement to satisfy the RPS or other measure included in 

the state plan. Commenters supported a requirement that states set up or participate in accounting 

systems or registries that will allowing for trading of renewable credits (similar to RECs) to 

prevent double-counting of credits. Commenters stated that EPA should retain the authority to 

find a state out of compliance if the state fails to procure the required number of allowances to 

cover their emissions. 

Commenters suggested that EPA may want to provide an accounting option for those states that 

decline to adopt a credit policy so that they can nonetheless use renewable power to comply with 

their target. Commenters stated that a state electing this option should be required to otherwise 

establish that the environmental attributes associated with the renewable power it uses to 

demonstrate compliance were not also used by another state. 
57

Commenters asked whether they would be able to receive credit for existing renewable sources 

to calculate their rate. Commenters also asked what options exist for net-metering customers and 

how energy savings (e.g., from rooftop solar) would be credited to the State Plan.

Comment 9: Comments regarding the use of trading systems other than RECs.

Response 9: In the final rule, to the extent qualifying RE generation measures are tied to a state 

plan, the quantified and verified MWh impacts of the measures may be used by an affected EGU 

or state to adjust a CO2 emission rate, regardless of whether the RE generation occurs inside or 

outside the state or territory. The final rule includes general eligibility requirements for 

resources, including RE resources which can be used to adjust the CO2 emission rate and specific 

methods to adjust the CO2 emission rate of an affected EGU to reflect RE, see section VIII.K.1

of the final rule preamble of the CPP. The final rule allows states to participate in interstate 

trading programs and specifies a unique acceptable unit of trading under a rate-based approach, 

the emission rate credit (ERC), a tradable compliance unit representing one MWh of electric 

generation (or reduced electricity use) with zero associated CO2 emissions. Requirements for 

rate-based emission trading programs, including those related to issuance or ERCs for RE 

generation and the tracking of ERCs, is described under section VIII.K.2 of the final rule 

preamble of the CPP. Section VIII.K.3 of the final rule preamble of the CPP describes the 

requirements and criteria related to proper ex post quantification and verification of MWhs from 

renewable electricity generation or demand-side EE savings

The following are summaries of the specific public comments under this comment:

Commenters expressed concern that the proposed rule provided little guidance about how states 

that do not include a REC trading system can account for renewable generation. Commenters 

provided as an example the use of power purchase agreements (PPAs) for out-of-state 

renewables to satisfy RPS requirements, which leads power producers that own generation in 

multiple states to use the environmental attributes of generation in one state to help meet RPS 

obligations in another state, as well policies such as feed-in tariffs, tax credits, and grants. 

Commenters asserted that without clear accounting rules from EPA, it could be impossible to 

distinguish between renewable energy generated in a state due to renewable energy measures 

implemented by another state, policy measures implemented by the state where generation is 

located, or non-policy market reasons. Commenters stated that the RECs associated with these 

types of power purchase agreements can vary and may lead to REC ownership uncertainty. 

Commenters suggested that for states choosing not to use a REC tracking system, EPA should 

establish a default rule that would only allow the state to include renewable energy MWhs in its 

compliance plan if it can demonstrate that an entity in that state has submitted credits for those 

MWhs. Commenters suggested a similar approach for voluntary REC purchases in rate-based 

state plans. Commenters argued that if federal and/or state agencies allow a state to take claiming 

rights away from a voluntary REC consumer, then the voluntary REC owner would have had its 

property rights taken without compensation. Commenters disagreed with this approach, arguing 

that this system would fundamentally disrupt the demand and financing for renewable energy 

projects. For voluntary REC purchases, commenters requested that EPA provide guidance 
58

similar to California's AB 32 cap and trade program, which retires emission allowances 

equivalent to the avoided emissions associated with voluntary REC purchases.

Comment 10: Comments expressing concerns regarding double-counting, conflicts between 

state approaches.

Response 10: The EPA agrees with commenters that it is important to minimize the risk of 

double-counting of emission impacts of measures, particularly across state plans, and has 

incorporated elements into the rule that seek to minimize it.

For example, states have the option to adopt multi-state plans, for either rate-based or massbased plans, that reflect regional interactions. These plans engage multiple states in the same 

system for purposes of tracking mass-based allowances or issuing and trading unique rate-based 

Emission Rate Credits (ERCs) as described below. 

Mass-based plans rely exclusively upon reported stack emissions for determining whether a 

mass-based CO2 emission goal is achieved and avoids concerns about counting the same mass 

reductions in two different mass-based states.

For rate-based plan compliance, the final rule specifies a general accounting approach that 

inherently acts to minimize state rate differences that may influence distortionary investments 

and ensures that quantified and verified MWh impacts of qualifying zero-emitting and lowemitting resources are applied consistently across all affected EGUs. The EPA revised the 

methodology used to calculate CO2 emission performance rates and state rate-based CO2 goals 

from the one used in the proposal to better reflect the regional nature of the grid among other 

things. Consistent with the calculation of CO2 performance rates and state rate-based CO2 goals 

in the final emission guidelines quantified and verified MWh impacts of qualifying zero-emitting 

and low-emitting resources tied to a state plan may be used by an affected EGU or state to adjust 

a CO2 emission rate, regardless of whether the renewable generation or demand-side EE savings 

occur inside or outside the state or territory. Double-counting of CO2 emission reductions is 

prevented, however, because the reported emissions from each unit are represented in the 

numerator of each of those unit’s emission rates and the method disallows any adjustment to any 

EGU’s reported emissions. The EPA will work with states using the rate-based approach that are 

interested in allowing the use of RE from outside the U.S. to adjust CO2 emission rates and 

documents the necessary conditions in Section VIII.K.1.a.(2)(c).

Because of the separate accounting of MWhs and CO2 emissions, with emission impacts inherent 

in reported stack CO2 emissions and zero-emitting MWh impacts requiring explicit adjustments, 

the accounting method corresponds with the use of MWh-denominated ERCs in the rate-based 

emission trading framework specified in this rule. This MWh accounting method creates a 

crediting system or rate adjustment process that is simpler to implement than one that requires an 

approximation of avoided CO2 emissions and indifferent to the rate-based CO2 emission goals of 

individual states, or the specific CO2 emission rate standards that states may apply, and the 

relative stringency of those goals or standards. 
59

An ERC is issued separately from any other instruments that may be issued for a MWh of energy 

generation or energy savings from a qualifying measure, such as a renewable energy certificate 

(REC). An ERC may be issued, however, based on the same data and verification requirements 

used by existing REC tracking systems for issuance of RECs that are used to meet state 

renewable portfolio standards. The EPA is aware of the potential for interactions between ERCs 

and RECs and encourages the states to consider, when developing their state plan, how existing 

instruments that are used to meet other regulatory requirements or in voluntary markets may 

interact with ERCs.

The EPA acknowledges in the final rule that there may be interactions between mass-based and 

rate-based plans regarding counting measures, specifically where measures that provide 

substitute or avoided generation, such as RE and demand-side EE, are located in a mass-based 

state and can also be used by a rate-based state in meeting the CO2 performance rates or state 

goals. The EPA has determined that, in the context of interactions among rate-based and massbased plans, there is not explicit double-counting of the CO2 emission reductions associated with 

counting measures located in mass-based states, considering the accounting methods outlined in 

this final rule. Though there is no risk of double-counting emissions, in response to commenter 

concern that overall CO2 emissions reductions would be foregone in situations where a source in 

a rate-based state counts the MWh from measures in a mass-based state, but the generation from 

that measure acts solely to serve load in the mass-based state, the EPA is restricting the ability of 

rate-based state to claim emission reduction measures, such as RE and demand-side EE, located 

in mass-based states. In order to avoid cutting some states off from regional RE supplies that are 

assumed in the BSER building block 3 and incorporated in the CO2 emission performance rates 

or state rate-based CO2 goals in the emission guidelines, the EPA has determined that it is 

appropriate for rate-based states to count MWhs from RE located in mass-based states, subject to 

the condition that the generation in question was intended to meet electricity load in a state with 

a rate-based plan. 

For a discussion about the elements incorporated into the final rule to minimize double-counting, 

see section VIII.L of the final rule preamble of the CPP. For more information about specific 

methods to adjust the CO2 emission rate of an affected EGU to reflect demand-side EE and 

renewable energy, including eligibility dates and the types of EE savings and RE MWhs that are 

eligible, see Section VIII.K.1 of the final rule preamble of the CPP. Requirements for rate-based 

emission trading programs and the issuance and tracking of ERCs, including qualifying 

measures, programs or projects, addressing the potential for interactions between ERCs and 

RECs or EECs, are addressed in section VIII.K.2 of the final rule preamble of the CPP. Section 

VIII.K.3 of the final rule preamble of the CPP describes the requirements and criteria related to 

proper ex post quantification and verification of MWhs from renewable electricity generation or 

demand-side EE savings to avoid overestimation as suggested by commenters. For information 

about mass-based emission standards with a market-based emission budget trading program, see 

section VIII.C.2 and VIII.J.2 of the final rule preamble of the CPP. 

The following are summaries of the specific public comments under this comment:

Several commenters expressed concern that the proposed rule presents potential for doublecounting of emission reductions resulting in undermining the rule. Commenters stated that 

compliance and voluntary markets can only ensure environmental and contractual integrity if 
60

there is a single end-user or claimant for each specific REC and the emissions and environmental 

attributes it represents. Commenters added if there is explicit or implicit duplicate ownership 

claims to a REC for compliance or voluntary purposes the REC is double counted and 

environmental and contractual integrity is compromised, and its value is lost. Commenters stated 

that double counting erodes the renewable energy market by eliminating the value of the REC, 

thereby turning customers away and eliminating a revenue stream for renewable generators; no 

one wants--or is willing--to pay for something they do not get. Commenters requested EPA to 

explain how its position that RECs would be a potential mechanism for tracking energy savings 

and emission reductions from RE would prevent double-counting. Commenters stated that if 

EPA finalizes the proposal based on a state's generation, the use of RECs will increase the 

chance for double counting of emission reductions. Commenters stated that RECs provide a 

means for renewable portfolio standards established by the states to be used as enforceable 

mechanisms as part of compliance plans. Commenters recommended that EPA set the renewable 

energy goal portion of the BSER based on retail sales of electricity, stating that this would 

reduce any potential for states to double count emission reductions. 

Commenters also noted that "EPA should adopt measures that address the proper accounting for 

all imports and exports of electricity, not merely the special cases of imports and exports 

associated with renewable energy and energy efficiency. The potential for double-counting exists 

for all such transactions." 

Commenters expressed concerns regarding double-counting that could arise in regional trading 

agreements that include both rate-based and mass-based approaches. Commenters expressed that 

since state rates and masses under the Proposed Rule include only in-state generation from 

affected EGUs, imported and exported generation as well as renewable energy generation are not 

reflected in state rates; as such, Commenters asserted that while state masses will automatically 

reflect the emissions impact of imported generation and renewable energy generation (both instate and imported), rate-based states could need to make manual adjustments for reductions 

from RE (e.g., claims for out-of-state reductions from RPS programs) that would result in 

double-counting. Commenters also argued that trading of RE between states using the same 

reporting method (i.e. rate-to-rate or mass-to-mass trading of RE or RECs) could result in double 

counting of avoided emissions between the Clean Power Plan and state compliance markets for 

RE (RPS programs) and/or the voluntary RE market wherever RECs (which convey avoided 

emissions as the compliance mechanism used in state RPSs and also as the currency for the 

voluntary market) and displaced generation (that is counted as avoided emissions under 111(d)) 

are not in the same state. 

Commenters stated that EPA should provide guidance regarding the requirements for RECs and 

adjustments to rates and masses to avoid double counting. Commenters recommended that EPA 

provide the states with a template or checklist containing all the required components for plans 

that rely on interstate trading to comply with the rates. Commenters asserted that states using 

rate-based systems must be required to track RE megawatt-hours (MWh) to avoid emissions 

from a single RE MWh being applied under multiple state mechanisms/programs. Commenters

asserted that adjustments to rates caused by renewable energy must be limited to renewable 

energy generation that has avoided emissions at affected EGUs, that has not been double 

counted, and that was included in the state plan.
61

Several commenters supported the use of RECs, with standards for state verification set by the 

EPA, to avoid double-counting. Commenters argued that RECs are the best way to track and 

account for RE and therefore are the best way to avoid double-counting. Commenters stated that 

EPA should provide that no adjustments be made to rates for renewable energy without RECs 

and for renewable energy not included in a state plan. Commenters argued that the RECs 

presented to the state for compliance should be either associated with the interconnect region 

(Eastern, Western or ERCOT) served by the utility, or should include documentation that ensures 

that the RECs are properly associated with power transferred from one interconnect to the other. 

Commenters asked that EPA clarify that it will require an upward adjustment to masses for 

renewables without RECs (e.g., power that is imported without the RECs and in-state renewable 

generation where RECs are sold out of state) and for renewable energy not included in a state 

plan, unless the state can demonstrate that the renewable energy is not affecting the mass. 

Commenters stated that the zero-carbon generation underlying a REC may vary in the extent to 

which it results in actual aggregate emissions reductions. Commenters explained that the EPA 

cannot simply rely on RECs as a surrogate for those reductions. Commenters also proposed that 

all RECs used for compliance be valued based upon the carbon emissions they avoid.

Commenters noted that there may not be a need for evaluation, monitoring and verification 

(EM&V) and tracking of every MWh of RE or EE savings included in a mass-based plan to 

prevent double counting, while commenters asked that EPA clarify that adjustments will still be 

necessary under a mass-based approach to address interstate effects. Commenters urged that 

EPA must also require mass-based multi-state regions to make similar adjustments as massbased states. Commenters provided as an example an instance where RGGI states may submit a 

multi-state, mass-based plan, and noted there is trading of electricity between RGGI and 

surrounding non-RGGI states, which could result in double counting unless the RGGI states 

adjust their mass. 

Commenters questioned the proposed suggestion that a mass-based state could adjust the overall 

CO2 emissions to account for the "export" of avoided CO2 emission credits. Commenters argued 

that RE and EE benefits are automatically accounted for under a mass-based program, which 

rends it impossible to unravel the location and type of fossil fuel-fired generation the specific 

unit of RE or EE has displaced. Commenters noted that any adjustment to overall CO2 emissions 

from a mass-based state's fleet would be derived from an arbitrary assumption because the state 

could not artificially subtract the RE or EE benefit from its compliance demonstration. To 

address this issue, commenters recommended that EPA prohibit rate-based states from taking 

credit for renewable generation that is already accounted for under the cap of a mass-based state, 

or develop an alternative approach that addresses the issue. 

Commenters stated that whether a state adopts a mass-based or rate-based program should not 

make a difference as long as the associated REC is retired appropriately, with the use of REC 

tracking systems. Commenters recommended that for states utilizing a mass-based approach, 

EPA should require the state to monitor its net energy imports over the compliance period of the 

proposed rule. Commenters noted that if a state realizes a significant increase in net imports 

relative to its consumption, then EPA could require an analysis of the cause of the imports to 

ensure that the state is not implicitly crediting RE and/or EE measures adopted by another state. 

Commenters reiterated that a state should also require utilities to provide evidence, and evaluate 
62

outside evidence, to reasonably estimate the amount of actual power from renewable energy 

resources that was actually delivered to the utility system and used. 

Commenters argued that rate-based systems could create the potential for "seams conflicts" with 

mass-based systems; specifically, commenters argued that states within a single RTO using these 

different systems could meet their emissions goals by shifting generation from the mass-based 

state to the rate-based state, instead of reducing emissions. Commenters provided as an example 

that coal plants in a rate-based system that rely on heat-rate improvements could be dispatched 

before (rather than after) lower emitting natural gas units in a mass-based system, because the 

production incentives in the rate-based state enable those units to lower their dispatch bids. 

Commenters stated EPA's final rule - or, at a minimum, formal guidance to states - should 

include rules governing how states may account for interstate trades of zero-carbon credits and 

allowances to avoid double-counting. Commenters provided a set of rules that EPA could 

include in the final rules to ensure that mass- and rate-based states alike can use trading to 

respond more nimbly to evolving market conditions, and can harness RPS and CO2 allowance 

programs to this end: (1) when a CO2 allowance is sold from a mass-based state, the pool of 

available allowances in that state is reduced, and generators in that state thus must reduce their 

emissions by one ton: the buyer state may deduct one ton of carbon from the numerator of its 

compliance function (if it has a rate-based system) or may emit one more ton of carbon (if it has 

a mass-based system); (2) when a zero-carbon credit is sold from a rate-based state, that state 

may not take credit for the underlying zero-carbon generation, so as to avoid double-counting: 

the buyer state may deduct 0.5 ton of carbon from the numerator of its compliance function (if it 

has a rate-based system) or may emit another 0.5 ton of carbon (if it has a mass-based system); 

(3) zero-carbon credits issued in mass-based states that use CO2 allowances may not be used for 

compliance in any other state: using these credits for compliance outside their state of origin 

would necessarily result in double-counting of the emissions-reduction benefit, for the 

underlying zero-carbon generation would automatically "count" towards that state's mass-based 

emissions goal simply by not emitting carbon and not requiring the purchase of allowances; (4) 

when a zero-carbon credit is sold from a mass-based state that does not use allowances, that state 

must reduce its emissions budget by 0.5 ton, so as to avoid double-counting: the buyer state may 

deduct 0.5 ton of carbon from the numerator of its compliance function (if it has a rate-based 

system) or may emit another 0.5 ton of carbon (if it has a mass-based system). Commenters also 

provided 8 accounting rules designed to count each emission reduction once and only once: 1) 

when a mass-based state sells a CO2 allowance, the selling state's generators must reduce their 

emissions by one ton; 2) when a mass-based state buys a CO2 allowance, the buying state's 

generators may emit one more ton of carbon; 3) when a rate-based state buys a CO2 allowance, 

the buying state may deduct one ton of carbon from the numerator of its compliance calculation; 

4) when a rate-based state sells a REC, the selling state may not take credit for the REC or the 

underlying zero-carbon generation; 5) when a mass-based state that does not use allowances sells

a REC, the selling state must reduce its emissions budget by 0.5 tons (assuming that the mass 

value of a REC is 0.5 tons of CO2); 6) a mass-based state that uses allowances may not sell a 

REC to be used for Clean Power Plan compliance in another state; 7) When a rate-based state 

buys a REC, it may deduct 0.5 tons of carbon from the numerator of its compliance calculation 

(assuming that the mass value of a REC is 0.5 tons of CO2 ); and 8) when a mass-based state 

buys a REC, its generators may emit another 0.5 tons of carbon (assuming that the mass value of 

a REC is 0.5 tons of CO2 ). 
63

Commenters suggested that EPA provide clear and effective guidance regarding double-counting 

and how EPA will address complications that arise due to differences between state programs, 

regardless of the approach chosen to address interstate effects. Commenters requested that EPA 

address how to handle when one state implements an RE program through an RPS, but the actual 

reduction of emissions occurs in another state. Commenters stated that the proposal appears to 

presuppose that states will either agree on how to proportion credit for RE reductions or that RE 

emission reductions for compliance will not be used where states cannot agree on distribution 

and the reduction may be double-counted. Commenters stated that this approach could increase 

compliance costs by rendering certain reductions unusable. Commenters inquired what 

requirements EPA would include to discourage double-counting and whether the requirements 

would interfere with existing markets or contracts.

Commenters differentiated between duplication and double-counting. Commenters stated that if 

both states include the same generation (individual MWh) and resulting reductions in their state 

plans, then this is duplicative, but if both states report the same reductions in their emissions 

performance, then that is double counting. Commenters encouraged EPA to differentiate 

between double-counting and double-claiming. Commenters defined double claiming as an 

instance when two or more states (or entities within a state) take credit for having been 

responsible for a single RE/EE investment (e.g., a state or entity that compels an RE investment 

in another state could claim the investment, while the state where the renewable energy is built 

will try to claim responsibility for the same action). In contrast, commenters cited double 

counting as occurring when the marginal emissions reductions reduced on the power grid (as 

estimated by dispatch modeling or AVERT) indicate that the emissions reduced as a result of the 

RE/EE investment occur outside the state that credits the RE generation towards its compliance 

goal. Commenters argued that EPA's proposed treatment of RE addresses double claiming but 

not double counting, making it highly likely that more than one state will take credit for 

emissions reduced. Commenters further argued that EPA's proposed treatment of EE addresses 

only double counting, and does not acknowledge the potential for double claiming that can 

happen within a state. Commenters stated that EPA should adequately address double-claiming 

through default rules and guidance: in the case of renewable energy, commenters recommended 

the state (or entity) that purchases the RE and/or the RE attribute should be able to take credit for 

the resulting emissions reductions. Commenters also recommended that in the case of EE, the 

credit be granted to the utility or to a government entity that offers incentives for the EE 

investment, or if there are no incentives, the private sector investor could keep the credit. 

Commenters further noted that double-claiming could be accounted for through the use of rules 

and tracking systems. Commenters urged that a federal rule could clarify that the state that 

compels an RE investment in another state should get credit for it (and not the state where the 

clean energy is built, if different), or the rules could be applied at the state level to allocate EE 

emissions reductions between a utility energy efficiency program and an ESCO. Alternatively, 

commenters suggested that a tracking system such as MRETS could ensure that credits are only 

claimed once.

To avoid double-counting, commenters recommended that RE and EE in a jurisdiction without 

any affected EGUs (where those measures have not otherwise been accounted for) should be able 

to be credited to another state (e.g., through a multi-state plan or agreement). Commenters also 

suggested prohibiting rate-based states from taking credit for RE or EE that is already accounted 

for under a mass-based program in another state or multi-state group. 
64

Commenters stated that EPA should attempt to prevent double counting of renewable energy 

before it occurs by cross-referencing state plans to check for double-counting and duplicative 

standards, and accounting for expected interstate impacts of RE when reviewing and approving 

plans. Commenters noted that EPA can jointly assess state plans and use regional modeling to 

identify potential double-counting. Commenters also pointed out that double counting between 

states due to rate- and mass-based compliance interstate effects could be avoided by using RECs 

in combination with EPA's cross-reference of state plans. Commenters recommended that EPA 

could avoid double-counting by providing guidance on EM&V methodologies that would be 

acceptable for states to demonstrate and take credit for emissions reductions achieved by EE and 

RE programs. 

Commenters suggested that EPA consider a multi-state modeling approach to avoid doublecounting, which would seek to recognize emissions reductions expected from EE/RE 

investments across all region, allowing all such investments to count towards compliance. 

Commenters described the approach as follows: states in a region would model all of planned 

EE/RE investments together, and determine the resulting marginal emissions reductions in each 

state; each state would then assign an emissions reduction value for each kWh of clean energy 

investment assumed in the state. Commenters noted that to demonstrate compliance, each kWh 

of EE/RE would earn emissions reductions at the in-state rate. Commenters asserted that 

although states would need to collaborate on modeling, they would not need to rely on each other 

for compliance. Additionally, Commenters asserted that this approach would capture all the 

emissions reductions from planned activities in the region that occur in each state, offering more 

credit than what would occur only through in-state investments. 

Commenters did not consider there to be significant double-counting concerns. Commenters 

noted that although the generating units displaced by RE generation may not always be in the 

same state that implements the RE measure or where the RE is physically located, the 

displacement results in a reduction of mass emission, but not a reduction of the unit's emission 

rate. Commenters asserted that unless the displaced unit also takes credit for the RE generation, 

the reduced dispatch does not help the unit meet its emission rate target. Commenters did not 

consider displaced generation and the generation of RECs to be double-counting. Commenters 

also acknowledged that there may be modest effects on the overall emission rate on the state 

level due to the displacement, but pointed out that the proposed approach to exclude peaking 

plants from the BSER rate would mean that displacement of peaking turbines would not change 

the state's emission rate; commenters disagreed with this exclusion. Commenters further noted 

that as long as all states involved in an exchange use rate-based plans, or all states within the 

same ISO or RTO adopted a mass-based system, there would be no double-counting concerns 

provided EPA adopts annual "true-up" procedures. Commenters noted that for certain states 

without their own emission reduction targets, double-counting is not a concern. Commenters 

argued that it is not necessary to ensure against double-counting of out-of-state RE, due to the 

presence of regional tracking systems already in place which would account for the RE produced 

to support compliance with state goals.

Some commenters Commenters (22768, 23450) asserted that EPA's Proposed Guidelines would 

impose unfair or unequal obligations or engender conflict among the states. One commenter 

Commenters (22768) argued that EPA has proposed conflicting approaches to crediting RE and 

EE reductions and for the treatment of individual state vs. multi-state plans. The commenter 
65

Commenters (22768) provided as an example the difference between the proposed approach for 

states to take into account all RE measures implemented for purposes of compliance with a RPS 

(regardless of whether the RE is generated in-state or out-of-state) and the proposed approach to 

limit credit for EE-related emission reductions to in-state activities only. The commenter 

Commenters (22768) argued that the proposed rules are overly simplistic and, as proposed, 

would create serious problems for states. Another commenter (23450) expressed concerns that 

states may have significantly different proposed carbon intensity goals and other unique 

characteristics, which would impose unworkable interstate compliance demonstration and 

recordkeeping obligations on utilities.; the commenter Commenters specifically noted that 

utilities with regional territory or ownership crossing the state lines of New Mexico, Texas, and 

Arizona could result in impossible compliance demonstration.

Commenters expressed concern that any trading system must be designed to ensure double 

counting is avoided, and that adequate safe guards are in place to verify that purchased RECs do 

ultimately displace fossil fuel-fired emissions in the United States. Commenters noted that if 

participation is expanded across national borders such that the EPA allows use of RECs 

generated outside of the United States for compliance, then the EPA should require such 

agreements be tied to delivery of the associated electricity into the United States for 

displacement of domestic fossil fuel-fired generation.

Comment 11: Comments requesting clarification on how to address unbundled RECs.

Response 11: In the final rule, quantified and verified MWh impacts of qualifying zero-emitting 

and low-emitting resources tied to a state plan may be used by an affected EGU or state to adjust 

a CO2 emission rate, regardless of whether the renewable generation or demand-side EE savings 

occur inside or outside the state or territory. Consistent with the EPA’s calculation of the CO2

emission performance rates and state rate-based CO2 goals in the final emission guidelines, the 

MWhs impacts are added to the denominator of an affected EGU’s reported CO2 emission rate, 

resulting in a lower, adjusted CO2 emission rate.

Because of the separate accounting of MWhs and CO2 emissions, with emission impacts inherent 

in reported stack CO2 emissions and zero-emitting MWh impacts requiring explicit adjustments, 

the accounting method corresponds with the use of unique MWh-denominated Emission Rate 

Credits (ERCs) in the rate-based emission trading framework specified in this rule. 

An ERC is issued separately from any other instruments that may be issued for a MWh of energy 

generation from a qualifying measure, such as a renewable energy certificate (REC), whether 

bundled or unbundled. An ERC may be issued, however, based on the same data and verification 

requirements used by existing REC tracking systems for issuance of RECs that are used to meet 

state renewable portfolio standards. The EPA is aware of the potential for interactions between 

ERCs and RECs and encourages the states to consider, when developing their state plan, how 

existing instruments that are used to meet other regulatory requirements or in voluntary markets 

may interact with ERCs.

For more information about specific methods to adjust the CO2 emission rate of an affected EGU 

to reflect renewable energy generation and eligibility requirements for resources that can be used 
66

to adjust a CO2 emission rate, including eligibility dates and the types of RE MWhs that are 

eligible, see Section VIII.K.1 of the final rule preamble of the CPP. Requirements for rate-based 

emission trading programs and the issuance and tracking of ERCs, including qualifying 

measures, programs or projects, and a discussion of addressing the potential for interactions 

between ERCs and RECs, are in section VIII.K.2 of the final rule preamble of the CPP. Section 

VIII.K.3 of the final rule preamble of the CPP describes the requirements and criteria related to 

proper quantification and verification of MWhs from renewable electricity generation. For 

additional information regarding how the final rule explicitly addresses double-counting

concerns through the MWh accounting approach and the allowance of multi-state plans, see 

section VIII.L of the final rule preamble of the CPP.

The following are summaries of the specific public comments under this comment:

Commenters stated that the proposal fails to adequately consider unbundled RECs. Commenters 

urged that because the proposal does not distinguish between unbundled RECs and the typically 

bundled RECs, significant double-counting issues could occur. Commenters noted that the 

existing REC trading system allows for RECs to be sold separately from the underlying MWh of 

renewable energy generated ("unbundled"), resulting in remaining MWh of "null power" that 

may be consumed by customers on the grid in the form of more carbon-intensive energy sources. 

Commenters also noted that unbundled RECs may be generated when the utility to which the 

resource is interconnected has elected not to purchase the REC; specifically, they noted that the 

Public Utilities Regulatory Policy Act ("PURPA") requires utilities to purchase the output from 

small renewable energy generators, called qualifying facilities ("QFs"), but that the Federal 

Energy Regulatory Commission allows that a sale of this nature does not necessarily encompass 

RECs. Therefore, commenters asserted that RECs generated by a QF do not always transfer to 

the utility even though the utility purchases the power, which could create a possible doublecounting situation if the interconnected utility tries to take credit for the null power. Commenters

also noted that many net metering customers are not required to transfer the RECs generated by 

their systems to the utility. Commenters stated that compliance would be complicated based on 

the ownership of unbundled RECs by entities such as independent power productions that are not 

regulated by state utility commissions. Commenters noted that the proposed rule is unclear on its 

intent regarding the treatment of these renewable energy attributes and is ambiguous on how 

states may count the bundled or unbundled RECs for compliance. Commenters reiterated that an 

implementing state or entity should be able to claim the environmental attributes of purchased 

renewable electricity from out-of-state generation, regardless of where it occurs, in its state 

compliance plan. Commenters requested that EPA provide clarification on which state retains the 

ability to claim emission reductions attributable to RE and RECs on a bundled or unbundled 

basis and how states should avoid double counting in instances in which one state claims credit 

for emissions reductions caused by renewable generation and another state that holds the 

environmental attributes of the same energy also claims credit. 

Commenters requested that EPA limit double-counting by ensuring that the carbon-free 

attributes and the energy itself are not separated (i.e., EPA should only allow bundled RECs).

Commenters argued that a bundled REC follows the proposed idea that limits credit of RE to 

states that actually consume the electricity. Commenters recommended that EPA not allow 

stand-alone (decoupled) Renewable Energy Certificates (REC's) to fulfill the proposed state 

goals, but instead evaluate the energy that is actually delivered to the utility or state claiming 
67

credit for those emissions reductions. Commenters argued that allowing REC's that are not 

combined with actual energy delivery would allow already over-performing states to monetize 

already existing or planned renewable energy generation with limited additional reductions in 

carbon dioxide emissions. Commenters asserted that companies that are already purchasing RE 

from out-of-region and receiving the RECs associated should be credited for those purchases. 

Commenters requested that where RECs and electricity are bundled, the contract for purchase of 

the RECs should accompany the purchase of the electricity to ensure that multiple parties are not 

using the same MWh of renewable energy generation to comply with their RPS obligations. 

Commenters recommended that EPA specify that PPAs, where RECs are tied to electricity 

consumed, should be included as a compliance option for Section 111(d) state compliance plans.

Commenters also requested that EPA 1) clarify that a generating state is not permitted to avoid 

emissions if the RECs are sold to another state, separate from null power, for RE generating 

capacity, and 2) assign an attribute profile for null power (i.e., an average or marginal grid 

emission value minus the renewable attributes for the purpose of calculating emissions from this 

null power). Commenters cautioned against using RECs as a form of emission offsets for which 

they were never intended. 

Commenters argued that EPA should not constrain states as to whether credits are bundled with 

electric power or not, but should leave the option to the market and individual states. 

Commenters contended that such decisions should be left to the market and individual state 

policies and that states should allow private actors to freely contract for environmental attribute 

credits associated with renewable power separate from the power itself, letting the market 

determine the best use of the attribute. Commenters also requested that EPA not disaggregate 

avoided emissions from RECs for 111(d) compliance. Commenters stated that disaggregating 

avoided emissions would 1) not avoid the need for tracking such emissions, 2) disrupt RPSs if 

the RPS could not claim the full benefit of the avoided emissions, 3) limit the use of RPSs for 

111(d) where the RPS currently allows unbundled RECs, and 4) increase the costs of compliance 

for states which would have to pay for avoided emissions that are currently separate from the 

REC. Commenters asserted that both RECs and the carbon reduction attributes of RE are distinct 

from the electricity and should be separately traded; Commenters stated that the REC should be 

able to be used to comply with a utility's RPS obligation as well as for purposes of compliance 

with CAA section 111(d). Commenters asserted that allowing unbundled GHG attributes is 

consistent with current state renewable programs which allow interstate movement of renewable 

or environmental attributes to meet supply and demand, and would allow states to develop their 

compliance strategy through a diverse mix of renewables that is not dependent on state-specific 

renewable resources. Commenters further argued that allowing unbundled environmental 

attributes would foster more efficient and robust GHG emission reductions and lead to lower 

costs, less regulatory burden, and greater technological innovation. 

Commenters argued that restrictions or prohibitions on imports and exports, including any 

requirement that those attributes be bundled with the electricity itself, would have unintended 

consequences for both individual states and states participating in multi-state arrangements, 

including artificial price signals and other barriers. Commenters asserted that any federal limits 

on the interstate flow of renewable attributes would skew in favor of a small subset of renewable 

technologies, decrease cost-effectiveness, and decrease flexibility to the states. Commenters 

requested that EPA encourage states to establish broad markets beyond geopolitical or NERC 
68

grid regions and work with ISOs to help align the various generation attribute tracking systems 

with each other and properly track RECs. 

Commenters noted that EPA should require the continued use of tracking systems for these 

environmental attributes, which are already used to support state RPS programs, for compliance 

purposes. Commenters argued against the creation of a new credit system for trading low-carbon 

attributes; Commenters urged that the RE and low carbon attributes significantly overlap, and a 

separate tracking system for each is unnecessary. Commenters reiterated that in markets where 

RECs and electricity are sold separately, the REC should only be retired once and used to satisfy 

one state's RPS compliance requirement. Commenters urged that if a state does not use a 

tracking system for environmental attributes, the state should only be allowed to include 

renewable energy MWhs in its compliance plan if it can demonstrate entities in the state have 

submitted environmental attribute credits for them. 

Comment 12: Comments regarding levels of credit.

Response 12: In the final rule, to the extent qualifying RE generation and demand-side energy 

efficiency measures are tied to a state plan, the quantified and verified MWh impacts of the 

measures may be used by an affected EGU or state to adjust a CO2 emission rate, regardless of 

whether the RE generation occurs inside or outside the state or territory. It is not necessary to 

determine the emission impacts of the MWhs as they will be reflected in the reported stack CO2

emissions of affected EGUs. The MWh accounting method addresses interstate effects, because 

it inherently accounts for how generation replacement and CO2 emission reduction impacts may 

cross state borders and is indifferent to avoided CO2 emission rates; it creates the same number 

of zero-emitting credits or adjustment for each MWh of energy generation or savings, wherever 

they occur. Details regarding the accounting approach for adjusting CO2 emission rate is 

included in Section VIII.K.1 of the final rule preamble of the CPP. A full discussion of treatment 

of interstate effects under the final guidelines is included in Section VIII.L of the final rule 

preamble of the CPP.

The following are summaries of the specific public comments under this comment:

Commenters suggested that different levels of credit should be awarded to RE and EE resource 

types based on each resource type's output profile and the region to which its generation is 

physically delivered, during both the plan approval and the compliance phase. Commenters 

stated that carbon emission reductions provided by RE and EE vary significantly depending on 

the time and location in which the resource is delivered. Commenters requested that the impact 

of location and time of production on emissions reductions should be accounted for, using either 

emissions calculation tools (such as AVERT) or standardized regional estimates. Commenters

further requested that in the process of retiring a REC in the compliance phase, states should be 

required to demonstrate the type and region of the resources that produced the REC.

Comment 13: Treatment of RECs for distributed generation.
69

Response 13: See section VIII.L of the final preamble to the CPP for the response to this 

comment. 

The following are summaries of the specific public comments under this comment:

Commenters asserted that the EPA must address cases where a load-serving utility treats 

distributed generation as a load-side resource and adjusts load forecasts to reflect anticipated 

growth in customer-sited generation. Commenters stated that if a utility adjusts load forecasts to 

reflect anticipated growth, it should not count the full capacity-based generation under Building 

Block 3, otherwise the generation would be double-counted.

Comment 14: Comments that the EPA should not impose restrictions on RECs/REC markets.

Response 14: In the final rule, the MWh accounting method corresponds with the use of 

Emission Rate Credits (ERCs) in the rate-based emission trading framework specified in this 

rule. The accounting method is consistent with the methodology used to calculate CO2 emission 

performance rates and state rate-based CO2 goals in the final rule, requires a quantification and 

verification of the MWh generated or avoided by an eligible measure, and thus Emission Rate 

Credits (ERCs) or adjustments are denominated in MWh.

An ERC is issued separately from any other instruments that may be issued for a MWh of energy 

generation or energy savings from a qualifying measure, such as a renewable energy certificate 

(REC) or an energy efficiency credit (EEC). An ERC may be issued based on the same data and 

verification requirements used by existing REC and EEC tracking systems for issuance of RECs 

and EECs that are used to meet state renewable portfolio standards or energy efficiency 

resources standards. The EPA is aware of the potential for interactions between ERCs and RECs 

or EECs and encourages but does not require the states to consider, when developing their state 

plan, how existing instruments that are used to meet other regulatory requirements or in 

voluntary markets may interact with ERCs and if they want to amend their policies in some way 

to reflect their priorities and circumstances.

The final rule also describes a wide variety of ERC providers or entities implementing EE/RE 

programs or projects that could potentially be issued ERCs provided that the measures meet the 

eligibility requirements described in Section VIII.K.1 of the final rule preamble of the CPP and 

the measurement and verification requirements in Section VIII.K.3 of the final rule preamble of 

the CPP. For more information about the requirements for ERC issuance related to rate-based 

emission trading approaches and ERC providers, see Section VIII.K.2 of the final rule preamble 

of the CPP.

For more information about specific methods to adjust the CO2 emission rate of an affected EGU 

to reflect demand-side EE and eligibility requirements for resources that can be used to adjust a 

CO2 emission rate, including eligibility dates and the types of EE savings and RE MWhs that are 

eligible, see Section VIII.K.1 of the final rule preamble of the CPP. Requirements for rate-based 

emission trading programs and the issuance and tracking of ERCs, including qualifying 

measures, programs or projects, addressing the potential for interactions between ERCs and 

RECs or EECs, are addressed in section VIII.K.2 of the final rule preamble of the CPP. Section 
70

VIII.K.3 of the final rule preamble of the CPP describes the requirements and criteria related to 

proper ex post quantification and verification of MWhs from renewable electricity generation or 

demand-side EE savings 

The following are summaries of the specific public comments under this comment:

Several commenters expressed that EPA should not impose restrictions on the form of credits or 

interrupt existing markets. Commenters noted that although some state RPSs require that 

electricity from qualifying renewable energy sources be produced or delivered within the state or 

a specified grid region, EPA should not impose these restrictions. Commenters also requested 

that EPA not dictate the form of the credit, but allow states to use renewable energy generated as 

part of a new or existing RPS program, as part of the voluntary renewable energy market, or as 

separate credits developed specifically as part of a state plan. Commenters described their vision 

of the accounting framework, stated that the environmental attributes would start with the RE 

generator for each unit of RE generated and then the environmental attributes could then be 

transferred using any instrument consistent with the law of the state where the generator was 

located. Commenters provided some examples of how instruments could be structured, including 

bundled with power in a bilateral contract; unbundled and sold separately from power; kept and 

retired by the owner of the renewable facility (such as if that owner were a utility or also owned 

EGUs); transferred or sold as part of a net metering agreement for distributed renewable 

generation. Commenters asserted that EPA should not dictate the form of acceptable 

environmental attribute credits. Commenters requested that EPA not promulgate any restrictions 

on the fungibility of allowances in regional credit markets (such as in RGGI), even if it means 

that the total allowances held by affected units with one state might exceed the individual state 

budget; Commenters asserted that EPA must apply an emissions cap to all of the states included 

in the plan. Commenters argued that a state plan that claims the credit for all in-state renewable 

energy generation would invalidate existing contracts that have already transferred all 

environmental attributes out-of-state, introducing significant uncertainty into the marketplace. 

Commenters requested that EPA should make clear that state plans do not alter current 

contractual agreements between renewable energy project developers and purchasers of power 

and/or environmental credits. Commenters urged that a final rule should encourage new markets 

and avoid disrupting current and expanding interstate markets, including the cross-border sale of 

renewable energy and attributes.

Commenters noted that in some cases, load-serving utilities do not receive RECs from customersited generation (e.g., rooftop solar panels). Commenters stated that depending on the states, 

RECs may be transferred to a utility without any additional payment, the REC may be 

transferred to the utility only if it has offered an incentive to the customer, or the REC may be 

retained by the customer. Commenters stated that in order to avoid double-counting, utilities or 

states may need to amend rules or laws to take possession of the RECs.

Comment 15: Comments suggesting that EPA provide options for cooperatives to sell credits 

for RE.
71

Response 15: In the final rule, the MWh accounting method corresponds with the use of 

Emission Rate Credits (ERCs) in the rate-based emission trading framework specified in this 

rule. The final rule includes requirements specific to rate-based emission trading programs that 

states must include in their plan to ensure the integrity of a rate-based approach that includes an 

emission trading program. These requirements include, among other things, provisions for 

issuance of ERCs by the state and/or its designated agent. The final rule also describes a wide 

variety of ERC providers or entities implementing EE/RE programs or projects that could 

potentially be issued ERCs provided that the measures meet the eligibility requirements 

described in section VIII.K.1 of the final rule preamble of the CPP and the measurement and 

verification requirements in section VIII.K.3. For more information about the requirements for 

ERC issuance related to rate-based emission trading approaches and ERC providers, see section 

VIII.K.2 of the final rule preamble. 

The following are summaries of the specific public comments under this comment:

Commenters suggested that the EPA develop a rule option that specifically lays out the 

opportunity for cooperatives to sell credits that would encourage cooperatives to transition to 

renewable energy sources. Commenters urged that cooperatives provide electric service to much 

of rural America.

Comment 16: Comments suggesting the final rule should assign RECs to IPPs to credit 

shutdown of EGUs.

Response 16: Consistent with the calculation of CO2 performance rates and state rate-based CO2

goals in the final emission guidelines, quantified and verified MWh impacts of qualifying zeroemitting and low-emitting resources that substitute for or avoid generation from an affected EGU 

and are tied to a state plan may be used by an affected EGU or state to adjust a CO2 emission 

rate. The accounting approach requires a quantification of the MWh generated or avoided by an 

eligible measure, and thus Emission Rate Credits (ERCs) or adjustments are denominated in 

MWh.

A rate based trading program would provide for the implementation and enforcement of rate 

based emission standards for a state plan that allows its affected EGUs to adjust a rate by the use 

of an ERC. For states that choose a rate-based emission trading program, the EPA is finalizing 

requirements specific to the program a state mus document including: provisions for issuance of 

ERCs by the state and/or its designated agent; provisions for tracking ERCs, from issuance 

through submission for compliance; and the administrative process for submission of ERCs by 

the owner or operator of an affected EGU to the state, in order to adjust its reported CO2

emission rate when demonstrating compliance with a rate-based emission standard. These 

requirements must be submitted for inclusion in the federally enforceable plan, per the statutory 

requirement that states provide for the implementation and enforcement of emission standards.

An ERC is issued separately from any other instruments that may be issued for a MWh of energy 

generation or energy savings from a qualifying measure, such as a renewable energy certificate 

(REC) or an energy efficiency credit (EEC). The EPA is aware of the potential for interactions 
72

between ERCs and RECs or EECs and encourages but does not require the states to consider, 

when developing their state plan, how existing instruments that are used to meet other regulatory 

requirements or in voluntary markets may interact with ERCs. 

If a state wants to include in their state plan the planned retirement of an individual affected 

EGU, the retirement could be codified in the state plan by adopting an emission standard of 0 

CO2 lb/MWh as of a certain date. The state would thus include in the state plan an emission 

standard of 0 CO2 lb/MWh for that affected EGU that applies after a specified date. The owners 

of the affected EGUs could apply for ERCs through the appropriate state ERC trading system.

For more information about specific methods to adjust the CO2 emission rate of an affected EGU 

to reflect demand-side EE and eligibility requirements for resources that can be used to adjust a 

CO2 emission rate, including eligibility dates and the types of EE savings and RE MWhs that are 

eligible, see Section VIII.K.1 of the final rule preamble of the CPP. Requirements for rate-based 

emission trading programs and the issuance and tracking of ERCs, including qualifying 

measures, programs or projects, addressing the potential for interactions between ERCs and 

RECs or EECs, are addressed in section VIII.K.2 of the final rule preamble of the CPP. Section 

VIII.K.3 of the final rule preamble of the CPP describes the requirements and criteria related to 

proper ex post quantification and verification of MWhs from renewable electricity generation or 

demand-side EE savings.

The following are summaries of the specific public comments under this comment:

Commenters stated that the final rule should account for a way for independent power producers 

(IPPs) to be issued a tradable REC for measures such as early shutdown of EGUs or agreements 

to dispatch an EGU under a state or EPA program. Commenters recommended that these credits, 

which are needed to meet the early reduction goals of the CPP, should be given directly to IPPs, 

dispatched stations, and regulated utilities. Commenters also requested that if an EGU 

voluntarily reduces emissions more than required to meet state goals, that EPA track such 

"overcompliance" to allow EE claims and RECs to be traded across states or to be utilized as 

adjustments to achieve compliance for other states.

Comment 17: Comments suggesting the proposal does not support market-based plans or capand-trade plans.

Response 17: EPA disagrees with the comments opposing the use of market-based plans. As 

discussed in Section VIII.C of the final rule preamble of the CPP, many commenters suggested 

that states should be encouraged to join or form market-based programs. Many commenters 

touted the economic efficiency benefits of such approaches, and noted that such programs have 

features that support electric reliability. The EPA agrees with these comments, and notes that it 

encouraged such approaches in the proposal. While the EPA is not requiring states to join and/or 

form regional market-based programs, we note that such programs can be helpful for many 

reasons, including features that support reliability. Market-based programs allow greater 

flexibility for affected EGUs both in the short-term and long-term. Under a market-based 

program, affected EGUs have the ability to obtain sufficient allowances or credits to cover their 
73

emissions in order to comply with their emission standards. Additionally, we continue to 

encourage states to cooperate regionally. Regional cooperation in planning and reliability 

assessments is an important tool to meeting system needs in the most cost-effective, efficient, 

and reliable way.

The final rule addresses the use of emission budget trading programs, including provisions 

required for such programs and the design of such programs in the context of a state plan. This 

includes program design approaches that ensure achievement of a state mass-based CO2 emission 

goal (or mass-based CO2 goal plus new source CO2 emission complement) (section VIII.J.2.b), 

as well as how states can use emission budget trading programs with broader source coverage 

and other flexibility features, like out-of-sector offsets and certain cost containment 

requirements, such as the programs currently implemented by California and the RGGI 

participating states (section VIII.J.2.c). Achievement of the state mass-based CO2 goal would be 

determined based solely on stack CO2 emissions from affected EGUs. Where a state program 

includes the ability of an affected emission source to use GHG offsets to meet a portion of its 

allowance compliance obligation, no “credit” is applied to reported CO2 emissions by the 

affected EGU. The use of offset allowances or credits in such programs merely allows an 

affected EGU to emit a ton of CO2 in the amount of submitted offset allowances or credits. In all 

cases, there is no adjustment applied to reported stack emissions of CO2 from an affected EGU 

when determining compliance with its emission limit.

Section VIII.J.2.d addresses other considerations for the design of emission budget trading 

programs that states may want to consider, such as allowance allocation approaches. Section 

VIII.J.3 addresses multi-state coordination among emission budget trading programs used in 

states that retain their individual state mass-based CO2 goals. The rule also includes in Section 

VIII.K.2 provisions required for states that choose to implement a market-based rate-based 

trading program to ensure the integrity of the program.

See section V.A of the final rule preamble of the CPP for EPA’s response to the comment's 

concern that trading programs increase emissions; 

The following are summaries of the specific public comments under this comment:

Commenters did not support the use of market-based trading programs, or cap and trade 

programs, to account for emissions reductions. Commenters argued that such an approach would 

not actually prohibit polluters from polluting, but would merely require them to purchase the 

right to pollute more by buying "credits". Commenters also asserted that such an approach would 

not actually reduce pollution, and that a cap-and-trade approach would not drive emission 

reduction, as it does not force large polluters to clean up their emissions. Commenters pointed to 

a comparison of EPA's Acid Rain Program with European Union and Japan regulatory 

"command and control" systems as an example of where trading has resulted in lower emissions 

reductions that would be acquired by strict regulation. 

Commenters further argued that the allowance of offsets is counterproductive to such plans. 

Commenters noted that although EPA denies the use of offsets in the proposed rule, it allows 

states to join existing market programs that may already allow for offsets. Commenters argued 

that by allowing states to join existing markets, these offsets would be introduced into an even 
74

larger market, including international markets, and therefore EPA would be unable to limit such 

offsets. 

Comment 18: Comments requesting the EPA establish credit trading systems for EE, similar to 

RECs.

Response 18: In the final rule, consistent with the calculation of CO2 performance rates and state 

rate-based CO2 goals in the final emission guidelines, quantified and verified MWh impacts of 

qualifying zero-emitting and low-emitting resources, tied to a state plan may be used by an 

affected EGU or state to adjust a CO2 emission rate, regardless of whether the renewable 

generation or demand-side EE savings occur inside or outside the state or territory. 

Because of the separate accounting of MWhs and CO2 emissions, with emission impacts inherent 

in reported stack CO2 emissions and zero-emitting MWh impacts requiring explicit adjustments, 

the accounting method corresponds with the use of MWh-denominated Emission Rate Credits 

(ERCs) in the rate-based emission trading framework specified in this rule. This MWh 

accounting method creates a crediting system or rate adjustment process that is indifferent to the 

rate-based CO2 emission goals of individual states, or the specific CO2 emission rate standards 

that states may apply, and the relative stringency of those goals or standards. 

An ERC represents one MWh of zero-emitting generation and is issued separately from any 

other instruments that may be issued for a MWh of energy generation or energy savings from a 

qualifying measure, such as a renewable energy certificate (REC). An ERC may be issued, 

however, based on the same data and verification requirements used by existing REC tracking 

systems for issuance of RECs that are used to meet state renewable portfolio standards. The EPA 

is aware of the potential for interactions between ERCs and RECs and encourages the states to 

consider, when developing their state plan, how existing instruments that are used to meet other 

regulatory requirements or in voluntary markets may interact with ERCs. When demonstrating 

compliance with a rate-based standard, an affected EGU would report its CO2 lb/MWh emission 

rate to the state regulatory body and would also surrender to the state any ERCs it wishes to use 

to adjust its reported emission rate.

The EPA received a number of comments from states and stakeholders about the value of the 

EPA’s support in developing and/or administering tracking systems to support state 

administration of rate-based emission trading systems. This could include regional systems 

and/or a national system. The EPA is exploring options for providing such support and is 

conducting an initial scoping assessment of tracking system support needs and functionality.

The EPA acknowledges in the final rule that there may be interactions between mass-based and 

rate-based plans regarding counting measures, specifically where measures that provide 

substitute or avoided generation, such as RE and demand-side EE, are located in a mass-based 

state and can also be used by a rate-based state in meeting the CO2 performance rates or state 

goals. The EPA has determined that, in the context of interactions among rate-based and massbased plans, there is not explicit double-counting of the CO2 emission reductions associated with 

counting measures located in mass-based states, considering the accounting methods outlined in 
75

this final rule. Though there is no risk of double-counting emissions, in response to commenter 

concern that overall CO2 emissions reductions would be foregone in situations where a source in 

a rate-based state counts the MWh from measures in a mass-based state, but the generation from 

that measure acts solely to serve load in the mass-based state, the EPA is restricting the ability of 

rate-based state to claim emission reduction measures, such as RE and demand-side EE, located 

in mass-based states. In order to avoid cutting some states off from regional RE supplies that are 

assumed in the BSER building block 3 and incorporated in the CO2 emission performance rates 

or state rate-based CO2 goals in the emission guidelines, the EPA has determined that it is 

appropriate for rate-based states to count MWhs from RE located in mass-based states, subject to 

the condition that the generation in question was intended to meet electricity load in a state with 

a rate-based plan. 

For a discussion about the elements incorporated into the final rule to minimize double-counting, 

see Section VIII.L. For more information about specific methods to adjust the CO2 emission rate 

of an affected EGU to reflect demand-side EE and renewable energy, including eligibility dates 

and the types of EE savings and RE MWhs that are eligible, see Section VIII.K.1. Requirements 

for rate-based emission trading programs and the issuance and tracking of ERCs, including 

qualifying measures, programs or projects, addressing the potential for interactions between 

ERCs and RECs or EECs, are addressed in section VIII.K.2. Section VIII.K.3 of the rule 

describes the requirements and criteria related to proper ex post quantification and verification of 

MWhs from renewable electricity generation or demand-side EE savings to avoid overestimation 

as suggested by commenters. For information about mass-based emission standards with a 

market-based emission budget trading program, see Section VIII.C.2 and VIII.J.2.

The following are summaries of the specific public comments under this comment:

Commenters stated they think the proposal also lack clarity regarding which entities and states 

would be able to use EE credits, whether interstate trading could be used to comply with the 

Clean Power Plan, and how out-of-state EE would be credited. Commenters disagreed with 

EPA's approach to EE that would credit only the share of the savings that are expected to reduce 

emissions at in-state EGUs. Commenters felt that the EPA's approach would result in EE being 

considered a less desirable compliance option. Commenters recommended that the EPA allow 

states to take credit for the full value of the energy efficiency investments with a state. 

Several commenters provided comments on accounting and tracking interstate emission 

reductions due to EE and avoiding double counting. Commenters referred to the option for states 

to take credit for emission reductions achieved out of state due to in-state EE, stated that this 

option would not result in double counting if it is combined with a clear accounting mechanism. 

Commenters stated that EPA should reinforce incentives for states to fully leverage their 

programmatic and regulatory tools (e.g., tax credits; codes and standards), and for utilities and 

their regulators to be willing to invest ratepayer dollars in EE measures and projects. 

Commenters stated that EPA should craft an accounting protocol for states to take credit for outof-state emission reductions due to in-state EE. Commenters attached a C2ES brief to their 

comment letter, entitled Cross-State Electricity Load Reductions Under EPA's Proposed Clean 

Power Plan (also available at http: //www.c2es.org/publications/ cross-state-electricity-loadreductions-under-epas-proposed-clean-power-plan). Commenters stated that the brief discusses 
76

options for claiming credit for emission reductions that occur across state lines. Commenters 

encouraged EPA to work with states to determine an accounting protocol. Commenters

contended that due to these interstate effects, simply measuring emissions and generation within 

a state may not be enough to show that reductions are being made. Commenters stated that a 

state may have to demonstrate what steps it took to cut generation to prevent two states claiming 

credit for the same emission reduction. Commenters stated that making sure there are no 

inadvertent disincentives will ensure effective efficiency programs that could even exceed EPA's 

targets. 

Commenters stated that states should have the ability to work with one another to determine the 

best method for accounting of such credits and costs, without having to be in a regional program, 

ensuring there is no double counting of reductions among states. Commenters stated that EPA 

can assist the states through detailed guidance on the ways it considers most effective to identify, 

allocate and ensure the integrity of EE credits shared among states, but without taking on a more 

substantive oversight role. 

Commenters recommended the EPA allow states to establish credit-trading platforms similar to 

those used for RECs (i.e., NEPOOL, PJM EIS GATS) that enable energy savings to be traded.

Commenters also recommended that EPA identify or facilitate an optional standardized credit 

tracking system for energy savings that states could join if they do not already have a system in 

place. Commenters stated that while such an interstate system does not currently exist, a clear 

signal from EPA that such a system would allow states to take full advantage of low-cost 

emission reduction measures from energy savings would likely 

facilitate the creation of such a system. Commenters stated that such a system, which states could 

join at their discretion, would particularly help those states without a tracking system already in 

place. Commenters stated that this would allow states acting together to take advantage of the 

lowest cost emission reduction opportunities through EE without having to participate in full 

multi-state compliance plans. Commenters urged EPA to provide a clear signal of its support for 

an interstate energy savings trading platform. 

Commenters also recommended that EPA build on the existing REC tracking system concepts to 

provide verification, tracking, and banking of EE avoided generation in MWh at the national 

level. Commenters stated that EPA should consider creating and maintaining its own system of 

tracking compliance for interstate credits and trading to ensure appropriate and consistent 

treatment of compliance actions and avoiding errors in crediting of results. 

Commenters stated that unlike with RE, where there is a risk that a competing claim may be 

staked by the state where the RE resource is located, or by the purchaser of "null power," when 

all states are rate-based there is no reason that another state would lay claim to those reductions, 

since they would only be identified by the entity implementing the EE program. Commenters

stated that, even where a fossil unit is displaced in a state other than the state taking credit for the 

EE, that will not result in double counting so long as EPA adopts the annual true-up procedure 

that Commenters recommended for states with mass-based limits . Commenters stated that 

because the mass-limited unit will have less generation factored into its rate-to-mass conversion, 

its overall mass target will be lower, neutralizing the benefit it received by having its emissions 

reduced due to an out-of-state EE program. Commenters contended that no double-counting will 
77

occur due to displacement of affected EGUs in rate-based states. Commenters stated that 

crediting 100% of EE results would not result in double-counting if EPA requires states using a 

mass-based compliance plan to account for any potential double counting issues in its state 

compliance plan by discounting its emission reduction compliance number by any emission 

reductions that are the result of out-of-state investments in EE or RE. Commenters also 

mentioned that this may provide incentive for states to participate in a multi-state compliance 

approach. Similarly, commenters stated that double counting EE savings can be addressed by 

requiring any states that opt for a mass-based target and that export electricity to rate-based states 

to adjust the baseline generation they use to set the mass-based target to ensure that no double 

counting occurs. 

Commenters stated that rate based compliance states that are investing in EE measures should 

include a commitment in the state compliance plans to provide any necessary data to mass-based 

compliance states upon request and EPA should verify the cross-state emission reductions 

resulting from EE measures in its review of each state's compliance plans. In addition, 

commenters stated that this approach may provide an incentive for states to participate in a 

multi-state compliance approach. 

Commenters stated that there is a legitimate concern of double counting when a state chooses a 

rate-based approach and gets full credit for energy savings achieved in the state, but then imports 

a significant amount of electricity from a state that chooses a mass-based approach. Commenters 

stated that it would be reasonable for the EPA to require an energy savings adjustment within the 

state where the savings occurs in this case. Commenters suggested that EPA could set a threshold 

for applying an adjustment factor during the implementation phase (e.g., it is required if a state 

that chooses the rate-based approach imports more than 5% of its electricity from a state that 

chooses the mass-based approach in any particular year). Commenters stated that this adjustment 

would not be necessary if an importing state chooses the mass-based approach for compliance. 

Commenters stated that EPA should require states to include provisions in their state plans to 

avoid double counting of energy savings among the various EE policies and programs included 

in the plans (e.g., for projects that participate in both utility and non-utility programs). 

Commenters contended that states should be given the flexibility to determine which programs 

will receive the credits where there is overlap, and to indicate how double counting will be 

avoided. 

Commenters stated that their state is in the process of discussing how to avoid double-counting 

emission reductions from EE with other states, and encouraged EPA to continue to work with 

states on this critical issue prior to finalizing the rule so that the CPP provides a workable 

solution for all states.

Comment 19: Comments regarding carbon pricing through RTOs/ISOs.

Response 19: In the final rule, the EPA offers states the flexibility to choose the state plan 

approach that works best for their priorities and circumstances. States can choose an emissions 

standards approach by placing federally enforceable emissions standards on their affected EGUs 
78

but implement complementary energy efficiency programs don’t explicitly receive credit under 

the final guidelines but lower the cost of compliance. Under the state measures approach, states 

can adopt a plan that does not place all the obligations on affected EGUs but includes measures 

implemented by the state, or by entities other than affected EGUs, that result in avoided 

generation and CO2 emission reductions at affected EGUs.

Measures implemented under the state measures plan type could include RE and demand-side 

EE requirements and deployment programs. This type of plan could align with existing state 

resource planning in the electricity sector, including RE and demand-side EE investments by 

state-regulated electric utilities. The state measures plan type also can accommodate emission 

budget trading programs that address a broader set of emission sources than just affected EGUs

subject to CAA section 111(d) and could accommodate imposition by a state of a fee for CO2

emissions from affected EGUs, an approach suggested by a number of commenters.

This plan type would allow the state to implement a suite of state measures that are adopted, 

implemented, and enforceable only under state law, and rely upon such measures in achieving 

the required level of CO2 emission performance from affected EGUs. The state measures under 

this plan type could be measures involving entities other than affected EGUs, or a combination 

of such measures with emission standards for affected EGUs, so long as the state demonstrates 

that such measures will result in achievement of a state’s mass-based CO2 goal (or mass-based 

CO2 goal plus new source complement). For more information about the specific requirements 

related to the emissions standards and state measures approaches, see Section VIII.C.

The following are summaries of the specific public comments under this comment:

Commenters requested that EPA explicitly allow for carbon pricing as a "beyond the fenceline" 

compliance option for states and consider drafting a model rule for states on the adoption of 

carbon pricing schemes. Commenters argued that this approach would utilize the existing market 

structure to determine least-cost compliance solutions and would explicitly reflect reliability 

contributions of plants. Commenters stated that carbon pricing would incorporate both long-term 

and short-term operational and reliability concerns and could be used to incentivize lower-carbon 

emitting resources. Commenters suggested that EPA could translate the proposed carbon 

emission reduction targets into targets for regional power markets (RTOs/ISOs) and apply those 

reductions through a market-based carbon price. Commenters argued that implementing carbon 

prices through RTOs/ISOs would provide for a "predictable and stable system" and could be 

more efficient and cost-effective than direct control of individual generation sources or a stateby-state carbon pricing approach. 

Comment 20: Comments Opposing RTOs leading trade markets.

Response 20: In the final rule, the EPA offers states the flexibility to choose the state plan 

approach that works best for their priorities and circumstances. It does not create new authorities 

or requirements for regional transmission organizations but does acknowledge that RTOs may 

have or be able to provide data, analyses and/or expertise that can support state decision making, 
79

particularly with respect to multi-state plans as described in Section VIII.C.5 and demonstrating 

performance as described in VIII.D.2.a.(3) of the final rule preamble of the CPP.

The following are summaries of the specific public comments under this comment:

Commenters opposed giving regional transmission organizations (RTOs) the authority to create 

new markets as a compliance vehicle. Commenters stated that RTOs have currently assumed the 

operation of competitive energy, capacity, ancillary service, and other markets, in which they 

currently centrally dispatch EGUs based on the marginal cost of operation of each individual unit 

based on EGU bids submitted to the RTO. Commenters noted that factoring CO2 compliance 

costs into existing EGU bids could result in dispatch of EGUs on a lower CO2 emission rate if 

the focus remains on consumers and transparency. However, commenters stated opposition to 

RTOs running these trading platforms or other new markets based on concerns regarding a lack 

of consumer focus or transparency in existing energy and capacity markets. Commenters further 

iterated that if new markets or trading platforms are rule by RTOs, this would significantly 

complicate the competitive energy market and could add unnecessary costs.

Comment 21: Comments supporting "alternative compliance payments" in interstate trading.

Response 21: The final rule addresses the use of emission budget trading programs, including 

provisions required for such programs and the design of such programs in the context of a state 

plan. This includes program design approaches that ensure achievement of a state mass-based 

CO2 emission goal (or mass-based CO2 goal plus new source CO2 emission complement) 

(section VIII.J.2.b), as well as how states can use emission budget trading programs with broader 

source coverage and other flexibility features, like out-of-sector offsets and certain cost 

containment requirements, such as the programs currently implemented by California and the 

RGGI participating states (section VIII.J.2.c). 

In the case where an emission budget trading program contains elements that functionally 

expand the emission budget in certain circumstances, such as the inclusion of an alternate 

compliance payment option, compliance by affected EGUs with the mass-based emission 

standards would not necessarily ensure that CO2 emissions from affected EGUs do not exceed 

the state’s mass-based CO2 goal (or mass-based CO2 goal plus new source CO2 emission 

complement). States could modify such programs to remove flexibility mechanisms that 

functionally expand the emission budget, such as out-of-sector offsets and certain cost 

containment reserve mechanisms, and submit the program under an emission standards plan 

type.

Where a state chooses to retain such flexibility mechanisms as part of an emission budget trading 

program, the program may only be implemented as part of a state measures plan type because 

these state flexibility mechanisms would not assure CO2 emissions from affected EGUs do not 

exceed the state’s mass-based CO2 goal (or mass-based CO2 goal plus new source CO2 emission 

complement). A description of the state measures plan type and related requirements is provided 

in section VIII.C and Section VIII.J.2.

The following are summaries of the specific public comments under this comment:
80

Commenters supported interstate emissions credit trading and a concept of "alternative 

compliance payments" that facilities could use when compliance costs exceeded the level of 

compliance payment. Commenters stated that this would create state-based clean technology 

funds that could be used for projects to reduce carbon pollution in these states.

Comment 22: Comments suggesting that Tribal lands should not be precluded from 

participating in carbon trading programs or required to have a 111(d) plan to sell RE to other 

states.

Response 22: See section VIII.G of the final rule preamble of the CPP for the EPA’s response to 

comments associated with RE sources on tribal lands that can be used for CPP compliance in a 

state. See section I.A of the final rule preamble of the CPP for the EPA’s response to the 

comments regarding continued EPA engagement with Tribes on the CPP. 

The following are summaries of the specific public comments under this comment:

Commenters noted that the proposed rule allows states to use qualifying renewable energy 

sources in other states to count towards meeting the state renewable portfolio standards. 

Commenters requested that this same opportunity be provided to Indian Tribes that sell 

renewable energy generated on tribal lands. Commenters requested that EPA engage Tribes in a 

discussion about this opportunity and how it may fit under the proposed rule. Commenters 

requested that EPA clarify the role that RECs will play in determining which jurisdiction or 

affected entity receives credit for renewable energy generation. Commenters asked whether RE 

would be counted in cases where renewables are built on tribal land and purchased by a utility 

for use beyond tribal land. 

Commenters asserted that EPA must clarify that tribal lands are not precluded from participating 

in carbon trading programs. Commenters requested that tribes should have the maximum 

flexibility to participate, with or without a tribal 111(d) plan, partial plan, or federal plan. 

Commenters also requested that EPA permit a hybrid approach and clarify that electric utilities 

are also able to participate in carbon credit trading plans separate and apart from the tribal 

government. Commenters argued that allowing such trading would be consistent with Section 

111(d) and existing emissions trading programs, similar to the Municipal Waste Combustor 

111(d) rules. Commenters urged that EPA could also permit this hybrid approach through its 

discretionary authority under CAA section 301(d) and the Tribal Air Rule. 

Commenters noted that some tribal authorities may want to ensure that the tribe receives tradable 

REC allowances for any RE developed on tribal land, regardless of who owns or operates the 

renewable resource. Commenters asked EPA to clarify whether a state, tribal nation, territory, or 

regulated entity can claim credit to renewable energy without holding the REC. Commenters

noted that should a tribal authority choose to seek authority for and develop an implementation 

plan that includes the development of renewable energy, it would need to negotiate with its 

business partners concerning REC ownership from renewable energy resources located on tribal 

lands.
81

Commenters recommended that EPA allow a Tribal set-aside as part of an interstate emissions 

credit trading program. Commenters suggested the program be modeled after a similar annual 

SO2 set-aside that grew out of the Western Regional Air Partnership. Commenters reiterated that 

this set-aside what intended to help ensure equitable treatment for tribal economies and prevent 

barriers to economic development. Commenters affirmed that the same rationale exists today 

and a set-aside should be incorporated into any national trading program under the proposed rule. 

Commenters also asserted that EPA should not inhibit the sale or exchange of tribal allowances 

in any state, such as by requiring the tribe to have a federal 111(d) plan or participate in a multijurisdictional plan in order of the allowances to be used. Commenters noted that tribes may have 

or develop excess carbon allowances that it could sell or trade in an open market, and that tribes 

should have the right to participate in such markets (such as the RGGI program). Commenters

strong opposed any rule that would condition a tribe's ability to have RE resources on tribal lands 

count toward a state's 111(d) goal on the premise that the tribe has a 111(d) plan, Commenters 

argued that such requirements did not exists prior to the proposed rule and would be overly 

burdensome to tribes.

5.7.5 Regional demonstration by states of emission performance

This section addresses comments on regional development and implementation of a plan to 

comply with the CPP.

Commenters have raised a number of issues related to this subsection which are organized by 

topics (comments) below. Responses are also provided for these topics.

Comment 1: Comments supporting regional demonstration by states of emission performance; 

the EPA should encourage coordination between states for regional programs to reduce costs; 

supports regional emissions cap that allows for diversity in state portfolios; RGGI as a prime 

example of a successful regional program; regional demonstration should be an option, not 

compelled.

Response 1: The EPA recognizes that there are multiple incentives for states to collaborate by 

implementing a multi-state plan. That is why EPA has promulgated a final rule that allows states 

to meet an aggregated joint goal, regardless of the specific level of their individual goals, 

because states share grid regions and impacts from plan implementation will be regional in 

nature. Further, multiple analyses, including those by ISOs and RTOs, indicate that regional

approaches could achieve state goals at lesser cost than individual state plan approaches. 

However, the EPA also recognizes the value in allowing for collaboration where states retain 

individual goals. These approaches could provide some of the benefits of a joint goal while 

reducing the negotiations among states necessary to develop a multi-state plan with a joint goal. 

As a result, the EPA has finalized the additional multi-state approaches described above in 

section VIII.C.5 of the final rule preamble of the CPP to provide for coordination while 
82

maintaining individual goals. These approaches would allow for interstate transfer of energy rate 

credits (ERCs) or emission allowances while retaining individual state goals.

The EPA is allowing for streamlined multi-state trading approach, states can develop their own 

programs and trade eligible RE or demand side EE with other states through a trade-ready 

system. The EPA is providing maximum flexibility in the types of state plans states can use to 

implement the emission guidelines. For states wishing to participate in a multi-state plan, the 

EPA is finalizing three forms of submittal that states may choose for the submittal of a multistate plan. See Section VIII.C.5 of the final rule preamble of the CPP for details on the different 

multi-state plan approaches the EPA finalized in this final CPP rule

In terms of how EE is can be used for compliance, states can adjust their CO2 emissions rate 

from eligible demand side EE and do not need to be implemented in its home states. This 

approach has changed from the proposal as suggested by the commenter below. See Section 

VIII.K.1 of the final rule preamble of the CPP for further details on how to use demand side EE 

in rate based plans. 

The following are summaries of the specific public comments under this comment:

Commenters support an approach where states are allowed to demonstrate compliance with 

emission performance on a regional basis. Commenters believed the EPA should encourage 

interstate coordination and collaboration because an interstate approach can reduce costs and 

help avoid challenges that arise when limiting systems to a specific state. 

Commenters noted that while the EPA has suggested a regional approach under which states' 

individual rate-based goals would be replaced by a single regional goal that would be equal to 

the weighted average of the state goals, it may not receive support from states whose goals are 

less stringent than the regional weighted average. Commenters stated a regional approach more 

likely to secure support would allow states to retain their individual goals, but would provide for 

credit trading between the states as a compliance measure. Commenters noted that interstate 

cooperation can lower the administrative burden on states and compliance entities, and help 

resolve equity issues that arise between power-exporting and power-importing states. 

Commenters (23597) noted that interstate programs have already been successful in a variety of 

contexts and specifically mentioned the Acid Rain Program, Cross-State Air Pollution Rule, 

regional haze initiatives, programs to address ozone transport issues, and RGGI. Commenters

believed that RGGI has demonstrated that a regional program that is closely aligned with the 

borders of an electricity grid is more efficient than programs that are constrained by state 

borders. Commenters also noted that a regional program can avoid market distortions. As an 

example, commenters mentioned the situation that would arise if one state's energy efficiency 

investments reduce emissions in a neighboring state. Commenters noted that in a regional 

program both states would be able to reap the emission reduction benefits of that energy 

efficiency. Commenters also highlighted RGGI as a successful multi-state program that includes 

features of mass-based caps and interstate trading, and noted the economic benefits of the 

program. 

Commenters recommended that EPA allow and assist states preferring a multi-state approach the 

flexibility to design one that does not by necessity mirror RGGI. Commenters stated that a state's 
83

participation in a multi-state agreement should not require that state's compliance goal to be 

absorbed, or blended, into a regional goal. 

Commenters stated the final rule should also ensure that states making energy efficiency or 

renewable energy investments be given credit for those efforts. Commenters believed that 

individual states participating in a regional program may reduce emissions through a variety of 

state-specific energy programs like renewable portfolio standards and energy efficiency 

programs. Commenters suggested that the regional emission cap can operate as an umbrella, 

encompassing and accounting for the emission reductions from these complementary programs. 

Commenters noted that because overall emissions are limited by the emissions cap, the 

complementary programs would not need to be federally enforceable. Commenters also stated 

that complementary programs would also serve to reduce the cost of complying with the regional 

emissions cap. Commenters noted that RGGI is one example of this approach being successfully 

implemented. Commenters stated that the RGGI states are well-positioned to comply with the 

proposed CPP by using the existing RGGI model. Commenters noted, however, that in order to 

demonstrate that the RGGI cap will be adequately stringent to comply with EPA's targets, the 

RGGI states will have to 1) Extend the RGGI cap to 2030, 2) Correct the cap decline trajectory, 

and 3) Restructure the cost containment reserve. Commenters stated that whether through direct 

participation in RGGI or through the creation of a similar program, states should take advantage 

of the successful blueprint that already exists in the Northeast. Commenters stated that as an 

alternative to participation in RGGI, groups of states may choose to develop their own massbased trading program as a CPP compliance mechanism. Commenters also stated should states 

choose this option, EPA should draw on the RGGI experience to facilitate interstate trading. 

Commenters requested that EPA make it as easy as possible for regional approaches to emerge. 

Commenters stated that this would allow interested states to incorporate policies that envision 

the development of regional linkages over time, rather than requiring states to work out all the 

details by the plan submission deadlines. Commenters also requested that EPA indicate that state 

plans that rely on discrete multi-state agreements would be approvable. Commenters stated that 

EPA should be explicit in the final rule about this regional flexibility, and provide guidance on a 

model approach, as it will achieve the goals of the Clean Air Act without putting an unnecessary 

burden on utilities.

Comment 2: Comments suggesting that the EPA should not compel RE regionalization.

Response 2: The final rule continues to give states significant flexibility in how they comply 

with requirements, including single state and multi-state plans and using both BSER and nonBSER measures as a means to comply. For example, RE measures can greatly assist states and 

affected EGUs in meeting the standards and/or state plan. Many studies assume that state plans 

will simply apply the BSER and do not recognize the large number of compliance approaches 

and opportunities that states and affected EGUs have available to them. States do not need to 

adopt the assumptions the EPA uses to set BSER.

EPA disagrees with the commenter that EPA’s renewable energy targets are too stringent. The 

global market for RE is projected to grow to $460 billion per year by 2030. RE growth is further 

encouraged by the significant amount of existing natural resources that can support RE 
84

production in the United States. In the Energy Information Administration’s Annual Energy 

Outlook 2015, RE generation grows substantially from 2013 to 2040 in the reference case and all 

alternative cases. 

The basis for quantifying building block 3 generation has been modified to incorporate historical 

deployment patterns for RE technologies as well as the economic potential identified through 

modeling projections. The introduction of historical capacity additions to the final methodology 

further grounds building block 3 generation in demonstrated levels of RE deployment that have 

been successfully incorporated into the power system. This adjustment also serves to harmonize 

the approach across all three building blocks in which historical data is the primary basis for 

identifying emission reduction opportunities under the BSER.

For further details on the EPA’s assumptions for RE under BB3 See Section V.E of the final rule 

preamble of the CPP.

The following are summaries of the specific public comments under this comment:

Commenters requested that EPA not compel regionalization of renewable energy targets as a 

means for enabling states to adapt to EPA's Block 3 renewable energy target. Commenters stated 

that MISO analysis indicates that EPA renewable targets have been set too stringent for the 

MISO states, due to high costs per ton CO2 reduction. Commenters suggested that states should 

have the option of entering into regional collaborations that help develop mutually beneficial 

renewable deployment measures.

Comment 3: Comments suggesting that implementation of the rule should be delayed.

Response 3: Commenters observed and EPA agrees that due to the interconnected nature of the 

power sector, units are not limited to such emission reduction measures within their state, and 

indeed any operational decisions that units take necessarily influence operational decisions at 

other units throughout the interconnected grid. As a result, in the final rule, we are finalizing CO2

emission performance rates, informed by regional emission reduction potential, for fossil fuelfired electric utility steam generating units and stationary combustion turbines that are applied 

consistently across all affected EGUs. As the same source category-specific performance rates 

are applied to all units in the contiguous U.S. regardless of the state in which they are located, 

any differences between state goals in this final rule stem only from the relative prevalence in 

each state of fossil fuel-fired electric utility steam generating units and stationary combustion 

turbines. The EPA has determined that commenters received ample time for response to 

comments to all information related to regionalize RE targets. 

The EPA disagrees with the commenter’s concern that the rule needs to be delayed because of 

reliability concerns. For example, the Analysis Group recently analyzed reliability considerations 

in MISO as the region considers how to comply with the final rule. The Analysis Group found 

that despite the large amount of coal that will likely retire in MISO in the coming years, the 

entities responsible for electric system reliability in MISO are prepared to collaboratively address 

any reliability issues that arise and that there is a “strong tool kit for managing `Essential 

Reliability Services‘ needed to assure high-quality electric service.” 
85

The following are summaries of the specific public comments under this comment:

Commenters stated that the issuance of the final rule should be delayed until EPA provides 

specifics on regional goals. Commenters were concerned that allocating renewable energy on a 

state-by-state basis is problematic based on the lack of specificity set forth in the NODA. 

Commenters noted that the absence of any demonstration that such an approach represents BSER 

precludes EPA from pursuing such an approach in the final rule. Commenters stated that if EPA 

wants to pursue this approach in the final rule, then it must delay issuance of the final rule and 

issue a revised proposed rule that specifies the proposed regions, the proposed regional goals, the 

methodology for apportioning goals and renewable energy to individual states, and the impact of 

this approach on states' emission rate requirements.

Commenters stated that until NERC has validated the reliability impacts of the proposed rule, 

implementation must be delayed. Commenters noted that Regional Transmission Organizations 

have indicated that the rule will cause thermal overloads and low voltage, while at the same time 

jeopardizing the reserve margin required for continued reliable operation. Commenters also 

noted concern about the compliance problems the proposed rule presents for a utility that relies 

on a single, coal- fired power plant in one state to serve load in completely different states.

Comment 4: Comments suggesting the proposed rule discourages regional cooperation.

Response 4: The EPA disagrees with the commenter’s concern. The final rule encourages 

regional cooperation in many ways. There are multiple incentives for states to collaborate by 

implementing a multi-state plan to meet an aggregated joint goal, regardless of the specific level 

of their individual goals, because states share grid regions and impacts from plan implementation 

will be regional in nature. Further, multiple analyses, including those by ISOs and RTOs, 

indicate that regional approaches could achieve state goals at lesser cost than individual state 

plan approaches.

The accounting approach described by the commenter is also inaccurate and does not reflect the 

final CPP rule accounting structure. The EPA is finalizing the ability for states to choose to 

implement a rate based or mass based approach. Naturally, the accounting structure for rate 

based plans are different than mass based plans, but in neither case does the same state have to 

assess both the emissions and clean energy generation for their individual plan. 

In the final rule, quantified and verified MWh impacts of qualifying zero-emitting and lowemitting resources tied to a state plan may be used by an affected EGU or state to adjust a CO2

emission rate, regardless of whether the renewable generation or demand-side EE savings occur 

inside or outside the state or territory. 

See Section VIII.C of the final preamble that describes the different rate and mass based plans. 

Section VIII.K.2.a of the final rule preamble of the CPP below describes the basic accounting 

method for adjusting a CO2 emission rate, as well as eligibility requirements for measures that 

may be used for adjusting a CO2 emission rate. See Section VIII.J of the final rule preamble of 

the CPP on additional considerations for mass based plans. 
86

The following are summaries of the specific public comments under this comment:

Commenters argued that although the proposed rule appears to encourage regional cooperation, 

the structure of the proposed rule discourages regional cooperation by pitting utilities against 

utilities and states against states. Specifically, commenters asserted that the proposed rule limits 

each state to counting both carbon-emitting and clean generation located within the state, which 

would make regional cooperation difficult.

Comment 5: Comments suggesting that the EPA should not allocate RECs at a regional level, 

but allow states to verify RECs and use a power delivery review.

Response 5: Under all types of state plans, states must ensure that the emission reduction 

measures counted as part of meeting their plan requirements are not duplicative of any measures 

that are counted by another state, in order to avoid double counting of the MWhs of generation or 

energy savings that these measure produce. See Section VIII.L of the final rule preamble of the 

CPP that addresses the commenter’s concern about avoiding double counting between rate based 

and mass based plans.

The EPA is finalizing requirements specific to rate-based emission trading programs as 

requirements the EPA has determined are necessary to assure the integrity of a rate-based 

approach. These specific requirements for a rate-based emission trading program include 

provisions for issuance of ERCs by the state and/or its designated agent; provisions for tracking 

ERCs, from issuance through submission for compliance; and the administrative process for 

submission of ERCs by the owner or operator of an affected EGU to the state, in order to adjust 

its reported CO2 emission rate when demonstrating compliance with a rate-based emission 

standard.

An ERC is issued separately from any other instruments that may be issued for a MWh of energy 

generation or energy savings from a qualifying measure, such as a renewable energy certificate 

(REC). An ERC may be issued, however, based on the same data and verification requirements 

used by existing REC tracking systems for issuance of RECs and EECs that are used to meet 

state renewable portfolio standards or energy efficiency resources standards. The EPA is aware 

of the potential for interactions between ERCs and RECs or EECs and encourages the states to 

consider, when developing their state plan, how existing instruments that are used to meet other 

regulatory requirements or in voluntary markets may interact with ERCs.

Requirements for rate-based emission trading programs and the issuance and tracking of ERCs, 

including qualifying measures, programs or projects and addressing the potential for interactions 

between ERCs and RECs, are in section VIII.K.2 of the final rule preamble of the CPP. Section 

VIII.K.3 of the final rule preamble of the CPP describes the requirements and criteria related to 

proper quantification and verification of MWhs from renewable electricity generation and 

demand-side EE.

The following are summaries of the specific public comments under this comment:
87

Commenters argued that allocating RE targets at a regional level, as opposed to state level, 

would introduce unnecessary complexity. Commenters suggested that states take responsibility 

for verifying RECs and the RECs presented by utilities to demonstrate compliance. Commenters 

asserted that using RECs would avoid confusion between states with major RE generation and 

the states that import that power. Commenters also recommended that utilities purchasing 

delivered RE and RECs should receive the credit for compliance purposed. Rather than using a 

regional REC compliance target, commenters favored a power delivery review to ensure that 

states provide guidance and incentives that ensure delivery of RE to their states while facilitating 

continued commerce in energy among the states. Commenters asserted that a power delivery 

review would encourage regionalization while avoiding the severing of single utilities with 

integrated planning, transmission and distribution systems into multiple regions. Commenters

noted that EPA should ensure there is no double-counting resulting from power transfers in or 

out of states with mass-based emission targets. 

Comment 6: Comments supporting regional emission targets; states should be allowed to 

apportion the regional emissions cap among states as they see fit.

Response 6: The EPA disagrees that regional emission goals should supersede individual state 

goals. The EPA has promulgated a final rule that allows states to meet an aggregated joint goal, 

regardless of the specific level of their individual goals, because states share grid regions and 

impacts from plan implementation will be regional in nature. However, the EPA also recognizes 

the value in allowing for collaboration where states retain individual goals. These approaches 

could provide some of the benefits of a joint goal while reducing the negotiations among states 

necessary to develop a multi-state plan with a joint goal. As a result, the EPA has finalized the 

additional multi-state approaches described above in section VIII.C.5 of the final preamble to 

provide for coordination while maintaining individual goals. These approaches would allow for 

interstate transfer of energy rate credits (ERCs) or emission allowances while retaining 

individual state goals. See section VIII.K.2 of the final rule preamble of the CPP for EPA’s 

tracking system requirements. 

The following are summaries of the specific public comments under this comment:

Commenters stated that meeting a regional emission cap should supersede individual state 

emission limits. Commenters believed that it should not matter how the participating states elect 

to apportion the regional emissions cap among the states provided the overall regional emissions 

cap complies with the guidelines. Commenters stated that although a particular state's actual 

emissions could theoretically exceed its individual state emission budget, they stated that this 

should not affect EPA's decision to accept a regional program as a pathway for compliance. 

Commenters questioned how states are to address interstate issues in their plans, as EPA has no 

authority to require states to join interstate emission reduction efforts. Commenters agreed that 

states should be able to design programs to account for the interstate nature of electricity 

generation through existing state public utility commissions and environmental regulatory 

institutions. Commenters stated that under a mass-based approach, a state that joins an interstate 
88

plan should be able to establish emission targets for the broad group of participating states rather 

than an individual state target, provided EPA can track compliance in the same way as an 

individual state plan. 

Comment 7: Comments regarding enforcement of regional plans; enforceability of emission 

caps.

Response 7: The EPA agrees with these commenters’ suggestions. For a mass-based emission 

trading program approach, the state plan would include as its federally enforceable emission 

standards requirements that specify the emission budget and related compliance requirements 

and mechanisms. These requirements would include: CO2 emission monitoring, reporting, and 

recordkeeping requirements for affected EGUs; provisions for state allocation of allowances; 

provisions for tracking of allowances, from issuance through submission for compliance; and the 

process for affected EGUs to demonstrate compliance (allowance “true-up” with reported CO2

emissions). Mass-based emission standards that take the form of an emission budget trading 

program must be quantifiable, verifiable, enforceable, non-duplicative and permanent. This 

includes the requirement for an affected EGU to surrender emission allowances equal to reported 

CO2 emissions, and meet monitoring and reporting requirements for CO2 emissions, among other 

requirements. These requirements may be submitted as part of the federally enforceable state 

plan through mechanisms with the appropriate legal authority and effect, such as state 

regulations, title V permit requirements for affected EGUs, and other possible instruments that 

impose these requirements specifically with respect to affected EGUs.

For additional information about different mass based trading program designs that are allowable 

under this final CPP rule see Section VIII.J of the final rule preamble of the CPP. 

The following are summaries of the specific public comments under this comment:

Commenters believed that a regional budget trading program is easily enforced. Commenters 

stated that under a budget trading program like RGGI, they noted enforceability, measurement, 

and verification are already incorporated into the program, since sources are required to obtain 

and hold a sufficient amount of allowances by the compliance deadline to cover emissions over 

the compliance period. Commenters noted this is a regulatory requirement that is generally 

incorporated as a federally enforceable condition in each source's operating permit. Commenters 

stated the emission cap is enforceable directly against individual sources, with the failure of a 

source to hold sufficient allowances being a violation of the state's program and the source's 

permit. Commenters stated compliance with the 111(d) emissions cap is then confirmed through 

"true-up" process in which states deduct allowances to cover emissions. Commenters believed 

this same approach could be incorporated into an approved Section 111(d) plan. 

Comment 8: Cost escalation limits for regional programs; states must demonstrate that these 

limits do not result in excess emissions.
89

Response 8: The final rule addresses the use of emission budget trading programs, including 

provisions required for such programs and the design of such programs in the context of a state 

plan. This includes program design approaches that ensure achievement of a state mass-based 

CO2 emission goal (or mass-based CO2 goal plus new source CO2 emission complement) 

(section VIII.J.2.b), as well as how states can use emission budget trading programs with broader 

source coverage and other flexibility features, like out-of-sector offsets and certain cost 

containment requirements, such as the programs currently implemented by California and the 

RGGI participating states (section VIII.J.2.c). 

Under this approach, the full set of regulations establishing the emission budget trading program 

that applies to affected EGUs and other fossil fuel-fired EGUs and other emission sources (if 

relevant) must be described as supporting documentation in the state plan submittal. This 

structure is appropriate to ensure that states with an emission budget trading program that 

addresses both affected EGUs and other fossil fuel-fired EGUs do not inappropriately submit 

requirements regarding entities other than affected EGUs for inclusion in the federally 

enforceable state plan. 

Such state programs could include a number of different design elements. This includes broader 

program scope, where a program includes other emission sources beyond affected EGUs subject 

to CAA section 111(d) and new fossil fuel-fired EGUs, such as industrial sources. Programs 

might also include design elements that make allowances available in addition to the established 

emission budget. This includes project-based offset allowances or credits from GHG emission 

reduction projects outside the covered sector and cost containment reserve provisions that make 

additional allowances available at specified allowance prices.

In the case where an emission budget trading program contains elements that functionally 

expand the emission budget in certain circumstances, such as the inclusion of an alternate 

compliance payment option, compliance by affected EGUs with the mass-based emission 

standards would not necessarily ensure that CO2 emissions from affected EGUs do not exceed 

the state’s mass-based CO2 goal (or mass-based CO2 goal plus new source CO2 emission 

complement). States could modify such programs to remove flexibility mechanisms that 

functionally expand the emission budget, such as out-of-sector offsets and certain cost 

containment reserve mechanisms, and submit the program under an emission standards plan 

type.

Where a state chooses to retain such flexibility mechanisms as part of an emission budget trading 

program, the program may only be implemented as part of a state measures plan type because 

these state flexibility mechanisms would not assure CO2 emissions from affected EGUs do not 

exceed the state’s mass-based CO2 goal (or mass-based CO2 goal plus new source CO2 emission 

complement). A description of the state measures plan type and related requirements is provided 

in section VIII.C and Section VIII.J.2 of the final rule preamble of the CPP.

Emission budget trading programs that include unaffected EGUs must be submitted as a part of a 

state measures plan type. Where an emission budget trading program addresses affected EGUs 

and other fossil fuel-fired EGUs, the requirements that must be included in the state plan are the 

federally enforceable emission standards in the state plan that apply specifically to affected 
90

EGUs, and the requirements that specifically require affected EGUs to participate in and comply 

with the requirements of the emission budget trading program.

If a state chooses to implement a mass-based program including both affected EGUs and new 

EGUs, and the total allowable emissions is in excess of the presumptively approvable power 

sector mass budget for that state, the state must provide a projection of CO2 emission 

performance. Likewise, if a state chooses a state measures state plan approach, a projection of 

CO2 emission performance is required. For details on the requirements for all state plans that 

must do CO2 performance demonstration see Section VIII.D.2. (a) of the final rule preamble of 

the CPP. 

The following are summaries of the specific public comments under this comment:

Commenters stated that regional budget trading programs may have design elements intended to 

limit sharp cost escalations. Commenters noted that RGGI allows sources to use offsets for a 

small portion (three percent) of their compliance obligations, and the program revisions that will 

take effect in 2014 include a Cost Containment Reserve (CCR) allow the distribution of a limited 

amount of additional allowances if prices exceed specified levels. These elements, commenters

noted, are intended to respond to unforeseen market conditions, such as greater-than-anticipated 

demand growth, but they may lessen emission reductions. Commenters stated that States 

participating in RGGI or similar regional programs should be able to either demonstrate that 

these design elements will not allow emissions in excess of those allowed by EPA's emission 

guideline, or include supplemental measures to ensure consistency with EPA's guideline.

Commenters recommended the EPA develop a mechanism to address any differences in the 

scope of sources covered by the Section 111(d) guidelines and the scope of sources subject to the 

requirements of the emission budget trading program. Commenters noted, for example, that 

RGGI may include certain smaller sources that may not be covered by the section 111(d) 

guidelines. Commenters noted if the additional sources cause the regional budget to be higher 

than the guidelines, then participating states would have to demonstrate that emissions from the 

sources covered by section 111(d) comply with the guidelines. Commenters believed the EPA 

should provide a rigorous and equitable methodology to determine compliance in these 

situations.

Comment 9: Comments suggesting the final rule should allow for non-contiguous states to form 

multi-state plans; rule should consider that current markets do not match state boundaries.

Response 9: The EPA agrees that non-contiguous states can form multi-state agreements. The 

EPA is finalizing a multi-state plan approach that enables states to retain their individual state 

goals for affected EGUs and submit individual plans, but to coordinate plan implementation with 

other states through the interstate transfer of ERCs or emission allowances. This approach 

facilitates interstate emission trading without requiring states to submit joint plans.

The EPA further clarified how multi-state plans with a joint goal for affected EGUs may be 

implemented. States may participate in more than one multi-state plan, if necessary, for example, 

to address affected EGUs in states that are served by more than one ISO or RTO. For example, a 
91

subset of affected EGUs in a state may participate in a multi-state plan. These clarifications are 

discussed in section VIII.C.5.d of the final rule preamble of the CPP.

In the final rule, quantified and verified MWh impacts of qualifying zero-emitting and lowemitting resources tied to a state plan may be used by an affected EGU or state to adjust a CO2

emission rate, regardless of whether the renewable generation or demand-side EE savings occur 

inside or outside the state or territory, and is unrelated to import or export of neighboring states.

An ERC is issued separately from any other instruments that may be issued for a MWh of energy 

generation or energy savings from a qualifying measure, such as a renewable energy certificate 

(REC). ERC may be issued, however, based on the same data and verification requirements used 

by existing REC tracking systems for issuance of RECs and EECs that are used to meet state 

renewable portfolio standards or energy efficiency resources standards. The EPA is aware of the 

potential for interactions between ERCs and RECs or EECs and encourages the states to 

consider, when developing their state plan, how existing instruments that are used to meet other 

regulatory requirements or in voluntary markets may interact with ERCs.

For more information about specific methods to adjust the CO2 emission rate of an affected EGU 

to reflect renewable energy generation and eligibility requirements for resources that can be used 

to adjust a CO2 emission rate, including eligibility dates and the types of RE MWhs that are 

eligible, see Section VIII.K.1. Requirements for rate-based emission trading programs and the 

issuance and tracking of ERCs, including qualifying measures, programs or projects and 

addressing the potential for interactions between ERCs and RECs, are in section VIII.K.2 of the 

final rule preamble of the CPP. Section VIII.K.3 of the final rule preamble of the CPP describes 

the requirements and criteria related to proper quantification and verification of MWhs from 

renewable electricity generation and demand-side EE.

In terms of electric grid regions used for determining BSER. The EPA recognizes that the North 

American electric grid has developed into a large, interconnected system. Electricity from a 

diverse set of generation resources such as natural gas, nuclear, coal, and renewables is 

distributed over high-voltage transmission lines divided across the continental United States into 

three synchronous interconnections – the Eastern Interconnection, Western Interconnection, and 

the Texas Interconnection. These three synchronous systems each act like a single machine.

The following are summaries of the specific public comments under this comment:

Commenters provided comments on the appearance that the proposed rule does not allow 

regional agreements between non-contiguous states. Commenters stated that the proposal only 

appears to allow contiguous states to participate in a regional demonstration of emission 

performance, which would obviate the need to specifically assign RE reductions to specific 

states. Commenters asserted that there are states that are not contiguous but that may want to 

participate in multi-state plans or that may want to use out of state RECs or RE generation from 

non-contiguous states to demonstrate compliance. Commenters noted that many states allow the 

purchase of RECs over large, multistate regions, as well as the acquisition of RE or zeroemissions attributes of RE through bilateral contracts or building in-state- or out-of-state- RE 

generation, and are not limited to actions in "neighboring" states. Commenters stated that 

limiting regional demonstrations to contiguous states would increase the cost of compliance. 

Commenters requested that imports/exports of renewable energy not be limited to contiguous 
92

states or ISO regions, but not extended to international imports. Commenters further remarked 

that additional restrictions or prohibitions on imports and exports (including requirements that 

attributes be bundled with generation) could result in artificial barriers and price signals in the 

market which could impede interstate flow of renewable energy. Commenters noted that the 

State where the renewable attribute is applied should be the state that applies that renewable 

electricity to their carbon intensity reductions, following the renewable attribute contract path. 

Commenters argued that the proposed rule does not recognize that regional power markets and 

balancing authorities do not match state geographic boundaries; commenters also argued that 

many states are split among multiple balancing authorities and will require additional guidance 

to comply with the rule. Commenters further noted that EPA did not define "electric grid 

region".

Comment 10: Role of FERC, impacts on consumer rates, and inequities in assigning state 

emission rates.

Response 10: In the development of the final rule, EPA officials worked closely with DOE and 

Federal Energy Regulatory Commission (FERC) officials to ensure, to the greatest extent 

possible, that actions taken by states and affected EGUs to comply with the final rule mitigate 

potential electric system reliability issues. Senior EPA officials met with each of the FERC 

Commissioners and EPA staff had frequent contact with FERC staff throughout the development 

the rule. FERC held four technical conferences to discuss implications of compliance approaches 

to the rule for electric reliability. EPA staff attended the four conferences and EPA leadership 

spoke at all of them. The EPA, DOE, and FERC will continue to work together to ensure electric 

grid reliability in the development and implementation of state plans. For more information 

about reliability considerations, see Section II.D and for more detail about EPA consultations 

about reliability, see section II.K of the final rule preamble of the CPP.

The EPA recognizes that there are multiple incentives for states to collaborate by implementing a 

multi-state plan. That is why EPA has promulgated a final rule that allows states to meet an 

aggregated joint goal, regardless of the specific level of their individual goals, because states 

share grid regions and impacts from plan implementation will be regional in nature. Further, 

multiple analyses, including those by ISOs and RTOs, indicate that regional approaches could 

achieve state goals at lesser cost than individual state plan approaches. However, the EPA also 

recognizes the value in allowing for collaboration where states retain individual goals. These 

approaches could provide some of the benefits of a joint goal while reducing the negotiations 

among states necessary to develop a multi-state plan with a joint goal. As a result, the EPA has 

finalized the additional multi-state approaches described above in section VIII.C.5 of the final 

rule preamble of the CPP to provide for coordination while maintaining individual goals. These 

approaches would allow for interstate transfer of energy rate credits (ERCs) or emission 

allowances while retaining individual state goals.

The final CPP is also allowing a state plan design that allows states to include new sources under 

certain conditions. A state may elect to use is mass-based emission standards applied to affected 

EGUs. Under this approach, the plan would include federally enforceable emission standards for 

mass CO2 emissions from affected EGUs. The plan would be designed to achieve the mass-based 
93

CO2 goal for a state’s affected EGUs (see section VII) or a level of CO2 emissions equal to or 

less than the mass-based CO2 goal plus the new source complement CO2 emissions (see section 

VIII.J.2.b of the final rule preamble of the CPP for details.) For example, a state plan designed to 

meet a state mass-based CO2 goal for affected EGUs plus a new source complement could 

include a mass-based emission budget trading program that applies to both affected EGUs, as 

well as new fossil fuel-fired EGUs. The program requirements for affected EGUs would be 

federally enforceable, while the program requirements for other fossil fuel-fired EGUs would be 

state-enforceable. This approach is described further in section VIII.J.2 of the final rule preamble 

of the CPP.

The following are summaries of the specific public comments under this comment:

Commenters stated that through FERC, the federal government has been actively encouraging, 

and in some instances requiring, the regional and inter-regional coordination of electric industry 

construction, operation, and markets. Commenters stated FERC has aggressively encouraged the 

creation and membership in regional transmission organizations (RTOs). Commenters stated that 

the Proposed Regulation challenges the regional economic dispatch currently employed by PJM

and that under the Proposed Regulation, CO2 dispatch considerations may vary from State to 

State. Additionally, commenters stated that States must make significant decisions about whether 

fossil-fuel units will be forced to retire or operate under substantial environmental constraints, 

both of which can detrimentally affect reliability and customer rates regulated by FERC. 

Commenters also stated that while parts of the Proposed Regulation encourage the States to band 

together to achieve compliance on a regional scale, the inequity of the disparate carbon emission 

rates and the uncertainty regarding compliance complicates attempts at regional compliance 

through cooperation. Commenters stated that by assigning disparate State emission rates, the 

Proposed Regulation tilts the playing field against States that are assigned excessively low 

carbon emission rates for existing units below the emission rates required of new units.

5.7.6 Assessment of interstate effects by the EPA in the course of state plan review

This section addresses comments on EPA's assessment of interstate effects during state plan 

review.

Commenters have raised a number of issues related to this subsection which are organized by 

topics (comments) below. Responses are also provided for these topics.

Comment 1: Assessment of interstate effects by the EPA may create uncertainty for individual 

states; EPA must address how it will assess interstate effects for RE/EE; the EPA should provide 

a mechanism for states to evaluate plans that would be acceptable.

Response 1: In the final rule, EPA revised the methodology used to calculate CO2 emission 

performance rates and state rate-based CO2 goals from the one used in the proposal to better 

reflect the regional nature of the grid among other things. In order to ensure consistency with the 
94

calculation of CO2 performance rates and state rate-based CO2 goals in the final emission 

guidelines, to avoid double-counting or inconsistent adjustment approaches across states, and to 

provide certainty to states regarding acceptable accounting methods, the final rule prescribes a 

general accounting approach states must use to adjust the CO2 emission rate of an affected 

source to reflect the MWh impacts of zero-emitting and low-emitting resource. Quantified and 

verified MWh impacts of qualifying zero-emitting and low-emitting resources tied to a state plan 

may be used by an affected EGU or state to adjust a CO2 emission rate, regardless of whether the 

renewable generation or demand-side EE savings occur inside or outside the state or territory. 

This ensures that affected EGUs receive full recognition for their investments, even if the 

impacts occur elsewhere, removing the need to determine exactly which EGUs reduced and 

changed power generation in response to the zero-emitting or low-emitting resource.

The final rule does not preclude states from determining resource adequacy and conducting 

integrated resource planning but may provide an opportunity for collaboration on resource 

planning and priorities as states develop their state plans.

For a discussion about the elements incorporated into the final rule to minimize double-counting, 

and how the rule addresses interstate effects, see section VIII.L of the final rule preamble of the 

CPP. For more information about specific methods to adjust the CO2 emission rate of an affected 

EGU to reflect demand-side EE and renewable energy, including eligibility dates and the types 

of EE savings and RE MWhs that are eligible, see Section VIII.K.1 of the final rule preamble of 

the CPP. Section VIII.K.3 of the final rule preamble of the CPP describes the requirements and 

criteria related to proper ex post quantification and verification of MWhs from renewable 

electricity generation or demand-side EE. For information about state plan approaches, see

Section VIII.C of the final rule preamble of the CPP.

The following are summaries of the specific public comments under this comment:

Commenters stated that if EPA is the final assessor of interstate effects, it may create uncertainty 

for individual states. Commenters asserted that states would not know whether they could 

include all RE generation included in a plan until after an EPA assessment of all submitted plans. 

They argued that this could undermine a state's ability to achieve target emission rates. 

Commenters suggested that EPA provide clear guidance as to how states should attribute RE 

reductions. Specifically, commenters requested that EPA provide guidance on how to allocate 

RE built by electric utilities to serve customers in multiple states, considering customer 

consumption patterns. 

Commenters raised several questions related to how EPA would assess interstate effects in the 

course of a state plan review. Commenters asked how statewide strategies would become a part 

of utility plans and how EE measures would be treated by EPA in their evaluations. Commenters

suggested that EPA provide examples of strategies and how they might count towards emissions 

reductions, as well as offer a mechanism for states to consistently evaluate plans and strategies to 

determine if they will constitute an acceptable plan. Commenters also stated that EPA should not 

intrude on the right of states to determine resource adequacy and integrated resource planning.
95

Comment 2: The EPA should provide guidance on how to allocate RE that serves customers in 

multiple states.

Response 2: In the final rule, EPA revised the methodology used to calculate CO2 emission 

performance rates and state rate-based CO2 goals from the one used in the proposal to be based 

upon three building blocks and better reflect the regional nature of the grid. In order to ensure 

consistency with the calculation of CO2 performance rates and state rate-based CO2 goals in the 

final emission guidelines, to provide consistent and transparent approach to accounting for RE 

and demand-side EE, and to avoid double-counting or inconsistent adjustment approaches across 

states, the final rule prescribes a general accounting approach states must use to adjust the CO2

emission rate of an affected source to reflect the MWh impacts of zero-emitting and low-emitting 

resource. Quantified and verified MWh impacts of qualifying zero-emitting and low-emitting 

resources tied to a state plan may be used by an affected EGU or state to adjust a CO2 emission 

rate, regardless of whether the renewable generation or demand-side EE savings occur inside or 

outside the state or territory. This ensures that affected EGUs receive full recognition for their 

investments, even if the impacts occur elsewhere, removing the need to determine exactly which 

EGUs reduced and changed power generation in response to the zero-emitting or low-emitting 

resource.

For a discussion about the elements incorporated into the final rule to minimize double-counting, 

and how the rule addresses interstate effects, see Section VIII.L. For more information about 

specific methods to adjust the CO2 emission rate of an affected EGU to reflect demand-side EE 

and renewable energy, including eligibility dates and the types of EE savings and RE MWhs that 

are eligible, see Section VIII.K.1. Section VIII.K.3 of the final rule preamble of the CPP

describes the requirements and criteria related to proper ex post quantification and verification of 

MWhs from renewable electricity generation or demand-side EE. For information about state 

plan approaches, see Section VIII.C of the final rule preamble of the CPP. 

The following are summaries of the specific public comments under this comment:

Commenters urged that EPA provide clear and unequivocal guidance to states regarding 

renewable energy and energy efficiency in order to ensure that plan approval processes are 

consistent. Commenters stated that otherwise, EPA will invite disparate treatment of renewable 

energy and energy efficiency among states, and may lead to states rushing to submit plans in 

order to be the first to get their approach to RE and EE approved and thus, setting a "standard" 

for what can be approved. Commenters stated this will force EPA to follow the approach adopted 

in the first approved plan or risk creating conflicts with subsequent approved plans. 

Commenters noted that this can occur not only within the same EPA Region (for example, 

between North Dakota and South Dakota), it is likely to occur between Regions (such as Iowa 

and Minnesota). Commenters gave an example whereby Minnesota and North Dakota disagree 

over whether Minnesota can count North Dakota wind under building block 3, Minnesota could 

expedite its rulemaking process in a race to beat North Dakota's plan submission and approval. 

Commenters stated that assuming Minnesota did so, and included a provision that allows it to 

count out-of-state wind in North Dakota (and elsewhere), the approval of Minnesota's plan 

would effectively prohibit North Dakota from counting wind located in its own state and owned 

by utilities that operate fossil facilities in North Dakota. Commenters stated that because 
96

Minnesota is located in EPA Region 5 and North Dakota is in EPA Region 8, it not only sets up 

a conflict between the states themselves, but potentially creates a Region by Region conflict. 

Commenters also stated that unless EPA states in uncertain terms that all renewable energy and 

energy efficiency is the property of the utility owner and freely transferable for use in any state, 

it creates a regulatory morass where Wyoming, for example, could allow a utility to use RE and 

EE generated elsewhere to offset CO2 emissions in the state, while Minnesota claims that it is 

entitled to use for its own compliance all RE and EE within its state borders.

Comment 3: The EPA must ensure emission reductions are not eroded due to changes in 

electricity generation between neighboring states with different plan structures.

Response 3: EPA acknowledges in the final rule that there may be interactions between massbased and rate-based plans regarding counting measures, specifically where measures that 

provide substitute or avoided generation, such as RE and demand-side EE, are located in a massbased state and can also be used by a rate-based state in meeting the CO2 performance rates or 

state goals. EPA has determined that, in the context of interactions among rate-based and massbased plans, there is not explicit double-counting of the CO2 emission reductions associated with 

counting measures located in mass-based states, considering the accounting methods outlined in 

this final rule.

Because of the separate accounting of MWhs and CO2 emissions, with emission impacts inherent 

in reported stack CO2 emissions and zero-emitting MWh impacts requiring explicit adjustments, 

the accounting method corresponds with the use of MWh-denominated ERCs in the rate-based 

emission trading framework specified in this rule. This MWh accounting method creates a 

crediting system or rate adjustment process that is indifferent to the rate-based CO2 emission 

goals of individual states, or the specific CO2 emission rate standards that states may apply, and 

the relative stringency of those goals or standards. 

Though there is no risk of double-counting emissions, in response to commenter concern that 

overall CO2 emissions reductions would be foregone in situations where a source in a rate-based 

state counts the MWh from measures in a mass-based state, but the generation from that measure 

acts solely to serve load in the mass-based state, the EPA is restricting the ability of rate-based 

state to claim emission reduction measures, such as RE and demand-side EE, located in massbased states. In order to avoid cutting some states off from regional RE supplies that are assumed 

in the BSER building block 3 and incorporated in the CO2 emission performance rates or state 

rate-based CO2 goals in the emission guidelines, the EPA has determined that it is appropriate for 

rate-based states to count MWhs from RE located in mass-based states, subject to the condition 

that the generation in question was intended to meet electricity load in a state with a rate-based 

plan. 

For a discussion about the elements incorporated into the final rule to minimize double-counting, 

see Section VIII.L. For more information about specific methods to adjust the CO2 emission rate 

of an affected EGU to reflect demand-side EE and renewable energy, including eligibility dates 

and the types of EE savings and RE MWhs that are eligible, see section VIII.K.1 of the final rule 

preamble of the CPP. Requirements for rate-based emission trading programs and the issuance 
97

and tracking of ERCs, including qualifying measures, programs or projects, addressing the 

potential for interactions between ERCs and RECs or EECs, are addressed in section VIII.K.2 of 

the final rule preamble of the CPP. Section VIII.K.3 of the final rule preamble of the CPP

describes the requirements and criteria related to proper ex post quantification and verification of 

MWhs from renewable electricity generation or demand-side EE savings to avoid overestimation 

as suggested by commenters. For information about mass-based emission standards with a 

market-based emission budget trading program, see Section VIII.C.2 and VIII.J.2 of the final 

rule preamble of the CPP.

The following are summaries of the specific public comments under this comment:

Commenters stated that in order to fulfill the statutory mandate to address harmful air pollution 

through limitations on emissions, the EPA must ensure that states achieve the necessary 

reductions through the actions taken in their plans and that emission reductions are not eroded 

due to changes in electricity generation between neighboring states that have different plan 

structures (rate vs. mass) or different target rates. 

Comment 4: Guidance needed on accounting for CO2 emissions from owned or purchased 

generation located in different states.

Response 4: In the final rule, EPA revised the methodology used to calculate CO2 emission 

performance rates and state rate-based CO2 goals from the one used in the proposal to be based 

upon three building blocks and better reflect the regional nature of the grid. In order to ensure 

consistency with the calculation of CO2 performance rates and state rate-based CO2 goals in the 

final emission guidelines, and to avoid double-counting or inconsistent adjustment approaches 

across states, the final rule prescribes a general accounting approach states must use to adjust the 

CO2 emission rate of an affected source to reflect the MWh impacts of zero-emitting and lowemitting resource. Quantified and verified MWh impacts of qualifying zero-emitting and lowemitting resources tied to a state plan may be used by an affected EGU or state to adjust a CO2

emission rate, regardless of whether the renewable generation or demand-side EE savings occur 

inside or outside the state or territory. This ensures that affected EGUs receive full recognition 

for their investments, even if the impacts occur elsewhere, removing the need to determine 

exactly which EGUs reduced and changed power generation in response to the zero-emitting or 

low-emitting resource.

EPA offers states the flexibility to choose the state plan approach and assign the responsibility 

for CO2 reductions and emission performance rates across the fleet of their affected EGUs in a 

manner that works best for their priorities and circumstances and still meets the emission 

guidelines. States can choose an emissions standards approach by placing federally enforceable 

emissions standards on their affected EGUs but implement complementary energy efficiency 

programs don’t explicitly receive credit under the final guidelines but lower the cost of 

compliance. Under the state measures approach, states can adopt a plan that does not place all the 

obligations on affected EGUs but includes measures implemented by the state, or by entities 

other than affected EGUs, that result in avoided generation and CO2 emission reductions at 

affected EGUs.
98

For a discussion about the elements incorporated into the final rule to minimize double-counting, 

and how the rule addresses interstate effects, see section VIII.L of the final rule preamble of the 

CPP. For more information about specific methods to adjust the CO2 emission rate of an affected 

EGU to reflect demand-side EE and renewable energy, including eligibility dates and the types 

of EE savings and RE MWhs that are eligible, see section VIII.K.1. Section VIII.K.3 of the final 

rule preamble of the CPP describes the requirements and criteria related to proper ex post 

quantification and verification of MWhs from renewable electricity generation or demand-side 

EE. For information about state plan approaches, see Section VIII.C of the final rule preamble of 

the CPP. 

The following are summaries of the specific public comments under this comment:

Commenters stated that EPA should apply 111(d) standards at the EGU, limited to technologies 

that can be implemented specifically at the EGU. Given the EPA's approach to proposing BSER 

as the entire electric system, commenters suggested that a state plan for implementation should 

equitably distribute the burden of required improvements, emission reductions and the cost of 

implementing emission reductions across all electric customers and utilities within a state. 

Commenters stated that all electricity customers and utilities should fairly share and contribute to 

carbon dioxide reductions in order to meet the energy policy being proposed by the EPA. 

Commenters stated that language should be added to the proposed CPP in the State Plan 

Components section, clarifying how owned or purchased generation, and associated CO2

emissions, from generating units located in different states should be accounted, regardless of the 

development and implementation of multi-state plans. Commenters noted that item 8 of 12 in 

that section discusses possible accounting for renewables including wind and EE for distribution 

utilities that operate in multiple states.

5.7.7 Other

This section contains comments on the treatment of interstate effects that are not addressed in 

other subsections of 5.7.

Commenters have raised a number of issues related to this subsection which are organized by 

topics (comments) below. Responses are also provided for these topics.

Comment 1: General support for multi-state approaches. Proposed rule did not provide enough 

information on how states may develop multi-state agreements.

Response 1: In the final rule, the EPA views the ability of a state to implement an individual 

plan or a multi-state plan as a significant flexibility that allows a state to tailor implementation of 

its plan to state policy objectives and circumstances. The EPA sees particular value in multi-state 

plans, which allow states to implement a plan in a coordinated fashion with other states. Such 

approaches can lead to more efficient implementation, lower compliance costs for affected EGUs 
99

and lower impacts on electricity ratepayers. Coordinated approaches also will help states identify 

and address any potential electric reliability impacts when developing plans.

The EPA received broad support in comments for allowing states to implement multi-state plan 

approaches, and has made multiple changes in the final rule to address many suggestions 

outlining different approaches states may want to take. These changes are intended to provide 

streamlined approaches for multi-state coordination while maintaining transparency and assuring 

that the CO2 emission performance rates or state CO2 emission goals are achieved.

The EPA is finalizing two approaches that allow states to coordinate implementation in order to 

meet the emission guidelines, as described in section VIII.C.5 of the final rule preamble of the 

CPP.

In response to comments, the EPA is also further clarifying how multi-state plans with a joint 

goal for affected EGUs may be implemented. The EPA is clarifying that states may participate in 

more than one multi-state plan, if necessary, for example, to address affected EGUs in states that 

are served by more than one ISO or RTO. The EPA is further clarifying that a subset of affected 

EGUs in a state may participate in a multi-state plan. These clarifications are discussed in section 

VIII.C.5.d of the final rule preamble of the CPP and the forms of submittal that states may 

choose for a multi-state plan are discussed in Section VIII.E.4 of the final rule preamble of the 

CPP.

The EPA agrees that the development of a multi-state plan may require additional time and, in 

this final rule the EPA is allowing for states participating in a multi-state plan to submit a request 

for a 2 year extension as described in Section VIII.E.2 of the final rule preamble of the CPP.

While the final rule does not explicitly require numerous state agencies and other organizations 

to work together in a regulatory context, the EPA encourages states to work engage key 

stakeholders as they develop their plan. EPA does not require the inclusion of an interstate 

enforcement mechanism. Specific details regarding the elements required in a multi-state plan 

are described in Section VIII.E.4 of the final rule preamble of the CPP. In the final rule, 

quantified and verified MWh impacts of qualifying zero-emitting and low-emitting resources 

tied to a state plan may be used by an affected EGU or state to adjust a CO2 emission rate, 

regardless of whether the renewable generation or demand-side EE savings occur inside or 

outside the state or territory. Consistent with the EPA’s calculation of the CO2 emission 

performance rates and state rate-based CO2 goals in the final emission guidelines which better 

reflects the regional nature of the grid and does not include demand-side EE in the calculation of 

BSER, the MWhs impacts are added to the denominator of an affected EGU’s reported CO2

emission rate, resulting in a lower, adjusted CO2 emission rate. Because of the separate 

accounting of MWhs and CO2 emissions, with emission impacts inherent in reported stack CO2

emissions and zero-emitting MWh impacts requiring explicit adjustments, the accounting 

method corresponds with the use of MWh-denominated Emission Rate Credits (ERCs) in the 

rate-based emission trading framework specified in this rule. The MWh accounting method 

addresses interstate effects, because it inherently accounts for how generation replacement and 

CO2 emission reduction impacts may cross state borders and is indifferent to avoided CO2

emission rates; it creates the same number of zero-emitting credits or adjustment for each MWh 

of energy generation or savings, wherever they occur.
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An ERC is issued separately from any other instruments that may be issued for a MWh of energy 

generation or energy savings from a qualifying measure, such as a renewable energy certificate 

(REC). An ERC may be issued, however, based on the same data and verification requirements 

used by existing REC tracking systems for issuance of RECs and EECs that are used to meet 

state renewable portfolio standards or energy efficiency resources standards. The EPA is aware 

of the potential for interactions between ERCs and RECs or EECs and encourages the states to 

consider, when developing their state plan, how existing instruments that are used to meet other 

regulatory requirements or in voluntary markets may interact with ERCs.

The EPA received a number of comments from states and stakeholders about the value of the 

EPA’s support in developing and/or administering tracking systems to support state 

administration of rate-based emission trading systems. This could include regional systems 

and/or a national system. The EPA is exploring options for providing such support and is 

conducting an initial scoping assessment of tracking system support needs and functionality.

The EPA will also provide support and technical resources to assist states as they develop For 

more information about specific methods to adjust the CO2 emission rate of an affected EGU to 

reflect renewable energy generation and eligibility requirements for resources that can be used to 

adjust a CO2 emission rate, including eligibility dates and the types of RE MWhs that are 

eligible, see Section VIII.K.1 of the final rule preamble of the CPP. Requirements for rate-based 

emission trading programs and the issuance and tracking of ERCs, including qualifying 

measures, programs or projects and addressing the potential for interactions between ERCs and 

RECs, are in section VIII.K.2 of the final rule preamble of the CPP. Section VIII.K.3 of the final 

rule preamble of the CPP describes the requirements and criteria related to proper quantification 

and verification of MWhs from renewable electricity generation and demand-side EE.

The following are summaries of the specific public comments under this comment:

Commenters supported multi-state coordination for compliance, stating that multi-state 

approaches will encourage more efficient and cost-effective compliance options. Commenters

noted that there have been several successful multi-state programs, such as regional haze 

regulations and RGGI. Commenters supported allowing states the flexibility to design programs 

that allow for multi-state collaboration, including mechanisms to trade RE and EE credits, or 

agreements to allocated avoided emissions from RE and EE. Commenters suggested that EPA 

clarify the variety of collaborative options available to states to encourage participation in multistate plans. Commenters inquired whether multi-state arrangements needed to include an 

interstate enforcement mechanism. Commenters asked that EPA provide guidance on the full 

range of potential multistate approaches, including agreements about renewable energy and 

energy efficiency, frameworks allowing emission reduction credits to cross state lines, and joint 

state plans. Commenters suggested that EPA and DOE make available information about 

regional electricity flows and interstate impacts of state programs to support collaboration, and 

provide guidance on how states can collaborate regionally. Commenters also supported 

providing an extended timeline for development of a multi-state plan. 

Commenters supported multi-state coordination to address multi-state utilities. Commenters

stated that a utility with compliance obligations arising from both 111(d) and RPS laws in 

multiple states cannot retire a REC for RPS compliance in one state (where the RPS is part of the 
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state's plan) and submit the same REC or MWh for another state's 111(d) compliance, without a 

multi-state agreement that ensures the total level of emissions reductions remains the same. 

Commenters noted that if states have combined their compliance obligations in a manner that 

ensures equivalent total emissions reductions, this approach could provide a low cost, efficient 

course of action.

Commenters asserted that the proposed rule did not provide enough information on how states 

may develop multi-state agreements. Commenters urged that in states where no multi-state 

program currently exists, EPA's proposed guidelines will require numerous state agencies and 

other organizations to work together in a regulatory context. Commenters noted that due to the 

complexity of these multi-state arrangements, the widespread usage of this approach in the nearterm is unlikely. Commenters further agreed with the proposed approach to apply actual CO2

emissions to the state in which they are generated. However, commenters also stated that it is 

problematic to limit compliance to only those actions within a state's borders when it comes to 

renewable electric generation. Commenters requested that the state's compliance plans allow for 

interstate transfer of carbon-free generation (MWH) or the credit for this type of generation, and 

that EPA establish procedures in their final regulations that provide clear guidance on the process 

in which carbon-free generation could be tracked on an interstate basis. Commenters further 

suggested that EPA consider being "the clearinghouse" for carbon-free generation tracking, to 

ensure the transferred MWH are accounted for. Commenters argued that this approach would 

expedite the use of interstate renewable generation without the need for lengthy negotiations 

between state agencies. 

Finally, Commenters expressed concern with the proposed rule's recommendation to require 

states that are net importers of power to transfer or discount the reductions achieved by end-use 

EE programs to the states where the generation occurs. Commenters argued that the transferring 

or discounting process was unnecessarily burdensome; specifically, Commenters argued that it is 

unnecessary to add the burden of determining the generating source for each MWH consumed in 

every state, since Building Block 4 establishes the same 2030 annual cumulative energy 

efficiency target of 1.5% for all states. Commenters requested that EPA allow states to adjust 

their MWH generated by the state's achieved level of end-use EE.

Comment 2: Multi-state approaches should include a process to address states joining/leaving 

the arrangement.

Response 2: The EPA agrees that a multi-state approach should include a process to address 

states joining or leaving a collaborative process or arrangement and provides explicit details in 

Section VIII.E.7.a of the final rule preamble of the CPP. 

The following are summaries of the specific public comments under this comment:

Commenters stated that multi-state approaches should include a process to address states joining 

or leaving a collaborative process or arrangement. Commenters recommended that EPA work 

with states to identify "on-ramps" and "off-ramps" in multi-state plans. Commenters

recommended that EPA provide guidance on how states could use a plan revision or other 
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mechanism to join or form future multi-state collaborations. Commenters expressed concern with 

how complying states in a multi-state arrangement would deal with potentially non-complying 

states.

Comment 3: Comments on how state compliance plays into compliance in other regional 

markets.

Response 3: In the final rule, mass-based plans rely exclusively upon reported stack emissions 

for determining whether a mass-based CO2 emission goal is achieved by the state or affected 

EGUs while for rate-based plan compliance, the final rule specifies a general accounting 

approach where quantified and verified MWh impacts of qualifying zero-emitting and lowemitting resources tied to a state plan may be used by an affected EGU or state to adjust a CO2

emission rate. The final rule does not explicitly require an assessment of how state compliance 

plays into the compliance of other regional markets as it is not relevant to compliance with the 

final rule. For more information about plan performance demonstration, see Section VIII.F.2 of 

the final rule preamble of the CPP.

The following are summaries of the specific public comments under this comment:

Commenters asked the EPA to consider not only whether states are meeting their own 

compliance goals, but also how state goals would play into the compliance of other regional 

markets.

Comment 4: The EPA should emphasize model plan components to facilitate state deployment 

of renewable energy and demand-side energy efficiency.

Response 4: In the final rule, the EPA encourages the use of renewable energy and energy 

efficiency to meet a mass-based or rate-based approach. Construction and use of renewable 

energy in a mass-based state can replace affected EGU generation and help bring the state closer 

to compliance. Under a rate-based approach, the final guidelines provide specific detail regarding 

criteria, eligibility and measurement and verification requirements related to the renewable 

energy and energy efficiency measures that may be used by an affected EGU or state to adjust a 

CO2 emission rate, regardless of whether the renewable generation or demand-side EE savings 

occur inside or outside the state or territory. The final rule also describes how and under what 

circumstances, under a rate-based state plan approach, eligible renewable energy and demandside energy efficiency may be issued an emission rate credit that can be used in a rate-based 

trading program. 

EPA is proposing a rate-based and a mass-based model rule for potential use by any state. The 

proposed model rule includes a set of presumptively approvable EM&V provisions that, if 

adopted, will likely satisfy the broad requirements for quantifying and verifying savings 

established in the final emissions guidelines. These provisions address a broad range of EM&V 

components, such as the application of protocols and guidelines, usage of EM&V methods, 
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determination of effective measure life (EUL), and others. Taken together, these provisions 

constitute a presumptively approvable approach for using demand-side EE to generate “emission 

rate credits” (ERCs) for use in state-led emission trading programs, and to otherwise adjust an 

EGU or statewide emission rate (consistent with the state plan submittal). To help states and EE 

providers satisfy the model rule provisions for EM&V, the draft EM&V guidance provides 

additional detail on options and approaches for implementing the provisions.

For more information about specific methods to adjust the CO2 emission rate of an affected EGU 

to reflect demand-side EE and eligibility requirements for resources that can be used to adjust a 

CO2 emission rate, including eligibility dates and the types of EE savings and RE MWhs that are 

eligible, see Section VIII.K.1 of the final rule preamble of the CPP. Requirements for rate-based 

emission trading programs and the issuance and tracking of ERCs, including qualifying 

measures, programs or projects, addressing the potential for interactions between ERCs and 

RECs or EECs, are addressed in section VIII.K.2 of the final rule preamble of the CPP. Section 

VIII.K.3 of the final rule preamble of the CPP describes the requirements and criteria related to 

proper ex post quantification and verification of MWhs from renewable electricity generation or 

demand-side EE savings. For more information about the EM&V provisions proposed for the 

model rule and the draft guidance document, see Section IV.D.8 of the preamble to the proposed 

Federal Plan and the draft guidance document.

The following are summaries of the specific public comments under this comment:

Commenters asserted that EPA should emphasize model plan components to facilitate state 

deployment of renewable energy and demand-side energy efficiency. Commenters also requested 

that EPA specify minimum criteria or requirements for each policy approach to ensure 

enforceability. 

Comment 5: Concerns with state-by-state approach; rule must recognize complexity of 

ownership of EGUs generating RE and differing regulatory structures between states.

Response 5: EPA revised the methodology used to calculate CO2 emission performance rates 

and state rate-based CO2 goals from the one used in the proposal to better reflect the regional 

nature of the grid among other things. Consistent with the calculation of CO2 performance rates 

and state rate-based CO2 goals in the final emission guidelines quantified and verified MWh 

impacts of qualifying zero-emitting and low-emitting resources tied to a state plan may be used 

by an affected EGU or state to adjust a CO2 emission rate, regardless of whether the renewable 

generation or demand-side EE savings occur inside or outside the state or territory. The final rule 

allows interested states to participate in interstate trading programs depending upon the type of 

approach the state selects and specifies a unique acceptable unit of trading under a rate-based 

approach, the emission rate credit (ERC), a tradable compliance unit representing one MWh of 

electric generation (or reduced electricity use) with zero associated CO2 emissions.

An ERC is issued separately from any other instruments that may be issued for a MWh of energy 

generation from a qualifying measure, such as a renewable energy certificate (REC). An ERC 

may be issued, however, based on the same data and verification requirements used by existing 

REC tracking systems for issuance of RECs that are used to meet state renewable portfolio 
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standards. The EPA is aware of the potential for interactions between ERCs and RECs and 

encourages but does not require that the states to consider, when developing their state plan, how 

existing instruments that are used to meet other regulatory requirements or in voluntary markets 

may interact with ERCs.

As described in the summary of major provisions section of the final rule (Section I.A.3), the 

EPA recognizes that each state has differing policy considerations – including varying regional 

emission reduction opportunities and existing state programs and measures – and that the 

characteristics of the electricity system in each state (e.g., utility regulatory structure and 

generation mix) also differ. Therefore, as in the proposal, each state will have the latitude to 

design a program to meet source-category specific emission performance rates or the equivalent 

statewide rate- or mass-based goal in a manner that reflects its particular circumstances and 

energy and environmental policy objectives. Each state can do so on its own, or a state can 

collaborate with other states and/or tribal governments on multi-state plans, or states can include 

in their plans the trading tools that EGUs can use to realize additional opportunities for cost 

savings while continuing to operate across the interstate system through which electricity is 

produced. A state would also have the option of adopting the model rules for either a rate- or a 

mass-based program that the EPA is proposing concurrently with this action.

The final rule clarifies a role for ISO/RTO assessment of reliability implications as states 

develop their plans as specified in Section VIII.G.2.c of the final rule preamble of the CPP.

For more information about specific methods to adjust the CO2 emission rate of an affected EGU 

to reflect renewable energy generation and energy efficiency, including eligibility requirements 

for resources that can be used to adjust a CO2 emission rate, see Section VIII.K.1 of the final rule 

preamble of the CPP. Requirements for rate-based emission trading programs and the issuance 

and tracking of ERCs, including qualifying measures, programs or projects, and a discussion of 

addressing the potential for interactions between ERCs and RECs, are in section VIII.K.2 of the 

final rule preamble of the CPP. Section VIII.K.3 of the final rule preamble of the CPP describes 

the requirements and criteria related to proper quantification and verification of MWhs from 

renewable electricity generation. For more information about specific methods to adjust the CO2

emission rate of an affected EGU to reflect demand-side EE and renewable energy, including 

eligibility dates and the types of EE savings and RE MWhs that are eligible, see Section VIII.K.1

of the final rule preamble of the CPP. Section VIII.K.3 of the final rule preamble of the CPP

describes the requirements and criteria related to proper ex post quantification and verification of 

MWhs from renewable electricity generation or demand-side EE savings. 

The following are summaries of the specific public comments under this comment:

Several commenters expressed concerns regarding the use of a state-by-state approach to achieve 

compliance given the presence of interstate effects. Commenters noted that the proposed goals, 

which are state-based, fail to account for the fact that the national electricity system operates 

across both state and/or tribal lines. 

Commenters asserted that EPA must clarify that all non-emitting energy and associated 

credits/attributes may be used in any state for compliance, and that the owner of the generation 

has the sole right to determine when and where to use the eligible generation and/or its 
105

credits/attributes for compliance. Commenters argued that no state should be able to unilaterally 

claim a right to utilize generation, credits, or attributes to which it does not directly have title. 

Commenters asserted that utilities have developed their portfolio of resources to achieve certain 

goals and have been free to choose such resources based on where the resource is located, the 

nature of the resource, the capital costs, the operating costs, available transmission, permitting 

and land use acquisition, and other factors. As such, Commenters argued that the final rule 

should in no way authorize the interference with contract or property rights of utilities to their 

own generation, and that utilities should be free to use the non-emitting resources and attributes 

in interstate commerce without fear of any state-imposed restrictions. Commenters made similar 

comments with respect to energy efficiency, stating that EPA must make explicit that energy 

savings must also be available for compliance in any state, regardless of where the savings occur, 

and that the proposed rule does not authorize states to interfere with the contract, property rights, 

or usage of energy savings in which utilities have made investment. Commenters urged EPA to 

provide in the final rule that renewable energy credits would be initially allocated to the entities 

that own the right to use or sell the renewable power associated with such credits.

Commenters expressed concern that the state-by-state approach negatively affects resources 

located in states and owned by entities that do not serve retail load or have retail service territory 

in that state. Commenters noted that if each affected resource in a state must comply with the 

state's plan, the entity would not have the ability to apply lower-cost compliance methodologies 

without EPA support of flexible allocation of RE and EE compliance attributes among entities in 

the state. Commenters argued that the approach in the proposed rule will prevent utilities from 

constructing renewable resources, because there are no assurances that those resources can be 

used to achieve compliance with CO2 reduction goals in the various states in which they operate. 

Commenters remarked that the proposed rule limits utilities to the interests of states, which could 

limit renewable resources to those located within state borders. Commenters urged that this could 

discourage utilities from investing in clean energy in a state if the energy credits are not 

transferable, and would force utilities to locate renewables only in the states where they emit 

CO2, which could increase costs. 

Commenters asserted that energy-importing states would be at the mercy of another state's plan 

to comply with the rule. Commenters suggested that a neighboring state could consider moving a 

large share of the compliance costs to consumers in an energy-importing state to meet its goals. 

Commenters stated that this could have unintended impacts on organized markets that cross state 

borders, and give certain states and unfair economic advantage. Commenters stated that the 

proposed rule requires states to make substantial carbon reductions to in-state generation fleets 

that often include units that serve only other States. Commenters stated that the proposed rule 

potentially places those facilities at a disadvantage compared to in-state facilities that are used to 

serve in-state customers. Specifically, commenters urged that the proposed rule could create 

substantial additional stranded costs for these facilities.

Commenters provided that utilities in a tribal area may be owned by participants in neighboring 

states, by both private and public participants, and may include utilities with operating facilities 

located in multiple jurisdictions. Commenters argued that the proposed rule fails to provide clear 

rules on how multi-jurisdictional entities will be regulated and receive credit for reductions. 

Commenters) also asserted that the proposed rule only proposes default rules on calculations for 

states plans as a whole, and ignores non-state entities that operate across state line or multi-
106

jurisdictional entities. Commenters argued that utilities which reduce coal by increasing lowemitting or zero-emitting generation do not receive any credits for such reductions because they 

are not the EGU operator.

Commenters also stated that the proposed rule appears to assume that the procurement of RE 

stops at state boundaries, and does not recognize the complexity of sources and ownership 

partners that must be taken into consideration with developing an implementation plan. 

Commenters reiterated that states procure electricity through RECs from EGUs that are diverse 

in terms of geographic location, fuel source, and ownership partners, including large for-profit 

investor owned utilities, municipal utilities, and multi-state cooperatives. Commenters also noted 

that these states may include EGU and transmission facilities within multiple regional 

transmission organizations. Commenters argued that the complexities of EGU ownership will 

complicate development of appropriate state plans, and may warrant more time for development. 

Commenters asserted that the state-by-state approach is at odds with an interconnected, interstate wholesale market where power is routinely produced in one state and consumed in another, 

and where a transmission system may be interconnected with several transmission and power 

authorities. Commenters also noted that the FERC has been actively establishing policies and 

regulations that encourage vibrant wholesale markets and it is not clear how to reconcile these 

policies with EPA's emissions reduction proposal.

Commenters stated that the way the Proposed Guidelines are written, EE and CO2 reduction 

requirements are calculated on a state basis; but EE impacts generation requirements that are 

realized on a cross-state border system basis. Commenters stated that EE benefits (avoided 

energy and capacity) impact a utility operating company's entire system. Commenters noted that 

the generation system for a utility may be located in different states, whereby establishing carbon 

reduction goals on a state-by-state basis may lead to cross-subsidization between states with 

respect to EE program costs. Commenters stated that the Proposed Guidelines do not include the 

specifics for utilities in RTOs/ISOs, other than that the RTOs/ISOs will help the states develop 

their plans. Commenters contended that the Proposed Guidelines are so vague on this point that it 

is difficult to provide meaningful comments regarding RTOs/ISOs and the impact of EE. Also, 

commenters stated that the Proposed Guidelines do not differentiate between retail choice states 

and vertically integrated states, which will greatly impact the extent to which RTOs/ISOs will 

need to participate. Commenters stated that in retail choice states like Ohio, where the utility 

customers are purchasing retail generation from Competitive Retail Electric Service (CRES) 

providers, it is unclear how the CO2 requirement will be calculated as the CRES provider may be 

located in a different state. Therefore, Commenters encouraged EPA to develop guidelines that 

contain sufficient detail so that electric utilities have the opportunity to understand how these 

rules impact them and their customers before being implemented. Commenters contended that 

the lack of detail in the Proposed Guidelines has the effect of creating significant uncertainty as 

to how these requirements will impact their electric power producing company and in turn, will 

likely increase the costs of providing electric service.

Commenters stressed the importance of recognizing the inherent differences in rate-based versus 

competitive energy markets and the need to provide for electric grid reliability. Commenters

noted that there will be issues between EGUs in states that operate in a competitive energy

market and EGUs in states that operate in a rate-based market that EPA must consider in a 
107

balanced way. As an example, commenters asked how the Clean Power Plan Rule will achieve 

economic and regulatory parity based on the expanding zone of influence of Regional 

Transmission Organizations (RTOs). Commenters questioned whether EPA could extend its 

regulatory authority in order to influence decisions made by RTOs, and how state agencies are to 

regulate decisions made by RTOs.

Comment 6: Unfair or unequal obligations among states; proposed rules would engender 

conflict among states.

Response 6: In the final rule, quantified and verified MWh impacts of qualifying zero-emitting 

and low-emitting resources tied to a state plan may be used by an affected EGU or state to adjust 

a CO2 emission rate, regardless of whether the renewable generation or demand-side EE savings 

occur inside or outside the state or territory. This ensures that affected EGUs receive full 

recognition for their investments even if the impacts occur elsewhere, removes the need to 

determine exactly which EGUs reduced and changed power generation in response to the zeroemitting or low-emitting resource and ensures that quantified and verified MWh impacts of 

qualifying zero-emitting and low-emitting resources are applied consistently across all affected 

EGUs. The accounting method corresponds with the use of MWh-denominated Emission Rate 

Credits (ERCs) in the rate-based emission trading framework specified in this rule. The 

accounting method only requires a quantification of the MWh generated or avoided by an 

eligible measure, and thus credits or adjustments can be denominated in MWh and do not need to 

represent an approximation of the CO2 emission reductions that result from those MWhs. This 

creates a crediting system or rate adjustment process that is simpler to implement than one that 

requires an approximation of avoided CO2 emissions. The MWh accounting method also creates 

a crediting system or rate adjustment process that is indifferent to the rate-based CO2 emission 

goals of individual states, or the specific CO2 emission rate standards that states may apply, and 

the relative stringency of those goals or standards.

For more information about specific methods to adjust the CO2 emission rate of an affected EGU 

to reflect demand-side EE and eligibility requirements for resources that can be used to adjust a 

CO2 emission rate, including eligibility dates and the types of EE savings and RE MWhs that are 

eligible, see Section VIII.K.1. Requirements for rate-based emission trading programs and the 

issuance and tracking of ERCs, including qualifying measures, programs or projects, addressing 

the potential for interactions between ERCs and RECs or EECs, are addressed in section 

VIII.K.2 of the final rule preamble of the CPP. Section VIII.K.3 of the final rule preamble of the 

CPP describes the requirements and criteria related to proper ex post quantification and 

verification of MWhs from renewable electricity generation or demand-side EE savings. For 

more information about Interstate effects, see section VIII.L of the final rule preamble of the 

CPP. 

The following are summaries of the specific public comments under this comment:

Commenters asserted that EPA's Proposed Guidelines would impose unfair or unequal 

obligations or engender conflict among the states. Commenters argued that EPA has proposed 

conflicting approaches to crediting RE and EE reductions and for the treatment of individual 
108

state vs. multi-state plans. Commenters provided as an example the difference between the 

proposed approach for states to take into account all RE measures implemented for purposes of 

compliance with a RPS (regardless of whether the RE is generated in-state or out-of-state) and 

the proposed approach to limit credit for EE-related emission reductions to in-state activities 

only. Commenters argued that the proposed rules are overly simplistic and, as proposed, would 

create serious problems for states. Commenters expressed concerns that states may have 

significantly different proposed carbon intensity goals and other unique characteristics, which 

would impose unworkable interstate compliance demonstration and recordkeeping obligations on 

utilities. Commenters specifically noted that utilities with regional territory or ownership 

crossing the state lines of New Mexico, Texas, and Arizona could result in impossible 

compliance demonstration.

Comment 7: Rule does not credit non-RE energy and should treat all power fairly for 

accounting purposes.

Response 7: The EPA revised the methodology used to calculate CO2 emission performance 

rates and state rate-based CO2 goals from the one used in the proposal. In order to ensure 

consistency with the calculation of CO2 performance rates and state rate-based CO2 goals in the 

final emission guidelines, and to avoid double-counting or inconsistent adjustment approaches 

across states, the final rule prescribes a general accounting approach states must use to adjust the 

CO2 emission rate of an affected source to reflect the MWh impacts of zero-emitting and lowemitting resource. Quantified and verified MWh impacts of qualifying zero-emitting and lowemitting resources, tied to a state plan may be used by an affected EGU or state to adjust a CO2

emission rate, regardless of whether the renewable generation or demand-side EE savings occur 

inside or outside the state or territory. This ensures that affected EGUs receive full recognition 

for their investments, even if the impacts occur elsewhere, removing the need to determine 

exactly which EGUs reduced and changed power generation in response to the zero-emitting or 

low-emitting resource. 

For more information about specific methods to adjust the CO2 emission rate of an affected EGU 

to reflect renewable energy and eligibility requirements for resources that can be used to adjust a 

CO2 emission rate, including the eligibility of nuclear, hydropower and international RE in 

Section VIII.K.1 of the final rule preamble of the CPP. For more information about how the rule 

and accounting method addresses interstate effects, see Section VIII.L of the final rule preamble 

of the CPP. .

The following are summaries of the specific public comments under this comment:

Commenters stated that EPA did not address interstate accounting of CO2 reductions associated 

with interstate implications related to the trading/transmission of all power, not just RE and EE 

measures and regardless of the fuel used to generate it. Commenters stated that EPA also did not 

address accounting of CO2 reductions associated with international implications. 

Commenters stated that nuclear power is transmitted across state and international boundaries 

and are one way that states reduce the need to build higher-emitting in-state base load resources. 
109

Commenters stated that, to the extent that power from new and existing nuclear units could be 

included in state compliance plans, interstate "imports" of nuclear generation could be a 

potentially important compliance tool that EPA should recognize. Commenters (stated that EPA 

should treat different types of generation (e.g., fossil or nuclear generation) fairly for "crediting" 

purposes, and treat MWh as they are purchased or conveyed across state lines in a similar 

manner for accounting purposes. 

Commenters stated that failure to recognize the interstate impacts of nuclear generation could 

create significant compliance challenges for neighboring states. Commenters stated that if 

nuclear units that serve multiple states are prematurely retired, before the estimated 80 year 

operating period used in the proposal, all of the states that consume power from these units could 

face unexpected compliance challenges. Commenters stated that these states may have to 

increase generation from existing affected fossil-based units to replace the nuclear generation 

and the state may no longer be able to demonstrate that it is reducing its emission rate consistent 

with its projected compliance glide path, unless the additional fossil-based units were accounted 

for in the state plan. 

Commenters stated that many states rely on that region's extensive network of federal and 

Canadian hydropower facilities to keep emissions low and to minimize the need to build higheremitting base load resources. Commenters stated that these important interstate and international 

uses of hydropower generation have no role in compliance under the proposed section 111(d) 

guidelines. Commenters contended that, to the extent that EPA allows hydropower to be used for 

compliance, the Agency should recognize that, like other renewable generation, this power is 

transmitted and traded across interstate and international boundaries. Commenters stated that the 

continued operation of existing hydropower generation is critical to the achievement of the state 

emission rate goals for many states and if this generation had to be replaced, this could create 

significant compliance challenges for many states. 

Commenters stated that some states have taken steps to decrease imports of coal-based electricity 

by replacing this power with that generated by new, in-state NGCCs. Commenters stated that not 

only do the proposed guidelines not recognize this interstate issue, they saddle states that already 

have made investments in new NGCCs with stringent standards, which decreases CO2 emissions, 

but increases in-state emission rates. 

Commenters stated that EPA's proposed guidelines place the entire burden of reducing emissions 

from existing affected units on the state in which an affected EGU is located. Commenters stated 

that this does not recognize that power from in-state EGUs often serves customers in other states 

and unfairly saddles some states with the obligation to reduce emissions related to the power 

consumed in other states. 

Commenters stated that energy with and without renewable characteristics is imported and 

exported across state boundaries and EPA must put forward a workable solution for EGUs that 

participate in multiple state markets. Commenters stated that the liability for emissions is tied 

jurisdictionally to the state in which the emissions are generated even though the energy may be, 

consumed across a wide geographic region. Commenters stated this forces an exporting state to 

accept the emissions burden of an exporting unit, including the burden to achieve the necessary 

reductions to achieve the state goal, even though the state itself uses only a portion of the energy. 
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Commenters stated that because EPA has developed a system approach one that crosses state 

boundaries - but relies on states to address emissions from units whose benefits cross borders, the 

liabilities and benefits are mismatched. Commenters stated that unlike RECs which states will 

seek to claim, fossil fuel energy consumed in another state will be perceived as a liability in the 

state in which the energy is generated, creating another set of equity issues for EPA to resolve. 

Commenters stated EPA's proposed model for dealing with multistate projects envisions that 

CO2 would be accounted for in the state in which it was emitted even though that may burden the 

''jurisdictional" state and provide no benefit. Commenters stated that an owner who has paid for a 

low-carbon-intensity resource located in another state should get the benefit of that low intensity 

resource. Commenters asserted that transferring a portion of that liability to a purchasing state 

must be done by rule. Commenters stated that no state would voluntarily add to its compliance 

reduction burden or allow a low intensity resource to be pilfered away. 

Commenters believed that under the proposed state-by-state compliance approach the CO2

emissions from fossil-fired units should be credited to the state where the electricity from that 

unit is consumed. 

Commenters stated that the EPA has been unclear on how types of generation including nuclear 

will be credited to states in meeting carbon dioxide emission targets. The commenters stated the 

EPA should provide clear standards for how each type of generation resource will be credited, 

and ensure that credit is consistent with goal setting.

Commenters stated that the draft rule offers no credit or recognition of nuclear power plants' 

zero-emission generation to owning partners outside of the states in which these plants are 

located The commenters stated that the proposed rule does not appropriately recognize nuclear 

assets as a whole or to its owner and their customers. The commenters recommended to provide 

zero-emission credit for their commitment. The commenters suggested that the final rules should 

ensure that the states establish credit for compliance purposes by allowing the MWh obtained 

from nuclear power, as delivered based on ownership, to those corresponding states. The 

commenters stated that this approach would directly serve and support the EPA's principal 

objective of ensuring continued operation of the nation's largest source of carbon-free generating 

capacity.

Comment 8: The EPA should clarify how to split emissions for co-owned fossil-fuel utilities 

that provide power to multiple states; address reliability concerns

Response 8: On reliability concerns, during the development of the final rule, EPA officials 

worked closely with DOE and Federal Energy Regulatory Commission (FERC) officials to 

ensure, to the greatest extent possible, that actions taken by states and affected EGUs to comply 

with the final rule mitigate potential electric system reliability issues. Senior EPA officials met 

with each of the FERC Commissioners and EPA staff had frequent contact with FERC staff 

throughout the development the rule. FERC held four technical conferences to discuss 

implications of compliance approaches to the rule for electric reliability. EPA staff attended the 

four conferences and EPA leadership spoke at all of them. The EPA, DOE, and FERC will 
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continue to work together to ensure electric grid reliability in the development and 

implementation of state plans. For more information about reliability considerations, see Section 

II.D and for more detail about EPA consultations about reliability, see Section II.K of the final 

rule preamble of the CPP.

The following are summaries of the specific public comments under this comment:

Several commenters requested clarification on how to split emissions from co-owned fossil-fuel 

fired plants that provide power to multiple states. Commenters stated that it is unclear how 

compliance requirements for these utilities would be addressed, especially where a utility may 

have conflicting compliance requirements based on the regulations of two different states. 

Commenters requested whether a specific agreement or trading scheme with each state would 

need to be negotiated, or whether one state would be required to absorb all emissions.

Commenters stated that failure to account for electric utilities whose operations traverse state 

boundaries and serve retail customers in multiple states will result in stranded costs and 

additional costs. Commenters provided as an example the state of Virginia, which may be 

affected by the carbon emission rates set in West Virginia, Ohio, and North Carolina based on 

co-owned operations that traverse these states and serve Virginia customers. 

Commenters urged that if states are not provided with reasonable emission rates and flexibility to 

achieve compliance, states could face additional costs for the construction and operation of new 

generation need to replace generation affected in other states. Commenters argued that the 

reliance on developing state plans with respect to generation located within the state borders does 

not match up with how electricity flows between states. Commenters specifically expressed 

concerns about North Carolina's system-wide dispatch, which is based on ownership by multiple 

investor-owned utilities that are located in and serve portions of both North and South Carolina, 

and uses least-cost dispatch to cycle EGUs between the states to reduce costs. Commenters

provided as an example a case where South Carolina's compliance plan may require early 

retirements of the IOU generating units in its state (without needing North Carolina's input on the 

development of the plan), which could result in North Carolina ratepayers paying for both early 

retired generation plants as well as for new generation to meet demand, as well as disruptions in 

reliability.

Commenters stated that the heavy reliance on state plans without clear guidance fails to address 

cross-border issues for utilities, such as the interstate transfer of RE/EE credits by the owner of 

the generation or energy savings. Commenters argued that RE and EE credits/attributes must be 

treated fairly and the utility or third party that owns the credits must be allowed to exercise its 

property rights to use those credits in any state of its choice. Commenters asserted that this 

fairness is essential to the effectiveness of integrated resource planning in which utilities 

carefully plan how to meet their obligation to provide reliable electric service in an economical 

and environmentally sensitive manner.

Commenters noted that the proposal specifically fails to take into account the issues that may 

arise among co-owners of NGCC units for compliance with building block 2. Specifically, 

Commenters noted that each owner of an NGCC unit would have a different set of needs, 

expectations, and contractual obligations, especially where owners have competing interests and 
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obligations in other states. Commenters provided as an example a situation where a partial owner 

of NGCC units may prefer to operate an out-of-state NGCC unit to meet its demand instead of an 

in-state unit, even if the in-state unit is needed to comply with the in-state reduction goals. 

Commenters provided a scenario in which a utility located in one state builds an NGCC unit in 

another state where the affected EGU would be in one RTO and the NGCC and load in another. 

Commenters stressed that the proposed rule does not provided guidance on how the utilities or 

the RTO must deal with dispatching power from a generator in one RTO to reduce emissions of 

an EGU in another RTO. 

Comment 9: Proposed rule does not address interstate reserve-sharing agreements.

Response 9: EPA believes it has been clear that sources are responsible for emissions; if the 

source is in a state, its emissions will be covered under the state plan. See the section VIII.C of

the final preamble to the CPP. However, the rule gives considerable flexibility to states to 

determine just how the emissions from the source will be treated in the context of a sharing 

arrangement. For example, the source could purchase emissions rate credits, or some other 

means of complying decided upon by the state plan. These arrangements could address the 

specifics of existing agreements to ensure that sharing commitments amount parties to the 

agreements could be met. 

The following are summaries of the specific public comments under this comment:

Commenters expressed concerns that the proposed rule does not address interstate reservesharing agreements that are designed to ensure reliability for customers. Specifically, 

Commenters discussed North Carolina's membership in a regional reserve sharing agreement that 

allows its members to pool reserve generation resources on a prorated basis, which commits 

multiple balancing authorities to maintain a share of sufficient reserves to maintain system 

stability. Commenters provided that North Carolina's balancing authorities meet their reserve 

obligations by having hydro, including pumped storage hydro power plants and fast-starting 

combustion turbine plants, available to start or ramp up, which are not affected EGUs under the 

proposed rule. Commenters stated that the proposed rule raises the question of whether the 

emissions related to the power that is used to replenish the pumped water would be attributed to 

North Carolina, or to other states in the reserve-sharing agreement that benefit from the reservesharing event.

Comment 10: The EPA should prohibit states from discriminating against out-of-state imports 

of electricity.

Response 10: In the final rule, to the extent qualifying RE generation and demand-side energy 

efficiency measures are tied to a state plan, the quantified and verified MWh impacts of the 

measures may be used by an affected EGU or state to adjust a CO2 emission rate, regardless of 

whether the RE generation occurs inside or outside the state or territory. It is not necessary to 

determine the emission impacts of the MWhs as they will be reflected in the reported stack CO2
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emissions of affected EGUs. The MWh accounting method addresses interstate effects, because 

it inherently accounts for how generation replacement and CO2 emission reduction impacts may 

cross state borders and is indifferent to avoided CO2 emission rates; it creates the same number 

of zero-emitting credits or adjustment for each MWh of energy generation or savings, wherever 

they occur. 

Details regarding the accounting approach for adjusting CO2 emission rate is included in Section 

VIII.K.1 of the final rule preamble of the CPP. Requirements related to measurement and 

verification of qualifying MWhs are described in Section VIII.K.3. A full discussion of 

treatment of interstate effects under the final guidelines is included in Section VIII.L of the 

preamble to the final rule. 

The following are summaries of the specific public comments under this comment:

Commenters expressed concern that based on the proposed rules requirement for states to 

implement programs that reduce carbon emissions from generation sources within state borders, 

some states may attempt to shift compliance costs by shifting those reductions to imported 

power. Commenters noted that an issue may arise where an entity with a compliance cost for 

generation in one state exports that power into another state and is charged additional compliance 

costs for the export of power into the receiving state. Commenters requested that EPA prohibit 

states from discriminating against out-of-state imports of electricity; specifically, Commenters 

requested that for power generated in an exporting state where there is a price on carbon 

emissions from generation sources, the importing state should be required to deem the generated 

power to have a zero carbon footprint upon being imported. Commenters recommended that 

EPA require each SIP to contain a non-discrimination clause for any state importing or exporting 

power from another state when both states are compliant with the rule. Commenters further 

urged that EPA could enforce such a provision by withholding approval of a SIP if the state plan 

is not set up with such a clause.

Comment 11: Tribal & Territorial Treatment of energy flows from international generation (RE 

and fossil-fuel).

Response 11: The final rule prescribes a general accounting approach states must use to adjust 

the CO2 emission rate of an affected source to reflect the MWh impacts of zero-emitting and 

low-emitting resource. Quantified and verified MWh impacts of qualifying zero-emitting and 

low-emitting resources tied to a state plan may be used by an affected EGU or state to adjust a 

CO2 emission rate, regardless of whether the renewable generation or demand-side EE savings

occur inside or outside the state or territory. The EPA will work with states using the rate-based 

approach that are interested in allowing the use of RE from outside the U.S. For more 

information about specific methods to adjust the CO2 emission rate of an affected EGU to reflect 

RE and demand-side EE, see section VIII.K of the final rule preamble of the CPP. The same 

section also describes the eligibility requirements and conditions for resources to be used to 

adjust a CO2 emission rate, including specific discussions regarding hydroelectric power and 

eligibility for the use of RE from outside the U.S. The rule describes the requirements and 
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criteria related to proper quantification and verification of MWhs from renewable electricity 

generation or demand-side EE savings in Section VIII.K.3 of the final rule preamble of the CPP. 

The following are summaries of the specific public comments under this comment:

Several commenters remarked on the appropriate treatment of energy flows across international 

borders. Commenters noted that Canada is a significant supplier of RE to the United States, 

while other commenters noted that Mexico has the potential to increase its export of RE to the 

United States in the form of wind energy. Commenters noted many American utilities rely on 

Canadian hydropower to offset fossil fuel-fired generation, and that Canadian hydropower is 

already sold into regional electric markets. Commenters commenting on the Tribal and 

Territories Supplemental Notice, stated that international imports of RE (or other qualifying 

resources) should be equally recognized as CPP compliance options. Commenters also stated 

that EPA should also allow the use of RE purchased from other countries for compliance with 

the CPP. Commenters stated that there is large potential for expansion of wind and hydropower 

capacity in Canada and if EPA does not allow cross-border RE to count towards compliance, 

these carbon-free resources may go undeveloped. 

Commenters stated that if a state or region relies on international RE, then the RE potential 

should be identified and included in the state or region's target setting and state plan.

Commenters supported treating RE imported to the United States similarly to RE generation 

within the United States, and be allowed to take credit for the imported RE. Commenters iterated 

that because the rule allows for out-of-state renewables to be counted toward a state's emissions 

targets, the rule should be expanded to explicitly include out-of-country renewable resources. 

Commenters stated that states should be allowed to include policies in their state plans that take 

into account existing hydropower generation, just as existing wind and solar energy resources are 

available as options for state goal compliance. Commenters also stated that the plan should allow 

a state to designate out-of-nation hydro as an eligible renewable resource. Commenters stated 

that hydropower should count without limitation on size. Commenters specified that the rule 

should include international renewable resources which meet Renewable Portfolio Standards 

(RPS) requirements. Commenters requested that EPA provide a clear statement that international 

renewables can be included in SIPs. Commenters noted that U.S., Mexican, and Canadian 

electric grids and infrastructure currently rely on each other for energy supply and should 

continue to be leveraged to encourage the advancement of renewable energy. Commenters

further argued that allowing cross-border trade in electricity would enable states to gain access to 

a more diversified portfolio of renewable resources, produced over a wider geographic area, 

which would mitigate issues associated with variability in renewable resources. Commenters

noted that three REC registries currently encompass Canadian provinces and Mexican states. 

Additionally, commenters stated that to allow out-of-country RE would support states which are 

currently looking to collaborate on the expansion of bi-national energy markets, as well as 

coincide with President Obama's U.S-Mexico Bilateral Framework on Clean Energy and Climate 

Change, which seeks to expand RE development along the U.S.-Mexico border. Commenters

specifically stated that RE emissions offsets should be calculated using a rigorous marginal 

resource modeling exercise that considers various scenarios and future GHG policies. 

Commenters provided as an example a recent study of Manitoba Hydro exports to the United 

States out to 2030. 
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Several commenters also provided comments on allowing the use of RE, especially hydropower, 

purchased from Canada and other countries. Commenters argued that the ability to access hydro 

capacity in Canada is an important and often cost-effective means to reduce emissions from 

affected EGUs. Commenters specifically noted that if they were to enter into a new PPA with 

Manitoba Hydro, this would be considered in their dispatch offerings and Integrated Resource 

Planning process and lead to lower emissions. Commenters expressed concern that if the final 

rule suggested that such a PPA would not have 111(d) compliance value, or leaves this uncertain, 

utilities will have less incentive to shift to zero-carbon generating resources. Commenters

recommended that imported Canadian hydroelectricity be fully credited towards achieving CPP 

compliance when it can be demonstrated that the environmental attributes of the hydroelectricity 

is not being double counted. Commenters referred to a letter from Canadian Ambassador Gary 

Doer to EPA Administrator McCarthy that the Canadian Government's view is that the lower 

emissions from Canadian-sourced electricity can serve as a useful resource to help some US 

regions to achieve compliance with EPA's proposed CPP requirements. Commenters also stated 

that Ambassador Doer also affirmed that the environmental attributes from Canadian-sourced 

electricity can satisfy documentation requirements that the resource is not being double counted 

for the environmental benefits. Commenters stated that EPA should enable the unrestricted use 

of imported Canadian hydroelectricity as an approved resource creditable for satisfying EPA's 

CPP state BSER target compliance requirements. Commenters stated that EPA must reevaluate 

the decision to not allow RE, specifically hydropower, imported from across national borders as 

a compliance option. Commenters stated that hydropower is a zero-carbon source of energy 

regardless of where it is generated, and atmospheric carbon does not respect national borders. 

Commenters stated that whether RE is imported or generated locally, it negates in direct one-toone correspondence the necessity to generate electricity through combustion of fossil fuels. 

Commenters stated that given the expressed purpose of the proposed rule, all such options should 

be allowed as compliance mechanisms, to the extent that overall carbon production from fossil 

fuel combustion is reduced. Commenters added that the CPP should not create any artificial 

barriers to electricity trade between the U.S. and Canada, and it should facilitate the use of all 

clean resources. Commenters supported counting international RE towards compliance, but 

requested that generation from any renewable energy resource existing as of the date of the 

proposed rule not count towards compliance. Commenters stated that EPA excluded existing 

hydropower resources from the RE baseline and has made clear that states will not be able to 

take renewable energy credit for existing hydropower, and the same restriction must apply to 

imported hydropower. Commenters stated that although states may wish to take credit for new 

imports (as in new contracts) from existing renewable sources rate, for non-hydro renewables, 

energy from existing sources should be treated similarly in the international and interstate 

contexts. 

Several commenters supported EPA's proposal to examine mechanisms to ensure that 

international RE generation actually offsets fossil-fuel fired generation in the jurisdiction taking 

credit for that generation. Commenters noted that because of the risk of cross-border leakage, 

and because EGUs outside of the U.S. are not subject to the CPP, such safeguards are 

appropriate. Commenters suggested that EPA could address this situation by requiring the entity 

seeking to take credit to provide evidence that the electricity generated was intended for U.S. 

consumption, such as through the existence of a power purchase agreement or firm transmission 

service rights. Commenters stated that EPA should only require that states demonstrate the 

displacement of fossil-fuel fired generating units by international resources to the extent that they 
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demonstrate displacement of in-state resources. Commenters also stated that EPA may need to 

work with states in order to verify increased RE imports are coupled with a decrease in power 

sector emissions, and that the environmental benefits of these imports are not double counted. In 

making these determinations, commenters recommended that EPA and states consider Canadian 

and provincial air regulations and greenhouse gas goals, renewable energy credit tracking, 

economics, and other factors. Commenters stated that for rate-based systems, EPA could set 

forth appropriate parameters and safeguards to ensure that in-state or in-region emissions are 

actually reduced by the imported RE. 

Commenters addressed concerns with double-counting resulting from imported renewable.

Commenters urged that double-counting can be avoided either through PPA provisions that 

establish clear and unique ownership of the environmental attributes of purchased generation, or 

through REC tracking on established registries, such as M-RETS. Commenters stated that 

tracking systems have operating procedures in place to prevent double counting by tracking the 

RECs within the system and between other tracking systems. Commenters described the 

procedures that Canadian hydropower producers use to register RECs and transfer energy into 

the US. Commenters stated that the rules applicable to REC markets strictly preclude double 

counting and that the RECs allocated to U.S. customers are no longer available for any use or 

claims within Canada. Commenters urged that the well-established systems of RECs have 

proven to be an effective means of preventing "double counting" of renewable generation. 

Commenters supported counting international RE towards compliance, particularly imported 

hydroelectric generation from Quebec. Commenters noted that because Quebec is subject to an 

emission cap, this helps to avoid potential double-counting issues that may arise when 

considering the crediting of imported renewable power. Commenters also argued that because 

over 99% of the energy produced in Quebec is derived from non-emitting hydroelectric power, 

importing hydroelectric power would not lead to increased generation of carbon emissions to 

meet Quebec's domestic power needs. 

Commenters stated that it is inappropriate to allow international imports. Commenters stated that 

international imports should not be allowed because they will not reduce GHG emissions from 

the U.S. Commenters argued that if a state or region chooses to take advantage of international 

energy, it should not be allowed to take credit for reduced utilization of international facilities 

that emit more CO2 than is allowed for designated facilities within its jurisdiction. Commenters

reiterated that if U.S. jurisdictions are allowed to increase reliance on electricity generated by 

international fossil-fuel EGUs to decrease utilization on U.S. facilities, then it could create a 

perverse incentive that increases dirtier energy flows. Commenters requested that EPA clarify in 

the final rule that a designated facility may not comply by shifting generation from designated 

facilities to international fossil-fuel plants with equal or higher CO2 rates. Commenters

acknowledged that although EPA cannot treat generation from international sources less 

favorably than domestic sources (per NAFTA and GATT regulations), it can treat international 

energy flows as though they are domestic flows. Therefore, commenters reasoned that the final 

rule should make clear that regardless of the source (domestic or international), states must not 

comply by replacing generation with higher CO2 emitting sources. 

Commenters argued that the proposed rule should also consider exported carbon emissions.

Commenters urged that states that export fossil fuel should be required to count the impacts of 
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those exports against their progress towards the targets if the exports go to locations outside the 

jurisdiction of the proposed rule.

Some commenters stated that imports and exports of RE should not be limited to contiguous 

states or ISO regions.

Comment 12: Imports and exports of RE should not be limited to contiguous states or ISO 

regions.

Response 12: This final rule does not in any way restrict the imports and exports of RE 

generation across states. Regarding whether such RE is eligible for the issuance of ERCs under a 

rate-based state plan, section VIII.K of the preamble states that all eligible emission reduction 

measures, including RE generation, may occur in any state, with certain limitations. To the 

extent these measures are tied to a state plan these measures may be used to adjust a CO2

emission rate, regardless of whether the associated generation or electricity savings occur inside 

or outside the state. Once a state has issued ERCs for that RE, then the ERCs can only be traded 

with state with compatible trading rules.

The following are summaries of the specific public comments under this comment:

Commenters stated that imports and exports of RE should not be limited to contiguous states or 

ISO regions. 

Comment 13: The EPA should develop a model electric utility code to support RE/EE

incentives.

Response 13: The EPA appreciates the comment. RE and demand-side EE are an integral part of 

this final rule, and can play a significant role in state-plan compliance. In the discussion of state 

plans in section VIII, the final rule provides significant detail on how states can have RE and 

demand-side EE play a strong role in state plans.

The following are summaries of the specific public comments under this comment:

Commenters urged the EPA, the Department of Energy, and FERC to jointly develop a statelevel model of electric utility code that incorporates RE/EE incentives for utilities (e.g., allowing 

higher rates of return on investments in carbon-free power, allowances to collect a bounty on 

green systems connected to the grid, or being allow to keep a percentage of the savings for each 

kWh avoided by end-use efficiency programs). Commenters urged that such a model electric 

utility code is needed for states to spur reforms and encourage utility participation in the CPP.
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Comment 14: When modeling its compliance plan, a state should consider what its neighboring 

states are doing and how that might affect them.

Response 14: The EPA agrees that, when developing their plan, a state would benefit from 

considering what its neighboring states are doing and how that might affect them. In the final 

rule, the EPA encourages states to collaborate formally or informally, considering the potential 

benefit of a regional or multi-state plan. For more information about multi-state plans, see 

Section VIII.C.5 of the final rule preamble of the CPP. For specific requirements related to 

developing a state plan projection, see Section VIII.D.2.a. (3) of the final rule preamble of the 

CPP. 

The following are summaries of the specific public comments under this comment:

Commenters mentioned that "state compliance plans should address how their compliance 

activities affect and interact with neighboring states" including "the expected change in the net 

electricity imports to a state." Commenters stated that quantitative modeling should be done if 

practical and qualitative and analytical evaluation might be sufficient as long as the state 

considers its own and neighbors plans with regard to: complying with assigned emissions rate 

targets; participating in a regional emissions rate averaging program; converting assigned 

emission rate targets into state-specific emissions caps; and converting assigned emission rate 

targets to caps to join a regional cap-and-trade program.

Comment 15: Commerce Clause implications of interstate trading

Response 15: EPA assumes that commenters’ reference to the “potential Commerce Clause 

issues” with cross-state crediting is a reference to the “dormant” or “negative” Commerce Clause

doctrine. That doctrine concerns limitations on the power of states—absent federal 

authorization—to enact laws that discriminate against interstate commerce either facially or ineffect. With respect to interstate crediting, section VIII.K.1.a(2) of the final rule preamble 

explains the eligibility requirements for resources used to adjust a CO2 emission rate, including 

the geographic eligibility requirements. Eligible emission reduction measures may occur in any 

state, with certain exceptions described in that section. For the reasons stated in sections V.A–B 

and VIII.L of the final rule preamble, and in the Legal Memorandum accompanying the final 

rule, trading of credits or allowances—both interstate and intrastate—is permissible under the 

federal regulatory scheme authorized by Clean Air Act section 111(d). Accordingly, there are no

dormant Commerce Clause issues for a trading program included in a satisfactory state plan 

approved pursuant to federal law. See, e.g., Hillside Dairy, Inc. v. Lyons, 539 U.S. 59, 66 (U.S. 

2003) (citing Prudential Ins. Co. v. Benjamin, 328 U.S. 408 (1946)) (“Congress certainly has the 

power to authorize state regulations that burden or discriminate against interstate commerce”); 

Ne. Bancorp. v. Bd. of Governors of Fed. Reserve Sys., 472 U.S. 159, 174–75 (1985) (state 

action authorized by federal law is “invulnerable to constitutional attack under the Commerce 

Clause).

The following are summaries of the specific public comments under this comment:
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Commenters asked, in the context of cross-state crediting for EE and RE, if the EPA has 

evaluated potential Commerce Clause issues.

Comment 16: Emissions leakage from state to state; States should have additional compliance 

obligations to account for inter-state leakage. CPP will limit leakage and level the playing field.

Response 16: There are other ways in which differing characteristics across states and sources 

could create risks of increased emissions under this rule through double counting of emission 

reduction measures or through foregone emission reductions due to movement of generation 

from one affected EGU to another affected EGU. The final rule addresses these concerns: first, 

through the characteristics of goal-setting and the framework of state plans, and second, through 

specific requirements intended to minimize the risk of double counting and increased emissions. 

More information on these concerns is provided in section VIII.L of the preamble.

The final rule also specifically deals with the issue of emissions leakage to new unaffected 

sources, and how it affects the equivalence of rate-based and mass-based goals to the CO2 

emission performance rates as an expression of BSER. Under this final rule, states have the 

opportunity to adopt rate-based or mass-based state goals as their emission standards as an 

alternative to the CO2 emission performance rates. The final rule demonstrates how the ratebased and mass-based state goals that the EPA has calculated are an equivalent expression of 

BSER as compared to the CO2 emission performance rates. As part of this demonstration, the 

EPA shows how the goals equivalently provide incentives to generate to existing affected EGUs 

and new sources, otherwise the form of the goal could result in emission leakage (defined in 

section VII.D). 

The rate-based goals included in the final rule minimize leakage because under a rate-based state 

goal, similar to the subcategory-specific emission performance rates, existing lower-emitting 

affected EGUs, primarily NGCC, are incentivized to increase their utilization in order to improve 

the average emission rates of affected EGUs overall. New units that are not subject to the ratebased state goal, and that are not an allowable measure for adjusting an EGU’s CO2 emission 

rate, will not experience this incentive to increase utilization. As a result, the imposition of a 

rate-based goal on affected EGUs is unlikely to encourage increased generation and emissions 

from unaffected new EGUs as compared to the CO2 emission performance rates.

Mass-based goals for existing sources, incur a leakage risk to the extent that they incent 

generation shifts from affected EGUs to unaffected fossil fuel-fired sources in a way that has a 

potential for leakage and may not be an equivalent expression of BSER. This occurs because, 

unlike in a rate-based system where rate-based averaging lowers the cost of generation from 

existing NGCC units relative to generation from new NGCC units, in a mass-based system the 

allowance price increases the cost of generation from existing NGCC units relative to generation 

from new NGCC units. The final rule addresses this concern by requiring states that adopt massbased state goals to demonstrate that they have addressed leakage in their state plan. In Section 

VII.D of the final rule preamble of the CPP, the EPA details the concerns regarding leakage in 

state goals and specifies that potential emission leakage must be addressed in a state plan with 
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mass-based emission standards. Specific options states can use to demonstrate that potential 

leakage has been addressed are in Section VIII.J.2.b of the final rule preamble of the CPP.

The following are summaries of the specific public comments under this comment:

Commenters stated that the CPP will strengthen the RGGI program by reducing the potential for 

leakage. Commenters noted that by regulating carbon emissions in other US states (beyond the 

RGGI states), the CPP will strengthen the RGGI program by leveling the economic playing field

between in-region EGUs regulated under RGGI and EGUs in neighboring states that do not 

currently regulate carbon emissions from EGUs. Commenters noted that regardless of location, 

reducing carbon emissions from EGUs will benefit all states, so it is appropriate that the CPP 

will subject all EGUs to similar requirements. Commenters stated that particularly perverse 

potential outcome of the status quo is emissions "leakage," in which EGUs in adjoining states 

increase generation (and emissions) in response to any economic signal provided by the RGGI 

program. Commenters stated that strengthening RGGI by reducing the potential for leakage is 

therefore an important benefit of the CPP.

Commenters said that EPA should require states to have additional compliance obligations if 

there were substantive changes in inter-state electricity transmissions. Commenters suggested 

three approaches: (1) "If a state increases its net electricity exports by more than 10 percent from 

a base year period the emissions rate standard that should apply to the associated incremental 

increase in electricity generation should be the more stringent of the state's standard or the 

average standard in the state's power region." (2) "States might be required to hold electricity 

transfer credits for electricity imports or exports that are greater than those observed in a base 

year period." And (3) "State's might be required to adjust the emissions rate calculation that is 

applied within their states compliance plan to provide incentives for greater utilization of low or 

nonemitting resources so that there is no increase in total emissions." Commenters also said that 

"to mitigate leakage the state standards could be calibrated to achieve greater conformity in the 

production incentive within a region or across the nation." Commenters also suggested that if 

needed states should use an output based allocation. Commenters calculated a net production 

incentive and did modeling to show that transmission limitations and location on the electricity 

grid are factors that need to be considered when looking at emissions leakage. In order to 

minimize leakage, commenters suggested a uniform credit price or having emissions rate 

standards adjusted to align with production incentives. Commenters also modeled many cap and 

trade program scenarios and suggested only giving a production incentive to lower-emitting or 

non-emitting resources if an output based allocation was used.

Commenters encouraged EPA to take action "to reduce the variation in state targets by 

increasing the GHG emissions reductions required in states that currently have less ambitious 

targets" to reduce the level of emissions leakage from state to state. Commenters defined 

environmental leakage as the "transfer of emissions from one region to another." Commenters

stated that the regulations should be crafted in a way that ensures overall reduction in emissions 

and does not merely transfer emissions from one state to another. Commenters stated that 

analysis suggested that leakage could be "14-19% of the total GHG emissions reductions" as 

proposed. Commenters explained that there are two forms of leakage: rate to rate leakage and 

rate to mass leakage. Commenters presented four subsections on leakage entitled: rate to rate 

leakage; rate to mass leakage; NRDC modeling of leakage potential; and policy options for states 
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to address emissions leakage. Commenters described rate to rate leakage and recommended "that 

EPA exclude existing renewables from its calculations of a state's initial emissions level." Then, 

commenters stated, "If EPA does this, and expands building block 1 to include opportunities for 

co-firing natural gas at coal plants or new natural gas plants in Building Block 2, then the risk of 

leakage will decrease. However, some risk of leakage will remain unless EPA standardizes state 

emissions targets across grid regions." Commenters described rate to mass leakage and affirmed 

that they believe that "mass based programs are superior to rate based programs." However, 

commenters were concerned because "there are boundary challenges between a state employing 

a rate-based program and a state employing a mass-based program." Commenters gave an 

example using West Virginia and Maryland (which is in RGGI) and stated that "under the Clean 

Power Plan, shifting 10 MWh of natural gas generation from Maryland to West Virginia would 

generate a credit equal to approximately 7,480 lbs CO2 in West Virginia without resulting in a 

commensurate decrease in the RGGI cap (assuming the natural gas plant has an emissions rate of 

1,000 lbs CO2/MWh)." Commenters used the IPM model to analyze the potential for leakage 

using the NRDC Reference Case (RC3) and analyzing two scenarios, the Mass Equivalents Case 

where all states were assumed to adopt a mass-based program, and a Leakage Case where all 

states were assumed to adopt mass-based programs, except for Pennsylvania and New Mexico. 

Commenters stated that "Pennsylvania and New Mexico were assumed to adopt the proposed 

June 2014 rate-based state targets. These two states were selected for this study because they 

may represent pronounced opportunities for leakage in their respective interconnected grid 

systems. The rate-based targets in Pennsylvania and New Mexico exceed the emissions rate of 

new natural gas combined cycle units, and they are located in proximity to states participating in 

cap-and-trade programs like the Regional Greenhouse Gas Initiative (RGGI) and California's 

AB32, respectively. The combination of these effects mean that each state could choose to build 

significant amounts of new NGCC units and export some of this generation to neighboring 

states, while still complying with its own rate target." Commenters stated that "in this analysis, 

we observed dynamics reflecting emissions leakage in Pennsylvania prior to the 2030 final 

compliance date" and that "in New Mexico, we observed minimal emissions leakage". 

Commenters concluded that "the potential for emissions leakage is significant and must be 

addressed by EPA and states in their plans. The potential for leakage may be sensitive to natural 

gas price differentials and transmission capacity between rate-based and mass-based states." 

Commenters presented policy options for states to address emissions leakage and recommended 

that "EPA describe a methodology for how they will measure and evaluate leakage over time." 

Commenters also recommended "that the responsibility to address leakage be placed on the 

states that increase electricity production, as they are the states that otherwise benefit from their 

less stringent emissions rate." Commenters presented four approaches to address leakage: first 

jurisdictional delivery approach, ex post evaluation and adjustment of state-level emissions 

reductions, require all states to evaluate statewide power sector performance against mass-based 

targets, and ex ante adjustment to level the playing field for generation. Under the first 

jurisdictional delivery approach commenters stated that "an entity that exports power out of a 

given state is required to submit credits to the state equal to the emissions leakage that would 

otherwise occur absent the submission of emissions credits." For the ex post evaluation and 

adjustment of state-level emissions reductions approach commenters stated that "EPA could 

require states to evaluate shifts in their balance of electricity supply and demand on an annual or 

bi-annual basis and account for any shifts through automatic ex-post adjustment of their GHG 

programs." For the require all states to evaluate statewide power sector performance against 
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mass-based targets approach commenters stated that "EPA could eliminate the threat of leakage 

by requiring all states, including those that adopt a rate-based approach, to evaluate whether the 

state's actual emissions exceeded the mass-based target that the state would have been subject to 

had it adopted a mass-based approach. States that exceeded their mass-based target would be 

required to adjust for excess emissions." For the ex ante adjustment to level the playing field for 

generation approach, commenters stated, "all new generation would be compared to the 

emissions rate for new units established under 111(b) or the state rate standard, whichever is 

lower, in order to prevent sources from taking advantage of less ambitious state emissions 

targets." Commenters further stated that there are advantages to the ex ante approach because if 

"EPA applies an up-front adjustment at the plant level" it "provides greater certainty for project 

developers." Commenters also said, "There is an advantage to placing them on plants whose 

generation increases: doing so avoids further penalizing plants that are already being 

outcompeted in the marketplace". 

Commenters stated that "EPA has the authority and responsibility to require state plans to 

address leakage", that "requiring states to prevent leakage does not compromise state flexibility" 

and that leakage could eliminate about 30% of the expected reductions from the Clean Power 

Plan. Commenters recommended that EPA adopt the following policies in the final rule: "1. All 

state plans must have provisions to prevent leakage: a. Responsibility could be assigned to states 

that increase net exports or reduce net imports; b. Alternatively, responsibility could be assigned 

to states that increase net imports or reduce net exports. 2. Set consistent rules for the treatment 

of all new fossil resources: a. Allowing states to elect to include or exclude new sources results 

in high leakage potential; b. If it is not feasible to require all states to account for new sources 

then all states should be required to exclude both new source emissions and generation from their 

compliance demonstrations. 3. Consistent with EPA's proposed methodologies for translating 

rate standards to mass standards, states that adopt a mass-based standard must either - a. Exclude 

generation served by new sources from the load used to convert from a rate standard to a mass 

standard; or b. Adopt a standard that is based on the inclusion of these megawatt- hours and 

count the emissions from new sources against the standard. 4. EPA should revise the 

methodology for treatment of Energy Efficiency as a component of BSER to credit states for 

100% of reduced generation to support statewide sales, regardless of whether the state is a net 

importer or exporter (provided that EPA requires states to prevent leakage due to interstate 

electricity trades)." Commenters also stated that "all state plans should be specifically required to 

include a process for maintaining the required level of performance reflected in the original 

BSER if net import levels fluctuate by more than a de minimis amount. Commenters also 

proposed several options that EPA could use to address leakage including the following: provide 

each state with a mass standard that reflects the BSER; allow states to adopt a rate standard, but 

provide a mass-based backstop for states that adopt rate standards in order to ensure that no state 

increases emissions beyond a level environmentally equivalent to BSER; or impose an average 

emissions rate standard for each grid region or the whole nation. Commenters also noted that 

"the best state-driven solution to prevent leakage caused by incremental electricity 

imports/exports would be for states to join regional programs with a uniform emission rate 

standard within the power markets in which they participate."
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5.8 PROJECTING EGU CO2 EMISSION PERFORMANCE

This section addresses comments on Projecting EGU CO2 Emission Performance. We have 

organized the comments in this section under seven subsections, 5.8.1 to 5.8.7. Responses to the 

comment topics of these subsections are discussed below along with summaries the specific 

public comments.

5.8.1 Electricity System Modeling Approaches for Projecting EGU CO2 Emissions

This section addresses comments on electricity system modeling approaches for projecting EGU 

CO2 emissions. We have organized the comments in this section under four subsections, 5.8.1a 

to 5.8.1d. Responses to the comment topics of these subsections are discussed below along with 

summaries the specific public comments.

Commenters have raised a number of issues related to this subsection which are organized by 

topics (comments) below. Responses are also provided for these topics.

Comment 1: Comments regarding IPM accounting of decommissioning expenses.

Response 1: IPM accounts for decommissioning of nuclear units, but not other types of units.

The following are summaries of the specific public comments under this comment:

Commenters asked if the EPA has considered the extent to which IPM accounts for 

decommissioning expenses for units.

Comment 2: Comments regarding a reliability safety valve.

Response 2: The EPA has addressed reliability safety valve comments in Section VIII.G.2 of the

final rule preamble of the CPP. Please refer to this section for EPA’s rationale and considerations 

related to reliability safety valve.

The following are summaries of the specific public comments under this comment:

Commenters stated that they supported "the concept of a reliability safety valve as proposed by 

PJM and other RTOs." Commenters thought that if there was no reliability safety valve, "there is 

no means for RTOs to ensure availability of short-term capacity during times of peak usage." 

Furthermore, commenters stated that, "If the safety valve is evoked to ensure reliability of the 

electric grid, state rates should be adjusted to account for the trigger of the safety valve."
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Commenters requested that the following option (among others) be implemented to improve the 

workability of the proposed guideline rule and to provide additional compliance flexibility to 

meet the emission targets established in the proposal: commenters urged EPA to include a safety 

valve or "off-ramp" to address both unexpected scenarios and to address electric system 

reliability or adverse rate impacts.

Comment 3: Comments regarding IPM assumptions for Florida.

Response 3: The EPA disagrees. For this rule, IPM is not used for state level projections or for 

setting state goals, but rather is used for broad, national assessments of program costs and 

impacts. See the RIA chapter 3. IPM is a multi-regional, dynamic, deterministic linear 

programming model of the U.S. electric power sector that the has been successfully used by EPA 

and private companies for over two decades to evaluate the economic and emission impacts of 

prospective environmental policies. Projections reflect the most recent and accurate information 

available. EPA has reviewed comments on IPM and has updated the model for use in the final 

rule; EPA believes the model results used in the final rule are reasonable.

The commenter statement that IPM uses nameplate capacity is incorrect; IPM uses net 

dependable capability.

The following are summaries of the specific public comments under this comment:

Commenters stated that the IPM has "flaws that result in inaccurate and unachievable 

compliance projections for Florida." Specifically, commenters said that IPM has errors because it 

used nameplate capacity instead of net capacity. Commenters said that EPA's model inter mixes 

nameplate capacity and net generation for projecting natural gas fired units resulting in an almost 

19% overstatement of summer net MWh from natural gas and leads to an exaggeration in coalfired retirements. Commenters stated that the IPM Base case has 160 Florida units retiring by 

2016 when the owners have identified that only 81 of these units will retire by 2016. 

Commenters provided a table listing out the units. Commenters stated that this results in lower 

projected compliance costs for the Clean Power Plan. Commenters requested EPA correct the 

errors in NEEDS and EMP, rerun the Base Case and Policy Case, recalculate the compliance 

costs, and give stakeholders an opportunity to comment on the revisions. Commenters further

stated that IPM showed "dramatic impacts on Florida" which are different from the FPSC's 

projections. Commenters said that IPM predicts in 2025, natural gas would provide over 85% of 

Florida's electricity and coal would only provide 2% while FPSC predicts that in 2022, natural 

gas fired combined cycle units will provide 59% of Florida's electricity and coal fired will 

produce 22 % of Florida's electricity.

Comment 4: Comments regarding IPM modeling results.

Response 4: The EPA disagrees. For this rule, IPM is not used for state level projections or for 

setting state goals, but rather is used for broad, national assessments of program costs and 

impacts. See the RIA chapter 3. IPM is a multi-regional, dynamic, deterministic linear 
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programming model of the U.S. electric power sector that the has been successfully used by EPA 

and private companies for over two decades to evaluate the economic and emission impacts of 

prospective environmental policies. Projections reflect the most recent and accurate information 

available. EPA has reviewed comments on IPM and has updated the model for use in the final 

rule. Although opinions of future coal production and use in individual areas will differ, IPM 

projections will reflect general industry trends, such as increasing coal production in areas like 

the Illinois basin and decreasing coal production in Central Appalachia in West Virginia and 

Kentucky referenced in the comment. EPA believes the model results as used in the final rule are 

reasonable.

The following are summaries of the specific public comments under this comment:

Commenters questioned the reliability of EPA's economic modeling of the electricity sector 

since they believed that some IPM modeling results in "odd and unlikely projections, such as that 

by 2020, 37% of the coal used for electricity generation in West Virginia will come from Illinois 

(none is now), and that only 11% of the coal used in Kentucky will come from that state (as 

opposed to 66% at present)."

Comment 5: Comments regarding modeling and revisiting models due to changing 

circumstances.

Response 5: In response to comments about state policy and analytic needs, the EPA, in 

consultation with U.S. DOE and other federal agencies, continued to refine its toolbox of 

decision support resources at: http://www2.epa.gov/ www2.epa.gov/cleanpowerplantoolbox. The 

site includes information on regulatory requirements, including state plan guidance and state plan 

decision support. The state plan guidance section serves as a central repository for the final 

emission guidelines, RIA, guidance documents, TSDs and other supporting materials. The state 

plan decision support section includes information to help states evaluate different approaches 

and measures they might consider as they initiate plan development. This section includes, for 

example, a summary of existing state climate and RE and demand-side EE policies and 

programs, information on electric utility actions that reduce CO2, and tools and information to 

estimate the emissions impact of RE and demand-side EE programs, including the AVERT 

model. For more information about Resources for States to Consider in Developing Plans, see 

Section VIII.H of the final rule preamble of the CPP.

The EPA is not requiring specific tools or emission quantification methodologies which states 

and/or affected EGUs must use when demonstrating the emission guidelines will be met as long 

as the method is technically sound and meet the criteria in the preamble. 

Energy storage technologies could be used to facilitate achievement of the CO2 emission 

performance levels for affected EGUs, or a state rate-based or mass-based CO2 goal for affected 

EGUs, in the emission guidelines. However, MWh output from an energy storage technology 

could not be used to adjust the reported CO2 emission rate of an affected EGU. It could facilitate 

greater grid penetration levels of RE generating technologies that are eligible for use in adjusting 

the reported CO2 emission rate of an affected EGU. The treatment of energy storage under a rate-
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based state plan, and the rationale for this treatment is discussed in section VIII.K.1.a.(5) of the

final rule preamble of the CPP.

The following are summaries of the specific public comments under this comment:

Commenters stated that, "With the development of all types of storage, solar can substantially 

displace natural gas and coal EGUs, and play an even more significant role in reducing carbon 

emissions." Commenters recommended that methodologies and models be developed for states 

to account for the benefits provided by storage that increase the use of solar power. Furthermore, 

commenters recommended that "EPA and the states periodically revisit the applications and 

models in the plan to account for new technologies and improved valuation curves," since they

expect that the costs associated with storage will come down as energy storage increases.

Commenters stated that EPA may recommend tools such as AVERT and provide methodologies 

to calculate and apply emission impacts of energy efficiency projects, programs, and policies, but 

that EPA should also allow states to submit their own calculation methodologies and conversion 

approaches to EPA.

Commenters stated that "the final rule should reduce its dependency on modeling" due to the 

uncertainty with the forecasts and the approximations that go into modeling algorithms. 

Commenters also pointed out that "the calculation of avoided emissions is a very complex, 

uncertain, and nontransparent process" and assigning CO2 credits for RE and EE requires 

regional level modeling. Commenters further stated that if states choose a mass-based limit then 

the state "would develop RPS/EE mandates to reduce the fossil generation requirements in order 

to stay under the CO2 mass limit" or "establish CO2 and offset markets" which should give 

people incentives to develop RE/EE.

Comment 6: Comments regarding IPM pollution control equipment life.

Response 6: The use of a 15 year life rather than a longer life for retrofits in IPM is based on 

comments from industry and others about the most appropriate period, given issues of physical 

life of the asset, life of the underlying facilities, and financing issues.

The following are summaries of the specific public comments under this comment:

Commenters stated that for the Clean Power Plan IPM analysis EPA assumed a fifteen year life 

for recently installed pollution control equipment but for other rules, such as the Regional Haze 

Rule, EPA assumed a twenty-year life. Commenters stated that "If there is a basis upon which 

EPA believes it is appropriate to use different assumptions for different programs, EPA should 

clearly explain why it has done so."

Comment 7: Comments regarding Regional Transmission Organizations (RTOs).
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Response 7: The EPA recognizes in the Preamble Section A.3.b that Regional Transmission 

Organizations contribute to ensuring reliability of the electric system and keeping the grid in 

balance. The EPA staff met with RTO council on several occasions to collect their ideas. The 

EPA encourages states that reside in an RTO to have discussion with their RTO as they develop 

their plans. As described in Section II.J of the final rule preamble of the CPP, in all state plans, 

as part of the supporting documentation, states must include a description of their required 

consultation with relevant ISOs/RTOs and/or planning/reliability authorities during plan 

development, including any recommendations and other comments provided by those authorities.

The following are summaries of the specific public comments under this comment:

Commenters asserted that the proposed Clean Power Plan does not adequately address the role of 

Regional Transmission Organizations (RTOs) and Independent System Operators (ISOs) in the 

transmission and distribution of electricity, or how they may factor into implementing a state 

plan. Commenters stated that most of Nebraska's utilities are members of the Southwest Power 

Pool (SPP), a RTO that spans all or parts of Arkansas, Kansas, Louisiana, Mississippi, Missouri, 

Nebraska, New Mexico, Oklahoma, and Texas. [FERC, Electric Power Markets, SPP 

(http://www.ferc.gov/market-oversight/mkt-electric/spp.asp)] Commenters noted that the SPP 

manages the sale, transmission, and distribution of electricity, and is responsible for transmission 

system maintenance and expansion planning; supply forecasting, reliability coordination, and 

load balancing; and energy market operations within its service area. [Southwest Power Pool/ 

About SPP (http://www.spp.org/section.asp?pageid=1)] Commenters noted that the SPP also 

retains regional dispatch authority over member utilities, deciding when to dispatch which power 

plants and to what degree on a daily basis, which can cause significant changes in power plant 

utilization from day to day as member states export or import power to and from other states 

depending on regional conditions.

In short, commenters stated that RTOs and ISOs form a crucial component of electric grid 

management, and their regional dispatch and balancing authority is essential to achieving the 

objectives of the Clean Power Plan, particularly with respect to any multi-state plans that may be 

put in place. Commenters stated that RTOs and ISOs do not recognize state boundaries in 

determining dispatch, which is at odds with the single- or multi-state plan approach of the Clean 

Power Plan. Commenters therefore requested that the EPA revise the Clean Power Plan to 

adequately address the role of these organizations.

Commenters agreed with EPA that "ISO/RTO analytic support would allow the state to monitor 

the effects of its plan on the regional electricity system..." and "...could help states assure that 

their plans are consistent with region-wide system reliability." Hence, commenters respectfully 

submitted that consultation with relevant system operators and planners (such as ISOs/RTOs) 

can provide substantial value in the development of the Final Rule and State Plans. Commenters

stated that appropriate consultations will allow EPA, states, and other entities responsible for 

grid reliability to identify potential reliability impacts, taking into consideration the intra-state, 

inter-state, and regional transmission and generation characteristics of system operations and 

planning that are critical to grid reliability. Further, because the Proposed Rule already sets forth 

a continuum of steps and processes, commenters stated that there are a wide variety of potential 
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paths to compliance and substantial flexibility with respect to the timing and stringency of any 

interim goals. Accordingly, commenters recommended that consultation occurs as early as 

possible and throughout all stages of Final Rule implementation, as necessary. Commenters 

stated this sort of "rolling" consultation will help ensure that the Final Rule does not negatively 

impact state, multi-state, and/or regional grid reliability. Additionally, commenters stated that the 

incorporation of the commenters' proposals discussed elsewhere into the Final Rule would 

facilitate such consultation with ISOs/RTOs.

Commenters requested that EPA require State Plans to include a component that describes the 

evaluation of impacts to state, multi-state, and/or regional grid reliability from the 

implementation of the proposed State Plan. Commenters explained that, in organized market 

regions, ISO/RTOs would perform the evaluation. Commenters noted that in vertically integrated 

regions, the registered entities responsible for reliability in the state and/or region, e.g., reliability 

coordinator, planning coordinator, etc., with independent review by the North American Electric 

Reliability Corporation ("NERC") or the Regional Entity, would perform the evaluation. 

Commenters stated that this component would also describe the assessment results and how the 

State Plan considered and/or addressed any identified impacts to grid reliability during the 

development of the State Plan. Commenters stated that appropriate NERC-registered entities 

(i.e., Reliability Coordinators and Planning Authorities) can facilitate the identification and 

consideration of electric system reliability in the development of State Plans (these are typically 

system operators and planners - e.g., ISOs/RTOs in organized market regions of the country).

Commenters stated that EPA must rely on RTOs and utilities to determine what changes to 

generation mix are feasible while still ensuring reliability of the electric grid.

Commenters stated that given both the complexity of the electric generating sector and the vital 

importance of a reliable supply of electricity for the Nation's security and the economic wellbeing and physical safety of its citizens, any final EPA emission guideline must allow the States 

to respond dynamically to the wide range of sometimes unpredictable conditions involving

the Nation's electrical generating resources, and the final guideline should be developed in full 

coordination with the Federal Energy Regulatory Commission and North American Electric 

Reliability Corporation.

Commenters requested EPA hold an RTO summit. Commenters stated that they believe that 

"compliance through fuel-shifting is most cost effective when implemented over a wide 

geographic area." Commenters encouraged EPA to hold an "RTO Summit" so utilities could 

explore this concept further.

Comment 8: Comments regarding public utility commissions.

Response 8: The EPA in the final emission guidelines is not requiring states to change their 

existing processes for interacting with their public utility commissions or divisions with their 

state. States will need to demonstrate they have adequate legal authority and funding to 

implement the measures in a state plan. The EPA recognizes that multiple stakeholders within a 

state will need to be a part of the state plan development and encourages that interaction. See 
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section VIII.D.2.a(6) of the final rule preamble of the CPP that discusses the details surrounding 

stakeholder engagement.

The following are summaries of the specific public comments under this comment:

Commenters stated that a primary tenet of the enabling legislation that created public utility 

divisions (PUDs) is governance by a locally-elected Board of Commissioners. Commenters

stated that implementation of the 111(d) rule should be structured in a manner that allows states 

to use existing processes to interact with PUDs, thereby minimizing the impact on local, 

publicly-owned utilities - particularly when their GHG emissions are de minimis.

Comment 9: Comments regarding public participation.

Response 9: In the final emission guidelines, states must meet the minimum public participation 

requirements of the final guidelines including a public hearing, and meaningful engagement with 

all members of the public and affected parties. One of the required components of an initial plan 

submittal to the EPA is a description of the public participation opportunities such as stakeholder 

and community meetings or public hearings throughout the 2 or 3 year plan development 

process. The EPA recognizes the importance of engaging community members like the 

NASUCA members and the state public utility commissions. The EPA can not require states to 

meet with specific organizations however, there should be ample opportunity for these important 

stakeholders to comment and engage with the environmental state agencies and inform the state 

plan process. Refer to section VIII.D.2.a of the final rule preamble of the CPP for details on this 

topic. 

The following are summaries of the specific public comments under this comment:

Commenters asked that EPA ensure that National Association of State Utility Consumer 

Advocates (NASUCA) members, and the utility customers they represent, are included in the 

state-level implementation process and resource decisions resulting from the Clean Power Plan. 

Commenters suggested that the EPA should require any state-level environmental agency 

charged with implementation of any final version of the Clean Power Plan to seek input from the 

state NASUCA member concerning the components of a state-level compliance plan prior to 

finalizing its terms. Commenters provided the following rationale for their request: 

• Commenters noted, according to the EPA, meeting the emission reductions 

proposed in the Clean Power Plan will require electric utilities and electric 

generators to, in some mixture, increase generation efficiency, change generation 

fuel mix, which may include building new natural gas fired generators and/or 

closing existing coal fired generators, increase the use of renewable energy 

generating sources and increase the use and availability of energy efficiency 

and/or conservation measures.

• Commenters noted that state-level implementation of any final version of the 

proposed Clean Power Plan will generally reside at a state-level environmental 
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agency. Commenters noted that in most cases, the state-level environmental 

agency in charge of implementing the Clean Power Plan will have different 

objectives, obligations and expertise than the state-level agency that regulates 

electric utility resource planning and rates (i.e., Public Utilities Commission). 

• Commenters noted that state-level environmental agencies are not primarily 

focused on identifying and promoting lowest reasonable cost solutions to 

ratepayers.

Commenters stated that the number of NASUCA member offices that have clear jurisdiction to 

participate before a state-level environmental agency is less than the number of NASUCA 

members that have jurisdiction to participate before the state-level agency that regulates electric 

utility resource planning and rates. As such, commenters stated that many NASUCA member 

offices, and the utility customers they represent, may be specifically excluded from participating 

in important decisions affecting changes to electric utility resource planning, the resources used 

to meet customer energy needs, the cost of these resources and impacts on customer rates that

result from these resources changes.

Comment 10: Comments regarding interim, final budgets, and state plans.

Response 10: The EPA has made many significant changes to the state interim and final budget 

goals. There is a wide range of flexibility available in the type and design of a state plan so it can 

meet the needs of individual utilities, such as the ones in the City of Tallahassee. The EPA in the 

final rule is providing states with maximum flexibility to achieve their emission standards or CO2

state goals in the emission guidelines. For example, states can enter into Multi-state plans, multistate coordination while retaining their individual state goals, and emission budget trading 

programs. Certain rate based state plans can use or purchase ERCs generated from eligible 

resources and do not need to replace resources within their state. These flexibilities provide 

enough latitude for all states to comply with this rule. See section VIII.C of the final rule 

preamble of the CPP for details on the different state plan approaches.

For adjustments made to states’ the interim and final budgets, see the changes from proposal to 

final and the GHG Mitigation Measures TSD which describes the technical aspects of setting the 

interim and final goals in the Final CPP Guidelines. The Final CPP also addresses commenters 

concerns that state plans must include credible and appropriate calculation methods. We describe 

the accounting approaches in VIII.K of the final rule preamble of the CPP and are requiring all 

demand-side EE and RE measures used to adjust the rate to have an Evaluation Measurement 

and Verification Plan (see the Evaluation, Measurement and Verification Guidance for DemandSide Energy Efficiency TSD for more information) to ensure the measures meet EPA’s 

quantifiable and verifiable requirements. 

The following are summaries of the specific public comments under this comment:

Commenters stated that "the interim and final budget is unachievable for the City of Tallahassee 

utilities" and is a key part of Florida's goal. Commenters also stated that "EPA's interim and final 

budget goals need to be adjusted to reflect the corrections in the technical data to reflect the 
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achievable CO2 emission goals while still having a reliable electric network. These adjustments 

also need to take into account the timing required to implement the significant changes that 

would be required by the electric industry. Commenters also stated that the state plans must be 

credible and use appropriate calculation methods."

Comment 11: Comments regarding IPM assumptions about transmission, dispatch and 

reliability.

Response 11: The EPA disagrees. IPM is an interregional dispatch and planning model (See 

model documentation at http://www.epa.gov/airmarkets/powersectormodeling.html). IPM 

imposes interregional transmission limits on the dispatch solution, and has increased the number 

of regions in recent versions to better capture transmission flows. For this rule, IPM is not used

for state level projections or for setting state goals, but rather is used for broad, national 

assessments of program costs and impacts. Contrary to the comments, EPA believes the model is 

sufficiently granular for this purpose.

With respect to the use of IPM for reviewing resource adequacy and reserves, the model is a 

planning model and enforces the planning reserve requirements. It is used in the context to 

provide a broad view of generation and transmission energy and capacity flows to assess 

potential concerns about reliability. EPA believes it is an appropriate tool for this purpose (see 

Resource Adequacy and Reliability Analysis TSD).

The following are summaries of the specific public comments under this comment:

Commenters stated that "EPA's IPM erroneously assumes that transmission is adequate within all 

the IPM regions" and that "prior to the implementation of the final rule, this assumption should 

be corrected, and transmission constraints within, as well as between, the IPM regions should be 

taken into account." Commenters noted that new transmission investment will probably be 

needed especially for coal generation replacement and to maintain reliability. 

Commenters noted that "IPM is categorically not a dispatch model" and had concerns about "the

ability of the IPM to accurately predict and demonstrate grid reliability under the proposed rule." 

Commenters urged "EPA to engage in outreach with the various RTOs, FERC, NERC, and other 

entities capable of adequately modeling dispatch scenarios under the proposed rule" to 

demonstrate grid reliability. 

Commenters stated that "EPA's use of the Integrated Planning Model does not assess the impact 

of the proposed rule on system reliability because the model is not capable of incorporating 

operating reserve requirements, actual transmission system constraints, or variable resources 

with sufficient granularity." Commenters noted that "EPA should incorporate utility planning 

principles into its proposed rule is to support utility reliability assessments rather than 

exclusively relying on the Integrated Planning Model (IPM) to determine reliability impacts." 

Commenters also stated that "IPM does not ensure that generation plants are dispatched to 

maintain sufficient operating reserves among all hours in the year." Furthermore, commenters

said that "IPM assumes significant coal unit retirements by 2020 but does not adequately model 
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transmission constraints that may be associated with retiring and adding generation resources." 

Commenters also stated that "IPM is similarly insufficient to address reliability issues associated 

with increased wind and other variable resources. Generation may only be added if it does not 

compromise the stability or reliability of the transmission system."

Comment 12: Comment about coal usage in Florida.

Response 12: For this rule, IPM is not used for state level projections or for setting state goals, 

but rather is used for broad, national assessments of program costs and impacts. See the RIA 

chapter 3. IPM is a multi-regional, dynamic, deterministic linear programming model of the U.S. 

electric power sector that the has been successfully used by EPA and private companies for over 

two decades to evaluate the economic and emission impacts of prospective environmental 

policies. Projections reflect the most recent and accurate information available. EPA has 

reviewed comments on IPM and has updated the model for use in the final rule. Although 

opinions of future coal production and use in individual areas will differ, IPM projections will 

reflect general industry trends, but future projections can differ considerably depending on the 

case and the scenario. EPA believes the model results as used in the final rule are reasonable.

The following are summaries of the specific public comments under this comment:

Commenters stated that in 2012 Florida generated 221,096 GWh from coal and EPA's model has 

this decreasing by 99% in 8 years to 2,898 GWh in 2020. Commenters stated that load 

dispatching, reserve margins, transmission loading will all be impacted by this and need to be 

evaluated.

Comment 13: Comment regarding IPM assumptions.

Response 13: The IPM assumptions are available at 

http://www.epa.gov/airmarkets/powersectormodeling.html. IPM imposes interregional 

transmission limits on the dispatch solution, and has increased the number of regions in recent 

versions to better capture transmission flows; in particular, the number of regions covering 

Louisiana has been increased. For this rule, IPM is not used for state level projections or for 

setting state goals, but rather is used for broad, national assessments of program costs and 

impacts. EPA believes the model is sufficiently granular for this purpose.

The following are summaries of the specific public comments under this comment:

Commenters stated that states should be able to review IPM assumptions because IPM failed to 

"capture the reality of a number of significant transmission constraints throughout Louisiana, but 

especially in South Louisiana; recognize the need to utilize older, less efficient EGUs located 

within transmission-constrained "load pockets" to meet the electricity demands of both industrial 

and residential ratepayers; and consider power generators in the state (i.e., qualifying facilities) 
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that, by federal mandate, have the right to sell power into the grid and the corresponding 

requirement on host utilities to purchase such power."

Comment 14: Comment regarding an explanation of seven key variables and appropriate 

sources in determining EGU CO2 projections.

Response 14: States can obtain the necessary information from the following organizations.

U.S. Department of Energy, Energy Information Administration, Annual Energy Outlook 

(AEO), North American Electric Reliability Corporation (NERC), Regional transmission 

organizations (RTOs)/independent system operators (ISOs) (e.g., PJM Interconnection, ISO-New 

England, NYISO), Vertically integrated utilities (e.g., a large power company that operates the 

electricity system for a specific region), State energy agencies (e.g., State Energy Office or 

Public Utility Commission (PUC)), and Regional councils that coordinate energy planning (e.g., 

Northwest Power and Conservation Council) or any other publically available data source. If a 

state wants to use another data source, they need to justify why it is more appropriate. The EPA 

clarifies what assumptions will be required as part of the CO2 emissions projections in Section 

VIII.D.2.(a)(3) of the final rule preamble of the CPP. The agency has added additional 

assumptions that are needed for projections and describes which state plans require a projection 

and which state plans do not require one.

The following are summaries of the specific public comments under this comment:

Commenters stated that EPA mentioned seven key variables that may determine EGU CO2

projections on page 17 of EPA's TSD titled "Projecting EGU CO2 Emission Performance in State 

Plans" (June 2014) but did not explain "where the data for each of the variables will or should 

come from." Commenters requested that the following sources be considered: - Electricity load 

growth projections (energy peak and demand) - State PUCs, EIA's AEO) - Fuel supply, delivery, 

and pricing assumptions - RTO/ISO, EIA - Cost and performance of electric generating 

technologies - EIA - EGU firm builds and retirements (e.g., those scheduled with a RTO/ISO) -

RTO/ISO - Transmission capability and RTO/ISO transmission expansion plans - RTO/ISO -

Applicable federal regulations (other than the EPA emission guidelines) - RTO/ISO, NERC, 

FERC - Applicable state regulations and programs (other than those that are included in the state 

plan) - State where generation occurs or state where demand occurs."

Comment 15: Comments regarding energy market trend projections.

Response 15: The EPA in the final rule is providing states with maximum flexibility to achieve 

their emission standards or CO2 state goals in the emission guidelines. For example, states can 

enter into Multi-state plans, multi-state coordination while retaining their individual state goals 

and emission budget trading programs. Certain rate based state plans can use or purchase ERCs 

generated from eligible resources and do not need to replace resources within their state. These 

flexibility provide enough latitude for all states to comply with this rule. See Section VIII. C of 
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the final rule preamble of the CPP for details on different state plan approaches states can use to 

comply with the emission guidelines. 

The EPA will allow states to use a reliability safety valve for when emergency situations arise, 

with certain restrictions. Section VIII.G.2 of the final rule preamble of the CPP provides

examples to illustrate several key attributes of the kinds of circumstances in which the reliability 

safety valve would apply.

The following are summaries of the specific public comments under this comment:

Commenters stated that it is a challenge to project energy market trends for the next 15 years and 

therefore proposed "that EPA include a framework for providing appropriate flexibility to head 

off potential unforeseen impacts to electricity affordability and reliability." Commenters added 

that the flexibility should be limited to minimize exploitation of a "safety valve."

Comment 16: Comments concerning the use of AVERT and EGRID and consider AVERT 

results questionable until EPA conducts a more thorough quality review of the tool.

Response 16: In the final rule, the EPA allows for the adjustment of a CO2 emission rate based 

on avoided MWhs, not avoided CO2 so avoided CO2 calculations using emission rates are not 

necessary. For more information about specific methods to adjust the CO2 emission rate of an 

affected EGU to reflect RE and demand-side EE and how the methods ensures consistency with 

the goal setting calculations in the final rule, see Section VIII.K.1 of the final rule preamble of 

the CPP.

In the final rule, EPA does not require a projection of CO2 emission performance for all state 

plan approaches. For those that do require a projection, EPA does not require that states use 

specific models, like AVERT, but gives states flexibility provided they use technically sound 

methods that are reliable and replicable. EPA addresses what types of state plan approaches 

require a projection and requirements related to methods and tools in Section VIII.D.2.a.(3) of 

the final rule preamble of the CPP.

The EPA disagrees with the commenters claims that AVERT has not gone through the proper 

quality control procedures. The EPA conducted an official peer review process as required by 

EPA for all tools that could be used for regulatory purpose. It also was benchmarked against an 

industry standard dispatch model and includes the appropriate caveats in its user manual.

Although AVERT is most appropriate as a screening tool for the final CPP, it is available for 

states to use for NAAQS compliance.

The following are summaries of the specific public comments under this comment:

Commenters noted concerns with the Avoided Emissions and Generation Tool (AVERT), 

including 1) it does not provide forecasting beyond five years which limits a state's ability to 

make long term assessments and agreements with states required for multi-state plan 

development; 2) it assumes that dispatching in the future will be similar to the recent past so does 
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not support planning beyond a few years and does not reflect that the rule will probably result in 

substantial changes to electricity dispatching and/or allow for the use of projected economic 

behavior; 3) approximates historical dispatch behavior using a statistical algorithm that does not 

represent transmission constraints or significant changes in grid structures or future economic 

conditions; 4) does not capture inter-regional transmissions and requires coordinating with all the 

other states in the electric grid region to estimate the expected reduction in MWhs and the hourly 

load profile for those MWhs in the reporting/planning period; and 5) commenters identified 

errors in the AVERT tool, notes that it produces unusual results, and does not believe that EPA 

followed a quality assurance and quality control plan in the development of AVERT and 

therefore considers the results generated to be questionable.

Commenters noted that EPA's AVERT is relatively simple and does not require a great deal of 

resources to use but noted that both the AVERT and EGRID models are not appropriate due to 

their limited short term forecasting capability and that EGRID factors are usually 2 years older 

than the most current year.

Commenters felt that the model limitations will not allow for educated projections for EE/RE 

quantification for state plans.

5.8.1a National-scale capacity expansion and dispatch planning models

[No comments were received on this topic.]

5.8.1b Utility-Scale Capacity Expansion and Dispatch Planning Models

[No comments were received on this topic.]

5.8.1c Electricity System Dispatch Simulation Model

Comment 1: Comment regarding IPM assumptions and results.

Response 1: For this rule, IPM is not used for state level projections or for setting state goals, 

but rather is used for broad, national review and for assessments of program costs and impacts.

See the RIA chapter 3. IPM is a multi-regional, dynamic, deterministic linear programming 

model of the U.S. electric power sector that the has been successfully used by EPA and private 

companies for over two decades to evaluate the economic and emission impacts of prospective 

environmental policies. Projections reflect the most recent and accurate information available.

EPA has reviewed comments on IPM and has updated the model for use in the final rule; EPA 

believes the model results used in the final rule are reasonable.
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The following are summaries of the specific public comments under this comment:

Commenters stated "that the assumptions used in EPA's Reliability and Cost Modeling Analysis 

are unrealistic, particularly with respect to electricity imports, power plant ownership, and 

energy efficiency." Commenters mentioned that it understand "that states can determine the 

ultimate path forward" which can be different from the IPM results but believe that it is 

inappropriate for EPA to rely on IPM results based on unrealistic assumptions to show "that the 

Agency's proposal is feasible and cost effective." Commenters stated that "EPA's Reliability and 

Cost Modeling Analysis predicts that Arizona would adopt a significantly different approach to 

meet the state's CO2 goals than EPA assumed in setting those goals." Commenters mentioned 

that "the goal setting approach assumes that all coal-fired generation would be displaced with 

existing, in-state NGCC generation, and that renewable energy and energy efficiency measures 

would increase according to the assumptions EPA made in establishing Building Blocks 3 and 4" 

but that "EPA's Reliability and Cost Modeling Analysis predicts that Arizona would import more 

than 5,800 MW of electricity from outside of the state, achieve even greater energy efficiency 

savings than assumed in setting the state goals, and keep 1,500 MW of coal generation online." 

Commenters also stated that "IPM predicts that Arizona will transition from a net exporter of 

energy to a significant net importer by 2020 only 2.5 years after EPA takes action on the state's 

compliance plan. Even more problematic, the IPM assumes that the imported electricity would 

come from California and the Pacific Northwest during the peak hours," and commenters 

asserted that EPA has not conducted a transmission infrastructure study to determine if this is 

possible. Furthermore, commenters stated that due to Arizona Corporation Commission's (ACC) 

IRP rules, utilities would not be able to rely on power from the Pacific Northwest for peak 

demand and that utilities might "construct new in-state generation and potentially new 

transmission to ensure adequate reliability at peak load conditions and minimize risk to 

customers that might be introduced by heavier reliance on energy markets or power that is 

generated several states away." Commenters mentioned that IPM does not properly account for 

power plants that are jointly owned and gave examples of how some of Arizona's generation 

goes out of state. 

Commenters also mentioned that "The model assumes that all power generated by a plant located 

within Arizona is available to meet Arizona's peak demand, regardless of whether a portion of 

that plant is owned by an out-of-state entity and their portion of electricity is exported out of 

state to serve that entity's load obligations. For example, the IPM assumes that the entire capacity 

of PVNGS (3,937 MW) is available to meet Arizona's peak demand. However, less than 50% of 

PVNGS is owned by Arizona utilities. In addition, some of Arizona's largest coal-fired power 

plants are jointly owned. For these resources, the portion of capacity that is not owned by 

Arizona utilities likely does not serve Arizona load. The IPM inaccurately assumes that the entire 

generation capacity from these plants is available to serve Arizona load, whereas in reality, a 

large fraction of this energy is owned by out-of-state entities and therefore leaves the state. 

Additionally, many of Arizona's existing NGCC plants are owned or partially owned by 

merchant providers. It is inaccurate to assume that generation from merchant-owned NGCC 

plants serves Arizona load unless a long-term purchased power contract is in place with an 

Arizona utility serving Arizona load." 
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Commenters said that a problem with Building Block 2 analysis is that it does not take into 

account needs to run generators on peak demand but focuses on annual data. For Building Block 

3, commenters pointed out that the Building Block analysis RE target is 3.7 million MWh in 

contrast to the IPM Model projection of 2.7 million MWh due to the differences in 

implementation of the state RPS targets in IPM versus the Building Block analysis. For Building 

Block 4, commenters said that some EE should be part of the IPM Base case analysis and that 

IPM overstates EE related peak load reductions. Commenters also stated that since no EE is part 

of the Base case the Clean Power Plan appears to be less expensive in the RIA since there is a 

lower electricity demand. Commenters stated that using the Building Block 4 Case as the 

baseline provides "a better estimate of the actual cost of the Policy." Commenters also stated that 

IPM ignores existing transmission reservations to transfer power among utilities and states, 

ignores the lack of centralized reserve sharing and dispatch among utilities and ignores the cost 

of contractual arrangements for imported capacity.

5.8.1d Multi-Sector Models

This section addresses comments on Multi-Sector Models specifically with regards to 

transportation electrification.

Commenters have raised a number of issues related to this subsection which are organized by 

topics (comments) below. Responses are also provided for these topics.

Comment 1: Comments regarding transportation electrification.

Response 1: The commenters asked EPA to consider transportation electrification in their 

methodology for rate to mass conversion and be able to recognize its impacts on electricity 

demand. In section VIII.K of the final rule preamble of the CPP, the EPA describes whether 

transportation electrification can be used as a measure that impacts CO2 emissions performance 

given that it is a measure that reduces CO2 outside of the electric power sector. 

The following are summaries of the specific public comments under this comment:

Commenters stated that, "The final guidelines should ensure that states are not penalized for 

reducing emissions from the transportation sector." Commenters argued that due to 

electrification of transportation vehicles affected units may emit more than the capped level of 

emissions but that overall emissions would be reduced. Commenters stated that EPA guidelines 

need to be adaptable depending on state circumstances and gave California as an example where 

electrification of vehicles is already being used to meet air quality goals. Commenters stated that 

they want EPA's final guideline to "recognize that states may adjust annual reports to reflect 

emissions increases related to transportation sector electrification, if necessary." Commenters

recommended that if there is a mass-based program option that includes both existing and new 

generation then EPA should "allow states that choose a mass-based equivalent target to adjust 

the target consistent with the actual transportation electrification load if appropriate." 
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Commenters recommended if there is a mass-based program option that includes both existing 

and new generation then EPA should allow the states to use the following formula to account for 

the actual transportation electrification load. "MBEGA = MBEGF+TE*ERBG Where: MBEGA 

is the adjusted final Mass-based Equivalent Goal, (Acronym changed for simplicity. It has 

"adjusted final" instead of A.) MBEGF is the final Mass-based Equivalent Goal adopted by EPA

in its final rule, (Acronym changed. It has "final" instead of F) TE is the actual transportation 

electrification load in excess of the transportation electrification load already included in the load 

forecast used to determine the Mass Equivalent Generation Level, and (Acronym changed, it had 

"additional" as subtext.) ERBG is the Emission Rate-Based Goal." Commenters suggested using 

this formula because projections of new transportation electrification load vary. Commenters

noted that EPA used AEO 2013 projections of 2.03 million electric vehicles in 2025 and thought 

this was conservative given CARB's estimate for 10 states with ZEV programs is 3.1 million 

electric vehicles in 2017-2025 and Navigant Research's projection of 2.75 million electric 

vehicles by 2023.

Commenters urged "EPA to take into consideration California's efforts to reduce criteria 

pollutant and greenhouse gas (GHG) emissions through transportation electrification if 

California sets a mass-based goal." Commenters noted that "increased transportation 

electrification will, however, lead to increased electricity demand and increased CO2 and criteria 

pollutant emissions at fossil-fueled EGUs within the South Coast Air Basin, although overall 

emissions will significantly decrease." Therefore, commenters stated that EPA should take 

transportation electrification into account when approving state emissions projections.

Commenters asked that EPA "ensure that 111(d) standards do not create disincentives to 

transportation electrification. Commenters further stated, "Transportation electrification is wellrecognized by experts, air regulators and others as a key strategy to reduce GHGs and other 

criteria pollutants. (For the purposes of this section, transportation electrification includes both 

on-road vehicles (including light-, medium-, and heavy-duty vehicles) as well as off-road 

equipment (such as forklifts, commuter and transit rail, ship shore power, airport ground support 

equipment, truck stop electrification, and transportation refrigeration units). Recognizing its 

importance, EPA and state air pollution regulators have programs to promote transportation 

electrification, such as EPA's light-duty vehicle GHG rules and state NAAQS attainment SIPs 

that include Zero-Emission Vehicle programs. EPA should ensure that the final rule is consistent 

with the goal of electrifying the transportation sector to reduce GHGs and other criteria 

pollutants." 

Commenters further stated that "transportation electrification is a key strategy to reduce carbon 

pollution and criteria pollutants."

Commenters wrote, "Since the electricity sector has the potential for greater GHG emissions 

reductions through the transition of generation to renewable energy, electrifying vehicles is a key 

long-term strategy for deep GHG, as well as criteria pollutant emission, reductions in the 

transportation sector."

Commenters noted, "According to the International Energy Agency (IEA), achieving the climate 

stabilization goal of 450 ppm by the end of this century requires half of the global light-duty 

vehicles sold in 2050, about 100 million vehicles, to be battery electric or plug-in electric 
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vehicles. The IEA's 2020 sales target for North America is about 1.5 million vehicles. IEA calls 

this decade a "make or break" period for plug-in electric vehicles ("PEVs") and that "EV/PHEV 

sales must reach substantial levels by 2015 and rise rapidly thereafter."

Commenters stated, "EPA has recognized the "game changing" nature of PEVs in reducing 

GHGs by providing two temporary incentives in its model year 2017 to 2025 light-duty vehicle 

("LDV") GHG emission standard program. First, it allows auto manufacturers to treat a certain 

number of electric vehicles, plug-in hybrid electric vehicles, and fuel cell vehicles as "zero 

emissions" by ignoring power plant and other upstream emissions. Second, it provides temporary 

sales multipliers for all battery electric vehicles, plug-in hybrid electric vehicles, and fuel cell 

vehicles sold in model years 2017 through 2021."

Commenters concluded that "Ten states have included PEVs in their state ozone SIPs, in the 

form of zero-emission vehicle ("ZEV") programs as part of their adoption of California's LowEmission Vehicle Program ("CA LEV III")" and "Clearly, ZEVs are an integral component of 

Clean Air Act emissions compliance generally."

5.8.2 Growth Tools for Projecting EGU Utilization and CO2 Emissions

This section addresses comments on growth rates.

Commenters have raised a number of issues related to this subsection which are organized by 

topics (comments) below. Responses are also provided for these topics.

Comment 1: Comments regarding growth rates.

Response 1: In the Final CPP rule the EPA is not requiring states to use EIA growth rates. The

EPA lists the eligible sources states can use to inform their growth rates, ISOs and RTO’s are 

valuable resources and their growth rates can be used in state’s projected performance so long as

they are properly representing the growth rates and demand assumptions. See the Incorporating 

RE and Demand-Side EE Impacts into State Plan Demonstrations TSD for further information 

about acceptable sources for growth rates, including ISO and RTOs.

The following are summaries of the specific public comments under this comment:

Commenters said States should determine growth rates and not have to use EIA growth rates. 

Commenters asserted that states should be able to determine the growth rate to apply to EGUs in 

their state based on forecasted future growth by the ISOs and RTOs. Commenters also stated that 

EPA "should not require states to use EIA growth rate estimates."
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5.8.3 Translating from a rate-based emission performance goal to a mass-based emission

performance goal

This section addresses comments on translating rate-based performance goals to mass-based 

performance goals. We have organized the comments in this section under three subsections, 

5.8.3a to 5.8.3c. Responses to the comment topics of these subsections are discussed below along 

with summaries the specific public comments.

Commenters have raised a number of issues related to this subsection which are organized by 

topics (comments) below. Responses are also provided for these topics.

Comment 1: Comments regarding factoring demand in rate-based and mass-based standards and 

conversions and allowing enough time for comments.

Response 1: The EPA is providing both rate-based and mass-based statewide goals in this final 

rule in place of having states determine the mass values themselves, in order to assure that the 

mass goals are an equivalent expression of the BSER. The mass goals provided enable growth in 

generation from affected EGUs. The new source complements to the mass-based goals are 

derived based on the expected future demand levels projected by the EIA’s AEO2015. See the 

CO2 Emission Performance Rate and Goal Computation TSD for CPP Final Rule for details on 

the calculations of these goals.

This final rule allows states to alternatively establish emission standards that meet rate-based or 

mass-based state goals. The EPA supports having the flexibility to use rate-based goals or massbased goals as part of state plans. 

The EPA will consider allowing states, via State Plan submittal or revision, to adjust their 

statewide rate or mass goal if such a change is necessary. See section VII of the final rule 

preamble of the CPP for further details on allowable adjustments to state wide mass-based CO2

goals.

In the June proposal, EPA took comment on a number of ways that States could convert rate 

based targets to mass based targets. Following the proposal, EPA received significant input 

from a wide variety of commenters that more detail on a methodology for calculating mass based 

equivalent targets based on historical data would be helpful. Many stakeholders also developed 

methodologies. Based on this large response, EPA supplemented the record on this limited 

portion of the rule. In particular, EPA proposed a methodology (similar to methodologies a 

range of commenters had developed independently) to convert the rate based targets to mass 

based targets. EPA believes the amount of time that commenters had to provide additional 

comment on the November TSD was sufficient because: 1) the methodologies provided were 

consistent with the proposed methodological construct for converting rate based targets to mass 

based targets; 2) no new data was introduced in the TSD describing this conversion; 3) the fact 

that a range of commenters independently developed similar approaches to the approach that 

EPA requested additional comment on demonstrates how much EPA's methodology built off of 
141

the original proposal and the fact that even absent the supplemental proposal, many stakeholders 

were already actively considering this issue as part of their comments; 4) the fact that the 

methodology that EPA was requesting comment on, was merely a calculation methodology and 

did not change any of the underlying control assumptions.

The following are summaries of the specific public comments under this comment:

Commenters stated that "the Mass-Based Equivalents TSD describes an approach for translating 

the rate-based goals that does not assume any increase in generation at existing units." 

Commenters stated they think states like California may have an increase in generation due to 

electrification of vehicles and that to support renewable integration they suggest that EPA 

"assign some of the increased generation associated with expected load growth to existing units." 

Commenters suggested that EPA switch from a rate-based standard to a mass-based standard or a 

rate-based standard with some baseline year's generation, say 2012, in the denominator. 

Commenters said this will eliminate three big problems with the proposed rate-based standard 

which are that energy conservation usually overestimates savings, states can subsidize solar or 

wind to meet their rate-based target, and during recessions electricity demand goes down making 

it harder to meet a rate-based target. 

If EPA decided to follow one of the approaches in the Rate-to-Mass TSD, then commenters

suggested two adjustments to account for future load growth and to ensure equivalency between 

rate-based and mass-based goals. Commenters suggested that EPA should allow states to 

incorporate reasonable assumptions for future load growth in option one in the Rate-to-Mass 

TSD. For option two in the Rate-to-Mass TSD, commenters suggested EPA provide a 

mechanism for the states to revise load growth if the EIA demand forecasts turn out to be 

incorrect. Commenters thought this might happen in California where transportation 

electrification could increase demand. Commenters also stated that for both approaches in the 

Rate-to-Mass TSD Building Blocks three and four do not match the proposed rate-base approach 

presented by EPA in June 2014. 

Commenters asserted that EPA did not provide enough time to analyze the rate-to-mass 

conversion in the Rate-to-Mass TSD and that any regulatory requirements and guidance of such 

an important aspect of the rule cannot be finalized without public comment and due process. 

Commenters also noted that RGGI, which was cited by EPA as an example program, needed 

flexibility to adapt and change its program, therefore, they stressed the need for "true flexibility 

to adjust state goals and plans when warranted." 

Commenters stated that the Rate-to-Mass TSD was released late in the notice-and-comment 

process and that if the stringency of the goals increase there should be an additional opportunity 

to comment. 

Commenters stated that they believe that the assumption "that electricity demand will hold 

steady or grow from now until 2030 is false" and EPA should modify the CPP, in order for the 

states to modify their plans if actual demand or a newly released electricity demand forecast 

deviates by more than 10% from the forecast used in a state's rate or mass based Implementation 

Plan. Commenters also stated that "conversion to mass-based goal via use of 2012 E-Grid 
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emissions should not be permitted." Commenters also stated that, "EPA should condition ratebased to mass-based compliance upon inclusion of all sources, both new and existing, within the 

mass-based compliance framework. A state would then be free to elect rate-based compliance for 

existing sources only, or to opt for mass-based compliance for both new and existing sources."

"Can EPA provide clarity in regards to a state using a mass-based rate (cap on tonnage for CO2

emissions) in its plan and the flexibility in this approach to support an increased generation 

demand (if it should occur during the interim phase)? Page 17 of the "Projecting EGU CO2

Emission Performance in State Plans" TSD suggests that mass-based goals may account for 

increases in generation at existing affected units projected to occur as a result of load growth. Is 

this correct?" 

Comment 2: Comments regarding Rate to Mass conversion questions.

Response 2: The EPA is providing both rate-based and mass-based statewide goals in this final 

rule in place of having states determine the mass values themselves, in order to assure that the 

mass goals are an equivalent expression of the BSER. See the CO2 Emission Performance Rate 

and Goal Computation TSD for CPP Final Rule for details on the calculations of these goals. 

This final rule allows states to alternatively establish emission standards that meet rate-based or 

mass-based state goals. The EPA supports having the flexibility to use rate-based goals or massbased goals as part of state plans. The EPA notes that it is the emission performance rates in 

section VI of the final rule preamble of the CPP that constitute the application of the BSER to the 

affected EGUs and serve as the chief regulatory requirement of this rulemaking. The statewide 

CO2 rate-based and mass-based emission performance goals provided in the final preamble as

metrics that states may choose to adopt when demonstrating compliance at the state level, and 

states may consider these goals when determining how to set unit-level compliance 

requirements. See Section VII of the final rule preamble of the CPP for the statewide CO2 goals. 

Since the EPA is providing these state-wide CO2 goals the individual comments related to how 

to translate from rate to mass based targets are no longer relevant to the final CPP rule. 

The EPA will consider allowing states, via State Plan submittal or revision, to adjust their 

statewide rate or mass goal if such a change is necessary. See Section VII of the final rule 

preamble of the CPP for further details on allowable adjustments to state wide mass-based CO2

goals.

The following are summaries of the specific public comments under this comment:

Commenters co-sponsored a 111(d) webinar on September 24, 2014 and generated the following 

questions on rate to mass conversion. 

Question 1: "EPA did not use modeling to calculate rate-based goals, but EPA's "Projecting EGU 

Emission Performance in State Plans" TSD discusses modeling in the context of mass-based 

goals. Why? Should states use EPA's IPM base case for the power sector through 2030 in order 

to develop business-as-usual baseline for mass goal conversion?" 
143

Question 7: "If a state were to multiply the interim goal by the total generation of affected 

sources and "affected entities" in a specific year to calculate the mass-based emission cap, is this 

method acceptable? (For example, Pennsylvania's interim goal is 1,179 lb/MWh net. If our net 

generation in 2020 is equal to our 2012 net generation of 150,858,087 MWh, our cap will be 

88,930,842 tons. If our net generation in 2020 is equal to EPA's projected net generation in 2020 

of 162,699,881 MWh, our cap will be 95,911,580 tons.)" 

Question 8: "Can a state use their year-to-year goals used in determining their interim goal 

(columns AQ to AZ in the 20140602tsd-state-goal-data-computation spreadsheet) to calculate 

the mass based cap? a. For example, in the attached spreadsheet, 2020-2029 rate based goals are 

converted by taking the numerator from columns AQ-AZ and setting that equal to the mass 

based goal. When you do that, the numerator is a constant value for 2020-2029, so the mass 

based goal is a constant value for 2020-2029 (column BC). Does EPA agree with this approach? 

If not, how should the calculation be changed?" 

Question 9c: "How do we address new renewable generation or new incremental hydro 

generation that is both scheduled to be completed and on-line after 2020 and all of the generation 

will serve out-of-state load?" 

Question15: " If a state elects to convert their rate-based goal to a mass-based goal and the 

effected entities consist only of those that own or operate affected EGUs, how much qualitative 

and quantitative detail on the various CO2 emission reduction and avoidance mechanisms (e.g., 

heat rate improvement, re-dispatch to natural gas, renewable energy, energy efficiency) that 

would be used by the affected entities to meet the mass-based goals needs to be included in the 

state plan?" 

Commenters co-sponsored a 111(d) webinar on November 20, 2014 and had the following 

question related to rate to mass conversion. 

Question 6: "By using Table 1 of the rate-to-mass goal translation TSD, GA EPD calculates that 

Georgia fossil generation in 2030 would shrink to 51 % of fossil generation in 2012. By 

comparison, data from the Annual Energy Outlook 2014 for the SERC-SE region project that 

2030 fossil generation will be 123 % of 2012 generation. See Table GA-2. How does EPA 

account for this very large disparity and is the fossil generation projected by the TSD realistic?"

Commenters stated that while the rule allows use of either a mass-based or rate-based goal, many 

states will likely use mass-based approach because it is more simple, however mass-based targets 

do not account for load growth, which creates incentive to rate-based because the rate remains 

the same regardless of fluctuations. Commenters suggested that to equalize the 2 options, EPA 

should consider population changes and load growth when setting target emission standards.

Commenters requested that the following option be implemented to improve the workability of 

the proposed guideline rule and to provide additional compliance flexibility to meet the emission 

targets established in the proposal: states should be provided the opportunity to seek future 

adjustments to their state targets based on changing circumstances. 
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Comment 3: Comment regarding CO2 reductions after 2030.

Response 3: In the Final CPP Rule, the EPA is requiring states to submit projected CO2

performance demonstrations through 2031. We are also requiring that the measures in place in 

2031 should not sunset. In addition, the state plan must identify requirements that continue to 

apply after 2030 and are likely to maintain affected EGU emission performance meeting the final 

goal. This provision will continue to protect public health and the environment after 2030 and 

beyond.

The following are summaries of the specific public comments under this comment:

Commenters stated that EPA should require CO2 reductions after 2030 to reflect BSER and 

mitigate climate change.

Comment 4: Comments regarding EM&V protocols.

Response 4: The preamble to the proposed Federal Plan describes the use of EM&V protocols 

for Energy Efficiency. Refer to section IV.D.8 of the preamble to the Federal Plan for more 

details. In addition the EPA will release a draft guidance on EM&V protocols and the public will 

have the opportunity to comment on this guidance document. The EPA welcomes stakeholder 

input on the guidance document.

The following are summaries of the specific public comments under this comment:

Commenters said that "states that choose to use energy efficiency for compliance need to 

develop and provide EPA with a plan for evaluating energy savings" and that a challenge to 

impose an emissions rate target is that "state approaches to EM&V differ". Commenters

encouraged EPA to impose strong guidance on EM&V practices since differences "in EM&V 

practices may provide an incentive to convert to a mass-based approach."

Comment 5: Comments regarding use of renewable energy credits.

Response 5: The EPA addresses this concern in the final rule. See section VIII.C.(1) of the final 

rule preamble of the CPP for details on the rationale for our true-up period for emission budget 

trading programs. See section VIII.K of the final rule preamble of the CPP for EM&V protocol 

discussion and the EPA’s criteria for preventing double counting of RECs.

The following are summaries of the specific public comments under this comment:

Commenters mentioned that each state's mass target limit should be based "on the actual 

regulated generation in that state during the compliance interval" with a "true-up" period similar 

to the Acid Rain Program. Commenters also stated that like RGGI there should be an annual 

readjustment to the mass-based program. Commenters also stated that in order for a state to 

receive credit for their EE measures under either a rate or mass based system the states would 
145

need to do EM&V. Commenters also proposed a rate to mass based conversion that prevents 

double counting renewable energy credits because a state can either sell the REC or use it during 

"true-up".

Comment 6: Comment regarding Rate to Mass interstate issues.

Response 6: The Final CPP Rule does address Rate to Mass interstate issues. See Section VIII.L 

of the final rule preamble of the CPP for the EPA’s rationale for the treatment of interstate 

effects and the interaction between rate and mass based state plan approaches. 

The following are summaries of the specific public comments under this comment:

Commenters stated that EPA should address potential interstate issues caused by having some 

states using a rate-based approach and other states using a mass-based approach for compliance.

5.8.3a Reference Case Scenario

This section addresses comments on EIA reference case scenarios. 

Commenters have raised a number of issues related to this subsection which are organized by 

topics (comments) below. Responses are also provided for these topics.

Comment 1: Comments regarding EIA’s electric demand growth projections.

Response 1: The commenters are concerned about the uncertainty of using EIA demand growth 

projections and the inability to revise their plan if the future turns out different than expected 

given projections and demand growth uncertainty. The EPA is finalizing that states may revise 

their plan under certain situations. See Section VIII.E.7 of the final rule preamble of the CPP for 

further details. States do not need to use EIA for their demand growth projections, the EPA lists 

a number of sources states can use, including the Regional Planning Organizations among others.

See section VIII. D of the final rule preamble of the CPP for details on the available data sources 

states can use for their demand projections.

The following are summaries of the specific public comments under this comment:

Commenters recommended that EPA should "use the US EIA Low Electric Demand Case for 

forecasting future electric demand." Commenters stated The Low Electric Demand Case 

assumed that electric demand will be flat through 2040 just like it was from 2008-2012 and it 

"results in faster coal fired power plant shutdowns, and lower total electric generation." 

Commenters mentioned that the reference case used by EPA assumed 1% growth in electric 

demand. Commenters stated that there is a likelihood that EIA will use a no growth reference 

case in the 2015 Annual Energy Outlook. 
146

Commenters stated that the "EPA made the assumption that there will be no electricity demand 

growth in the future in contrast to EIA's Annual Energy Outlook 2014 with projections to 2040 

released April 2014" and commenters also stated that they have concerns about the EPA's 

"expertise in the area of energy forecasting." Furthermore, commenters stated that they have 

concerns about the accuracy of the tools EPA is proposing the states use to project CO2

emissions, electric demand, and the growth of RE and EE for the next ten years. Commenters

pointed out that 5 out of 9 ten-year AEO projections have a greater than 10% margin of error. 

Commenters stated that "despite the EIA's substantial expertise, the accuracy of their projections 

is in many cases limited. Commenters stated that in the proposed rule, states, whom have far less, 

or in some cases no expertise in the projection of CO2 emissions or electricity demand or sales, 

would be tasked with developing a similar projection. Commenters stated this projection would 

then become federally enforceable, and the states held accountable for any errors or misprojections. Furthermore, commenters stated that once federally enforceable, the projections and 

required measures taken in the state to meet them become relatively inflexible, which raises great 

concerns should such measures impact grid reliability or introduce unforeseen or substantial 

costs to the states." Commenters also stated that "EPA does not have the expertise or authority to 

require states to develop plans that essentially micromanage the electric grid."

Comment 2: Comment regarding unit retirements.

Response 2: The baseline inventory the EPA uses relies on historical data and does not 

incorporate anticipated future retirements. The EPA and most commenters supported this 

treatment as they viewed those scheduled retirements (and corresponding emission reductions) as 

an alternative compliance flexibility based on already scheduled reductions. 

The following are summaries of the specific public comments under this comment:

Commenters stated that "EPA should expressly allow states to rely on unit retirements occurring 

after the baseline year(s) to meet Section 111(d) goals. Commenters stated that retirements 

should be given equal credit under a rate-based or a mass-based program." 

Commenters said that "even if the retirement was planned before the Proposed Rule," the EPA 

should not include it in the reference case because this penalizes the state.

Commenters wanted EPA to clarify that "retirement of coal-fired power plants after 2012 would 

count toward compliance under a mass-based cap." Commenters stated that EPA should allow 

full credits for retirements occurring after the baseline year and that the "retirements should be 

given equal credit under a rate-based or a mass-based program." Commenters asserted that under 

the current proposed rule states that use a rate-based goal will not fully benefit from a unit's 

retirement if the replacement generation comes from out of state. Commenters also stated that 

the state's "reference case" should include all EGUs that a company or state has agreed to retire 

and then this reference case should be used to determine the mass based goal.

Commenters asked how states could account for retirements and other changes as the states are 

developing their plans and projecting emissions performance over the compliance period 

(keeping in mind that not all states have modeling tools available).
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5.8.3b Mass-Based CO2 Emission Goal Policy Scenario

This section addresses comments on mass-based CO2 emissions goals.

Commenters have raised a number of issues related to this subsection which are organized by 

topics (comments) below. Responses are also provided for these topics.

Comment 1: Comment regarding mass-based plans with administrative adjustments.

Response 1: The EPA is allowing mass based plans to be an option for state plan compliance.

See section VIII.E.7 of the final rule preamble of the CPP that describes when and how states 

can submit plan revisions to the EPA under certain circumstances. 

The following are summaries of the specific public comments under this comment:

Commenters stated that EPA should allow mass-based plans for state plan compliance as long as 

the states are allowed to make administrative adjustments if there are increases or decreases in 

electricity demand from fossil fuel-fired generators due to EE and RE efforts.

Comment 2: Comment regarding mass-based approach and controls.

Response 2: The commenter has expressed his support for certain types of BSER approaches.

States have the flexibility to choose a rate based or mass based goal to comply with the EPA 

emission guidelines in this final CPP. 

The following are summaries of the specific public comments under this comment:

Commenters do not "support the levels of control proposed in either the rate-based or massbased approach" but do "support the use of a mass-based approach that is reflective of the level 

of emission control achievable through the application of BSER at all existing power plants."

5.8.3c State Plan Policy Scenario

[No comments were received on this topic.]

5.8.4 Projecting CO2 emission performance under a state plan

This section addresses types of projections that will be required in a state plan.
148

Commenters have raised a number of issues related to this subsection which are organized by 

topics (comments) below. Responses are also provided for these topics.

Comment 1: Comments regarding the types of projections that will be required in a state plan.

Response 1: The EPA has further clarified the types of projections that will be required in state 

plan submittals. The performance projection will differ depending on the type of state plan a 

state chooses to submit. The way energy efficiency and renewable energy (EE/RE) will be 

accounted for in a state plan also is dependent on the type of state plan a state chooses to use to 

comply with EPA’s emission guidelines. See section VIII.D.2(a)(3) State Plan Performance 

Demonstration and Section VIII.K. of the final rule preamble of the CPP for details on 

requirement related to performance projections and how to account for EE/RE in a rate based 

plan. 

The following are summaries of the specific public comments under this comment:

Commenters stated that the Missouri Department of Natural Resources supported only projecting 

"the statewide average emission performance levels of affected entities, which can include credit 

for renewable generation and avoided generation from energy efficiency under a rate-based 

approach" in the state plans.

5.8.5 Applied Considerations for Different Types of State Plans

This section addresses considerations for different types of state plans.

Commenters have raised a number of issues related to this subsection which are organized by 

topics (comments) below. Responses are also provided for these topics.

Comment 1: Comments regarding enforceability requirements.

Response 1: The EPA has clarified the key components related to state based allowance trading 

and how the enforceability requirements differ depending on if the state plan is an emissions 

standards plan, which is federally enforceable and a state measures state plan that may have both 

federally enforceable and state enforceable elements. Please refer to Section VIII. C. for an 

overview of state plan approaches and Section VIII. J. of the final rule preamble of the CPP for 

details on the additional considerations for mass based plans. 

The following are summaries of the specific public comments under this comment:
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Commenters asserted that EPA should consider making some specific key components of statebased allowance systems federally enforceable such as total allowances in the system and 

requiring sources to hold allowances. Commenters also stated that implementation details should 

be subject to state law and be enforceable by the state.

5.8.5a Approaches for Estimating the Future Effects of State Energy Efficiency 

Requirements, Programs, and Measures

[No comments were received on this topic.]

5.8.5b Potential Uses of Energy Efficiency Projections for State Plan Emission Projections

This section addresses energy efficiency projections uses in state plans.

Commenters have raised a number of issues related to this subsection which are organized by 

topics (comments) below. Responses are also provided for these topics.

Comment 1: Comments regarding energy efficiency and BSER.

Response 1: The EPA has determined not to include demand-side energy efficiency (building 

block four) in the BSER of this final rule. Although we do not need to determine the overall 

scope of the phrase “system of emission reduction,” we recognize that commenters have raised 

extensive legal concerns about building block 4. We recognize that building block 4 is different 

from building blocks 1, 2, and 3 and the pollution control measures that we have considered 

under CAA section 111. Accordingly, in light of our past practice and current policy in 

implementing section 111, as well as the legal concerns raised in public comment, today’s final 

action excludes building block 4 from the BSER. Since we are not including BB4 in BSER and 

we do not need to address this concern. This determination is discussed in section V.B of the 

final rule preamble of the CPP.

The following are summaries of the specific public comments under this comment:

Commenters stated that they believe that "EPA's BSER determination should not include 

reductions attributable to energy efficiency programs because these programs are not under the 

direct control of the utility and cannot be traced to solely offsetting CO2 emissions from existing 

affected EGUs." Furthermore, commenters stated that if EPA wanted to use energy efficiency 

then EPA should do a generating unit-by-generating unit analysis that would demonstrate a 

direct correlation to a specific affected EGU. Commenters also stated that if EPA includes 

energy efficiency as a component of BSER then EPA should take into consideration Floridaspecific technical and achievable energy efficiency according to Florida Statues and the CAA. 

Commenters also stated that "EPA's proposed ten percent reduction in net retail electric sales as a 
150

result of Building Block 4 is unreasonable, in terms of both proposed cost and achievability, 

based on Florida's actual historic data."

5.8.5c Data Issues and Considerations for Using and Developing Energy Efficiency 

Projections

This section addresses data issues to use and develop energy efficiency projections.

Commenters have raised a number of issues related to this subsection which are organized by 

topics (comments) below. Responses are also provided for these topics.

Comment 1: Comments regarding energy efficiency projections in state plans.

Response 1: The EPA has included requirements in the final rule that describes the assumptions, 

methods and emission quantification methodologies states could use in their projected 

performance demonstration. The elements of the projection and whether EE would need to be 

explicitly accounted for will depend on the type of state plan a state chooses to submit to EPA.

Refer to section VIII. D.2(a) of the final rule preamble of the CPP and the Incorporating RE and 

Demand-Side EE Impacts into State Plan Demonstrations TSD that describes the type of data 

sources and evidence a state would need to provide. 

The following are summaries of the specific public comments under this comment:

Commenters asked the following questions regarding BB4:

• What evidence would EPA want in order for a state to demonstrate that the proposed EE 

trajectory is unreasonable for their circumstances? 

• What evidence should be submitted if a party wanted to demonstrate that a higher or 

lower annual EE reduction is feasible?

Comment 2: Comments regarding Reported/Projected EE vs. Actual Savings

Response 2: The final CPP allows broad flexibility in how to comply with the emission 

standards or state goals in the final guidelines. Sources have the ability to purchase ERCs as a 

way to adjust the CO2 emissions rate and mass based states can join emission budget trading 

programs or coordinate through multi-state plans. Even if the projected energy savings doesn’t 

happen exactly as expected these additional flexibilities will allow states and sources the latitude 

to still meet their future goals.

The following are summaries of the specific public comments under this comment:
151

Commenters stated that EPA needs to account for differences in reported and projected energy 

efficiency savings versus actual savings, as well as acknowledge the potential consequences if 

projected savings are not met.

Commenters urged EPA to acknowledge that projected savings from a demand-side program or 

measure cannot be forecasted with exact precision. Commenters stated that EPA should provide 

leniency in the case that energy efficiency measures do not meet the projected savings. 

Commenters noted that the inconsistency between projected and actual savings is usually a result 

of many factors effecting EE programs that are outside the control of those implementing the 

technologies. Commenters stated that in the event that a state does not meet its goal due to the 

difference between projected and actualized savings from an EE measure, where the cause of the 

difference is not a result of an error on the states' part, EPA should have an alternative means of 

compliance. Commenters cited a paper, which includes almost half of the programs included in 

the analysis, that shows utility reported savings as being substantively higher than the evaluated 

savings and that predicted savings were also significantly different than evaluated savings 

(Resources of the Future, "Energy-Efficiency Program Evaluations) (see Figure 21 of their 

comment letter, Total Resource Cost (TRC) Test (Program Benefits/ Program Costs)) (see 

http://www.rff.org/documents/rff-dp-10-16.pdf). Commenters cited a table showing the 

realization rates, which is the ex-post estimated savings divided by ex-ante projected savings (see 

Energy-Efficiency Program Evaluations. http://www.rff.org/documents/rff-dp-10-16.pdf); the 

realization rates show the significant difference in actual or real savings and the forecasts.

Commenters stated that by basing the majority of the proposed plan analysis on reported data, 

EPA did not provide a cushion for situations in which the reported savings from energy 

efficiency measures do not accurately reflect the actual savings. Commenters stated the 

difference can be a result of the many factors on which effective programs are dependent, many 

of which are outside the control of those implementing the technologies.

5.8.5d Approaches for Estimating the Future Effects of State Renewable Energy 

Requirements, Programs, and Measures

This section addresses the effects of state renewable energy requirements.

Commenters have raised a number of issues related to this subsection which are organized by 

topics (comments) below. Responses are also provided for these topics.

Comment 1: Comments regarding biomass.

Response 1: Biomass is not considered part of the best system of emission reduction in this rule 

and therefore it is not included in goal-setting or compliance evaluations. However, similar to 

other technologies outside of BSER, biomass may be considered as a part of a state’s plan to 

meet the emission guidelines.
152

For more information regarding Building Block 3, refer to Section V.E of the final rule preamble

of the CPP. 

A discussion regarding the use of some biomass feedstocks for compliance purposes can be 

found in Section VIII.I.2.c and Section VIII.K.1 of the final rule preamble of the CPP.

The following are summaries of the specific public comments under this comment:

Commenters quoted studies showing that forest-derived biomass can increase net atmospheric 

CO2 compared to fossil fuels. Commenters said that "EPA included biomass in RE and 

erroneously assumed that burning biomass does not lead to CO2 emissions." Commenters urged 

EPA to establish a framework that distinguishes between biomass feedstocks that will increase 

atmospheric CO2 and those that will decrease CO2 over a 10-20 year timeframe.

5.8.5e Renewable Portfolio Standards

This section addresses renewable portfolio standards.

Commenters have raised a number of issues related to this subsection which are organized by 

topics (comments) below. Responses are also provided for these topics.

Comment 1: Comments regarding a renewable portfolio standard scenario.

Response 1: The final guidelines say that a state can use renewable energy as a part of their state 

plan compliance. The EPA agrees there is more opportunity to adopt RE. The global market for 

RE is projected to grow to $460 billion per year by 2030. RE growth is further encouraged by the 

significant amount of existing natural resources that can support RE production in the United 

States. In the Energy Information Administration’s Annual Energy Outlook 2015, RE generation 

grows substantially from 2013 to 2040 in the reference case and all alternative cases. In the 

reference case, RE generation increases by more than 70 percent from 2013 to 2040 and accounts 

for over one-third of new generation capacity. See the final CO2 Emission Performance Rate and 

Goal Computation TSD for CPP Final Rule for further details on EPA’s renewable energy goal 

calculations. 

The following are summaries of the specific public comments under this comment:

Commenters conducted a comparison analysis of a business-as-usual (BAU) scenario against a 

30% Renewable Portfolio Standard (RPS) scenario, and a natural gas fuel switching scenario, 

using a spreadsheet model and the MyPower modeling software developed by researchers at the 

Wisconsin Energy Institute (WEI). Commenters stated that "Both models show that the 30% 

RPS can reduce Wisconsin's CO2 emissions below EPA's targets, at a lower cost than the fuel 

switching scenario." Commenters said that these runs were done with the assumptions that fossil 

fuel prices rise steadily at 2% annually, and where natural gas prices reflect historical volatility 
153

observed from 1998-2013. Commenters stated that this illustrated "the value of renewables as a 

hedge against price volatility."

Comment 2: Comments regarding renewable energy potential and RPS obligations.

Response 2: The final guidelines state that a state can use renewable energy as a part of their 

state plan compliance. See the final CO2 Emission Performance Rate and Goal Computation 

TSD for CPP Final Rule for further details on EPA’s renewable energy goal calculations. 

The following are summaries of the specific public comments under this comment:

Commenters said that "EPA Fails to Adequately Acknowledge State RE Potential" and take into 

account states' RPS obligations. Commenters presented examples for several states such as 

Illinois, Hawaii and Iowa where commenters said "even though Iowa produced 14.2 million 

MWh of renewable electricity in 2012, its 2030 RE target is just 8.6 million MWh." Commenters

recommended that at a minimum, "EPA's approach assume that states reach their own 

independently-set RPS targets." Commenters had the following comment of how EPA should 

credit renewable energy, "If EPA chooses to retain its preferred methodology of crediting each 

state with the renewable energy that it has "implemented," then the baseline RE should be 

recalculated to reflect that compliance criteria. On the other hand, if EPA credits a state with all 

of the renewable energy generation within its borders, then no state should be assumed to lose 

RE generation as part of its state target calculation."

5.8.5f RPS as an Input to Electricity Sector Modeling

This section addresses RPS and modeling.

Commenters have raised a number of issues related to this subsection which are organized by 

topics (comments) below. Responses are also provided for these topics.

Comment 1: Comments regarding RPS design.

Response 1: The EPA agrees that states with different electricity market structures would design 

their RPS requirements in a way to meet their unique needs. In the final CPP rule the EPA also 

makes it clear that RE from RPS should be non-duplicative. In Section VIII.D.2.b (3) of the final 

rule preamble of the CPP, the EPA describes an example of when a duplicative emission 

standard would occur, which is prohibited under this final CPP rule. For example, it is prohibited 

to apply a quantified and verified MWh from a wind turbine to more than one state’s CAA 

section 111(d) plan to adjust the CO2 emission rate of an affected EGU, except in the case of a 

multi-state plan where CO2 emission performance is demonstrated jointly for all affected EGUs 
154

subject to the multi-state plan. For further details see Section VIII.D.2.b. of the final rule 

preamble of the CPP. 

The following are summaries of the specific public comments under this comment:

Commenters suggested that "infrastructure development under these state-level RPS programs is 

essential." Commenters said that "states with a deregulated wholesale power markets have the 

ability to engage in integrated resource planning, while also benefitting from a competitive 

generation market, allowing a wide amount of latitude for RPS design." Commenters also said 

that "many states allow the procurement of renewable energy to count toward RPS requirements 

if it is delivered into the RTO, ISO, or other organized market" and that "a renewable energy 

developer in a large wholesale market can then theoretically sell into multiple states with RPS 

requirements."

5.8.5g Data Needs for Estimating Generation Resulting from State RPS

This section addresses data needs for RPS development.

Commenters have raised a number of issues related to this subsection which are organized by 

topics (comments) below. Responses are also provided for these topics.

Comment 1: Comments regarding data needs from EGUs.

Response 1: Not all state plans require a projection of CO2 emissions performance, section VIII. 

D.2.(a)(3) of the final rule preamble of the CPP describes which state plan designs require a 

projection. The Final rule also provides a list of all affected EGUs that are subject to the 

emission guidelines and EPA is not requiring a specific methodology that states must use to 

project their future emissions. See Section IV. D of the final rule preamble of the CPP for the 

definition of an affected EGU. The EPA provides a list of key assumptions and data 

requirements for projections in Section VIII. D.2.(a)(3) of the final rule preamble of the CPP.

The following are summaries of the specific public comments under this comment:

In order to answer the question, "What kind of data do states need to gather regarding emissions 

from their power plants," commenters stated that states should "first identify and categorize the 

existing electric generating units covered by the rule, "gather historical CO2 emissions data from 

40 CFR Part 75 reports, and "identify the methodology used to measure future GHG emissions."

5.8.5h Feed-In Tariff

[No comments were received on this topic.]
155

5.8.5i Data Needs for Estimating Generation Resulting from Feed-In Tariff and 

Performance-Based Tax Incentives

[No comments were received on this topic.]

5.8.5j Emission Budget Trading Programs

This section addresses cap and trade program design.

Commenters have raised a number of issues related to this subsection which are organized by 

topics (comments) below. Responses are also provided for these topics.

Comment 1: Comments regarding cap and trade system design.

Response 1: The final guidelines describe different state plan approaches states can choose to 

implement to achieve the interim and final goals outlined in EPA’s guidelines. There is 

flexibility within the state plan approach options that would allow a state to use the type of 

program Commenters suggested above. Refer to Section VIII.C of the final rule preamble of the 

CPP for details on the design features of these types of programs. 

The following are summaries of the specific public comments under this comment:

Commenters stated that they support the Clean Power Plan Proposed Rule. Commenters also 

stated that any cap and trade system designed should have the following characteristics: permits 

auctioned to upstream companies (not given away for free); an escalating price floor on permit 

prices; revenues returned to consumers as a dividend; and limited offsets and loopholes.

5.8.5.k Addressing the Sectoral Scope of Emission Budget Trading Programs

[No comments were received on this topic.]

5.8.5l Addressing Multi-Sector Emission Trading

[No comments were received on this topic.]
156

5.8.5m Addressing Emission Offsets

This section discusses emission performance and the use of offsets as emission reduction 

strategies. 

Commenters have raised a number of issues related to this subsection which are organized by 

topics (comments) below. Responses are also provided for these topics.

Comment 1: Comments regarding emission offset issues.

Response 1: The EPA disagrees with the commenters that out-of-sector offsets may be counted 

toward meeting a CO2 emission performance level for affected EGUs or a state CO2 goal, 

because out-of-sector offsets are not connected to the electrical grid and so cannot reliably 

address stack CO2 emissions from affected EGUs. See Sections V.B.3.c and VIII.K.1 of the final 

rule preamble of the CPP. However, state plans may accommodate emission budget trading 

programs that may include out-of-sector GHG offsets, which we are finalizing as an option under 

the state measures plan type. See Section VIII.J.2.d of the final rule preamble of the CPP. For 

these reasons and other reasons discussed in section 1.2 of this document, as well as in section 

VIII of the Legal Memorandum, this rule provides states more flexibility than the “real choice” 

the D.C. Circuit has required in the context of CAA section 110. Accordingly, we disagree with 

some commenters that the final emission guidelines impermissibly restrict states’ flexibility in 

plan design, and we further disagree with the commenters’ characterization of this rule as 

encroaching upon the federal-state balance of the CAA. The EPA will not be providing out of 

scope carbon offset methodology given that they may not be counted toward CPP compliance, 

therefore these comments are out of scope to the final CPP.

The following are summaries of the specific public comments under this comment:

Commenters stated that EPA should consider recognizing "each state's existing initiatives and 

programs that can count toward their offsets, such as electric vehicle incentives and energy 

efficiency requirements." 

Commenters recommended that EPA allow "offset programs as a potential compliance strategy 

in the final rules." 

Commenters stated that "Out-of-sector carbon offsets have proven to be a simple and verifiable 

means to reduce greenhouse gases and should be included in EPA's compliance calculations." 

Commenters recommended that "Statements suggesting that out-of-sector offsets cannot be 

included in a State's compliance calculation should be removed from the Rule." Furthermore,

commenters said that "a state should be able to count ANY GHG emission reductions from 

projects that meet sufficiently stringent standards of environmental integrity. The Agency could 

avoid further ambiguity by providing guidelines to states on the establishment of state 

administered programs or utilizing pre-existing voluntary offset programs." 
157

Commenters wanted clarification from EPA as to why carbon offsets could not be used to 

achieve for the Clean Power Plan. 

Commenters recommended that EPA "clarify that states may use GHG offsets to achieve any 

emission reductions their state plan."

Commenters stated that in refusing to "count" out-of-sector offsets, EPA is limiting the states' 

legal ability to craft their own preferred plans. Commenters said section 111(d) of the CAA 

directs EPA to "prescribe regulations which shall establish a procedure similar to that provided 

by Section 110." Commenters said courts have interpreted Section 110 to impose a "federalism 

bar" which underscores state discretion to choose a SIP that best suits its needs. Commenters

said that under Section 110, states must have "real choice" with regard to the control measure 

options available to them to meet their SIP requirements. Commenters said the court in Michigan 

went on to say it would disfavor a rule that left the states with alternatives that the states "would 

consider unreasonable or impracticable." 

Commenters stated that failing to include out-of-sector offsets as a compliance method 

unreasonably restricts a state's ability to design its own plan. Commenters said the exclusion is 

especially limiting where offset programs currently exist and capture very real and very positive 

GHG reductions. Commenters said that allowing out-of-sector offsets to be used only for noncompliance purposes will essentially render them moot in practice, serving to undermine the goal 

of both the CPP and existing cap-and-trade programs. Commenters said existing programs now 

must alter the way these important projects are treated. Commenters said they must make up for 

any reductions from out-of-sector offsets currently recognized through other policies or set a 

stricter emissions standard than the one set forth in the CPP that would then allow out-of-sector 

offsets to be used only in the headroom above the EPA-required goal. Commenters said these are 

both "unreasonable and impracticable" alternatives that will force a state's hand in how to treat 

these offsets - they will simply not include them.

Comment 2: Comments regarding offsets and additionality.

Response 2: The EPA agrees with commenters who asserted that out-of-sector offsets may not 

be counted toward meeting a CO2 emission performance level for affected EGUs or a state CO2

goal, because out-of-sector offsets are not connected to the electrical grid and so cannot reliably 

address stack CO2 emissions from affected EGUs. See Sections V.B.3.c and VIII.K.1.b of the 

final rule preamble of the CPP. However, state plans may accommodate emission budget trading 

programs that may include out-of-sector GHG offsets, which we are finalizing as an option under 

the state measures plan type. See Section VIII.J.2.d of the final rule preamble of the CPP.

Regarding the use of allowances or Emission Rate Credits from other states or countries, see 

Section VIII.K.1 of the final rule preamble of the CPP.

A discussion regarding the use of some biomass feedstocks, including waste-derived feedstocks, 

for compliance purposes can be found in VIII.I.2.c and Section VIII.K.1 of the preamble.
158

The following are summaries of the specific public comments under this comment:

Commenters asserted that "EPA's Criteria For Acceptable Offsets In A State Plan To Be 

"Additional" Is Arbitrary And Unnecessary And Will Penalize Affected Sources For Making 

Investment Decisions That Reduce GHGs Prior To The Establishment Of The State Plans." 

Commenters agreed with EPA "that out-of-sector offsets can provide flexibility to States." 

However, commenters stated that "EPA appears to apply this concept in an arbitrary manner by 

incorporating a so-called "additionality" requirement: A key criterion that must be met for the 

award of offset allowances or credits is a demonstration that the offset project is "additional" 

(i.e., that it would not have occurred absent the incentive provided through the award of the 

offset allowance or credit)." Commenters said that one of their members made a decision to 

convert a unit to natural gas combustion in anticipation of EPA's rule and now would be 

penalized by not getting offsets since they were an early mover. Furthermore, commenters stated 

that in order to "allow companies to reduce GHG emissions in a cost-effective manner" EPA 

should "allow multi-state companies that generate offsets to use them in any State where they 

have affected EGUs that are regulated under Section 111(d)" and "EPA should explicitly permit 

the use of international offsets under the same conditions that it permits domestic offsets." 

Commenters also asserted that "EPA's criteria for acceptable offsets in a state plan to be 

"additional" is arbitrary and unnecessary and will penalize affected sources for making 

investment decisions that reduce GHGs prior to the establishment of the state plans." 

Commenters stated that the "additionality" requirement was "unfair to those entities that have 

made investment decisions since the baseline year (2012) that, in part, were made in anticipation 

of regulatory programs such as this one to reduce GHG emissions." Commenters also said that 

states should be able to incorporate out of sector offsets into a trading program as long as the 

offset credits were generated after 2012. Commenters also said that EPA should allow multi-state 

companies that generate offsets to use them in any other state. 

Commenters stated that they believe that EPA has proposed the wrong definition of 

"additionality." Commenters urged EPA to fix the definition of "additionality" so that "beneficial 

carbon savings projects" reflecting best practices even if they pre-date the proposal could be 

counted.

Commenters noted "that EPA has allowed inclusion of "offsets" from renewables and other 

sources in meeting the targets." Commenters recommended that EPA allow EPA "streamlined 

bilateral trading arrangements between states" and not require formal regional coalitions in order 

to trade offsets.

Commenters stated that the rule should "not allow states to let polluters buy pollution offsets to 

meet emissions requirements." Commenters asserted that offsets caused the families living near 

power plants to "continue to breathe toxic emissions" and that "given the 50-year lifespan of 

carbon in the atmosphere after is it released, offsetting also poses a real risk to long-term climate 

stability."

Commenters stated that carbon offsets from outside the power sector must not count towards 

compliance with the emission reduction requirements of the Clean Air Act.
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Commenters stated that "out-of-sector offsets should be permitted to be used for compliance." 

Commenters also stated that the proposed rule appears to present "conflicting guidance regarding 

the use of offsets for compliance" and requested clarification. Commenters asserted that "if 

unrelated out-of-sector offsets are not allowed, EPA should allow the use of offsets that are 

directly related to generating units, such as methane destruction credit for generators utilizing 

landfill gas or biogas from anaerobic digesters." 

Commenters stated that all different kinds of offsets should be offered as options in the final rule 

as "alternatives to direct reductions from our EGUs." Commenters recommended that the 

"beneficial reuse of coal ash," terrestrial carbon sequestration, improving nitrogen application 

efficiency by farmers, landfill gas generating and use of low or zero emitting vehicles be 

considered as offsets and ways to achieve carbon reduction goals. Commenters also stated that 

renewable power including wind and solar power will be needed to achieve "meaningful GHG 

reductions." 

Commenters recommended "including a clear and explicit recommendation that gives states the 

power to use both in and out-of-sector offsets in establishing state targets for the Clean Power 

Plan and in meeting emission performance compliance goals." Commenters recommended that 

EPA allow for "offsets from the land use and agricultural sectors" because these "Offsets are a 

cost effective way for states to meet their goals, while working towards more long term solutions 

focused solely on EGU reductions." Commenters also encouraged "EPA to complete the 

Biogenic Emissions Accounting Framework in a way that accounts for the lifecycle GHG 

reduction potential of biomass" to "further support the development of offset projects and 

markets." 

Commenters stated that forest carbon offsets would provide flexibility to meet emissions 

reduction targets and an added incentive to keep working forests intact. 

Commenters stated that "The Final Rule should state explicitly that offsets from outside the 

electricity generation industry, while allowable for crediting in state plans, must be justified in 

relation to the Clean Power Plan." Commenters said that "States should have the flexibility to use 

emissions reductions of methane in the oil and gas industry to the extent that natural gas use is 

increased in that state to offset some of the carbon dioxide emissions reductions required in the 

CPP. Similarly, states that begin to work toward electric transportation options could also be 

allowed offsets to the extent that overall emissions will be reduced. Generic offsets, however, 

such as tree planting, should not be allowable within the CPP, regardless of the benefits, because 

they are not related to the CPP. The language in 79 Federal Register 34910 should be made 

clearer and should specifically allow certain offsets as an option." 

Commenters urged EPA to clarify that forestry based offsets would be allowed as a means of 

compliance and noted that RGGI allows forestry based offsets. Commenters recommended that 

"EPA should clarify that out-of-sector offsets, including those from forestry projects, should be 

eligible for inclusion in 111(d) state implementation plans for the purpose of complying with 

EPA's proposed emission reduction goals."
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Comment 3: Comments regarding industrial energy efficiency and offsets.

Response 3: Demand-side EE measures including industrial efficiency programs and demand 

response may be used to adjust a CO2 emission rate, provided they meet the general eligibility 

requirements outlined in Section VIII.K of the final rule preamble of the CPP and the MWh 

electricity generation or electricity savings are properly quantified and verified. Eligible Demand 

Side Measure actions are those that are non-emitting and avoid, rather than shift, the use of 

electricity by an electricity end-user. The quantified and verified MWh that may be used for such 

an adjustment are determined based on the MW of demand reduction multiplied by the hours 

during which such a demand reduction is achieved. DSM measures must be appropriately 

quantified and verified, in accordance with requirements in the emission guidelines, as discussed 

in section VIII.K.3 of the final rule preamble of the CPP.

The following are summaries of the specific public comments under this comment:

Commenters stated that guidelines should allow for flexibility in implementation. Commenters

expressed that in order "to achieve the best overall result, state implementation plans should let 

all forms of energy efficiency and demand response activities from industrial sources ('outsidethe-fence line') compete with other emission reduction technologies." Along these lines, 

commenters encouraged "existing state and regional GHG programs to include industrial energy 

efficiency and demand response as offsets with compensation adequate to support expansion of 

those programs."

Comment 4: Comment regarding offsets.

Response 4: The final CPP is publishing uniform emission guidelines in the sense that the ratebased goals and mass-based goals are equivalent to each other, and therefore the emission 

guidelines are uniform while still allowing states flexibility to comply with these uniform targets 

in the emission guidelines. The EPA disagrees with this commenter’s point of view that the final 

rule should promulgate uniform state plans for compliance. Rather, we have determined that 

maximum flexibility in choosing a state plan pathway allows states to meet their CO2 emission 

performance rates or state CO2 emission goals while reducing costs, maintaining reliability and 

achieving reasonable emission reductions in a reasonable time frame.

As for GHG offsets, out-of-sector offsets may not be counted toward meeting a CO2 emission 

performance level for affected EGUs or a state CO2 goal because out-of-sector offsets are not 

connected to the electrical grid and so cannot reliably address stack CO2 emissions from affected 

EGUs. See Sections V.B.3.c and VIII.K.1.b of the final rule preamble of the CPP. However, the 

state plans may accommodate emission budget trading programs that may include out-of-sector 

GHG offsets, which we are finalizing as an option under the state measures plan type. See 

Section VIII.J.2.d of the final rule preamble of the CPP. For these reasons and other reasons 

discussed in section 1.2 of this document, as well as in section VIII of the Legal Memorandum, 

this rule provides states more flexibility than the “real choice” the D.C. Circuit has required in 

the context of CAA section 110. Accordingly, we disagree with some commenters that the final 

emission guidelines impermissibly restrict states’ flexibility in plan design, and we further 
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disagree with the commenters’ characterization of this rule as encroaching upon the federal-state 

balance of the CAA.

The EPA disagrees with the commenters that the EPA made conflicting statements with respect 

to offsets in the proposed rule. For clarification, the proposed rule did not propose to allow outof-sector offsets to demonstrate CO2 emission performance by affected EGUs but did propose to 

allow both in-sector offsets that would achieve the required level of emission performance for 

affected EGUs and emission budget trading programs including out-of-sector GHG offsets.

The following are summaries of the specific public comments under this comment:

Commenters wanted uniform guidelines in the regulations especially for offsets so the law would 

be "fair and effective."

Commenters said another stark example of regulatory ambiguity is EPA's incomprehensible 

offset policy. Commenters stated, in some places within EPA's preamble and TSDs, EPA 

specifically notes that 'out of sector' offsets would not be approvable. Commenters stated, in 

other places, EPA seems to indicate the offsets can be used in existing trading plans at the state 

level for compliance. Commenters said, in still others, EPA seems to indicate that offset 

programs can be used in mass-based programs but not in rate-based programs. Commenters 

asserted that this ambiguity must be eliminated from the final rule and states should be afforded 

the flexibility of fully utilizing both sector and out-of-sector offsets provided that appropriate 

quantification methodology is employed. Commenters noted that these ambiguities become more 

acute because state plans are to be approved by regional staff personnel. Commenters 

questioned, while the approval process follows headquarters direction, how will that process 

work in this case? Commenters said states are expected to propose unique and creative 

compliance options. Commenters said some may represent cutting edge technologies, programs 

or new types of incentives. Commenters noted that inclusion in state plans of innovative 

compliance mechanisms could face disapproval by regional staff that are operating without clear 

and consistent regulatory guidance, defeating the very purpose of the creative "state laboratories 

of invention." Commenters said such a result again would upset the political and policy choices 

made at the state government level. Commenters asserted that EPA must include sufficient

guidance in the definition of affected entities to ensure that states are allowed to experiment and 

that companies acting to implement the CPP are allowed to invest capital in new units and 

technologies with the certainty that such measures are consistent with the CPP. Commenters 

noted, absent this additional specificity in the rule itself, EPA exposes states and sources alike to 

the actions or opinions of federal regional personnel. Commenters said, worse, lawsuits from 

members of the public who disagree about the value of a project would create even more 

uncertainty in the development of a compliance plan that is already full of uncertainty. 

Commenters stated that this infirmity in the proposal stems from the "square peg, round hole" 

that underpins the whole CPP. The commenters said that EPA is using an existing source 

performance standard to jump start a change to a lower carbon economy. Commenters said the 

CAA may not be stretched this far.

Commenters stated that in not counting out-of-sector offsets, EPA is limiting the states' legal 

ability to craft their own preferred plans. Commenters explained that Section 111(d) of the CAA 

directs EPA to "prescribe regulations which shall establish a procedure similar to that provided 
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by Section 110." 42 U.S.C. Section 7411(d), and the cases which have interpreted Section 110 

have imposed a "federalism bar" which underscores state discretion to choose a SIP that best 

suits its needs. EME Homer City Generation, L.P. v. EPA, 696 F.3d 7, 29 (D.C. Cir. 2012). 

Specifically, under Section 110, commenters noted, states must have "real choice" with regard to 

the control measure options available to them" to meet their SIP requirements. Michigan, 213 

F.3d at 687 (D.C. Cir. 2000), and the court in Michigan went on to say it would disfavor a rule 

that left the states with alternatives that the states "would consider unreasonable or 

impracticable." Michigan, 213 F.3d at 688. Commenters continued, stating that by not including 

out-of-sector offsets as a compliance method a state's ability to design its own plan is 

unreasonably restricted, and the exclusion is especially limiting where offset programs currently 

exist and capture very real and very positive greenhouse gas reductions. Commenters remarked 

that allowing out-of-sector offsets to be used only for non-compliance purposes will essentially 

render them moot in practice, serving to undermine the goal of both the CPP and existing capand trade program. Commenters stated that existing programs now must alter the way these 

important projects are treated, and they must make up for any reductions from out-of-sector 

offsets currently recognized through other policies or set a stricter emissions standard than the 

one set forth in the CPP that would then allow out-of-sector offsets to be used only in the 

headroom above the EPA-required goal. Commenters agreed with the court in believing that 

offsets are a dynamic and important way to control greenhouse gas emissions. Commenters said, 

at the same time, in understanding the unique nature of offsets, state and regional approaches 

appropriately limit and control them. Commenters explained (verbatim) State and regional 

programs which have adopted cap and trade programs have made concerted efforts to tightly 

regulate and control out of sector offsets in order to alleviate any uncertainty. Commenters said 

one way in which they have done this is by only allowing very specific types of offsets to be 

included. Commenters noted the Regional Greenhouse Gas Initiative ("RGGI"), comprised of 

states and provinces in the Northeastern United States and Eastern Canada, allows for offsets in 

only five categories: (1) landfill methane capture and destruction; (2) reduction in emissions of 

sulfur hexafluoride; (3) sequestration of carbon due to U.S. forest projects (reforestation, 

improved forest management, avoided conversion) or afforestation (for CT and NY only); (4) 

reduction or avoidance of CO2 emissions from natural gas, oil, or propane end use combustion 

due to end use energy efficiency in the building sector; and (5) avoided methane emissions from 

agricultural manure management operations. Commenters noted, similarly, California's cap and 

trade program, promulgated by the California Air Resources Board ("CARB") pursuant to the 

Global Warming Solutions Act of 2006, includes offsets in one of only five categories: (1) 

livestock projects; (2) urban forest projects; (3) U.S. forest projects, (4) ozone depleting 

substances projects; and (5) mine methane capture projects. By limiting the scope of projects that 

can be considered, commenters stated that these programs are able to include only those offsets 

that are viable and verifiable. Commenters said another way to ensure the reliability of out of 

sector offsets is through the concept of "additionally." Commenters stated, in California, CARB 

included offsets and provided credit only for those reductions that are "additional, quantifiable, 

permanent, verifiable and enforceable." Commenters stated the Global Warming Solutions Act 

defined "additionally" as reductions that are "in addition to . . . . any other [GHG] emission 

reduction that would otherwise occur." Global Warming Solutions Act, S.35862(d)(2) (2006). 

Commenters noted that CARB refined this definition to mean reductions are additional if they 

"exceed any [GHG] reductions or removals that would otherwise occur in a conservative 

business as usual scenario." Cal. Code Regs. tit. 17, S.9582(a)(4). In Citizens Climate Lobby and 
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Our Children's Earth Foundation v. California Air Resources Board, commenters said the 

environmental advocacy organizations challenged the program on the grounds that CARB's 

additionally standard was insufficient. Citizens Climate Lobby and Our Children's Earth 

Foundation v. California Air Resources Board, No. CGC 12 519554 (San Francisco Sup. Ct., 

filed March 27, 2012). Commenters stated, in rejecting their claim and upholding the program, 

the Superior Court of California stated that "additionally is essential to the environmental 

integrity of an offset program because if reductions are not additional, then the cap and trade 

program will not reduce GHG emissions beyond what would have occurred anyway." Citizens 

Climate Lobby at 6. Commenters stated that the court also acknowledged the fundamental 

importance of offsets to any cap and trade program, claiming "offsets reduce the cost of emission 

reductions because uncapped sources can reduce their GHG emissions at a lower cost than the 

covered source making the same reduction," and that "offsets incentivize innovation and bring 

about GHG emission reductions in sectors of the economy that are difficult or impossible to 

directly regulate." Id. Commenters stated the company agrees with the court in believing that 

offsets are a dynamic and important way to control greenhouse gas emissions, and at the same 

time, in understanding the unique nature of offsets, state and regional approaches appropriately 

limit and control them. 

Comment 5: Opposition to allowing offsets as an emission reduction strategy.

Response 5: We agree with the commenters that (out-of-sector) offsets should not be counted 

toward meeting a CO2 emission performance level for affected EGUs or a state CO2 goal, but for 

a different reason: measures that reduce CO2 emissions outside the electric power sector may not 

be counted because out-of-sector offsets are not connected to the electrical grid and so cannot 

reliably address stack CO2 emissions from affected EGUs. See Sections V.B.3.c and VIII.K.1.b

of the final rule preamble of the CPP. We note, however, that the final emission guidelines allow 

state measures like emission budget trading programs to include out-of-sector GHG offsets. 

Regarding the commenters’ concerns about offsets potentially increasing emissions, the final 

emission guidelines require that state plans that include state measures also include a backstop of 

federally enforceable standards on affected EGUs that fully meet the emission guidelines and 

that would be triggered if the plan failed to achieve on schedule the required emission reductions. 

Regarding the commenters’ concern about permanence, the final guidelines require states using 

the state measures plan type to demonstrate that state measures are permanent. See Section 

VIII.D.2 of the final rule preamble of the CPP. Regarding the commenters’ concerns about 

verification, the final emission guidelines require states with state measures plans to report 

annually on their progress toward milestones. See Section VIII.C.3 and VIII.D.2 of the final rule 

preamble of the CPP. The final guidelines also require verification measures for EE and RE. See 

Section VIII.K.3 of the final rule preamble of the CPP. 

The following are summaries of the specific public comments under this comment:

Commenters argued that offsets do not offer a reliable solution to emissions reductions, and are 

in fact a significant liability and loophole to achieving real, additional, and permanent reductions. 

The commenters stated that the primary interest in offsets is their potential to make it easier and 

cheaper for polluters to meet emissions reduction requirements because offsets cost less per 
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credit than emissions credits. The commenters argued that, even though offsets cost less than an 

emissions credit, the non-monetary costs are not reflected in the price. The commenters stated 

that offsets create pollution hot spots that cause significant public health and environmental costs 

for nearby communities. The commenters stated that offsets are not comparable to direct

emissions reductions because they allow companies to pay to continue polluting at the source, 

while an emissions reduction supposedly occurs elsewhere. 

The commenters argued that allowing companies to pay to pollute does very little to discourage 

or decrease emissions in the present and in future generations. According to the commenters, the 

U.S. Government Accountability Office points out that, "[i]n theory, offsets allow regulated 

entities to emit more while maintaining the emissions levels set by a cap and trade program or 

other program to limit emissions."

The commenters noted that offsets also risk causing increased emissions. The commenters noted 

that several verification requirements must be met for an offset to be valid, but indicated that it is 

very hard to meet all of the requirements. In particular, the commenters stated that the 

requirement to ensure offset permanence is highly problematic--forest offsets easily risk 

impermanence due to destruction from wildfires and other natural disasters. The commenters 

indicated this creates opportunities for fraud, corruption and minimal emissions reductions--if 

not increased emissions--because of illegitimate offsets that are still released into the market. 

According to the commenters, a company in California could purchase an offset elsewhere that 

might not create an emissions reduction, leading to a net increase in emissions because the 

company continues to pollute at the source.

The commenters also noted that offsets can take a long time to create, but the credits for offsets 

are in demand now. According to the commenters, the remedy to this has been to create systems 

of forward crediting and forward selling. The commenters stated that forward crediting requires 

allocating an offset before it can have produced the expected emissions reduction. The 

commenters argued that this form of "I-owe-you" offset is another liability and leaves the door 

open to the possibility of no emissions reduction and even increased emissions.

Comment 6: Support for allowing out-of-sector offsets.

Response 6: The EPA disagrees with the commenters that out-of-sector offsets may be counted 

toward meeting a CO2 emission performance level for affected EGUs or a state CO2 goal, 

because out-of-sector offsets are not connected to the electrical grid and so cannot reliably 

address stack CO2 emissions from affected EGUs. We disagree that out-of-sector offsets should 

be counted as “coming from” EGUs because EGUs implement out-of-sector offset programs; the 

question is not whether EGUs fund or incentivize emission reductions in other sectors but 

whether measures result in a reduction of CO2 emissions produced by affected EGUs. See 

Sections V.B.3.c and VIII.K.1.b of the final rule preamble of the CPP. We also disagree that by 

excluding out-of-sector offsets as a compliance option, EPA is specifically limiting compliance 

to BSER. See Section VIII.K.1.a of the final rule preamble of the CPP. However, the EPA agrees 

with the commenters that state plans may accommodate emission budget trading programs that 
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may include out-of-sector GHG offsets, which we are finalizing as an option under the state 

measures plan type. See Section VIII.J.2.d of the final rule preamble of the CPP.

The EPA disagrees with Commenters that the proposed rule seemed to give conflicting guidance 

regarding the use of offsets. For clarification, the proposed rule did not propose to allow out-ofsector offsets to demonstrate CO2 emission performance by affected EGUs but did propose to 

allow both in-sector offsets that would achieve the required level of emission performance for 

affected EGUs and emission budget trading programs including out-of-sector GHG offsets.

In response to commenters’ recommendations that the EPA let states incorporate carbon offset 

options in their CPP compliance plans if "outside the fence" alternatives are mandated and the 

commenter’s statement that the EPA would be specifically limiting compliance to its proposed 

BSER by excluding out-of-sector offsets as a compliance option, we note that the final 

guidelines allow but do not require states to use the state measures plan type, a state plan 

approach that includes state-enforceable measures that apply to entities besides affected EGUs. 

See Section VIII.C.3 of the final rule preamble of the CPP. Under the state measures plan type, 

emission budget trading programs may include out-of-sector GHG offsets. See Section VIII.J.2.d

of the final rule preamble of the CPP.

We disagree with commenters that EPA should allow states to use a 'Weight of Evidence' 

approach for out-of-sector offsets because, as noted above, out-of-sector offsets are not 

connected to the electrical grid and so cannot reliably address stack CO2 emissions from affected 

EGUs. 

The following are summaries of the specific public comments under this comment:

Commenters stated that the proposed rule seems to give conflicting guidance regarding the use of 

offsets for compliance, initially stating (at 79 FR 34910) that "the EPA is not proposing that outof-sector GHG offsets could be applied to demonstrate CO2 emission performance by affected 

EGUs in a state plan," then stating in the next sentence that "emission limits for affected EGUs 

that are included in state plans could still include provisions that provide the ability to use GHG 

offsets for compliance with the emission limits, provided those emission limits would achieve the 

required level of emission performance for affected EGUs." The commenters stated that out-ofsector GHG offsets represent one of the most powerful mechanisms for flexibility and cost 

containment available in existing cap-and-trade programs, and can deliver significant economic 

and environmental (wildlife habitat, water quality, air quality, etc.) co-benefits. The commenters 

recommended that the EPA should clarify that out-of-sector offsets may be used for compliance. 

Commenters stated that the CPP does not allow any offsets to carbon emissions such as foresting 

or green space accounting. The commenters stated that power cooperatives cover vast amounts 

of territory and the ability to engage in offsets would give us a very viable option to reduce our 

carbon footprint. The commenters recommended that the EPA let states incorporate carbon offset 

options in their CPP compliance plans if "outside the fence" alternatives are mandated.

The commenters stated that the EPA errs in not including "out-of-sector" offsets. The 

commenters stated that the EPA fails to allow out-of-sector offsets, foreclosing a compliance 

option of unquestionable environmental benefit. The commenters noted that the Agency 
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concedes, however, that every existing cap-and-trade program allows for offsets to be used for 

compliance purposes. The commenters stated that the EPA reconciles this discrepancy by 

allowing out-of-sector offsets to be retained under those plans and included under new plans -

but not for compliance with the CPP. The commenters noted that the EPA justifies this unusual 

and contradictory policy on the basis that "all of the emission reduction measures included in the 

agency's BSER reduce CO2 emissions from affected EGUs," whereas out-of-sector offsets 

apparently do not. The commenters stated that by excluding out-of-sector offsets as a compliance 

option, EPA is specifically limiting compliance to its proposed BSER.

Commenters stated that the EPA's failure to consider out-of-sector offsets belies the rule's 

purported flexibility.

Commenters stated that while the Agency has dramatically expanded the scope of its BSER and 

state goal calculation, it has severely constricted a state's ability to comply with it. The 

commenters stated that by excluding out-of-sector offsets for compliance in an effort to stay 

between the very loose "source category" lines it has drawn for itself, EPA has abandoned its "all 

hands on deck" approach to regulating GHG emissions from power plants. The commenters 

stated that the EPA treats energy efficiency and demand response programs, which are really 

"offset" programs, differently than "out of sector" offset programs. Even though not directly in 

the power sector, the commenters stated that the EPA's newly-created expansive source category, 

out-of-sector offsets are a proven and accepted means to reduce and manage GHG emissions and 

should logically be included as a compliance measure. The commenters stated that the EPA 

draws the distinction that its BSER building blocks "reduce CO2 emissions from affected EGUs." 

Specifically, commenters stated that the EPA says that for emission budget trading programs that 

regulate EGUs and include offsets, which it defines as "emissions reductions from sources not 

regulated by the trading program," emissions reductions from offsets would not be counted when 

evaluating CO2 emission performance because "those reductions would not come from affected 

EGUs." The commenters stated that interestingly, these statements are not in the proposed rule, 

while the "additionality" criteria discussed above is in the proposed rule.

Commenters stated that but for EGUs taking the initiative to implement carbon-offset programs, 

these offset programs - which reduce carbon emissions - would not exist. Logically, the 

commenters stated that these EGUs are reducing the overall emission of this global pollutant into 

the atmosphere. The commenters stated that it is difficult to understand how EPA can determine 

that reductions from offsets owned and operated by EGUs do not "come from" EGUs, yet 

theoretical reductions resulting from convoluted market string-pulling from demand-side energy 

efficiency and renewable energy - much of which is not in any way controlled by EGUs - do 

"come from" EGUs. Meanwhile, the commenters stated that out-of-sector carbon offsets have 

proven to be a simple and verifiable means to reduce carbon emissions. The commenters stated 

that while EPA abandoned its traditional technology-based standard in this expansive proposal, 

EPA falls back on this traditional line of thinking in refusing to consider out-of-sector offsets for 

compliance with the CPP.

Commenters stated that EPA should allow states to use a 'Weight of Evidence' approach for outof-sector offsets.
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Comment 7: Comments supporting out-of-sector offsets from the agricultural sector.

Response 7: The EPA disagrees with the commenters that out-of-sector offsets from agricultural 

practices may be counted toward meeting a CO2 emission performance level for affected EGUs 

or a state CO2 goal, because out-of-sector offsets are not connected to the electrical grid and so 

cannot reliably address stack CO2 emissions from affected EGUs. See Sections V.B.3.c and 

VIII.K.1.b of the final rule preamble of the CPP. 

However, the EPA agrees with commenters that states should be allowed to emulate existing 

programs like the California Air Resources Board's Compliance Offset Program and RGGI in 

developing their state plans and that state plans may accommodate emission budget trading 

programs that may include out-of-sector GHG offsets. We are finalizing this as an option under 

the state measures plan type. See Section VIII.J.2 of the final rule preamble of the CPP.

The EPA disagrees that the regulation is likely to increase prices for rural ratepayers, while we 

agree that states should be able to join multistate plans. States will be able to address the 

economic interests of their utilities and ratepayers by using the flexibilities in this final action to 

reduce costs to consumers, minimize stranded assets, and spur private investments in renewable 

energy and energy efficiency technologies and businesses. They may also, if they choose, work 

with other states on multi-state approaches that reflect the regional structure of electricity 

operating systems that exists in most parts of the country and is critical to ensuring a reliable 

supply of affordable energy.

The following are summaries of the specific public comments under this comment:

Commenters stated that the preamble to the proposed rule argues that the proposed rule provides 

states with the flexibility to structure their programs as they see fit and indicates the EPA's intent 

to allow states to comply with their specific emission goals without relying entirely on emitting 

EGUs. However, the commenters stated that the proposed rule does not allow states to consider 

emission offsets occurring anywhere other than EGUs in building state compliance plans. The 

commenters stated that the EPA has implemented emission reduction trading systems under 

different sections of the CAA before, and there is no language in 111(d) preventing EPA from 

implementing such a system for GHGs. The commenters stated that the final rule should create, 

or at least verify states' authority to create, offset trading programs for agricultural conservation 

practices. The commenters stated that otherwise, EPA is missing an opportunity to increase 

flexibility and ensure GHG emissions are mitigated by those in the best position to do so. The 

commenters stated that the EPA could attain even more flexibility, nationwide, by establishing a 

federal offsets program in the final rule. 

In particular, the commenters stated that farmers can provide significant flexibility in reducing 

greenhouse gasses in the atmosphere, mitigating the harmful effects of climate change. The 

commenters stated that the option to sell offsets to EGUs will also provide another source of 

income for rural communities, which is important since the regulation is likely to increase prices 

for rural ratepayers.
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Commenters encouraged EPA to include clear language in the rules allowing the use of out-ofsector offsets by states to meet their emission performance targets, and to ensure that carbon 

offsets are included as reduction mechanisms. 

Commenters stated that EPA should consider carbon offsets from agriculture. According to the 

commenters, to ensure equitable treatment of states, the EPA should allow states that currently 

do not have carbon offset programs to develop individual plans that are functionally equivalent 

to acceptable state plans. The commenters stated that such plans would emulate existing 

programs that include agricultural offsets (i.e., California Air Resources Board's Compliance 

Offset Program, RGGI and the Western Climate Initiative, Inc.). In addition, the commenters 

stated that the possibility of merging state programs should be considered in acknowledgement 

of the administration's interests in promoting energy and carbon exchanges to meet regulatory 

compliance.

Comment 8: Support for use of out-of-sector offsets from the forest sector as a compliance 

measure.

Response 8: The EPA disagrees with the commenters that out-of-sector offsets may be counted 

toward meeting a CO2 emission performance level for affected EGUs or a state CO2 goal, 

because out-of-sector offsets are not connected to the electrical grid and so cannot reliably 

address stack CO2 emissions from affected EGUs. See Sections V.B.3.c and VIII.K.1.b of the 

final rule preamble of the CPP. However, the EPA agrees with the commenters that state plans 

may accommodate emission budget trading programs that may include out-of-sector GHG 

offsets, which we are finalizing as an option under the state measures plan type. See Section 

VIII.J.2.D of the final rule preamble of the CPP.

The EPA disagrees with commenters that EPA failed to provide a clear position with respect to 

offsets in the proposed rule. For clarification, the proposed rule did not propose to allow out-ofsector offsets to demonstrate CO2 emission performance by affected EGUs but did propose to 

allow both in-sector offsets that would achieve the required level of emission performance for 

affected EGUs and emission budget trading programs including out-of-sector GHG offsets.

The following are summaries of the specific public comments under this comment:

Commenters recommended that EPA allow states to consider out-of-sector offsets as a 

compliance measure. Commenters pointed to EPA's recognition in the proposed rule that 

America's forests provide a wide range of environmental benefits beyond the production of 

biomass feedstocks that can be combusted for energy in place of fossil fuels. In particular, the 

commenters pointed to EPA's statements that growing forests act as a carbon "sink" and that 

"America's forests currently play a critical role in addressing carbon pollution, removing nearly 

12 percent of total U.S. greenhouse gas emissions each year." 79 FR 34,924. If used 

appropriately, the commenters indicated the increased carbon benefits associated with working 

forests could provide states with additional flexibility to achieve EPA's emission reduction in a 

low-cost manner. The commenters pointed to EPA's acknowledgement that market-based 

emission trading programs (and potentially other compliance mechanisms) can incorporate out-
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of-sector, project-based emissions offsets as additional flexibility mechanisms to comply with 

GHG emission reduction goals. The commenters stated that forestry-based offsets and other 

innovative out-of-sector emissions reducing mechanisms that recognize forest carbon benefits 

from forests and wood products (collectively, "offsets") could provide a degree of flexibility in 

state implementation plans, and recommended that EPA adopt an expansive view of the types of 

compliance options that states can include in their implementation plans. 

However, according to commenters, EPA failed to provide a clear position with respect to offsets 

in the proposed rule, and the commenters urged EPA to clarify in the final rule the role that 

offsets can play in implementing the state emission reduction targets. For example, the 

commenters noted that EPA asserted in the proposed rule that "the EPA is not proposing that 

out-of-sector GHG offsets could be applied to demonstrate CO2 emission performance by 

affected EGUs." But the commenters further noted that EPA immediately followed by asserting 

that "emission limits for affected EGUs that are included in state plans could still include 

provisions that provide the ability to use GHG offsets for compliance with emission limits ...."). 

According to the commenter, EPA made similar conflicting statements in the technical support 

documents, stating "Under this approach, state plans would ignore the CO2-equivalent emissions 

reductions projected to be achieved through offsets, when projecting the CO2 emissions 

performance that will be achieved by the affected EGU source category through implementation 

of the state plan. This does not mean that an emission budget training program included in a 

state plan could not include an offset component."). Based on these statements, the commenters

argued that it is difficult to determine the role, if any, that offsets can play in state 

implementations, particularly since EPA is proposing to set emission reduction goals on an 

aggregate basis for each state and not for individual affected EGUs.

To resolve this uncertainty, commenters suggested that EPA clarify that out-of-sector offsets, 

including those from forestry projects, should be eligible for inclusion in state implementation 

plans for the purpose of complying with EPA's proposed emission reduction goals. The 

commenters argued that to do so would be consistent with EPA's stated objective of providing 

states with flexibility in achieving GHG emission reductions. The commenters also noted that, 

by looking beyond fossil fuel-fired EGUs and considering emissions reductions from other parts 

of the electricity sector (including reduced demand by consumers), EPA is already incorporating 

emissions reductions from sources outside of the regulated source category, and the commenters 

argued that there is no principled reason for drawing the line in a manner that excludes forestrybased offsets. The commenters further noted that, since GHGs are well-mixed in the atmosphere, 

there are no geographic concerns with any difference in the location between the forests that 

sequester carbon and the fossil fuel-fired EGUs that comprise the regulated source category. 

Thus, to the extent that forest sequestration offers a lower-cost option for reducing net GHG 

emissions than the options included in EPA's Building Block approach, the commenters 

suggested that states should be free to incorporate forestry offsets and other innovative out-ofsector emissions reducing mechanisms that recognize forest carbon benefits from forests and 

wood products into their implementation plans.

Commenters made a similar argument. The commenters noted that EPA proposed to limit how 

the states can credit the use of out-of-sector CO2 offsets. The commenters noted that the proposal 

allowed states to use offsets for meeting EGU-specific emission limits but did not allow states to 

use out-of-sector CO2 offsets to project how states would meet their emission reduction targets. 
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If the proposal is finalized as proposed, the commenters recommended that EPA allow states to 

consider voluntary offset projects as a compliance measure that can reduce CO2 emissions. 

According to the commenters, growing and expanding forests sequester carbon from the 

atmosphere, resulting in a reduction in GHGs. The commenters recommended that EPA clarify 

that voluntary offset projects such as product and permanent wood structure sequestration, active 

forest management, afforestation, reforestation, and recycling are cost-effective and viable 

options to reduce CO2 emissions. The commenters also recommended that states be allowed to 

count emission reductions from measured and verified sequestration of additional carbon stock 

from sustainably managed forests relative to a state's baseline in meeting their emission 

reduction targets.

Comment 9: Request that out-of-sector offsets involving clean electrification not be eliminated 

or disincentivised in state plans.

Response 9: The EPA disagrees with the commenters that out-of-sector offsets like 

electrification that displaces petroleum fuels for transportation may be counted toward meeting a 

CO2 emission performance level for affected EGUs or a state CO2 goal, because out-of-sector 

offsets are not connected to the electrical grid and so cannot reliably address 

stack CO2 emissions from affected EGUs. See Sections V.B.3.c and VIII.K.1.b of the final rule 

preamble of the CPP. However, the EPA agrees with the commenters that state plans may 

include out-of-sector GHG offsets, but only as part of emission budget trading programs, which 

we are finalizing as an option under the state measures plan type. We also agree that certain 

opportunities supported by the commenters would be appropriate under the state measures plan 

type, such as improved efficiency in the use of electricity and substitution of low-GHG emitting 

electricity production processes. See Sections VIII.C.3 and VIII.J.2.d of the final rule preamble 

of the CPP.

The following are summaries of the specific public comments under this comment:

Referring to state plans, commenter stated that as the electric sector decarbonizes and generates 

electricity with a lower carbon emissions intensity, electrification of more carbon-intensive 

sectors has the potential to cost-effectively reduce GHGs across the U.S. economy. The 

commenter stated that electrification has been long recognized in the energy-economics 

literature, technology studies, and the climate policy area as a cost-effective approach to mitigate 

GHGs. For example, the commenter noted that while the implementation of an electrification 

strategy could cost-effectively reduce GHG across multiple sectors, the CO2 emissions from the 

power sector could remain flat or even slightly increase. The commenter stated that while it is 

understood that compliance for out-of-sector reductions is challenging, the commenter stated 

such reductions should not be excluded if appropriate rigor and durability can be demonstrated. 

The commenter recommended that care should be exercised so that state plans do not to 

eliminate or disincentivize clean electrification. 

The commenters concluded that the most substantial opportunities for near-term GHG 

reductions, using technology that is deployable now or is likely to be deployable soon, include 

the following: 
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• Improved efficiency in the use of electricity and fuels, especially in the buildings 

sector, but also in industry and transport vehicles. 

• Substitution of low-GHG emitting electricity production processes, which may 

include renewable energy sources, fuel switching to natural gas, nuclear power, 

and electric power plants equipped to capture and sequester CO2. 

• Displacement of petroleum fuels for transportation with fuels with low- or zero-

(net) GHG emissions.

Comment 10: Commenters suggested that states should be allowed to count towards compliance 

goals all activity that captures carbon, including verifiable offsets.

Response 10: The EPA disagrees with the commenters that out-of-sector offsets may be counted 

toward meeting a CO2 emission performance level for affected EGUs or a state CO2 goal, 

because out-of-sector offsets are not connected to the electrical grid and so cannot reliably 

address stack CO2 emissions from affected EGUs. See Sections V.B.3.c and VIII.K.1.b of the 

final rule preamble of the CPP. However, the EPA agrees with the commenters that state plans 

may include out-of-sector GHG offsets, but only as part of emission budget trading programs, 

which we are finalizing as an option under the state measures plan type. See Section VIII.J.2.d of 

the final rule preamble of the CPP.

The following are summaries of the specific public comments under this comment:

Commenters suggested that states should be allowed to count towards compliance goals all 

activity that captures carbon, including verifiable offset, which at a minimum must include CO2

emissions captured and sequestered from industrial facilities.

Commenters stated opposition that as a matter of policy that RE generating resources must be 

located in a state to offset CO2 emissions for that state's 111(d) plan.

Comment 11: Comments suggesting that the EPA should ensure that states have maximum 

flexibility to incorporate offset programs into their SIPs that allow use of direct air capture 

(DAC) technologies.

Response 11: The EPA disagrees with the commenters that out-of-sector offsets such as DAC 

technology may be counted toward meeting a CO2 emission performance level for affected 

EGUs or a state CO2 goal, because out-of-sector offsets like DAC technologies are not connected 

to the electrical grid and so cannot reliably address stack CO2 emissions from affected EGUs.

Given the reason that we are not permitting out-of-sector offsets to be counted toward meeting a 

CO2 emission performance level or state CO2 goal, strict standards on out-of-sector offsets could 

not ameliorate the issue. See Sections V.B.3.c and VIII.K.1.b of the final rule preamble of the 

CPP. However, the EPA agrees with the commenters that states may continue to operate capand-trade and offset programs that use out-of-sector and non-source-based GHG offsets. We are 
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finalizing that state plans may accommodate emission budget trading programs (which may 

include out-of-sector GHG offsets) as an option under the state measures plan type. See Section 

VIII.J.2.d of the final rule preamble of the CPP. We are not finalizing the proposed portfolio 

approach. See Section VIII.C.4 of the final rule preamble of the CPP.

The EPA disagrees with the commenters that EPA made conflicting statements with respect to 

offsets in the proposed rule. For clarification, the proposed rule did not propose to allow out-ofsector offsets to demonstrate CO2 emission performance by affected EGUs but did propose to 

allow both in-sector offsets that would achieve the required level of emission performance for 

affected EGUs and emission budget trading programs including out-of-sector GHG offsets.

The following are summaries of the specific public comments under this comment:

Commenters stated that, because they are not necessarily implemented at EGUs, DAC 

technologies may be incorporated into state and regional cap-and-trade and/or offset programs 

that allow EGUs and other regulated entities to take advantage of the environmental benefits of 

the technologies as part of a broader regulatory program. The commenters stated that EPA needs 

to be clearer, therefore, about the degree to which it will give states the flexibility to continue to 

develop and implement innovative GHG capture technologies such as DAC technology and 

incorporate them into existing and future cap-and- trade and offsets programs as part of their 

SIPs.

On the one hand, the commenters noted that the EPA claims that the proposed rule gives states 

wide leeway to construct a broad variety of GHG reduction programs in their SIPs. For example, 

the commenters noted that the EPA states that "this proposal would ... provid[e] states with 

ample opportunity to design plans that use innovative, cost-effective strategies that take 

advantage of investments already being made in programs and measures that lower the carbon 

intensity of the power sector and reduce GHG emissions." On the other hand, the commenters 

noted that the EPA has also stated that it "is not proposing that out-of-sector GHG offsets could 

be applied to demonstrate CO2 emission performance by affected EGUs in a state plan." The 

commenters noted that the EPA also states, however, that "emission limits for affected EGUs that 

are included in state plans could still include provisions that provide the ability to use GHG 

offsets for compliance with the emission limits, provided those emission limits would achieve the 

required level of emission performance for affected EGUs." Given these seemingly conflicting 

statements, the commenters pointed out that it is not clear how and to what extent existing 

regional and state plans, such as those in the Regional Greenhouse Gas Initiative in the 

northeastern United States, and the Compliance Offset Program in California, will retain the 

ability to allow out-of-sector and non-source based GHG offset programs under this rule, and the 

degree to which innovative technologies such as DAC technology could be incorporated into the 

states' plans. 

The commenters suggested that the EPA clarify its intent in the final rule. According to the 

commenters, without the flexibility to include emissions trading or out-of-sector offsets, states 

incorporating such programs in their GHG regulations would be required to set more stringent 

state-only standards to ensure some regulatory "nudge" toward use of DAC and similar 

technologies. The commenters stated that this should not be necessary. The commenters stated 

that the EPA has already laid the groundwork for allowing states to allow excess GHG emissions 
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reductions generated by DAC and similar technologies to be credited in an emissions trading or 

offset program. For example, the commenters noted that in its 2005 Clean Air Mercury Rule, the 

EPA determined that a "standard of performance" for mercury under Section 111(d) may include 

a mercury emissions trading program as part of a "best system of emissions reduction." The 

commenters suggested that EPA should allow the same flexibility for GHGs.

The commenters explained that states have already provided a workable model to incorporate 

offsets into a GHG SIP that ensures that GHG reductions generated from offsets can be tracked. 

According to the commenters, the California Compliance Offset Program, for example, includes 

rigorous standards for ensuring that any reductions in GHG in the atmosphere are "real, 

permanent, quantifiable, verifiable, enforceable, and additional." The commenters noted that 

requiring that states incorporate similar standards with respect to the use of offsets generated by 

out-of-sector or "beyond the fence line" DAC technologies should ameliorate EPA's concerns 

that such offsets and related strategies are not "self-correcting." 

At a minimum, the commenters stated that the EPA should give full weight to Section 116 of the 

Act and continue to allow states to operate cap-and-trade and offset programs and create the 

regulatory opportunity for innovative technologies such as DAC technology to be developed to 

meet state GHG reduction goals that may be more stringent than the emissions limitations in the 

proposed rule. The commenters stated that the EPA should make explicit in the final rule that the 

"portfolio approach" available to states would not penalize states or regions from implementing 

GHG reduction strategies that are not determined by EPA to be BSER or are not specifically 

included in the building blocks for compliance that EPA has identified.

Comment 12: Comments suggesting that the EPA should include an allowance for states to 

regulate other pollutants that have global warming potentials.

Response 12: The EPA disagrees with the commenters that out-of-sector offsets that reduce 

pollution that is not emitted by affected EGUs, such as replacing oil-fired hot water heaters with 

time-controlled electric heaters, may be counted toward meeting a CO2 emission performance 

level for affected EGUs or a state CO2 goal. This is because out-of-sector offsets are not 

connected to the electrical grid and so cannot reliably address stack CO2 emissions from affected 

EGUs. See Sections V.B.3.c and VIII.K.1.b of the final rule preamble of the CPP. However, the 

EPA is finalizing that state plans may accommodate emission budget trading programs (which 

may include out-of-sector GHG offsets) as an option under the state measures plan type. See 

Section VIII.J.2.d of the final rule preamble of the CPP.

The following are summaries of the specific public comments under this comment:

Commenters stated that because the EPA is proposing the states can include measures that 

decrease power demand, and therefore dispatch, of coal-fired power plants and regulated NGCC 

affected units, it should also include an allowance for the state to establish new regulations for 

other pollutants that have an established global warming potential not now regulated by sections 

110 or 112 in the power plant sector as an offset to continuing carbon emissions. The 

commenters provided as an example the replacement of older, inefficient oil-fired hot water 
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heaters with time-controlled electric heaters, which would increase electric power demand but 

decrease global warming gases. The commenters noted that this type of a project should be 

allowed as an offset. 

5.8.5n Multi-State Emission Trading Programs

This section addresses multi-state emissions trading programs.

Commenters have raised a number of issues related to this subsection which are organized by 

topics (comments) below. Responses are also provided for these topics.

Comment 1: Comments regarding interstate trading of RE and EE credits.

Response 1: The EPA has taken all of these comments into consideration and the EPA has 

incorporated many of the comments from this commenter below in the final CPP rule. The EPA 

is allowing for streamlined multi-state trading approach, states can develop their own programs 

and trade eligible RE or demand side EE with other states through a trade-ready system. EPA is 

providing presumptively approvable EM&V protocols. The EPA is providing maximum 

flexibility in the types of state plans states can use to implement the emission guidelines. States 

can also see an extension in their initial plan as long as have proper justification. See section, 

VIII. C of the final rule preamble of the CPP for state plan approaches including multi-state 

plans. See Section VIII.E of the final rule preamble of the CPP for plan submittal and approval 

process and timing. See Section VIII. K of the final rule preamble of the CPP on EM&V 

information and eligible RE and demand side EE measures for further details.

The following are summaries of the specific public comments under this comment:

Commenters stated that "a streamlined multi-state trading approach should be allowed" and that 

formal interstate agreements should not be required. Commenters also said that states should be 

able to develop their own programs to trade RE or EE credits with other states and thought a 

federal tracking system for credits could be developed. Commenters further thought that 

"federally-approved evaluation, monitoring and verification protocols" would give plausibility to 

the credits. Commenters also stated that they would like the EPA final guideline to provide a lot 

of flexibility and not exclude credit or trading programs like the EPA proposal does. 

Commenters would also like a two year extension for submittal and approval of section 111(d) 

plans for states that are working to develop alternative approaches to trading RE and EE credits.

Comment 2: Comments regarding multi-state trading, interim goals and more time for

compliance.
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Response 2: The EPA is finalizing that state plan submittals are due on September 6, 2016, 

which is 13 months after finalization of the emission guidelines, with the option of an extension 

to submit final state plans by September 6, 2018, which is three years after finalization of this 

rule. The first interim goal has been moved to 2022, two years later than what EPA proposed.

The compelling nature of the climate change challenge, and the need to begin promptly what will 

be a lengthy effort to implement the requirements of these guidelines, warrant this schedule. The 

EPA believes this will give states ample time to develop multi-state emission plans. 

The following are summaries of the specific public comments under this comment:

Commenters supported the development of multi-state emissions trading programs to trade 

carbon emission allowances but stated that the proposed rule does not allow for enough time to 

develop multi-state emissions trading programs and suggested that "the CPP should delay 

interim goals until these programs can be established."

Comment 3: Comments regarding EPA administering a trading program for EE credits, 

renewable energy credits, and emission credits.

Response 3: The EPA received a number of comments from states and stakeholders about the 

value of the EPA’s support in developing and/or administering tracking systems to support state 

administration of rate-based emission trading programs. The EPA is exploring options for 

providing such support and is conducting an initial scoping assessment of tracking system 

support needs and functionality. See Section VIII.C of the final rule preamble of the CPP for 

further details. 

The following are summaries of the specific public comments under this comment:

Commenters suggested that EPA could "administer programs that track emission or generation 

credits or instruments to support and facilitate trading between states such as an emission 

reduction tracking system, renewable energy certificates (RECs) and Evaluation, Measurement 

and Verification (EM&V) for trading EE credits."

Comment 4: Comments regarding multistate agreements.

Response 4: The EPA recognizes that there are multiple incentives for states to collaborate by 

implementing a multi-state plan. That is why EPA has promulgated a final rule that allows states 

to meet an aggregated joint goal, regardless of the specific level of their individual goals, 

because states share grid regions and impacts from plan implementation will be regional in 

nature. Further, multiple analyses, including those by ISOs and RTOs, indicate that regional 

approaches could achieve state goals at lesser cost than individual state plan approaches. 

However, the EPA also recognizes the value in allowing for collaboration where states retain 

individual goals. These approaches could provide some of the benefits of a joint goal while 

reducing the negotiations among states necessary to develop a multi-state plan with a joint goal. 
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As a result, the EPA has finalized the additional multi-state approaches described above in 

section VIII.C.5 of the final rule preamble of the CPP to provide for coordination while 

maintaining individual goals. These approaches would allow for interstate transfer of energy rate 

credits (ERCs) or emission allowances while retaining individual state goals.

The following are summaries of the specific public comments under this comment:

Commenters stated that "states should also be allowed to enter into multistate agreements that 

allow for emissions budgeting so long as the emission reductions are real, verifiable, and are not 

being claimed by another entity or state" because it may make more sense for a state to use a 

regional budgeting approach instead of Renewable Energy Credits (RECs). 

Commenters stated that "EPA should be open to approving multi-state compliance arrangements 

so long as the collective outcome, for the states involved, results in emissions reductions equal to 

or greater than the sum of those required of each state complying independently within its 

boundaries." Commenters also stated that EPA should be flexible and allow multi-state 

arrangements that are different from the "RGGI" design, "encompass all the covered emissions 

of two or more states," allow states to do a single exchange with one state or multiple exchanges 

with multiple states.

5.8.6 Process Considerations for conducting EGU CO2 emission projections

This section addresses EGU CO2 emission projections.

Commenters have raised a number of issues related to this subsection which are organized by 

topics (comments) below. Responses are also provided for these topics.

Comment 1: Comments regarding controlled performance testing.

Response 1: The EPA has analyzed the technical feasibility, costs, and magnitude of CO2

emission reductions achievable through heat rate improvements at coal-fired steam EGUs based 

on engineering studies and on these EGUs’ reported operating and emissions data. We conclude 

that taking action to improve heat rates is a common and well-established practice within the 

industry that is capable of achieving meaningful reductions in CO2 emissions at reasonable cost, 

although, as discussed earlier, we also conclude that the quantity of emission reductions 

achievable through heat rate improvement measures is insufficient for these measures alone to 

constitute the BSER. The EPA’s quantification of the CO2 emission reductions achievable 

through heat rate improvements as a component of the BSER (building block 1) is discussed in 

Section V.C. of the final rule preamble of the CPP and in the GHG Mitigation Measures TSD for 

the CPP Final Rule.

Many actions will reduce the reported CO2 emissions or CO2 emission rate of an affected EGU, 

without the need for additional accounting or monitoring and reporting requirements beyond the 

required CEMS tracking of actual stack CO2 emissions and tracking of actual energy output. The 
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effect of these actions will result in changes in reported CO2 emissions and/or energy output by 

an affected EGU.

As one of many examples of a fossil-fuel fired EGU taking restrictions on hours of operation for 

the purpose of avoiding CAA obligations, Manitowoc Public Utilities in Wisconsin obtained a 

title V renewal permit that limited the operating hours of the single simple-cycle combustion 

turbine to not more than 194 hours per month, averaged over any consecutive 12 month period, 

as part of limiting its potential to emit for volatile organic compounds below the title V threshold 

of 100 tpy, and carbon monoxide, nitrogen oxides and sulfur dioxide below the PSD threshold of 

250 tpy. As another example, Sunbury Generation LP in Pennsylvania obtained a minor new 

source preconstruction permit, called a plan approval, for a repowering project from the 

Pennsylvania Department of Environmental Protection in 2013 that limited the hours of 

operation of three combined cycle combustion turbines that were planned for construction in 

order to remain below the significance threshold for GHGs. The Legal Memorandum includes 

numerous other examples of power plants accepting permit limits that reduce generation to meet, 

or avoid the need to meet, emission limits.

The following are summaries of the specific public comments under this comment:

Commenters stated that plants require testing to understand current performance and to establish 

the degree of available heat rate improvement opportunities. Commenters were concerned plants 

may lack good instrumentation and measurements, or they may have run for a significant period 

since their most recent controlled performance test was conducted. Commenters stated that major 

changes to the configuration and operation of the plant, major equipment changes, and/or 

changes in the type of fuel burned can also change the opportunity for improvements. 

Commenters noted that performance testing plays a significant role in establishing an accurate 

baseline to enable plant owners to make good decisions to improve heat rate through O&M 

improvements and/or upgrades. Commenters stated that periodic testing can also be effective in 

verifying that improvements are sustained, or aiding the owner/operator in determining when 

corrective actions are needed to sustain performance. Commenters stated that there is currently a 

wide variation in types of testing performed at coal plants and no common guidelines exist for 

evaluating unit performance across the fleet. Commenters stated that the most rigorous test is 

typically applied during commercial acceptance of new plants or during major rebuilds, 

upgrades, or retrofits. Commenters stated that while it may not be necessary, practical, or costeffective to require that level of testing on a periodic basis, they suggested some reasonable 

means of testing and monitoring could be very helpful in determining and sustaining heat rate 

improvements at individual plants. Commenters recommended the EPA consider developing 

guidance on testing, with participation and input from industry stakeholders

Commenters stated that it is unclear how EPA's assumptions within building block 1 could be 

implemented and enforced and that it is infeasible to identify or develop a set of heat rate or CO2

emission rate limitations that could be applied to all designated facilities within the regulated 

source categories, given the diversity of existing sources and the large number of known and 

unknown, controllable and uncontrollable variables that impact heat rate performance. 

Commenters noted they had evaluated recent permits issued for both coal-fired and NGCC units 

across the nation, and found no examples of a permit where a heat rate standard has been 

imposed as an operating limit. 
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Improvements made through BB1 cannot be reliably projected or enforced

5.8.6a Provision of the EPA Guidance

[No comments were received on this topic.]

5.8.6b Party that Translates the Rate-Based Goal to a Mass-Based Goal

This section addresses translating rate-based goals to mass-based goals.

Commenters have raised a number of issues related to this subsection which are organized by 

topics (comments) below. Responses are also provided for these topics.

Comment 1: Comments regarding EPA providing a mass-based CO2 goal for each state and 

clarifying whether these goals can be adjusted.

Response 1: The EPA is providing both rate-based and mass-based statewide goals in this final 

rule in place of having states determine the mass values themselves, in order to assure that the 

mass goals are an equivalent expression of the BSER. See the CO2 Emission Performance Rate 

and Goal Computation TSD for CPP Final Rule for details on the calculations of these goals. 

This final rule allows states to alternatively establish emission standards that meet rate-based or 

mass-based state goals. The EPA supports having the flexibility to use rate-based goals or massbased goals as part of state plans. The EPA notes that it is the emission performance rates in 

section VI of the final rule preamble of the CPP that constitute the application of the BSER to the 

affected EGUs and serve as the chief regulatory requirement of this rulemaking. The statewide 

CO2 rate-based and mass-based emission performance goals provided in the final preamble as

metrics that states may choose to adopt when demonstrating compliance at the state level, and 

states may consider these goals when determining how to set unit-level compliance 

requirements. See Section VII of the final rule preamble of the CPP for the statewide CO2 goals. 

The EPA does acknowledge that state-level rate-based goals or mass-based goals may be 

sensitive to inventory changes within a state’s fleet. That is, the EPA used a representative 

baseline that aggregated data for “likely affected” units. However, if subsequent applicability 

review or formal applicability determinations change the status of these units as of 2012 in 

regards to their inclusion or exclusion in the state’s inventory of affected EGUs, the EPA will 

consider allowing states, via State Plan submittal or revision, to adjust their statewide rate or 

mass goal if such a change is necessary. See Section VII of the final rule preamble of the CPP for 

further details on allowable adjustments to state wide mass-based CO2 goals.
179

The following are summaries of the specific public comments under this comment:

Commenters argued that including only rate-based limits in the rule may discourage a state from 

a mass-based system. Commenters argued that a state will know the precise rate-based goal it 

must meet in advance of submitting its implementation plan, but cannot know the precise massbased goal since the translation from the rate-based goal to a mass-based goal must first be 

approved by EPA. For these reasons, commenters recommended the EPA provide a presumptive 

mass-based CO2 annual emission goal in the final, but permit the state to adjust it or translate it 

into a rate-based goal. 

Commenters suggested the EPA provide "presumptive" translations of rate-based goals to massbased goals for each state, but allow states to either adopt EPA's mass-based limit or propose an 

alternative mass-based limit as part of the state plan. 

Commenters recommended the EPA establish mass-based standards in the rule to prevent 

states from setting high mass-based limits by overestimating their business as usual growth in 

electric demand or by exaggerating transmission constraints that might overestimate business as 

usual capacity factors in high emitting units. 

Commenters urged "EPA to continue working with states on appropriate approaches to 

converting EPA's rate-based goals to reasonably equivalent mass-based goals." Commenters 

stated that EPA should allow "states to propose their own methodology" and the final rule should 

let states "calculate interim and final mass-based goals that match the emission performance that 

would be expected under EPA's rate-based approach." 

Commenters stated that "EPA should make it as easy for a state to convert to a mass-based target 

by including a set of mass-based targets for existing sources within each state. These mass-based 

targets would be those regarded as equivalent to the rate-base standard currently in the proposed 

Plan." 

Commenters asked EPA to provide more clarity for states in translating emission rate to massbased goals. Commenters stated that EPA should provide more "clarity for states to translate the 

emission rate goals to mass-based caps. Commenters also would like EPA to state that EPA 

"would approve a state cap based on 2012 generation multiplied by the 2030 target emission rate 

goal." 

Commenters urged EPA to calculate mass-based targets for the states so that they can compare 

the "rate-based and mass-based carbon targets for the states and how a state's regulators and 

electric utilities could implement carbon reductions under each approach."

Commenters asked EPA to provide more guidance to translate emission rate to mass-based 

goals. Commenters declared that EPA needs to continue to work with states to provide clear 

guidance on how to translate rate-based goals into mass-based goals.

Commenters requested that "EPA provide all states with the mass-based calculation of the state 

goal." Commenters further stated that "state-by-state calculation of a rate-based approach to a 

mass-based approach presents unnecessary complication and inconsistency state goal-setting, 

and results in regulatory uncertainty on the part of states and affected utilities, who must await 
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EPA approval to determine whether their goal calculation is sufficient. The EPA could avoid 

such difficulties by providing each state with the mass-based emissions goal, providing the states 

with the substantive opportunity to provide comments and corrections on the mass-based goals, 

as they have with the rate-based goals." 

Commenters stated that EPA's "final guidelines should allow states to convert the rate-based 

goals to mass emissions budgets that are comparable in stringency to the rate-based state goals" 

and that mass budgets are needed to implement trading programs like RGGI. 

Commenters recommended that EPA "allow states to choose a methodology for translating the 

rate-based goal to a mass-based goal, as long as the rate-based stringency is maintained." 

Commenters also stated that the methodology should be transparent. 

Commenters stated that "EPA must ensure in its final rule that any mass-based translation is truly 

equivalent to a corresponding rate-based goal." Commenters stated that a mass-based protocol 

encourages states to replace retiring fossil units with new fossil (gas) units and therefore, believe 

that a rate-based rule is environmentally preferable since retiring fossil units would be replaced 

with RE and EE. 

Commenters recommended that EPA allow states to calculate mass based goals that are 

equivalent to EPA's rate-based goals.

Commenters supported that the states should have the flexibility to use state specific data and 

assumptions to convert to rate-based goals to mass-based goals. 

Commenters asked EPA to be clear in the final rule about what the states "must provide to ensure 

their formula for translating the rate-based goals to mass-based goals is approvable." 

Commenters also stated that "EPA's guidance should specify acceptable analytical methods" and 

"default input assumptions" but that "states should be allowed to deviate from these default 

methods and assumptions with justification." 

Commenters stated that EPA should be clear on "the distinctions between rate- and mass-based 

targets for developing EPA-approvable compliance plans. Commenters stated that this would 

have "implications for how states determine their EE and other compliance strategies and 

policies."

Comment 2: Comments regarding mass-based and rate-based goals.

Response 2: The EPA is providing states the ability to choose to comply with the final emission 

standards by implementing a rate based or mass based state plan. States can decide the best 

approach that meets each state’s individual need, while maintaining the goals in the final CPP 

rule. See Section VIII.C of the final rule preamble of the CPP for different state plan approaches. 
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The EPA is providing both rate-based and mass-based statewide goals in this final rule in place 

of having states determine the mass values themselves, in order to assure that the mass goals are 

an equivalent expression of the BSER.

The fact that mass goals for existing sources are themselves quantified in a way that is an 

equivalent expression of the BSER, the form of mass goals is only equivalent if leakage from 

new sources is addressed. The EPA is therefore requiring that states adopting a mass-based 

implementation include a strategy that addresses leakage, or the state may otherwise provide 

justification that leakage would not occur under the state’s implementation. The required 

demonstration and options to minimize leakage are discussed in detail in Section VIII.J of the 

final rule preamble of the CPP. 

To address the potential for emission leakage to new sources under a mass-based plan approach, 

the EPA is requiring that a state submitting a plan that is designed to meet a state mass-based 

CO2 goal for affected EGUs must demonstrate that the plan addresses and mitigates the risk of 

potential emission leakage to new sources. Section VIII.J of the final rule preamble of the CPP 

describes the options that would provide sufficient demonstration that potential emission leakage 

has been addressed in a mass-based state plan.

The EPA is also providing an EPA-provided mass budget that includes the state mass-based CO2

goal for affected EGUs plus a new source CO2 emission complement, this option could be 

presumptively approvable. The EPA will evaluate the approvability of this aspect of an 

individual state plan using the model rule through independent notice and comment rulemaking.

A state could establish federally enforceable, mass-based emission standards for affected EGUs,

complemented by state-enforceable mass-based emission standards for new fossil fuel-fired 

EGUs. This approach could involve an emission budget trading program that includes affected 

EGUs as well as new fossil fuel-fired EGUs.

The following are summaries of the specific public comments under this comment:

Commenters stated they believe the EPA should encourage states to adopt the mass-based limits 

and believe that including mass-based limits in the rule will make it easier for states to do so.

Commenters also noted that even though a state may prefer a mass-based goal, it nevertheless 

may be led by administrative convenience combined with resource constraints to settle for a ratebased approach.

Commenters stated they believe the EPA should allow states to propose mass caps that are 

comparable to their rate-based goals. Commenters believed states should have the flexibility to 

determine how to make the conversion from rate-based to mass-based limits, including how to 

handle different measures under the mass-based goals (e.g., how to treat new natural gas 

combined cycle (NGCC) units). 

Commenters believed the EPA should not reject any state plan that proposes a mass-based limit 

that does not achieve the same emissions levels as achieved under the rate-based goal. The two 

methods of achieving emissions goals, commenters argued are entirely different and states 

should be allowed to determine their mass-based goal in any way they see fit since significant 

discretion is afforded to states under Section 111(d). Commenters recommended the EPA make a 
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determination that mass-based goals codified in a state plan or plans will be approved with no 

further need for review.

Commenters recommended that EPA "take active steps to lower the barriers to regional 

cooperation on mass-based compliance for both new and existing sources." Commenters stated 

that "EPA should also provide an alternative mass-based target that incorporates emissions from 

new sources." Commenters said this will help states because "providing states with these targets 

rather than asking them to develop them will significantly lower the burden and perceived legal 

risk of states opting for a mass-based approach." 

Commenters proposed that "EPA reject any call to adopt new gas for goal-setting and 

compliance purposes." 

5.8.7 Other

This section addresses a variety of comments with regards to state plans and projecting EGU 

CO2 emission performance.

Commenters have raised a number of issues related to this subsection which are organized by 

topics (comments) below. Responses are also provided for these topics.

Comment 1: Comments regarding more time for modeling, whether specific tools can be used 

and reliability of CO2 data projections.

Response 1: The EPA is not requiring specific tools or emission quantification methodologies 

states and/or affected EGUs must use when demonstrating the emission guidelines will be met as 

long as the method is technically sound and meet the criteria in the preamble. For these details 

refer to Section VIII.D.(2) in the final rule preamble of the CPP under the State Plan 

Components Approvability Criteria where we answer these comments. For state plan submittal 

timing see Section VIII.E of the final preamble of the CPP. 

The EPA is not requiring specific tools or emission quantification methodologies states and/or 

affected EGUs must use when demonstrating the emission guidelines will be met as long as the 

method is technically sound and meet the criteria in the preamble. For these details refer to 

Section VIII.D.(2) of the final rule preamble of the CPP under the State Plan Components 

Approvability Criteria where we answer these comments.

The following are summaries of the specific public comments under this comment:

Commenters stated that if EPA requires states to provide detailed modeling with the state plans 

then the state must be provided more time. Commenters stated that they thought EPA "is seeking 

to impose unnecessary burdens on states that the Agency is not authorized under section 111(d) 

to require. States should determine the manner in which they will evaluate the performance of 

their plans. At the very least, EPA must provide more time to states if it wants to encourage 
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states to undertake the sort of detailed modeling and related work EPA appears to prefer." 

Commenters recommended "that EPA develop guidance that describes acceptable projection 

approaches, tools, and methods for use in an approvable plan" and also recommended "that EPA 

accept collective state CO2 projection tools such as Eastern Regional Technical Advisory 

Committee (ERTAC) EGU."

Commenters asserted that with regard to projections of future CO2 emissions the states should be 

able to use data that is "most reasonably available" or EPA should provide guidance. 

Commenters recommended that EPA should "not require IPM modeling for state-level emissions 

projections."

Commenters stated that Carnegie Mellon is developing a tool that can be used by States in 

developing their state-specific plan. Commenters stated the tool will evaluate emissions and 

costs associated with different carbon mitigation methods.

Can states use a non-IPM model to project generation by affected EGUs?

Comment 2: Comment regarding developing a model rule.

Response 2: The EPA is proposing model rules for both mass-based and rate-based emission 

trading programs. State plans that include the finalized model rule for a rate-based emission 

trading program could be presumptively approvable as meeting the requirements of CAA section 

111(d) and these emission guidelines. The EPA would evaluate the approvability of such plans 

through independent notice and comment rulemaking. States would be able to choose whether 

they are implementing a single or multi-state plan. 

The following are summaries of the specific public comments under this comment:

Commenters recommended EPA develop a model trading rule and "clarify whether states 

incorporating by reference would be considered subject to single or multi-state plan 

requirements."

Comment 3: Comment regarding using established regional frameworks and multi-state 

arrangements.

Response 3: The EPA agrees with this comment, and notes that it encouraged such approaches 

in the proposal. While the EPA is not requiring states to join and/or form regional market-based 

programs, we note that such programs can be helpful for many reasons, including features that 

support reliability. Market-based programs allow greater flexibility for affected EGUs both in the 

short-term and long-term. Under a market-based program, affected EGUs have the ability to 

obtain sufficient allowances or credits to cover their emissions in order to comply with their 

emission standards. Additionally, we continue to encourage states to cooperate regionally. 

Regional cooperation in planning and reliability assessments is an important tool to meeting 
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system needs in the most cost-effective, efficient, and reliable way. See Section VIII.C.5 where 

the EPA describes multi-state plan options in the final rule preamble of the CPP.

The following are summaries of the specific public comments under this comment:

Commenters also supported the option "to use established regional renewable energy credit 

tracking systems and processes in multi-state arrangements." Commenters strongly supported 

"allowing states to use the Western Renewable Energy Generation Tracking System (WREGIS) 

for compliance with renewable energy programs, and further note that it is already well suited to 

use in multi-state arrangements." Commenters also said, "States should work cooperatively to 

avoid double counting of emissions reductions from renewable energy and energy efficiency, 

and should address double counting in their EM&V plans."

Comment 4: Comment regarding credit for prior CO2 reductions.

Response 4: The EPA received many comments requesting that the agency recognize early 

actions for the emission reductions they provide prior to the performance period. The EPA 

recognizes the validity and importance of this comment, and as a result has determined to 

provide a program – called the Clean Energy Incentive Program – in which states may choose to 

participate. The Clean Energy Incentive Program is designed to reward investment in certain RE 

and demand-side EE projects that commence construction after the effective date of this rule and 

that generate MWh or reduce end-use energy demand during 2020 and 2021. State participation 

in the program is optional. 

Under the Clean Energy Incentive Program, states may set aside allowances from their interim 

targets or generate early action emission rate credits (ERCs, as defined in section VIII.K.2 of the 

final rule preamble of the CPP), and allocate to eligible projects allowances or ERCs equivalent 

to each MWh generated or avoided. For further details, see section VIII.B.2 for details in the in 

the final preamble of the CPP.

The following are summaries of the specific public comments under this comment:

Commenters stated that the Clean Power Plan "should provide states with credit for prior CO2

reductions as option towards meeting a reasonable national target for reducing CO2 emissions."

Commenters stated that the proposed rule's "ambiguity and lack of incentives to offset carbon 

pollution with non-emitting generation in the short term is counter to the purposes of regulatory 

policy to reduce carbon emissions as soon as possible." Commenters further stated that the 

proposed rule does "not provide clear incentives to states to continue the expansion of the 

existing renewable energy standards and energy efficiency standards, especially between now 

and 2020" and that this could cause state legislatures "to postpone legislation to increase 

renewable energy and energy efficiency standards."
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Comment 5: Comment regarding modeling and analysis data availability for renewable energy

and energy efficiency.

Response 5: The EPA agrees with the commenter for renewable energy. In the final rule the 

EPA increased the amount of RE in building block for for BSER. The basis for quantifying 

building block 3 generation has been modified to incorporate historical deployment patterns for 

RE technologies as well as the economic potential identified through modeling projections. The 

introduction of historical capacity additions to the final methodology further grounds building 

block 3 generation in demonstrated levels of RE deployment that have been successfully 

incorporated into the power system. The EPA revised its data for onshore wind and solar 

technologies to reflect the mid-case estimates from the National Renewable Energy Laboratory’s 

(NREL’s) 2015 Annual Technology Baseline. The EPA selected the NREL 2015 Annual 

Technology Baseline (ATB) estimates based on the quality of its data as well as NREL’s 

demonstrated success in both reflecting and anticipating RE cost and performance trends. All 

modeling and analysis are provided in the GHG Mitigation Measures TSD for the CPP Final 

Rule and RIA for the final CPP. 

As for energy efficiency. The EPA determined to not include EE as a part of BSER. See Section 

V.A. of the final rule preamble of the CPP for details on EPA’s rationale for why we did not 

include EE in the final CPP. However, Demand Side EE is still generally available for 

compliance purposes. Section VIII. K of the final rule preamble of the CPP addresses demand 

side EE and eligible measures that can be used in state plan compliance. 

The following are summaries of the specific public comments under this comment:

Commenters stated that "EPA's model significantly underrates the potential growth of renewable 

energy and energy efficiency" and that all of the modeling and analysis should be made 

available.

Comment 6: Comment regarding expanding mass-based system to include new natural gas 

plants.

Response 6: The final CPP emission guidelines provide states with a number of potential plan 

pathways for meeting the emission guidelines. A plan pathway represents a specific plan design 

approach used to meet the emission guidelines. These plan pathways are discussed in section 

VIII.C.2 through C.5 of the final rule preamble of the CPP, and further elaborated in sections 

VIII.J of the final rule preamble of the CPP (for mass-based emission standards) and VIII.K of 

the final rule preamble of the CPP (for rate-based emission standards). For example, a state could 

establish federally enforceable, mass-based emission standards for affected EGUs,

complemented by state-enforceable mass-based emission standards for new fossil fuel-fired 

EGUs. This approach could involve an emission budget trading program that includes affected 

EGUs as well as new fossil fuel-fired EGUs. This approach facilitates interstate emission 

trading, through either a “trading-ready” single-state plan approach or through a multi-state plan. 

Under a “trading-ready” plan, interstate emission trading may occur without the need for a multistate plan. 
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The following are summaries of the specific public comments under this comment:

Commenters encouraged EPA to allow "states that choose mass-based systems to expand their 

budgets to cover new natural gas plants and to regulate them, entirely under state authority, 

within the same mass-based system the state uses to regulate existing power plants under Section 

111(d)."

Commenters stated that the mass-based limit should be the only federally enforceable provision 

in a mass-based state plan. Commenters stated that if a state or states propose a mass-based plan, 

"the mass-based limit should be the only federally enforceable provision." Commenters further 

stated that if the state's mass-based plan addresses emissions from EGUs that may become 

affected units then, "these units should not be subject to additional regulation as they pass the 

111 (d) affected unit threshold."

Comment 7: Comments regarding energy efficiency data, eligibility of energy storage, 

transmission and distribution and granting credit for energy efficiency for state plans.

Response 7: In Section VIII.K.1(a) of the final rule preamble of the CPP, the EPA discusses the

broad categories of measures that are available to reduce CO2 emissions from affected EGUs 

under a rate-based state plan. All state plans must demonstrate that measures included in the plan 

are quantifiable and verifiable. Solar power is an eligible RE measures for state plans. 

Energy storage may not be directly recognized as an eligible measure that can be used to adjust a 

CO2 emission rate, because storage does not directly substitute for electric generation from the 

grid or avoid electricity use from the grid. The electric generation that is input to an energy 

storage unit may be used to adjust a CO2 emission rate, but the output from the energy storage 

unit may not. However, energy storage can be used as an enabling measure that facilitates greater 

use of RE, which can be used to adjust a CO2 emission rate.

The EPA determined that for RE and demand-side EE measures in state plans the state will also 

need to include quantification, monitoring, and verification provisions in its plan for these 

measures. The EPA will release a draft Evaluation Measure and Verification EM&V Guidance 

Document for comment along with this final CPP rule.

See section VIII.K.3 of the final rule preamble of the CPP for discussion of EM&V requirements 

for use of RE and demand-side EE in a state plan. For additional details for incorporating 

demand side EE and RE in state plan projections see the Incorporating RE and Demand-Side EE 

Impacts into State Plan Demonstrations TSD. 

EPA agrees with the commenter that states should not be required to submit time differentiated

savings from their EE programs and EPA is not prohibiting states to include more detailed 

hourly data MWh data in their state plans.

Not all state plans are required to conduct a projection. If a state decides to implement certain 

plans that doesn’t require a projection then modeling is not required. States using demand Side 

EE and RE for rate based plans do not need to estimate the emission impacts of these measures.
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The EPA understands that it can be analytically challenging to estimate the quantity of GHG 

emissions that may be reduced or avoided by implementing demand-side energy efficiency 

projects. In the final CPP rule, states can get credit for eligible zero or low emitting by adjusting 

the reported CO2 emissions rate of affected EGU as described in Section VIII.K.1.a (2)-(10) of 

the final rule preamble of the CPP. For rate based plans, these MWh are added to the 

denominator of an affected EGU’s reported CO2 emission rate, resulting in a lower adjusted CO2

emission rate. Therefore, adding MWh from these resources to the denominator of an affected 

EGU CO2 emission rate allows mass CO2 emission reductions from these measures to be fully 

reflected in an adjusted CO2 emission rate.

The EPA’s draft guidance on EM&V for measures and quantifying EE will be going through a 

notice and comment period. Commenters can comment on this draft EM&V guidance, which 

will be released at the same time as this final CPP rule.

The following are summaries of the specific public comments under this comment:

Commenters stated that Concentrating Solar Power and "other energy supply, storage, 

transmission and management measures, are making it increasingly possible to reduce 

greenhouse gas and other emissions from the power sector while maintaining reliability and 

reasonable cost." Commenters recommended that EPA, DOE, NERC, ERCOT and ISO/RTOs, 

and other governmental entities, "should provide as much guidance as possible for planning, 

implementing, monitoring and measuring the effectiveness of measures to be incorporated in 

State Plans."

Commenters stated "that states should not be required to submit time differentiated savings from 

their EE programs." However, since "the impact of EE programs on CO2 emissions can vary 

greatly according to the time of day and by season" commenters recommended "that states that 

can demonstrate that they have high quality load shape data be given the option to include time 

differentiated energy savings in their implementation plans."

Commenters stated it is analytically challenging to estimate the quantity of GHG emissions that

may be reduced or avoided by implementing demand-side energy efficiency projects. 

Commenters stated that to estimate reduced GHG emissions in this context requires complex 

modeling designed to calculate (i) the change in electricity load for each hour of the day an EE 

project is expected to operate, and (ii) the "marginal" emissions reductions associated with the 

marginal electric generation unit in a region that can be expected to reduce its output in response 

to the change in electric load. Commenters stated accomplishing this requires the use of regional 

electric generation dispatch modeling tools and other sophisticated analysis methods that not all 

entities have at their disposal. Commenters stated instead of requiring these burdensome 

methods, to the extent that states can credibly show that these emission reductions have occurred, 

EPA should grant credit for these actions under a state plan.

Commenters noted that if the EPA restricts the types of efficiency measures that are eligible for 

credit towards compliance with a rate-based target, this may cause a discrepancy in how energy 

efficiency is treated under the two approaches. Commenters further recommended that the EPA 

can address this by 1) promulgating detailed guidance for incorporating energy efficiency 

measures that would not qualify for credit under a rate-based approach into baseline emissions 
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projections in the determination of a mass-based target, 2) allowing for the revision of 

projections and mass-based targets to reflect new information during the implementation period, 

and/or 3) allowing states to receive credit for the broadest possible range of energy efficiency 

measures reducing the sorts of measures that would receive passive credit in a mass-based state 

but no credit in a rate-based state.

Commenters said the EPA must adopt approaches that ensure that final regulations, should they 

be issued, rely on those guidelines that treat energy efficiency and DSM programs as 

complementary means of achieving emission reductions and are not included as federally 

enforceable mandatory components of state plans. Commenters said that given the differences 

between the proposed rule under section 111(d) and the existing section 110 programs, any 

existing EPA guidance and explanatory texts on the possible inclusion of energy efficiency in a 

state implementation plan under section 110 must not be used as a proxy for the treatment of 

energy efficiency under this proposal. Commenters said that not only are these documents 

irrelevant, they are not regulations and have not been subject to notice and comment.

Comment 8: Comment regarding GHG leakage with other countries.

Response 8: This final CPP rule demonstrates to other countries that the United States is taking 

action to limit GHG emissions from its largest emission sources, in line with our international 

commitments. The impact of GHGs is global, and U.S. action to reduce GHG emissions 

complements and encourages ongoing programs and efforts in other countries.

The State Department Special Envoy for Climate Change Todd Stern, the lead U.S. climate 

change negotiator, noted the connection between domestic and international action to address 

climate change in his speech in New Haven, CT on October 14, 2014:

“This mobilization of American effort matters. Enormously. It matters because the United 

States is the biggest economy and largest historic emitter of greenhouse gases. Because, 

here, as in so many areas, we feel a responsibility to lead. And because here, as in so 

many areas, we find that American commitment is indispensable to effective international 

action.

And make no mistake – other countries see what we are doing and are taking note. As I 

travel the world and meet with my counterparts, the palpable engagement of President 

Obama and his team has put us in a stronger, more credible position than ever before.”

The EPA senior agency officials met with a number of labor union representatives about 

reducing carbon pollution using CAA section 111(d). Those unions included: the United Mine 

Workers of America; the Sheet Metal, Air, Rail and Transportation Union (SMART); the 

International Brotherhood of Boilermakers, Iron Ship Builders, Blacksmiths, Forgers and 

Helpers (IBB); United Association of Journeymen and Apprentices of the Plumbing and Pipe 

Fitting Industry of the United States and Canada; the International Brotherhood of Electrical 

Workers (IBEW): and the Utility Workers Union of America. In addition, agency leaders met 
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with the Presidents of several unions and the President of the American Federation of LaborCongress of Industrial Organizations (AFL-CIO) at the AFL-CIO headquarters.

The following are summaries of the specific public comments under this comment:

Commenters stated that the Clean Power Plan should contain provisions to avoid industrial GHG 

leakage with other countries since there is "an absolute direct relationship between U.S. energy 

costs and manufacturing employment, and the manufacturing trade deficit."

Comment 9: State energy mix changes.

Response 9: The EPA has determined that a state interim and final CO2 emission goals for 

affected EGUs in a state may be adjusted to address inventory changes within a state’s fleet of 

affected EGUs. If these changes occur before a state submits its initial or final plan, the state 

should indicate in its submittal the circumstance that necessitates the goal adjustment and the 

revised interim or final CO2 emission goal. If the circumstances occur after a state has an 

approved plan, a state must submit a modification to its approved plan. The plan revision 

submittal must indicate the circumstance that necessitates the goal adjustment, the revised 

interim and/or final CO2 emission goal, and the adjustments to the enforceable measures in the 

plan. See section VII of the final rule preamble of the CPP for details.

The following are summaries of the specific public comments under this comment:

Commenters stated that "EPA's long-term emissions targets do not seem well-equipped to deal 

with changes to the current energy mix in each state." Commenters asked implementation 

questions about whether EPA would recalculate emissions targets and states would submit new 

SIPs if the energy mix in a state changed. Commenters 2asked the following questions,"1. EPA's 

long-term emissions targets do not seem well-equipped to deal with changes to the current 

energy mix in each state. a. What happens if nuclear facilities are retired at a rate that exceeds the 

"at risk" capacity that EPA uses to establish the state's emission rate target? b. What happens if 

an existing coal or NGCC facility is modified or reconstructed? c. What happens if a fossil fuelfired facility is retired? d. What happens if EPA's Accounting Framework changes the status of 

biomass energy that is currently counted as "zero-emission" renewable energy? Will the 

Framework be binding on the States? Interested parties are not able to fully comment on the 

111(d) proposal without reviewing the Framework. 2. Does EPA need to recalculate the 

emissions target if these types of changes occur? Do States need to submit new implementation 

plans? Could individual facilities be subject to changing emissions reduction obligations based 

on the actions of unrelated facilities?"

Comment 10: Comment regarding addressing all greenhouse gases and total lifecycle emissions.

Response 10: The EPA has determined that measures that reduce CO2 emissions outside the 

electric power sector may not be counted toward meeting a CO2 emission performance level for 

affected EGUs or a state CO2 goal, under either a rate-based or mass-based approach, because all 
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of the emission reduction measures included in the EPA’s determination of the BSER reduce 

CO2 emissions from affected EGUs.

The EPA’s analysis found that the net upstream methane emissions from natural gas systems and 

coal mines and CO2 emissions from flaring of methane will likely decrease under the Clean 

Power Plan. Furthermore, the changes in upstream methane emissions are small relative to the 

changes in direct emissions from power plants. The technical details supporting this analysis can 

be found in the Regulatory Impact Analysis (RIA) of this final rule.

The following are summaries of the specific public comments under this comment:

Commenters stated that the rule should address all greenhouse gases and total lifecycle 

emissions, and added that "for gas-fired power plants, this includes methane leakage during 

production, processing, and transmission, emissions from flaring at gas wells, and energy 

consumed in the production and transport of liquefied natural gas ("LNG")."

Commenters urged EPA to consider whether the carbon rules are aggressive enough to offset 

increases in natural gas usage and methane burning over the next ten plus years.

Comment 11: Comment regarding combined annual performance goal for a utility company.

Response 11: The EPA agrees, the final CPP provides many flexibilities to comply with the final 

emission guidelines. The EPA in the final rule is providing states with maximum flexibility to 

achieve their emission standards or CO2 state goals in the emission guidelines. This includes 

having combined annual performance goals or state-wide goals for all affected EGUS that are 

equal to the EPA’s final emission guidelines. For example, states can enter into Multi-state plans, 

multi-state coordination while retaining their individual state goals and emission budget trading 

programs. Rate based programs can use or purchase ERCs generated from eligible resources 

(e.g., demand side energy efficiency and renewable energy).

The following are summaries of the specific public comments under this comment:

Commenters stated the way the rule is proposed the states must ensure that every affected entity 

has a permanent emission standard and believe that this limits flexibility in achieving CO2

reductions. Commenters proposed that a utility company should be able to have a combined 

annual performance goal for its affected EGUs.

Comment 12: Comment regarding Wood Mackenzie analysis.

Response 12: This comment is unclear. Coal is still being mined profitably in the IPM runs. The 

coal outlook used in IPM is regularly updated; information from Wood MacKenzie is only one 

component of that analysis and updating.

The following are summaries of the specific public comments under this comment:
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Commenters stated that the Wood Mackenzie analysis is wrong because it assumes "that there 

are abundant US coal deposits that can still be mined profitably." Furthermore, commenters said 

that the U.S. needs to repower since the U.S. doesn't have much "economically recoverable coal" 

left.

Comment 13: Comment regarding compliance approach during interim period.

Response 13: For each state, the EPA has finalized that projections must demonstrate the state 

plan will meet the interim goal for the interim period of 2022-2029 and a final goal by 2030. For 

the interim period, the EPA has also finalized three interim step goals: interim step 1 goal for 

2022-2024, interim step 2 goal for 2025-2027 and interim step 3 goal for 2028-2029. States are 

free to establish different interim step goals than those the EPA has specified in this final rule. If 

states choose to determine their own interim step goals, the state must demonstrate that it will 

still meet the interim goal for 2022-2029 finalized in this final rule and the plan submittal must 

include in its supporting documentation a description of the analytic process, tools, methods, and 

assumptions used to make this demonstration.

The EPA recognizes the importance of ensuring that, during the 8-year interim period (2022-

2029) for the interim performance rates or interim state goal, a state is making steady progress 

toward achieving the required level of emission performance. For both emission standards plans 

and state measures plans, the final rule requires periodic checks on overall emission performance 

leading to corrective measures or implementation of the backstop, if necessary, as described in 

section VIII.F.3 of the final preamble of the CPP. States must demonstrate that the interim steps 

were achieved at the end of the first two interim step periods. In 2032 and every 2 years 

thereafter, states must demonstrate that affected EGUs achieved the final performance rates or 

state goal on average during each 2-year reporting period (i.e., 2030-31, 2032-33, 2034-2035 

etc.). The multi-year performance periods for measuring actual plan performance against the 

performance rates or state goals allow states some flexibility that accounts for seasonal operation 

of affected EGUs, and inclusion of RE and demand-side EE efforts.

EPA is also allowing flexibility in rate based state plans to help meet each interium period. As 

discussed in section VIII.C.2.a of the final rule preamble of the CPP, a MWh of generation or 

savings that occurs in 2022 or a subsequent year may be carried forward (or “banked”) and 

applied in a future year. For example, a MWh of RE generation that occurs in 2022 may be 

applied to adjust a CO2 emission rate in 2023 or future years, without limitation. These MWh 

may be banked from the interim to final periods. 

The final CPP allows broad flexibility in how to comply with the emission standards or state 

goals in the final guidelines. Sources have the ability to purchase ERCs as a way to adjust the 

CO2 emissions rate and massed based states can join emission budget trading program or 

coordinate through multi-state plans. Even if the projected energy savings doesn’t happen 

exactly as expected these additional flexibilities will allow states and sources the latitude to still 

meet their future goals.

The following are summaries of the specific public comments under this comment:
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Commenters noted that the preamble indicates that states must demonstrate compliance over a 

10-year average period for the interim goal (2020-2029), and then starting in 2030, states are 

required to meet the final goal based on a 3-year rolling average period. Commenters noted that 

these flexible compliance periods allow the state to determine the transition rate necessary to 

meet the interim and final goals. However, commenters noted that the proposal also requires 

states to project emission performance for each year from 2020-2029 in their plans, which could 

preclude a state from offering this transition flexibility to affected sources. 

Commenters noted the proposed section 60.5740 [79 FR 34952]:

(a)(3)(iii) For the interim plan performance period you must identify the emission 

performance levels anticipated under the plan during each year 2020 through 2029.

Commenters stated that one potential would be to determine a conservative amount of emissions 

comprising the difference between: 1) the amount of emissions allowed over 10 years if the state 

were to transition directly to the final goal in 2020, and 2) the amount of emissions that would 

occur over 10 years if the state used the interim goal from 2020-2029. Commenters noted that 

states could award affected EGUs emission allowances equivalent to this difference in 2020 and 

allow them to be used at any time over the 10-year interim period. Commenters stated that this 

would help to ease the transition to existing unit CO2 requirements while ensuring the interim 

goal is achieved. Commenters stated if a state elected to go with such an approach, it would be 

difficult to project how quickly the state's adjusted rate would begin to fall. Because the interim 

goal is based on the average emission rate over a 10 year period, commenters suggested that the 

EPA allow states the option of projecting the average emission performance level for the 

cumulative portion of interim period that has passed in each respective year. Commenters 

provided a table (Table 2) showing how a state's plan could project emission performance for 

every individual year in the interim performance period, and alternatively project emission 

performance for each year. Commenters stated that this approach would offer transition 

flexibility to the affected EGUs, while enabling a state to project worst-case scenarios that will 

still meet its interim goal over the 10-year period.
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5.9 TREATMENT OF EXISTING STATE REGULATIONS AND PROGRAMS

This section addresses crediting existing state regulations and programs toward compliance with

the CPP. The majority of the comments in this section deal with the date from which existing 

programs were undertaken may be credited. Other comments discuss banking credits for future 

use, what type of programs should be credited, and suggestions for how to credit emissions 

reductions. Responses to the comment topics are discussed below, along with summaries of the 

specific public comments. 

Comment 1: Comments stating that the EPA allow states to take credit for existing state 

programs

Response 1: The EPA received many comments suggesting that the EPA should recognize early 

actions for the emission reductions they provide prior to the performance period. The EPA 

recognizes the validity and importance of these perspectives, and as a result, the final rule 

contains two provisions that enable states to incentivize early investments in zero-emitting 

generation and demand-side EE. 

First, states adopting rate-based plans may award ERCs to qualified providers that implement 

any eligible projects from 2013 onward for the quantified and verified MWh of generation or 

savings those projects provide in 2022 and subsequent years. Affected EGUs may use ERCs 

issued under each of these provisions for compliance with their assigned emission standards or 

bank the ERCs for use in any compliance period. In a mass-based context, similar efforts will be 

inherently reflected in the affected EGUs stack emissions in 2022 forward. For more details on 

this treatment of early actions, see section VIII.K of the preamble to the final rule.

Second, the EPA has developed the Clean Energy Incentive Program, an optional program 

designed to reward investment in certain RE and demand-side EE projects that commence 

construction after the effective date of this rule and that generate MWh or reduce end-use energy 

demand during 2020 and 2021. Under this program, states may set aside allowances from their 

interim targets or generate early action ERCs (as defined in section VIII.K.2 of the final rule 

preamble), and allocate to eligible projects allowances or ERCs equivalent to each MWh 

generated or avoided. For more details on this program, see section VIII.B.2 of the preamble to 

the final rule.

The EPA has clarified which actions count and when such actions count generally in section 

VIII.K.1. and more specifically in section VIII.K.3 on EM&V requirements for RE resources 

used to adjust a CO2 rate. Requirements for rate-based emission trading programs and the 

issuance and tracking of ERCs, including qualifying RE measures, programs or projects and 

addressing the potential for interactions between ERCs and RECs, are addressed in section 

VIII.K.2.

The following are summaries of the specific public comments under this comment:
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Many commenters thought EPA should provide credit for states that make GHG emissions 

reductions prior to 2020. These commenters contended that EPA should allow states to bank 

emission reductions that result from state requirements, measures and programs instituted before 

2020 and use them for compliance after 2020. Commenters suggested that if a state or entity can 

show verifiably that it has reduced its emissions via some measure, it should receive credit under 

the building block computation of the state’s emission reduction goal. Several commenters 

supported limited banking of credits.

Commenters recommended the guidelines allow states to earn credit for CO2 emission reductions

achieved through existing GHG cap-and-trade programs and RPSs after the start of the program 

in 2020. Commenters supported EPA allowing states to develop their section 111(d) plans based 

on various programs and strategies for reducing CO2 and other greenhouse gas emissions from 

the electric power sector. 

Commenters stated that EPA should provide states full credit for early actions to protect citizens’

energy needs and reduce carbon emissions, while other commenters recommended the EPA 

provide states with “the flexibility to maximize credit for early actions.” Commenters suggested 

EPA consider how to “better reflect the progress that states have made in achieving emission 

reductions.” Commenters recommended the EPA expand the scope of the existing programs

provisions of its Proposed Guidelines to give the broadest favorable treatment possible to EE 

actions taken to reduce CO2 emissions, regardless of whether those actions were taken prior to 

the proposal of the Proposed Guidelines. 

Several commenters provided examples of early reduction activities they believe should be 

credited. 

Commenters noted measures that utilities in the state of Minnesota have already undertaken (e.g., 

CHP and district heating/cooling) that have proven to be cost-effective emission reduction 

measures, and demonstrate the state is keeping pace with the overall emission reduction targets 

being proposed. Therefore, commenters stated, the EPA should accept these early actions and 

ongoing measures for improvements as satisfying the CPP requirements for Minnesota.

Commenters from Arkansas stated that the EPA should give credit for use of existing clean 

renewable resources, noting SWPA Hydro specifically. Commenters noted several existing and 

soon to be on-line run-of-the-river hydropower projects (approximately 300 MW capacity) that 

were developed with recognition of the contribution that they could make to the City of 

Cleveland's carbon-free energy portfolio and, as such, they should not be denied credit under any 

state plans simply because they are pre-existing projects. Commenters encouraged EPA to design 

its regulations to maximize energy efficiency to allow emissions already reduced to count for 

compliance (citing recent RGGI comments).

Commenters noted that the effective date for EE MWh to be counted for compliance with the 

CPP should be the date the CPP is finalized, assuming EPA's objective for including EE in the 

CPP rule is to ensure that states and utilities aggressively promote EE and reduce CO2 emissions 

by reducing the demand for electricity. Commenters stated that the EPA has touted the flexibility 

of the CPP many times. Commenters stated that it is difficult to see why EE achieved before the 

rule is final should not be captured for compliance with the rule. Commenters stated that the 

EPA's position on EE should be that earlier is better. Commenters stated that the CPP should not 
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impose perverse incentives that would delay the implementation of EE programs so that they 

may be counted for compliance. Commenters noted that states and utilities will pursue EE more 

aggressively and more quickly if such actions result in credit towards compliance. Commenters 

stated that EPA should accept and give a facility credit for the EE savings it is currently 

achieving or will achieve in the near future. 

Commenters stated that one year after the 2012 baseline year, they achieved 614 GWh of savings 

through energy efficiency programs, and had a company-owned and contracted portfolio that 

generated 2,158 GWh of renewable energy. Commenters argued that these savings from existing 

programs will continue every year until the interim compliance period begins and should be 

bankable for use during the interim compliance period.

Commenters urged EPA to allow credit for existing RE projects, and noted that Maine had

developed significant amount of RE in the form of wind power before EPA proposed the rule. 

Commenters stated that Maine has geographical limitations to how much additional wind power 

or other RE that can be developed in the state. Commenters noted that the timing of these 

projects coming on-line does not negate the effectiveness of these units in reducing carbon 

emissions.

Commenters stated that Pennsylvania has implemented the Act 129 program, under which 

electric distribution companies (EDCs) regulated by the Pennsylvania Public Utility Commission 

(PUC) must achieve specific emissions reductions targets. Commenters asserted that reductions 

made under this program should be eligible for credit, but are concerned that structural aspects of 

the program could prevent appropriate credit being taken. Commenters stated Pennsylvania’s Act 

129 targets have been set in three-year phases with the specific targets based on a cost 

effectiveness evaluation by an independent evaluator. Commenters stated the PUC is currently 

developing targets for Phase III of the program and is concerned the duration of Phase III may 

not overlap with the compliance period. Commenters stated that while PUC has the statutory 

authority to establish longer phases that align the phase with the compliance period, that could 

result in the loss of any advantage from improved cost-effectiveness over the term. Commenters

asked that the EPA further analyze the structure of existing state programs and determine the 

best way to harmonize state and federal requirements. 

Commenters agreed that the EPA should allow states and utilities to count the energy savings 

from energy efficiency measures installed starting in 2020, even if they result from efficiency 

policies that were adopted and took effect prior to 2020, as long as these activities are 

incremental and are an element of the state's 111d compliance plan.

Commenters stated that there has been significant confusion regarding which existing renewable 

energy measures can be counted towards compliance and when credit will be given. Commenters 

requested EPA to clarify which actions count and when such actions count. 

Commenters interpreted the rule as only permitting states to count emission reductions beginning 

in 2020 from programs/measures that were implemented on or after June 18, 2014. Commenters

also requested clarification regarding the treatment of natural gas combined cycle plants built 

between 2013 and 2019.
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Commenters supported EPA's proposal allowing state solar measures which exist after the date 

of proposal can be used to drive emissions reductions during the compliance period. Commenters 

also interpreted the proposal to allow existing renewable energy measures and actions to count if 

implemented prior to June 18, 2014 because building block 3 was factored into determination of 

the state goals. Commenters concluded that MWh from renewable energy capacity installed 

pursuant to an existing measure or program any time prior to 2020 can be counted towards 

compliance during the compliance period if the existing measure is included in a SIP.

Comment 2: Comments suggesting that the EPA would be penalizing states for taking early 

action if they do not allow credit for early reductions

Response 2: The EPA received many comments suggesting that the EPA should recognize early 

actions for the emission reductions they provide prior to the performance period. The EPA 

recognizes the validity and importance of these perspectives, and as a result, the final rule 

contains two provisions that enable states to incentivize early investments in zero-emitting 

generation and demand-side EE. 

First, states adopting rate-based plans may award ERCs to qualified providers that implement 

any eligible projects from 2013 onward for the quantified and verified MWh of generation or 

savings those projects provide in 2022 and subsequent years. Affected EGUs may use ERCs 

issued under each of these provisions for compliance with their assigned emission standards or 

bank the ERCs for use in any compliance period. In a mass-based context, similar efforts will be 

inherently reflected in the affected EGUs stack emissions in 2022 forward.

Second, the EPA has developed the Clean Energy Incentive Program, an optional program 

designed to reward investment in certain RE and demand-side EE projects that commence 

construction after the effective date of this rule and that generate MWh or reduce end-use energy 

demand during 2020 and 2021. Under this program, states may set aside allowances from their 

interim targets or generate early action ERCs (as defined in section VIII.K.2), and allocate to 

eligible projects allowances or ERCs equivalent to each MWh generated or avoided. For more 

details on this program, see section VIII.B.2 of the preamble to the final rule.

The following are summaries of the specific public comments under this comment:

Several commenters contended that by not allowing states to take credit for reductions made 

prior to 2020, the EPA is penalizing States who were early adopters of programs and other 

measures to reduce GHG emissions. For example, commenters noted several energy efficiency 

and renewable energy actions (including solar and geothermal energy projects) undertaken by the 

town of Wyandotte, MI between 2009 to 2012. Commenters requested clarifications in the final 

rule that ensure reduction activities such as the ongoing coal plant retirements happening under 

the Clean Air Clean Jobs Act that the rule cites are unequivocally recognized toward compliance 

with the rule.

Commenters argued that forward looking states should get credit for their leadership. 
197

Commenters argued the proposal punishes forward thinking states because they are not allowed 

to repeal/discontinue programs/rules that reduce CO2 until 111d plans are approved. Commenters

noted that states would have to go forward with these programs while getting no credit.

Commenters contended that because states and utilities that have undertaken RE and EE 

programs are potentially forced to spend more than other entities, it is appropriate for EPA to 

designate some mechanism to provide credit for early action in establishing state emission 

reduction goals. Commenters stated that their states early action justifies EPA revising its Clean 

Power Plan targets so consumers are not punished for forward-looking policy. Commenters 

suggested that EPA can eliminate these penalties by either utilizing an earlier baseline period, or 

by giving states credit for early actions to reduce GHG emissions when they demonstrate 

compliance with their interim and final goals.

Commenters noted that New Jersey has been directly implementing EE and RE programs since 

2003 under the banner of NJCEP. Commenters noted that the average EE and RE program 

expenditures averaged $142 million over the last 13 years, and that the cost is increasing 

annually. Commenters added that the RPS compliance cost from 2004 through 2014 adds 

another $1.157 billion to the cost of clean energy in New Jersey, with the bulk of this cost being 

in the solar REC (SREC) program, which funds solar RE projects. Commenters noted that 

currently, solar makes up 2% of the electricity used in New Jersey, and through the recently 

enacted solar RPS, that value will increase to 4% by 2026. Commenters concluded that the 

proposed rule fails to properly recognize the importance of emissions reductions from existing 

state RE and EE programs. Commenters believed that, by embedding the existing renewable 

generation and energy efficiency in the goal setting calculation, EPA has created an inequity 

between states that have invested in renewables and energy efficiency and those that have not.

Comment 3: Comments suggesting that states should be given credit for emissions reductions 

from existing programs beginning on the date the existing program was implemented

Response 3: The final rule contains two provisions that enable states to incentivize early 

investments in zero-emitting generation and demand-side EE.

First, states adopting rate-based plans may award ERCs to qualified providers that implement 

any eligible projects from 2013 onward for the quantified and verified MWh of generation or 

savings those projects provide in 2022 and subsequent years. Affected EGUs may use ERCs 

issued under each of these provisions for compliance with their assigned emission standards or 

bank the ERCs for use in any compliance period. In a mass-based context, similar efforts will be 

inherently reflected in the affected EGUs stack emissions in 2022 forward.

Second, the EPA has developed the Clean Energy Incentive Program, an optional program 

designed to reward investment in certain RE and demand-side EE projects that commence 

construction after the effective date of this rule and that generate MWh or reduce end-use energy 

demand during 2020 and 2021. Under this program, states may set aside allowances from their 

interim targets or generate early action ERCs (as defined in section VIII.K.2 of the final rule 

preamble), and allocate to eligible projects allowances or ERCs equivalent to each MWh 
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generated or avoided. For more details on this program, see section VIII.B.2 of the preamble to 

the final rule.

EPA also notes that demand-side EE is no longer part of the calculation of the emission 

performance standards that are applied to affected sources, but demand-side EE is still eligible 

for ERC issuance. Therefore no level of demand-side EE is assumed in the CO2 emission 

performance rates, and affected sources can still use ERCs that originate from eligible demandside EE, including from eligible early action, for compliance with their assigned emission 

standards. States adopting rate-based plans can also award ERCs for generation in 2022 and 

subsequent years from incremental nuclear and hydropower capacity installed from 2013 

onward. Finally, the EPA appreciates the importance of early actions by states and utilities to 

reduce fossil electricity use and CO2 emissions at affected sources. EPA’s approach to 

determining the CO2 emission performance rates and state goals that are achievable considering 

cost is a forward-looking approach that starts from the state of the electricity system in 2012.

The following are summaries of the specific public comments under this comment:

Commenters noted that the EPA's "best practices for energy efficiency" are partially based on the 

energy efficiency targets and savings demonstrated by Arizona, but noted that EPA did not give 

Arizona credit for its work as an early adopter of these measures. Commenters believed states 

such as Arizona should be able to count some portion of verified savings/production since 

inception of their standards. 

Commenters stated that permanent hardware replacement programs should be given credit for 

savings realized during the period of performance regardless of when they were installed.

Commenters supported allowing existing state programs and measures to be included in state 

plans regardless of implementation date. Commenters stated that any HRI that a facility has 

implemented, regardless of when, that was assumed in the S&L study used to develop Building 

Block 1, should be included as reductions meeting the plan requirements. Commenters 

contended that EPA must allow states to demonstrate compliance with all zero-emitting 

generation, including nuclear and hydroelectric power generation, in operation during the period 

of the state plan, regardless of when the zero-emitting generation was placed in service.

Commenters suggested that the rule should provide incentives for at least 70% existing and 

under-construction nuclear generation, and recognize these as compliance strategies for reaching 

state goals. The commenters also suggested to give credit to early action and investment in low 

to no carbon sources.

Comment 4: Comments suggesting that states should be able to take credit for early reduction 

emissions in order for them to recapture some of their early investment costs and cushion the 

costs of implementing the CPP

Response 4: The EPA agrees that early action should be recognized, and had provided a way 

that some early reductions can be counted toward meeting the requirements of the rule. In order 
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to provide an incentive for early investments to proceed as planned, the EPA is establishing the 

Clean Energy Incentive Program (CEIP) described in section VIII.B.2. State participation in this 

program is optional. If a state chooses to participate in the CEIP, it may award early action ERCs 

and allowances to certain RE and demand-side EE projects that achieve MWh of generation (for 

RE) or end use savings (for EE) in 2020 and 2021, prior to the start of the interim compliance 

period.

Early investments will also lower costs of compliance for the reductions that they will provide 

during the performance period 2022 and going forward. They will reduce emissions at affected 

EGUs and in a rate-based context ERCs based upon the MWhs they produce 2022 onward can be 

used to adjust affected source emission rates.

The following are summaries of the specific public comments under this comment:

Commenters expressed concern that for utilities to be able to perform under a cap-and-trade 

system within their state or states perform under a regional cap-and-trade system, they should be 

able to take credit for the early efforts they have already made, giving them the opportunity to 

recapture some the early investment costs.

Commenters noted that early reduction credits would reduce the incremental costs of reductions 

achieved in the future by securing investment and infrastructure from implementation now.

Commenters provided an analysis of the savings that would be made if states were allowed to 

take credit for early actions.

Commenters stated that allowing states to use renewable energy megawatts that displace fossil 

megawatts between 2012 and 2020 toward compliance would cushion the harsh effects of the 

early onset of emission reduction requirements in Oklahoma. Commenters further believed that 

this would reward environmental stewardship and create an economic and compliance incentive 

for companies to bring renewable resources online as quickly as possible.

Commenters urged EPA to reduce the significant economic burden of the CPP by providing 

credit to states that have already reduced their CO2 emissions due to market-driven forces such 

as increased natural gas use, the retirement of older coal plants, and/or the construction of new 

nuclear generation.

Comment 5: Comments suggesting that the EPA give states credit for emission reductions made 

after 2012

Response 5: The EPA received many comments suggesting that the EPA should recognize early 

actions for the emission reductions they provide prior to the performance period. The EPA 

recognizes the validity and importance of these perspectives, and as a result, the final rule 

contains two provisions that enable states to incentivize early investments in zero-emitting 

generation and demand-side EE. 
200

First, states adopting rate-based plans may award ERCs to qualified providers that implement 

any eligible projects from 2013 onward for the quantified and verified MWh of generation or 

savings those projects provide in 2022 and subsequent years. Affected EGUs may use ERCs 

issued under each of these provisions for compliance with their assigned emission standards or 

bank the ERCs for use in any compliance period. In a mass-based context, similar efforts will be 

inherently reflected in the affected EGUs stack emissions in 2022 forward. ERCs issued in 2022 

or a subsequent year may be carried forward and used for demonstrating compliance in a future 

year. For example, an ERC issued for a MWh of RE generation that occurs in 2022 may be 

applied to adjust a CO2 emission rate in 2023 or future years without limitation. ERCs may be 

banked from the interim plan performance period to the final plan performance period. See 

section VIII.K.2.e. of the preamble to the proposed rule for more details on ERC banking.

Second, the EPA has developed the Clean Energy Incentive Program, an optional program 

designed to reward investment in certain RE and demand-side EE projects that commence 

construction after the effective date of this rule and that generate MWh or reduce end-use energy 

demand during 2020 and 2021. Under this program, states may set aside allowances from their 

interim targets or generate early action ERCs (as defined in section VIII.K.2), and allocate to 

eligible projects allowances or ERCs equivalent to each MWh generated or avoided. For more 

details on this program, see section VIII.B.2 of the preamble to the final rule.

The following are summaries of the specific public comments under this comment:

Several commenters contended that EPA should allow credit for emission reduction measures 

taken after 2012. Commenters thought that because EPA used total 2012 CO2 emission levels as 

the baseline for setting the state goals, it is reasonable to count CO2 emission reductions resulting 

from all actions taken after 2012 when assessing CO2 reductions achieved. 

Commenters noted that the approach of banking is not foreign to states, as many states already 

permit the carryover of renewable energy produced in one year to satisfy RPS requirements in a 

subsequent year, as well as banking programs that EPA has created in the past, noting the NOx 

SIP Call specifically. Commenters noted these early actions could include increasing or 

extending the RPS, reducing the RGGI cap, financial incentives for solar and other distributed 

technologies, or new investments in energy efficiency. Commenters suggested that EPA could 

signal to states that it will approve plans that include banking provisions by describing in detail 

the type and quantity of banking acceptable to EPA.

Commenters noted that allowing credit banking would allow a state to begin demonstrating 

emission performance earlier and develop a more gradual emission reduction trajectory.

Commenters suggested that EPA develop mechanisms for the following actions taken after 2012 

to be credited to the interim compliance period: New renewable energy production, energy 

efficiency program savings, heat rate (efficiency) improvements on affected sources, retirements 

of coal-fired plants, pumped storage facilities and nuclear plant uprates.

Commenters requested EPA provide credit for pre-2014 energy efficiency programs toward the 

2030 targets. Commenters added that efficiency programs put in place prior to June 2014 should 

not be treated differently than those adopted after June 2014.
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Commenters recommended that measures installed prior to the proposal date and savings 

achieved prior to the performance period (2014-2020) should be credited.

Commenters contended that a January 1, 2013 start date is consistent with how most existing 

efficiency programs are measured and verified, i.e., on a calendar year basis. Commenters stated 

that it would overly complicated to have two separate measurements of EE activities - one 

starting in January 2013 for existing state purposes and one starting in June 2014 for EE 

accounting in a state plan.

Commenters recommended extending the interim period to be 15 years, beginning in 2015 and

extending through 2030. Commenters added that if could not be applied to all states, the 

recommendations should be provided as an option for early adopters. Commenters concluded 

that there was no reason to treat actions conducted before 2020 differently than similar actions 

taken during the 2020-2030 time period.

Commenters stated that if states generate more renewable energy and achieve energy savings 

above 1.5 percent in 2012-2020 EPA should allow states to bank this generation to avoid 

noncompliance in future years. Commenters added that these banked credits could be necessary 

to prepare for unknown future circumstances, such as extreme weather, as well as compliance 

beyond the 2030 date of the final goal. Commenters provided an example with regards to their 

nuclear units. Commenters stated that three Minnesota nuclear units with licenses are scheduled 

to expire in 2030, 2033, and 2034 (Monticello Unit 1, Prairie Island Unit 1, and Prairie Island 

Unit 2, respectively). Commenters stated that the impending expiration of these nuclear licenses 

raises reliability and compliance issues that could be mitigated if early action earns compliance 

credits that may be used after 2030.

Commenters supported the ability to bank RECs without expiration. Commenters also requested 

EPA to clarify that RECs generated beginning January 1, 2013 and not yet sold may be banked 

and utilized for compliance beginning in 2020.

Commenters added that verifiable energy efficiency savings that exceed a state's 2012 baseline 

energy efficiency savings or EPA's 2017-2019 building block #4 energy efficiency percentages 

should be eligible to be banked and used for compliance with EPA's interim target.

Several commenters contended that emission reduction measures prior to 2012 should be 

allowed. Commenters specified dates for which credits for early emission reductions should 

begin. For example, commenters supported crediting actions since 2008 through the beginning of 

the compliance period. Commenters supported crediting actions since 2001. Commenters

supported states being able to credit actions back to 2004. Commenters supported states being 

able to credit actions back to 2000. Commenters suggested a date of 2005 as the cut-off date for 

states to take credit for early emissions reductions. Commenters noted that 2005 was the initial 

year of the Presidents Climate Action Plan. Commenters added that a date of 2005 provides a 

defensible period that goes back far enough to capture most, if not all, RE, EE, and CO2 emission 

reduction measures that should be credited. Commenters added that using 2005 as the start is 

also justified because measures may have been taken pursuant to the Energy Policy Act of 2005, 

which contained several renewable energy goals, such as carbon capture, subsidies for wind and 

other renewable energy producers. Commenters also recommended that if the starting point is 
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changed to 2005, EPA should not increase any state specific CO2 targets as result of this change 

because it would eliminate the benefits of taking early actions and penalize states that have done 

so.

Commenters contended that EPA should give credit to action taken at the state level by at least 

2011.

Comment 6: Comments suggesting that the EPA should give states credit for all emissions 

reductions made between the date of the CPP proposal and 2020

Response 6: The EPA received many comments suggesting that the EPA should recognize early 

actions for the emission reductions they provide prior to the performance period. The EPA 

recognizes the validity and importance of these perspectives, and as a result, the final rule 

contains two provisions that enable states to incentivize early investments in zero-emitting 

generation and demand-side EE. 

First, states adopting rate-based plans may award ERCs to qualified providers that implement 

any eligible projects from 2013 onward for the quantified and verified MWh of generation or 

savings those projects provide in 2022 and subsequent years. Affected EGUs may use ERCs 

issued under each of these provisions for compliance with their assigned emission standards or 

bank the ERCs for use in any compliance period. In a mass-based context, similar efforts will be 

inherently reflected in the affected EGUs stack emissions in 2022 forward. ERCs issued in 2022 

or a subsequent year may be carried forward and used for demonstrating compliance in a future 

year. For example, an ERC issued for a MWh of RE generation that occurs in 2022 may be 

applied to adjust a CO2 emission rate in 2023 or future years without limitation. ERCs may be 

banked from the interim plan performance period to the final plan performance period. See 

section VIII.K of the preamble to the proposed rule for more details on ERC banking.

Second, the EPA has developed the Clean Energy Incentive Program, an optional program 

designed to reward investment in certain RE and demand-side EE projects that commence 

construction after the effective date of this rule and that generate MWh or reduce end-use energy 

demand during 2020 and 2021. Under this program, states may set aside allowances from their 

interim targets or generate early action ERCs, and allocate to eligible projects allowances or 

ERCs equivalent to each MWh generated or avoided. For more details on this program, see 

section VIII.B.2 of the preamble to the final rule.

The EPA also notes that plant retirements that occur after 2012 will reduce total emissions from 

affected EGUs, and will reduce both total emissions from affected EGUs in a state and lower the 

emission rate of affected EGUs in a state, assuming that generation will increase at loweremitting affected EGUs and possibly at new sources.

The following are summaries of the specific public comments under this comment:

Several commenters suggested that EPA recognize carbon reduction measures that take place 

between proposal of the Clean Power Plan (June 18, 2014) and 2020. Commenters argued that to 

allow states to use energy efficiency and renewable energy actions achieved from the date of the 
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proposal until 2020 to comply with the interim goals, would appropriately benefit states that 

have already begun reducing the carbon intensity of the power sector and are well-positioned to 

continue doing so. 

Commenters supported allowing incremental emission reductions resulting from existing and 

new state requirements, programs, and measurements instituted after June 18, 2014 and prior to 

2020 to be credited toward compliance with both the interim and final state emission targets. 

Commenters added that early action credits should be provided for emission reductions resulting 

from the implementation of EE, RE, or any other action or measure that is undertaken post 2014 

interim period and prior to the start of the program because such actions will reduce emissions, 

would incentivize states to reduce emissions earlier, and would allow states to gradually 

implement RE, EE, and other emission reduction strategies which will allow for better planning 

and adjusting to changes in dispatch and consumption.

Commenters suggested that EPA allow states to bank emission reduction credits for new actions 

stemming from programs included in the state compliance plan and achieved between 2014 and 

2019. Commenters agreed that the earliest recognized date should coincide with the date of the 

proposed rule (June 18, 2014), while other commenters suggested January 2014 as the earliest 

recognized date.

Commenters supported allowing all cumulative energy efficiency savings realized as of the date

of proposal be credited to meeting the interim and final goals.

Commenters supported crediting actions made after the rule is final but before 2020. 

Commenters supported crediting actions before the CPP was proposed. 

Commenters recommended that EPA provide states with the flexibility to take credit for actions 

taken after the NOPR was issued and before 2020, and count the credit toward achievement of 

the states compliance obligation. Commenters added that this would ensure states have an 

incentive to reduce GHG prior to 2020 and would also prevent a dip in market activity in the 

renewable energy sector. Commenters recommended that EPA allow states that have achieved 

significant avoided emissions during 2014 to 2019 due to existing EE programs, receive credit 

under both a rate-based and mass-based for their achievements.

Commenters suggested that EPA should allow credit for new carbon reduction actions, including 

increasing existing policies, adopting new policies and deploying new facilities, taken after that 

date and before the plan performance period (2020) to count toward achievement of the state's 

carbon emission targets. Commenters suggested that measures such as new legislation, new 

regulations, executive orders, or municipal government or public utility commission approvals of 

integrated resource plan (IRP) elements undertaken between 2014 and 2020 would be eligible for 

early action credit. Commenters further supported the proposed distinction for existing 

renewable energy requirements to ensure that all existing renewable projects can generate 

electricity that can be used for compliance when the program starts in 2020.
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Comment 7: Comments stating that the EPA should allow states to take credit for past energy 

efficiency achievements published in the EIA-861

Response 7: The EPA disagrees with the commenter that all past EE achievements in the EIA861 should be credited. EPA’s approach to determining the CO2 emission performance rates and 

state goals that are achievable considering cost is a forward-looking approach that starts from the 

state of the electricity system in 2012. Some of those achievements after 2012 can be 

recognized to the extent they are still lowering emission in 2022 going forward, and to the extent 

their impacts can be recognized under the Clean Energy Incentive Program. The EPA recognizes 

the validity and importance of established programs, and the final rule contains two provisions 

that enable states to incentivize early investments in zero-emitting generation and demand-side 

EE. For more details on these programs, see section VIII.B and VIII.K of the preamble to the 

final rule.

The following are summaries of the specific public comments under this comment:

Commenters contended that EPA should recognize results of past EE achievements as published 

in EIA-861. 

Comment 8: Comments suggesting that EPA should give states credit for all emissions 

reductions made between the date the state plan is approved and 2020

Response 8: The final rule contains two provisions that enable states to incentivize early 

investments in zero-emitting generation and demand-side EE. 

First, states adopting rate-based plans may award ERCs to qualified providers that implement 

any eligible projects from 2013 onward for the quantified and verified MWh of generation or 

savings those projects provide in 2022 and subsequent years. Affected EGUs may use ERCs 

issued under each of these provisions for compliance with their assigned emission standards or 

bank the ERCs for use in any compliance period. In a mass-based context, similar efforts will be 

inherently reflected in the affected EGUs stack emissions in 2022 forward.

Second, the EPA has developed the Clean Energy Incentive Program, an optional program 

designed to reward investment in certain RE and demand-side EE projects that commence 

construction after the effective date of this rule and that generate MWh or reduce end-use energy 

demand during 2020 and 2021. Under this program, states may set aside allowances from their 

interim targets or generate early action ERCs (as defined in section VIII.K.2 of the final rule 

preamble), and allocate to eligible projects allowances or ERCs equivalent to each MWh 

generated or avoided. For more details on this program, see section VIII.B.2 of the preamble to 

the final rule.

The following are summaries of the specific public comments under this comment:

Commenters suggested that EPA should allow states to achieve compliance with interim goals 

beginning when the state's compliance plan is approved by EPA. Commenters stated that in 
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addition to benefitting early-acting states, these approaches would eliminate the proposal's 

incentive to delay investments in renewable energy and energy efficiency until 2020. 

Commenters stated that EPA should allow new renewable energy and energy efficiency actions 

taken after filing a state plan to be counted toward interim target compliance in 2020. 

Commenters added that credit should not be contingent on some future state plan. 

Commenters supported counting energy savings measures beginning in 2017 from policies and 

programs included in state plans, whether the policies and programs began prior to 2017 or after 

2017. Commenters explained that counting energy savings from measures installed starting in 

2017 towards each state's emissions rate goals is consistent with the Building Block 4 calculation 

used in establishing the emissions rate goals. Commenters added that counting measures would 

start after publication of the final rule, when EM&V requirements are defined and state plans are 

prepared at least on a preliminary basis. Commenters stated that eligible measures should be 

those that are adopted as part of policies or programs included in state plans. Commenters stated 

that by starting the counting of measures in 2017, states and utilities will have an incentive to 

ramp up energy efficiency policies and programs in the 2017-2019 time period, not just starting 

in 2020. Commenters added that States and utilities have already planned energy efficiency 

programs for 2015 and 2016 as a result of other state policies or goals and it is highly unlikely 

that these programs will be eliminated or cut back if the Clean Power Plan does not allow 

counting efficiency measures installed prior to 2017. Commenters concluded that if measures 

from eligible state and utility policies and programs are tracked and counted starting in 2017, 

energy savings credit from these measures should begin in 2020 as the EPA has proposed. 

Commenters stated that most efficiency measures installed during 2017-19 are long-lived and 

will provide substantial energy savings in 2020 and thereafter, and thus will contribute energy 

savings credits during the compliance period (e.g., if a measure with a 12 year lifetime is 

installed through a utility program in 2018, the utility would be able to count the savings over 10 

of the 12 years for purposes of Clean Power Plan compliance). Commenters also stated that 

States and utilities that want to realize substantial energy savings starting in 2020 will need to 

begin programs prior to 2020 given the time required to ramp up to high levels of program 

participation and energy savings. Commenters added that starting energy savings credits sooner 

than 2020 would have the undesirable effect of reducing the overall CO2 emissions reductions 

achieved by the Clean Power Plan, unless the CO2 emissions rate reduction targets are 

strengthened; i.e., the emissions rate targets are lowered.

Commenters believed that states that already implemented very aggressive RE and EE programs 

may have difficulties meeting interim goals even with credit for early actions under either 

crediting approach. Commenters stated that the first approach proposed by EPA would give 

credit for emissions reductions occurring during the plan period (2020-2029) "as a result of 

actions taken after a specified date" but before the plan June 18, 2014. Commenters were

concerned that EE savings for actions implemented after the June 2014 could be counted in the 

cumulative savings for 2020 and later, but those occurring before 2020 would not count towards 

compliance with interim goals. Even if June 2014 is selected for the start date of emissions 

savings actions, commenters stated that Arizona will have an inconsistency between their interim 

and final goals. Regarding the second approach, where credit is given for emission reductions 

occurring before 2020, commenters stated that this alternative is too amorphous for them to 

assess its potential impact on compliance with the interim goal with any degree of precision.
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Commenters noted that Arizona utilities were subject to and in compliance with ambitions RE 

and EE programs before EPA proposed the CPP, so therefore it is unlikely that Arizona could 

adopt new programs and achieve significant reductions under the new programs prior to 2020.

Commenters suggested the action start date be either after a final state plan is submitted to EPA, 

or after a specified date such as January 1, 2017. Commenters recommended allowing banking 

for early actions taken between the 2012 baseline period and 2020 to alleviate the emission 

reduction pressure of the interim compliance period. Commenters suggested allowing credit for 

actions taken back to 2013, immediately following the baseline year. Commenters requested that 

demand-side or other carbon savings beginning in 2011 (the mid-point of 2010-2012) be credited 

under the CPP. 

Several commenters supported allowing existing solar measures to receive credit for a limited 

time prior to the 2020 compliance period. Commenters explained that states should be allowed to 

bank MWh generated from the date their SIP is submitted, and that those credits be eligible for 

compliance purposes for 36 months from the date of the start of the compliance period. 

Commenters added that limited banking after SIP approval ensures that only measures included 

in approved SIPs are used for compliance and incentivizes states to submit SIPs for approval in a 

timely manner. Commenters stated that limiting banking to 2-3 years is aligned with best 

practices of most RPSs and regional markets which allow banking for 2-3 years without 

significantly reducing overall state goals.

Commenters suggested that EPA consider allowing states to demonstrate compliance in 2017, so 

states can take credit for efficiency savings in the years 2017-2019. Commenters added that 

energy savings in 2014 and 2015 are already occurring and activities for 2016 are already 

underway based on current standards and various state and utility programs. 

Comment 9: Comments suggesting that states may delay or suspend their own emission 

reduction programs if EPA does not allow credit for existing GHG emission reduction programs

Response 9: The EPA appreciates the commenters’ concerns, but do not believe states will delay 

or suspend their emission reduction programs, particularly to the extent these programs meet 

multiple goals and priorities of states, such as increasing the affordability of electricity and 

reductions in other air pollutants. Still, the EPA recognizes the validity and importance of 

established programs, and the final rule contains two provisions that enable states to incentivize 

early investments in zero-emitting generation and demand-side EE. For more details on these 

programs, see section VIII.B and VIII.K of the preamble to the final rule.

The following are summaries of the specific public comments under this comment:

Several commenters stated that failure to obtain credit for early actions would create an incentive 

for states to delay or suspend emission reduction measures so they will count for the compliance 

plan. 
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Commenters were concerned that if EPA does not provide credit for early action then any new 

state legislation or regulation to address CO2 emissions would be negatively impacted. 

Commenters believed that “failure to provide adequate recognition for these actions will upset 

those expectations and will undoubtedly discourage future forward looking actions from being 

taken as a result.” Commenters stated that in states where existing energy efficiency programs 

are set to expire ahead of the compliance period, decision makers may seek to postpone actions 

to renew these programs to ensure any resulting emission reductions are captured for the purpose 

of compliance with the state performance standard. Commenters added that emissions avoided in 

2015 are at least as valuable as those made in 2020 and added that allowing banking of credit 

would remove the incentive for delaying efficiency programs.

Commenters stated that counting emission reductions from 2020 through 2029 to meet the final 

targets work against the goal for reducing carbon intensity as it is less likely that reduction 

measures will be made prior to that time. 

Commenters contended that EPA should not develop a system that discourages early reductions, 

no matter how few they may be, and EPA must consider the timing of states needing to adopt 

programs and bring them online in order to start realizing reductions in 2020.

Commenters stated that EPA's proposed approach of not allowing state plans to take into account 

emissions reductions generated prior to 2020 discourages state and utility initiation of new 

policies and programs, as well as property owners and utilities from installing new projects,that 

are required beyond existing policy. Commenters continued that these entities have a perverse 

incentive to delay projects until the compliance period begins, which in turn threatens to reduce 

the overall environmental effectiveness of the rule. Commenters stated this disincentive is 

particularly pronounced for energy efficiency measures, which may have a limited credit life.

Commenters further noted that they have long supported recognition and encouragement of early 

emissions reductions. 

Commenters noted that the state of Michigan will meet its renewable portfolio standard and 

energy efficiency mandates by the end of 2015 and is considering new energy legislation for 

programs beyond 2015. Commenters stated the structure of the proposed 111(d) rule creates 

perverse incentives to delay implementation of new or existing RE or EE programs until 2017 or 

later since no credit under the EPA Building Block method would be given for reductions 

achieved from existing renewable and energy efficiency programs. 

Comment 10: Comments supporting allowing electric power suppliers that over-comply in any 

given year to bank the resulting RECs for compliance in subsequent years or be allowed to 

transfer the credit to other affected electric power generators for their compliance use under the 

program.

Response 10: In the final emission guidelines, states may award ERCs to qualified providers that 

implement any eligible projects from 2013 onward for the quantified and verified MWh of 

generation or savings those projects provide in 2022 and subsequent years. Affected EGUs may 

use ERCs issued under each of these provisions for compliance with their assigned emission 
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standards or bank the ERCs for use in any compliance period. In a mass-based context, similar 

efforts will be inherently reflected in the affected EGUs stack emissions in 2022 forward. For 

more details on the treatment of early actions, see section VIII.K of the preamble to the final 

rule.

The following are summaries of the specific public comments under this comment:

Commenters supported allowing electric power suppliers that over-comply in any given year to 

bank the resulting RECs for compliance in subsequent years. Commenters stated that this would 

allow power suppliers to vary their compliance activities to achieve the least-cost method of 

compliance.

Commenters contended that EPA should allow bankable credits for retired power plants that 

meet compliance obligations under section 111(d) program or be allowed to transfer the credit to 

other affected electric power generators for their compliance use under the program. 

Commenters contended that credit should be provided for all fossil-fuel power plants that 

shutdown on or after June 18, 2014. 

Comment 11: Comments suggesting that all carbon reductions under existing state programs 

should be counted toward compliance

Response 11: The final rule contains two provisions that enable states to incentivize early 

investments in zero-emitting generation and demand-side EE.

First, states adopting rate-based plans may award ERCs to qualified providers that implement 

any eligible projects from 2013 onward for the quantified and verified MWh of generation or 

savings those projects provide in 2022 and subsequent years. Affected EGUs may use ERCs 

issued under each of these provisions for compliance with their assigned emission standards or 

bank the ERCs for use in any compliance period. In a mass-based context, similar efforts will be 

inherently reflected in the affected EGUs stack emissions in 2022 forward.

Second, the EPA has developed the Clean Energy Incentive Program, an optional program 

designed to reward investment in certain RE and demand-side EE projects that commence 

construction after the effective date of this rule and that generate MWh or reduce end-use energy 

demand during 2020 and 2021. Under this program, states may set aside allowances from their 

interim targets or generate early action ERCs (as defined in section VIII.K.2 of the final rule 

preamble), and allocate to eligible projects allowances or ERCs equivalent to each MWh 

generated or avoided. For more details on this program, see section VIII.B.2 of the preamble to 

the final rule.

The following are summaries of the specific public comments under this comment:

Commenters supported any type of carbon reductions under state programs be counted toward 

compliance. Commenters contended that it was essential that early action crediting be uniformly 

available irrespective of the type or types of measures for which a state may seek credit. 

Commenters added that in particular, emission reduction measures based on utilization of natural 
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gas must be eligible for any early action crediting on equal terms with other potential emission 

reduction measures. Commenters stated that dictating how early emission reductions must be 

achieved would unnecessarily limit the incentive to take advantage of those measures that may 

carry the greatest immediate benefits. Commenters concluded that excluding certain types of 

early action measures would create arbitrary disparities on the basis of what sorts of early action 

are feasible or most prudent in each state, rendering the proposed emission targets more difficult 

or costly to achieve in some states than others. Commenters encouraged EPA to allow 

compliance strategies to expand beyond the utility sector where appropriate if they can be 

properly evaluated and credited, such as vehicle electrification.

Comment 12: Comments regarding the approach to crediting emission reductions for states with 

existing programs

Response 12: In order to ensure consistency with the calculation of CO2 performance rates and 

state rate-based CO2 goals in the final emission guidelines, and to avoid double-counting or 

inconsistent adjustment approaches across states, the final rule prescribes a general accounting 

approach states must use to adjust the CO2 emission rate of an affected source to reflect the 

MWh impacts of zero-emitting and low-emitting resource. Quantified and verified MWh impacts 

in 2022 going forward from qualifying zero-emitting and low-emitting resources implemented

after 2012 may be used by an affected EGU or state to adjust a CO2 emission rate, regardless of 

whether the renewable generation or demand-side EE savings occur inside or outside the state or

territory. 

Consistent with the EPA’s calculation of the CO2 emission performance rates and state ratebased CO2 goals in the final emission guidelines, the MWhs impacts are added to the 

denominator of an affected EGU’s reported CO2 emission rate, resulting in a lower, adjusted CO2

emission rate. The reported CO2 emissions reflect the actual emission reductions from the 

deployment of qualifying non-emitting and low-emitting resources across the regional grid.

Further adjustment of CO2 emissions, such as through the subtraction of emissions from the 

numerator, such as those estimated by applying an emissions factor to the MWhs, would double 

count CO2 emissions impacts across the grid and is, therefore, not permitted under the general 

accounting approach. 

These requirements align eligibility with certain factors and assumptions used in establishing the 

BSER, and by extension, application of the BSER to the performance levels established for 

affected EGUs in the guidelines. The strategies suggested by commenters are generally 

incompatible with these accounting requirements. For more information about specific methods 

to adjust the CO2 emission rate of an affected EGU to reflect RE and demand-side EE, see 

section VIII.K of the final rule preamble to the CPP. The rule describes the provisions related to 

proper quantification and verification of MWhs from renewable electricity generation or 

demand-side EE savings in section VIII.K of the final rule preamble.

The following are summaries of the specific public comments under this comment:
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Commenters stated that utilities with an emission rate program should be allowed to earn credit 

in the form of MWh of increased generation over the baseline from non-emitting resources and 

MWh savings from energy efficiency programs. Commenters stated that the resulting MWh 

would be available to be added to the denominator in calculating a state's emission rate during 

one or more compliance periods. 

Commenters suggested that credit could be provided by subtracting MWh from the denominator 

of the state rate calculation or total mass reduction requirement incrementally starting in 2017 

and depreciated at a rate of 10 percent over the following 10 years. Commenters provided an 

example of a state that has entities that have verifiably reduced CO2 emissions relative to 

business as usual by 10 MWh via a solar power system and energy efficiency measures since 

2005. Commenters suggested that the state should be allowed to calculate these measures into its 

state goals by adding the 10 MWh to its goal/target denominator starting in 2017 and decreasing 

that 10 MWh amount by 10 percent each year. 

Comment 13: Comments suggesting that the EPA may unintentionally exclude some state 

programs

Response 13: The EPA appreciates the commenters’ concerns. The EPA recognizes the validity 

and importance of established programs, and the final rule contains two provisions that enable 

states to incentivize early investments in zero-emitting generation and demand-side EE. For 

more details on these programs, see section VIII.B and VIII.K of the preamble to the final rule.

Consistent with other types of RE, new hydroelectric power generating capacity installed after 

2012 is eligible for use in adjusting a CO2 emission rate. Relicensed facilities are considered 

existing capacity and, therefore, are not eligible for use in adjusting a CO2 emission rate, unless 

there is a capacity uprate as part of the relicensed permit. In such a case, only the incremental 

capacity is eligible for use in adjusting a CO2 emission rate. See section VIII.K of the preamble 

to the final rule for more information.

With respect to nuclear generation, the EPA has finalized that generation from new nuclear units 

and capacity uprates at existing nuclear units will be eligible for use in adjusting a CO2 emission 

rate, just like new and uprated capacity RE. However, consistent with the reasons discussed in 

the preamble for not including the preservation of existing nuclear capacity in the BSER –

namely, that such preservation does not actually reduce existing levels of CO2 emissions from 

affected EGUs – preserving generation from existing nuclear capacity is not eligible for use in 

adjusting a CO2 emission rate. See section VIII.K of the preamble to the final rule for more 

information.

The following are summaries of the specific public comments under this comment:

Commenters expressed concern that EPA may be unintentionally excluding some programs, 

requirements or measures that should not be excluded. Commenters stated that the definition of 

existing should be relative to 2020 but not necessarily relative to today. Commenters stated that 

EPA should clarify that it does not intend to exclude programs, requirements, or measures that 

do not exist today. Commenters added that it should be clear that just like for hydropower, any 
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RE source in existence before 2020 would be considered eligible for inclusion in the plan 

regardless of when it became "on the books", was established, or was anticipated. Commenters

added that EPA acknowledges, with the exception of hydropower, the RE levels represent total 

RE, rather than incremental amounts above a baseline, so the RE generation can be supplied by 

any RE capacity regardless of its date of installation. Commenters assumed this to mean that 

provided Ohio EPA reaches its interim goal of 6% of total generation from RE and a final goal of 

11%, whether that RE was in existence prior to 2020, 2017 or even 2012, its generation can 

apply to the goal, including hydropower that was not even included in the goal setting, and 

requests EPA to clarify this requirement. Commenters added that EPA should clarify that 

existing nuclear beyond the 6% of at-risk generation should also be able to be applied as an 

existing measure. Commenters stated that because EPA is proposing states can take credit for 

"any additional new nuclear generating units or uprating of existing nuclear units, relative to a 

baseline of capacity. Commenters stated EPA must allow states to take credit for preserving 

greater than 6% of these zero-emitting sources.

Comment 14: Comments regarding existing mass-based emission budget programs

Response 14: The mass-based plan approaches in the final rule provide pathways that can 

accommodate existing mass-based emission budget programs such as RGGI and California's 

carbon reduction program.

First, the final rule provides a pathway for a mass-based emission standard plan with a marketbased emission budget trading program to meet the mass-based state goal for affected existing 

EGUs. Within this pathway, there is an option for a state to adopt an emission budget program

that includes sources beyond the existing EGUs that are regulated under CAA section 111(d), as 

long as it assures that the affected existing sources meet their mass-based state goals. Further, the 

EPA has calculated emission budgets for states that include the state’s mass-based goal along 

with a new source complement that can cover projected emissions from new sources. If the state 

adopts an emission budget under state law as that is equal to or more stringent than EPA’s 

calculated budget, this could be part of a presumptively approvable state plan in which the state 

could meet its obligation by showing its affected existing EGUs and new sources have met the 

total emission budget specified in the state plan.

If these emission standard plan approaches do not fit the structure of the existing state program 

that includes a mass-based emission budget, the state can adopt a state measures plan, in which 

the state can use a variety of measure to assure that they meet their mass-based state goal.

The plan approaches are discussed in section VIII.C of the final rule preamble of the CPP and 

additional considerations and requirements for mass-based state plans are provided in section 

VIII.J of the final rule preamble.

The following are summaries of the specific public comments under this comment:

Commenters requested EPA clarify the applicability of existing cap-and-trade programs, like 

California's or RGGIs, to EPAs Clean Power Plan. Commenters requested EPA consider and 

avoid the implementation of regulations that may penalize or otherwise unduly harm participants 
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of existing carbon programs that have acquired emission rights either through allowances or 

offsets. Commenters added that California's carbon reduction program incorporates a multisector cap-and-trade approach to reduce carbon emissions. Commenters requested EPA clarify 

whether the emissions targets, as laid out under the California program which incorporate 

reductions from other sectors in addition to electric generation, will be sufficient to qualify as 

reductions under the EPAs goals for the state, or alternatively provide some guidance on the 

conversion of a mass based target to the rate based targets under EPAs proposal including more 

specific guidance as to how a multi-sector accounting, such as in the case of California, could be 

bifurcated to show compliance under EPAs electricity sector proposal. Commenters supported 

using existing cap-and-trade programs under RGGI and California AB32 programs to be part of 

state plans and define an emission reduction trajectory for affected existing EGU's in those 

states. Commenters contended that EPA must ensure that compliance with the federal program 

complements compliance efforts now required for California State program, and that entities 

participating in state programs that meet federal requirements should be able to comply with 

federal programs with minimal additional procedural hurdles, focusing energy on emissions 

reductions rather than process. 

Commenters stated that a major component of California's carbon reduction program is the 

acceptability of California Carbon Offsets (CCO). Commenters stated that under California's 

current program, an offset is a credit that represents a reduction or removal of greenhouse gases 

by an activity that can be measured, quantified, and verified. Commenters stated that individual 

offset projects can be implemented to generate offset credits, which can then be sold and used by 

a covered entity as a compliance instrument in the Cap-and-Trade Regulation to satisfy up to 8% 

of its compliance obligation. Commenters stated that CCOs must be greenhouse gas reductions 

or removals that are real, additional, quantifiable, verifiable, permanent and enforceable and 

must go through a stringent set of standards. Commenters stated that each offset credit is equal to 

one MTCO2e. Commenters requested EPA clarify the applicability or acceptability of CCOs for 

compliance under the EPAs proposed rule. Commenters requested an official statement from the 

EPA as to whether carbon emissions offsets included in California, RGGI or any other state 

programs will be eligible as a mechanism of compliance under the proposed EPA rule. 

Commenters also requested EPA to explain what standards will be required for an offset 

program, submitted as part of a state’s SIP, to be an eligible method of compliance under the 

proposed EPA rule. Commenters contended that EPA should be clear that states (including 

California) that operate or may choose to operate an allowance system that extends beyond 

covered EGUs may still use that system as part of their compliance plans, provided that they can 

demonstrate that the system, operating in tandem with any other relevant state programs, will 

assure that the federal targets are met. Commenters stated that section 111 (d) sector-specific 

compliance ought not to disrupt the functioning of more complete economy-wide carbon control 

systems, provided those systems also demonstrate that section 111 (d) targets for the covered 

sector will be satisfied as part of their operations. Commenters expressed concern that 

uncritically adding federally enforceable obligations for covered entities, and requiring U.S. EPA 

review for all program amendments, would have significant implications for California's Section 

111 (d) compliance strategy and its Cap-and-Trade Program. Commenters stated that these 

implications include potentially limiting ARB's ability to efficiently amend the underlying 

regulations without potentially lengthy U.S. EPA approval processes and extending Clean Air 

Act citizen suit and permitting challenges for program participants. Commenters believed that 

ARB's Cap-and-Trade Program can play an integral role in our compliance strategy, and may be 
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the nucleus that furthers a market-based emissions trading program in the West within the 

context of the proposed rule. However, commenters contended that not every aspect of their Capand-Trade Program need be federally enforceable in order to show compliance with the targets 

proposed in the rule. Commenters suggested that EPA have a federally enforceable requirement 

that covered EGUs participate in the California market program would ensure Section 111(d) 

compliance. Commenters requested EPA confirm that such an approach, with sufficient 

analytical support, would be acceptable.

Comment 15: Comments suggesting that the EPA should not exclude existing non-renewable 

state energy programs

Response 15: The EPA appreciates the commenters’ concerns. The EPA recognizes the validity 

and importance of established programs, and the final rule contains two provisions that enable 

states to incentivize early investments in zero-emitting generation and demand-side EE. For 

more details on these programs, see section VIII.B and VIII.K of the preamble to the final rule.

First, states adopting rate-based plans may award ERCs to qualified providers that implement 

any eligible projects from 2013 onward for the quantified and verified MWh of generation or 

savings those projects provide in 2022 and subsequent years. Affected EGUs may use ERCs 

issued under each of these provisions for compliance with their assigned emission standards or 

bank the ERCs for use in any compliance period. In a mass-based context, similar efforts will be 

inherently reflected in the affected EGUs stack emissions in 2022 forward. This applies to RE, 

demand-side EE, incremental nuclear capacity, and any other measure eligible under the 

requirement specified in section VIII.K of the preamble.

The EPA notes that changes to affected EGUs since 2012 that have reduced their emission will 

be helping to reduce the affected EGU’s emissions be lower than they would have otherwise 

been.

The following are summaries of the specific public comments under this comment:

Commenters disagreed with excluding other non-renewable energy State programs that are 

equally capable of reducing CO2 emissions from the electricity sector. Commenters contended 

that EPA relied on EERS in the same manner as existing RPS when calculating State specific 

goals, and it was arbitrary and capricious to fail to give them the same status it has proposed for 

existing RPS programs. Commenters added that there was no reason to limit the applicability of 

existing State programs to those EPA relied in setting the State emission reduction targets. 

Commenters contended that EPA cannot rely on existing state programs and measures to bolster 

the assertion that the proposed goals are achievable, but deny states the right to use the 

reductions that are achieved by these measures to demonstrate compliance. Commenters added 

that EPA should make clear that the "existing measures" limitation in the proposal, if applicable 

to any measure in a state's compliance plan, is not applicable to actions that reduce affected unit 

emission before 2020, including unit closures, HRI projects, and changes in dispatch between 

existing coal-based units and natural-gas based units. Commenters agreed that existing measures 

should be allowed to count during the compliance period, and can help states meet interim 
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compliance goals set forth in the original proposal. However, commenters stated that during the 

comment period there has been significant confusion regarding exactly which existing renewable 

energy measures can be counted towards compliance and when credit will be given, and this 

confusion is already threatening potential emission reductions by slowing project development 

because states and EGUs are uncertain which actions will count towards compliance, and when 

these actions can count. Commenters requested that in the final rule the EPA more clearly state 

which actions can count towards compliance and when such actions count. 

Comment 16: Comments that the EPA should work with states to develop compliance 

pathways, equivalency determinations, and consistent evaluation and quantification methods for 

existing programs

Response 16: Throughout the comment period prior to this final rule, the states had several 

opportunities to provide EPA with their feedback on the rule, include through an extended 

comment period and many meetings with one or multiple states, as are reflected in records in the 

docket. In the development of the final emission guidelines’ state plan approaches, EM&V 

requirements and accounting approaches, the EPA has considered the needs of states and sought 

to ensure that existing programs were recognized and had a role in state plans. We will continue 

to work with states throughout the development, submittal and approval of state plans.

The following are summaries of the specific public comments under this comment:

Commenters suggested that EPA collaborate with states to develop compliance pathways and 

model rules for existing programs. As part of this recommendation, commenters suggested that 

EPA develop a procedure for allowing states to demonstrate equivalency with the emission 

guidelines that ensures reductions are achieved using consistent evaluation and quantification 

methods.

Comment 17: Comments suggesting that renewable energy programs should count toward 

compliance even when not part of an existing state requirement, program or measure.

Response 17: As part of the changes from proposal and final, generation from renewable energy 

capacity no longer needs to be specifically associated with an existing state requirement, 

program or measure under the rate-based emission standard plan approach. States implementing 

a rate-based emission standard plan can recognize and issue ERCs for any generation that meets 

eligibility requirements that is located in any rate-based state. These states can even recognize 

RE located in a mass-based state if it meets certain conditions (see the geographic eligibility 

discussion in section VIII.K and the interstate effects discussion in section VIII.L). If renewable 

energy is to be recognized under a rate-based state measures plan approach, it must be associated 

with a specified measures and the plan has to show that the specified measures will achieve the 

goal. Additional complementary measures not specified in the plan can be implemented that will 

reduce EGU CO2 emission and help the state achieve the mass CO2 goal, these need not be 

specified in the plan.
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The following are summaries of the specific public comments under this comment:

Commenters contended that EPA must not make the eligibility for existing renewable energy 

programs count toward compliance contingent on whether they are an existing "state 

requirement, program, or measure". Commenters contended that EPA has failed to account for 

the significant investments in renewable energy made by electric generating companies through 

their rate payers. Commenters believed that EPA’s failure to recognize these efforts affirmatively 

discourages company-driven environmental programs.

Comment 18: Comments suggesting that the EPA allow new state programs to count toward 

compliance not just state programs that were in effect when guidelines were proposed

Response 18: The EPA confirms that measure implemented after the date of proposal can 

contribute to meeting requirements under this final rule. States adopting rate-based plans may 

award ERCs to qualified providers that implement any eligible projects from 2013 onward for 

the quantified and verified MWh of generation or savings those projects provide in 2022 and 

subsequent years. Affected EGUs may use ERCs issued under each of these provisions for 

compliance with their assigned emission standards or bank the ERCs for use in any compliance 

period. In a mass-based context, similar efforts will be inherently reflected in the affected EGUs 

stack emissions in 2022 forward.

The following are summaries of the specific public comments under this comment:

Commenters recommended the EPA affirm that states can include in compliance plans emission 

reductions that occur during the compliance period without reference to whether these reductions 

were achieved by measures "on the books" at the time the guidelines were proposed.

Comment 19: Comments recommending that the EPA allow states with existing EE and RE 

programs be allowed to determine the method used to quantify emission reductions from these 

programs

Response 19: The EPA is providing states with flexibility regarding how they meet EM&V 

requirements. The EPA addresses considerations for incorporating CO2 emission reduction 

measures in state plans in section VIII.K of the preamble to the final rule. Evaluation, 

measurement, and verification (EM&V) requirements for RE are specifically addressed in 

section VIII.K.3. This section of EPA’s final emission guidelines require that all EE providers 

demonstrate that they will quantify and verify MWh savings using best-practice EM&V 

approaches. One way to make this demonstration is to use the presumptively approvable EM&V 

approaches specified in the proposed Model Rule in section IV.D.8. States may also submit other 

means of meeting the EM&V requirements so long as the state satisfactorily demonstrates in the 

state plan submittal that such alternative means of addressing requirements are as stringent as the 

presumptively approvable approach.
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The following are summaries of the specific public comments under this comment:

Commenters recommended that EPA allow those states with existing efficiency and renewable 

energy programs to continue to determine the methods used to measure, evaluate, and quantify 

current and future kilowatt-hours of energy savings and renewable energy production.

Commenters expressed concern that if EPA indicates that it will define or specify energy 

efficiency savings or renewable energy generation differently from the state's current approach, it 

could require changes to their programs, which could cause the activity to be stalled resulting in 

no carbon reductions due to uncertainty. Commenters concluded that if national approaches or 

standards are developed, states should be able to opt into such standards to the extent they are 

preferable, mature, and have been vetted. Commenters stated that measures to force uniformity 

by EPA may be counter-productive for states (such as Hawaii) that have unique constraints, 

requirements, or climates.

Comment 20: Comments suggesting that the EPA should compare state early emission reduction 

programs to the emissions standards for new natural gas plants or state’s interim emission rate if 

that is lower.

Response 20: The EPA appreciates the commenters’ suggestion. Due to the importance of early 

action, the EPA is recognizing eligible early actions in the same way as it is recognizing actions 

implemented during the performance period, with a zero MWh ERC for each MWh of zeroemitting generation and demand-side EE the early action produces in 2022 forward. 

Additionally, the EPA has developed the Clean Energy Incentive Program, an optional program 

designed to reward investment in certain RE and demand-side EE projects that commence 

construction after the effective date of this rule and that generate MWh or reduce end-use energy 

demand during 2020 and 2021. For more details on these programs, see section VIII.B.2 and 

VIII.K.2.e of the preamble to the final rule.

The following are summaries of the specific public comments under this comment:

Commenters suggested that EPA may wish to consider comparing early action in states 

employing rate or mass based programs against the emissions standard for new natural gas plants 

under section 111(b), or the states GHG emissions rate for the interim control period, whichever 

is lower. Commenters also suggested crediting states adopting mass-based programs based on 

how much they reduce emissions below their approved cap for the interim compliance period in 

conjunction with or in place of the first approach.

Comment 21: Comments requesting clarification on how existing state demand-side EE 

programs will be treated under the CPP

Response 21: The EPA received many comments suggesting that the EPA should recognize 

early actions for the emission reductions they provide prior to the performance period, including 

demand-side EE. The EPA recognizes the validity and importance of these perspectives, and as a 
217

result, the final rule contains two provisions that enable states to incentivize early investments in 

zero-emitting generation and demand-side EE. 

First, states adopting rate-based plans may award ERCs to qualified providers that implement 

any eligible projects, including demand-side EE, from 2013 onward for the quantified and 

verified MWh of generation or savings those projects provide in 2022 and subsequent years. 

Affected EGUs may use ERCs issued under each of these provisions for compliance with their 

assigned emission standards or bank the ERCs for use in any compliance period. In a mass-based 

context, similar efforts will be inherently reflected in the affected EGUs stack emissions in 2022 

forward.

Second, the EPA has developed the Clean Energy Incentive Program, an optional program 

designed to reward investment in certain RE and demand-side EE projects that commence 

construction after the effective date of this rule and that generate MWh or reduce end-use energy 

demand during 2020 and 2021. Under this program, states may set aside allowances from their 

interim targets or generate early action ERCs (as defined in section VIII.K.2), and allocate to 

eligible projects allowances or ERCs equivalent to each MWh generated or avoided. For more 

details on this program, see section VIII.B.2 of the preamble to the final rule.

The following are summaries of the specific public comments under this comment:

Commenters stated it is unclear how EPA will treat existing demand-side efficiency programs 

that yield efficiency improvements during the compliance window. 

Commenters stated that some state renewable power standards award utilities credits for energy 

efficiency kWh in excess of the allowable energy efficiency and noted that utilities are allowed 

to use the credits in a future year to meet requirements. Commenters asked if EPA addressed this 

type of system in the rule.

Comment 22: Comments proposing strategy for encouraging states to take early action

Response 22: The EPA acknowledges the comment, but is not creating a disincentive for states 

to delay action. The EPA recognizes the validity and importance of established programs, and 

the final rule contains two provisions that enable states to incentivize early investments in zeroemitting generation and demand-side EE. For more details on these programs, see section 

VIII.B.2 and VIII.K.2.e of the preamble to the final rule.

The following are summaries of the specific public comments under this comment:

Commenters thought that rather than allowing credits for early action, the EPA should encourage 

states to begin implementing emission reduction programs by including measures that create a 

disincentive for states to delay action. To accomplish this, commenters recommended an 

increased ramp-up rate assignment to states that had not met or exceeded the average U.S. total 

incremental or cumulative savings rates by year-end 2012. For these states, commenters

supported a targeted 0.38 percent rate of improvement in incremental annual savings per year, as 

opposed to the 0.2 percent rate proposed by EPA. Commenters noted that, in a mass-based 
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approach, a set-aside for energy efficiency could be used where the set-aside is larger in the first 

year(s) to accommodate several years of early crediting.

Comment 23: Comments suggesting that credit given for existing state programs must not 

reduce effectiveness of CPP

Response 23: The EPA received many comments suggesting that the EPA should recognize 

early actions for the emission reductions they provide prior to the performance period. The EPA 

recognizes the validity and importance of these perspectives, and as a result, the final rule 

contains two provisions that enable states to incentivize early investments in zero-emitting 

generation and demand-side EE. Both of these strategies maintain the effectiveness of the 

program while recognizing early action.

First, states may award ERCs to qualified providers that implement any eligible projects from 

2013 onward for the quantified and verified MWh of generation or savings those projects 

provide in 2022 and subsequent years. Affected EGUs may use ERCs issued under each of these 

provisions for compliance with their assigned emission standards or bank the ERCs for use in 

any compliance period. In a mass-based context, similar efforts will be inherently reflected in the 

affected EGUs stack emissions in 2022 forward. For more details on this treatment of early 

actions, see section VIII.K of the preamble to the final rule.

Second, the EPA has developed the Clean Energy Incentive Program, an optional program 

designed to reward investment in certain RE and demand-side EE projects that commence 

construction after the effective date of this rule and that generate MWh or reduce end-use energy 

demand during 2020 and 2021. Under this program, states may set aside allowances from their 

interim targets or generate early action ERCs (as defined in section VIII.K.2), and allocate to 

eligible projects allowances or ERCs equivalent to each MWh generated or avoided. For more 

details on this program, see section VIII.B.2 of the preamble to the final rule.

The following are summaries of the specific public comments under this comment:

Several commenters (were concerned that credit for early actions should not impact the 

effectiveness of the CPP. Commenters urged EPA to ensure that any credit given for early 

actions does not “erode the environmental integrity of the Clean Power Plan by crediting

"business-as-usual" actions.” Commenters recommended EPA strengthen the emission targets if 

early action credits are allowed. Commenters believed that the years between 2012 and 2020 

present a challenge for compliance crediting, since providing credit for emission reductions 

during this time encourages earlier actions by moving emission reductions earlier in time.

However, commenters were concerned "business-as-usual" emission reductions that occur 

during this time would have happened regardless of the Clean Power Plan.

Commenters encouraged EPA to balance credit for early action and credit or incentives to act 

between 2015 and 2020 with the overall stringency of the Clean Power Plan. Commenters

cautioned that if too much credit is provided for actions before 2020, the Clean Power Plan will 

result in too few activities to reduce carbon pollution after 2020. Commenters did not support 

recognition of additional early action without an increase in stringency. Commenters added that 
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stringency could be increased without recognizing additional early action. Commenters added 

that if stringency is significantly increased, they supported finding ways to recognize additional 

early action and provide incentives to act between 2015 and 2020. Commenters supported 

providing credit for early action, but contended that credit for prior actions should be left to the 

states to settle, but requested that any credit given for actions prior to 2012 do not result in an 

emission limit less stringent than what EPA requires.

Commenters believed states should not receive extra credit for energy savings occurring prior to 

2020 or from measures installed prior to 2020 because this would weaken the standards and 

result in lower emission reductions during the 2020-2030 time period. Commenters added that 

they would support EPA allowing for some emissions reduction credits for new or incremental 

actions that occur in the 2017-2019 time period after a state's carbon emission reduction plan is 

approved (e.g., for the expansion of energy efficiency programs in the 2017-19 period and the 

incremental energy savings for those years, relative to energy savings levels occurring in say the 

2014-16 period). Commenters also recommended emission reductions below the state goal level 

could be banked for use in the first compliance period.

Commenters urged that if early action credit is provided in the final rule EPA must ensure that 

such crediting does not erode the environmental integrity of the Clean Power Plan by crediting 

business-as-usual actions. Commenters added that crediting for early action should take place in 

the context of strengthened state targets that better reflect the full potential for emission 

reductions under the best system of emission reduction, as discussed above with respect to each 

of the building blocks and the formula change. Commenters recommended that EPA credit such 

actions in a manner that does not over-reward such actions and undermine the benefits of the 

Clean Power Plan.

Commenters stated that any adjustments to credit early actions should not increase the actual 

national carbon dioxide intensity of power generation in the later years of the period covered by 

the rule, beginning in 2025. Commenters recommended that any adjustments to credits for early 

action be tailored to the cumulative carbon dioxide emissions from 2016 through 2024 are no 

larger than would have been allowed absent the consideration of credit for early action. 

Commenters added that in order to provide maximum flexibility to states while meeting this 

objective, the enforceable standard for the period prior to 20125 should be formulated as a limit 

for each state on the average carbon dioxide emissions intensity during the entire period from 

2016 through 2024, leaving it to the state implementation plans to determine each stats specific 

glide path.

Commenters contended that unlimited banking or extended banking of emission reductions 

beyond a 3 year timeframe should not be permitted for states because it damages the ability of 

the Clean Power Plan to lock-in long-term emissions reductions and systematic long-term change 

by allowing states to increase actual emissions in compliance years. Commenters added that 

unlimited banking would let states accumulate credits before the first compliance period 

resulting in states lagging behind on actually cutting carbon emissions. Commenters added that 

the emission reduction targets would be weakened and the targets would no longer accurately 

reflect BSER.
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Commenters recommended allowing banking of avoided generation from energy efficiency that 

could be used during the present year or future years to comply with the rule but Commenters

urged EPA to develop limits on the type of EE measures that are given credit, the life of the 

measure, and the vintage of the credit to ensure only real savings are credited.

Commenters noted that allowing states to take credit for early action programs that would occur 

anyway would impact the overall emission reductions achieved by the Clean Power 

Plan. Commenters noted that giving compliance credit to actions taken between 2012-2020, 

which would have happened regardless of the Clean Power Plan creates a bank of compliance 

credits that will be used by that state during the compliance period in the place of other, beyond 

business‐as‐usual emission reducing actions. Commenters stated that the overall emission 

reductions achieved by the Clean Power Plan will be reduced the same amount as the credit. 

Commenters also stated that there are several highly compelling reasons to begin taking action 

now, including reductions in co-pollutants and job creation resulting from energy efficiency and 

clean energy investments. Commenters argued that States and companies can take advantage of 

the 5 years between the finalization of the standards and the beginning of the compliance period 

to gradually build out renewable generation and build up energy efficiency programs so that 

these resources are ready to deliver carbon reductions. If EPA does decide to provide early action 

credit, commenters urged the Agency to ensure that such crediting does not provide credit for 

business‐as‐usual actions. If crediting of early actions is allowed, commenters recommended the 

state goals should be strengthened in anticipation of that credit.

Comment 24: Comments suggesting that credit for early actions should be limited to private 

sector investments outside of state EE programs

Response 24: The EPA disagrees that credit for early actions should be limited to private sector 

investments outside of state EE programs, states are recognized in this final rule for their early 

actions to implement energy efficiency, as is supported by a significant number of comments. 

The EPA recognizes the validity and importance of established programs, and the final rule 

contains two provisions that enable states to incentivize early investments in zero-emitting 

generation and demand-side EE. For more details on these programs, see section VIII.B.2 and 

VIII.K.2.e of the preamble to the final rule.

The following are summaries of the specific public comments under this comment:

Commenters suggested that any credits for early energy efficiency investments should limited to 

private sector investments outside of state energy efficiency resource standards and that comply 

with approved MRV methodologies.

Comment 25: Comments suggesting that the EPA give states credit for early actions that reduce 

emissions below their state targets

Response 25: The EPA appreciates the commenters’ suggestion. Due to the importance of early 

action, the EPA is recognizing eligible early actions in the same way as it is recognizing actions 
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implemented during the performance period, with a zero MWh ERC for each MWh of zeroemitting generation and demand-side EE the early action produces in 2022 forward. 

Additionally, the EPA has developed the Clean Energy Incentive Program, an optional program 

designed to reward investment in certain RE and demand-side EE projects that commence 

construction after the effective date of this rule and that generate MWh or reduce end-use energy 

demand during 2020 and 2021. For more details on these programs, see section VIII.B.2 and 

VIII.K.2.e of the preamble to the final rule.

The following are summaries of the specific public comments under this comment:

Commenters stated that early action in addressing pollution is something that should be 

recognized and supported, and that they have long supported recognition of early action in 

context of the Clean Power Plan. However, commenters stated that there are complex questions 

to resolve on how to properly accomplish this recognition. Commenters stated that the proposed 

framework does not provide for assessment of past emission reduction performance, and that 

states and companies that have already transitioned to lower carbon and energy efficiency are 

closer to full deployment of BSER than others. Therefore, commenters suggested that EPA 

should also consider clarifying that states that go beyond their targets would receive credit for 

those actions under future updates of the carbon pollution standards for power plants.

Commenters added that credits for renewable generation and energy efficiency programs that 

exceed what is required to meet a states goal during a compliance period should be allowed to be 

banked for use in a subsequent compliance period.

Comment 26: Comments suggesting that early actions should be credited above 100 percent

Response 26: The EPA disagrees that early actions should be credited above 100 percent. Due to 

the importance of early action, the EPA is recognizing eligible early actions in the same way as it 

is recognizing actions implemented during the performance period, with a zero MWh ERC for 

each MWh of zero-emitting generation and demand-side EE the early action produces in 2022 

forward. Additionally, the EPA has developed the Clean Energy Incentive Program, an optional 

program designed to reward investment in certain RE and demand-side EE projects that 

commence construction after the effective date of this rule and that generate MWh or reduce 

end-use energy demand during 2020 and 2021. For more details on these programs, see section 

VIII.B.2 and VIII.K.2.e of the preamble to the final rule.

The following are summaries of the specific public comments under this comment:

Commenters suggested the value of early energy efficiency investments be credited at a rate 

above 100 percent due to the higher value of near-term CO2 reductions. Commenters noted than 

the Synthesis Report of the Fifth Assessment Report, the Intergovernmental Panel on Climate 

Change (IPCC) noted that: "Inertia in the economic and climate systems and the possibility of 

irreversible impacts from climate change increase the benefits of near-term mitigation efforts 

(high confidence). Delays in additional mitigation or constraints on technological options limit 

the mitigation options and increase the long-term mitigation costs as well as other risks that 
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would be incurred in the medium to long term to hold climate change impacts at a given level." 

(http://www.ipcc.ch/pdf/assessment-report/ar5/syr/SYR_AR5_LONGERREPORT.pdf (p.87)). 

Commenters believed that by giving a higher credit to early actions, the EPA will encourage 

states to accomplish their CO2-reduction goals even faster while simultaneously discouraging 

utilities from putting existing and planned energy efficiency policies and programs on hold.

Comment 27: Comments suggesting alternatives credit banking for states that take early action

Response 27: The EPA received many comments suggesting that the EPA should recognize 

early actions for the emission reductions they provide prior to the performance period. The EPA 

recognizes the validity and importance of these perspectives, and as a result, the final rule 

contains two provisions that enable states to incentivize early investments in zero-emitting 

generation and demand-side EE. 

First, states may award ERCs to qualified providers that implement any eligible projects from 

2013 onward for the quantified and verified MWh of generation or savings those projects 

provide in 2022 and subsequent years. Affected EGUs may use ERCs issued under each of these 

provisions for compliance with their assigned emission standards or bank the ERCs for use in 

any compliance period. In a mass-based context, similar efforts will be inherently reflected in the 

affected EGUs stack emissions in 2022 forward. For more details on this treatment of early 

actions, see section VIII.K of the preamble to the final rule.

Second, the EPA has developed the Clean Energy Incentive Program, an optional program 

designed to reward investment in certain RE and demand-side EE projects that commence 

construction after the effective date of this rule and that generate MWh or reduce end-use energy 

demand during 2020 and 2021. Under this program, states may set aside allowances from their 

interim targets or generate early action ERCs (as defined in section VIII.K.2 of the final rule 

preamble), and allocate to eligible projects allowances or ERCs equivalent to each MWh 

generated or avoided. For more details on this program, see section VIII.B.2 of the preamble to 

the final rule.

The following are summaries of the specific public comments under this comment:

Commenters noted their preference for credit banking approach, but suggested some alternative 

approaches EPA could use, including starting the compliance period for states in 2017 or 2018, 

while maintaining the business-as usual emission rate for states until 2020. Commenters stated 

that this approach would allow states to recognize actions implemented before 2020, but would 

not penalize states that do not have opportunities for such pre-2020 abatement. Commenters

further suggested that this approach could be applied to all states, or offered on an "opt-in" basis.

Comment 28: Comments suggesting early action credits cannot completely ease concerns over 

NGCC ramp rate, and the EPA should either phase in or eliminate interim goals.
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Response 28: The EPA respectfully disagrees. We are providing states with substantial 

flexibility as to how they structure those plans to achieve the 111(d) requirements. The flexibility 

includes, for example, the choice of approaches, trading, time to develop plans, additional time 

before the start of the interim performance period (postponed from 2020 until 2022), and the 

ability to shift emission rate achievement between performance periods. In response to additional 

analysis and many comments, we have modified the proposal and RIA – the establishment of 

CO2 emission reduction standards is regionally based. The Building Blocks are not prescriptive, 

and states may consider local circumstances as they develop their plans, including system 

reliability, the need for ancillary services other regulatory requirements and infrastructure. See 

sections V.A, V.D, VIII.A, VIII.C and VIII.G of the final rule preamble of the CPP and Chapter 

3 of the GHG Mitigation Measures TSD for the CPP Final Rule supporting the final CPP. 

Additionally, the EPA recognizes the validity and importance of established programs, and the 

final rule contains two provisions that enable states to incentivize early investments in zeroemitting generation and demand-side EE. For more details on these programs, see section 

VIII.B.2 and VIII.K.2.e of the preamble to the final rule.

The following are summaries of the specific public comments under this comment:

Commenters noted that while crediting early action could provide some relief to the concerns 

they expressed about the ramp rate of NGCC, they did not see early action and changes to 

Building Block 2 as necessarily interchangeable. Commenters suggested that crediting early 

actions is only a partial solution to easing the effect of the "emissions cliff" for late-acting states, 

and suggested that EPA, either eliminate interim goals, or at a minimum, phase in both building 

blocks 1 and 2 when calculating goals for the interim period. Commenters stated that EPA 

should not be concerned that using both approaches will make early acting states' interim goals 

too lax, because all states will still be required to meet the same final goals and will thus have to 

install emission reduction measures during the interim period.

Comment 29: Comments stating that allowing credit for early reductions would incentivize 

states and utilities to accelerate implementation of RE and EE programs

Response 29: The EPA recognizes the validity and importance of early reductions, and as a 

result, the final rule contains two provisions that enable states to incentivize early investments in 

zero-emitting generation and demand-side EE. 

First, states may award ERCs to qualified providers that implement any eligible projects from 

2013 onward for the quantified and verified MWh of generation or savings those projects 

provide in 2022 and subsequent years. Affected EGUs may use ERCs issued under each of these 

provisions for compliance with their assigned emission standards or bank the ERCs for use in 

any compliance period. In a mass-based context, similar efforts will be inherently reflected in the 

affected EGUs stack emissions in 2022 forward. For more details on this treatment of early 

actions, see section VIII.K of the preamble to the final rule.
224

Second, the EPA has developed the Clean Energy Incentive Program, an optional program 

designed to reward investment in certain RE and demand-side EE projects that commence 

construction after the effective date of this rule and that generate MWh or reduce end-use energy 

demand during 2020 and 2021. Under this program, states may set aside allowances from their 

interim targets or generate early action ERCs (as defined in section VIII.K.2), and allocate to 

eligible projects allowances or ERCs equivalent to each MWh generated or avoided. For more 

details on this program, see section VIII.B.2 of the preamble to the final rule.

The following are summaries of the specific public comments under this comment:

Commenters stated that providing credit for early reductions will incentivize states, utilities and 

generators to accelerate the timetable for developing renewable resources, leading to even more 

climate change benefits before the interim requirements take effect and would provide a tangible 

reward to industry leaders who have promoted the use of renewable energy, while maintaining 

the stringency of the final requirements.

Commenters stated that providing a few years of credit would incentivize additional new RE 

deployment that might otherwise not get built or built as quickly.

Commenters contended that EPA should provide limited banking for carbon reduction actions 

taken after January 1, 2017, and before the plan performance period begins. Commenters stated 

that this would help ensure that states have an incentive to engage in carbon reduction measures 

prior to that period and get a jump on being better positioned to achieve their final compliance 

goals.

Commenters stated that allowing pre-2020 reductions would incentivize utilities and states to 

reduce their emissions earlier resulting in earlier benefits to the environment. Commenters added 

that in the case of mass-based programs, states should also be able to quantify easily the tonnage 

reductions achieved by qualifying early actions undertaken prior to the start of the program in 

2020.

Comment 30: Comments suggesting that regulators can use the experience gained from existing 

state GHG emission reduction programs to develop and implement their state plans

Response 30: The EPA agrees with the commenters. When developing the framework for state 

plans, the EPA took into account the programs that states have already implemented that reduce 

GHG emissions, and the EPA has provided specifics regarding how many existing state 

programs can fit under state plan requirements. For more information on state plans, see sec. VIII 

of the preamble.

The following are summaries of the specific public comments under this comment:

Commenters stated that regulators would gain valuable insight and experience on how to run 

GHG emission reduction programs as well as evaluate, monitor, and verify resulting reductions. 
225

Commenters concluded that with this experience, programs can be modified and made more 

effective during the actual compliance period.

Comment 31: Comments suggesting that the EPA should allow limited banking of credits for 

early actions for a period of 36 months

Response 31: The EPA has developed the Clean Energy Incentive Program, an optional program 

designed to reward investment in certain RE and demand-side EE projects that commence 

construction after the effective date of this rule and that generate MWh or reduce end-use energy 

demand during 2020 and 2021. Under this program, states may set aside allowances from their 

interim targets or generate early action ERCs (as defined in section VIII.K.2), and allocate to 

eligible projects allowances or ERCs equivalent to each MWh generated or avoided. This 

program allows for a limited number of ERCs or allowances to be awarded for early action with 

unlimited banking, while maintaining stringency and ensuring early development of RE and 

demand-side EE. For more details on this program, see section VIII.B.2 of the preamble to the 

final rule. 

The following are summaries of the specific public comments under this comment:

Commenters suggested allowing for limited banking, recommended that states should be allowed 

to bank MWh generated from the date their SIP is submitted, and that those credits be eligible for 

compliance purposes for 36 months from the date of the start of the compliance period. 

Commenters further stated that limiting banking to 3 years is aligned with best practices of most 

RPSs and regional markets which allow banking for 3 years without significantly reducing 

overall state goals. While commenters supported limited banking, they believed that unlimited 

banking or extended banking of emission reductions beyond a 3 year timeframe should not be 

permitted for states, as extended or unlimited banking would undermine the effectiveness of the 

CPP. Additionally, commenters noted, extended or unlimited banking creates distortions in the 

market by allowing states and EGUs to choose not to create new renewables until late in the 

compliance period or only create new renewables early on. 

Comment 32: Comments suggesting that the EPA should work with NACAA and states to 

develop a system of crediting early actions taken by states to reduce GHG emissions

Response 32: The EPA recognizes the validity and importance of established programs, and the 

final rule contains two provisions that enable states to incentivize early investments in zeroemitting generation and demand-side EE. For more details on these programs, see section 

VIII.B.2 and VIII.K.2.e of the preamble to the final rule. The EPA also notes that comments 

from NACAA and the states informed the development of this final rule.

The following are summaries of the specific public comments under this comment:
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Commenters suggested EPA work with NACAA and the individual states to address the issue of 

crediting early actions.

Comment 33: Comments suggesting the EPA should allow RGGI to keep its current 3-year 

block compliance period.

Response 33: The state plan approaches offered in this final rule offer sufficient flexibility that 

to accommodate specific program elements of RGGI. While the interim and final plan 

performance periods do not align with RGGI’s current three-year control periods, if the RGGI 

participating states choose, they could include the RGGI program as a state measure under a state 

measures plan type. This plan type would not require alignment of RGGI control periods with 

the interim and final plan performance periods under the emission guidelines. The state plan 

types are discussed in section VIII.C. of the preamble to the final rule. Mass-based state plan 

approaches using emission budget trading programs are discussed in section VIII.J.2 of the 

preamble to the final rule.

The following are summaries of the specific public comments under this comment:

Commenters stated EPA should permit RGGI to keep its current 3-year block compliance period 

rather than a 3-year rolling compliance period, as long as the RGGI states can demonstrate that 

the program will achieve the required levels of stringency on the timeframe required in the final 

emission guideline. 

Comment 34: Comments suggesting that EPA should work with states to approve inclusion of a 

CCR.

Response 34: The state plan approaches offered in this final rule offer sufficient flexibility that 

they can accommodate the specific program components included in RGGI, such as a costcontainment reserve (CCR). If the RGGI participating states choose to retain elements that could 

functionally expand the CO2 emission budget of the program, such as a CCR or use of GHG 

offsets, the RGGI program could be submitted as a state measure under a state measures plan 

type. The state plan types are discussed in section VIII.C. of the preamble to the final rule. Massbased state plan approaches using emission budget trading programs are discussed in section 

VIII.J.2 of the preamble to the final rule.

The following are summaries of the specific public comments under this comment:

Commenters stated RGGI uses a cost-containment reserve to mitigate increases in allowance 

prices. Commenters said if the states choose to include a Cost Containment Reserve (CCR) 

going forward in their 111(d) plans, EPA should work with states to approve inclusion of a CCR 

so long as the plans meet the required stringency levels in the final 111(d) guideline irrespective 

of the deployment of the CCR. 
227

Comment 35: Comments suggesting that the EPA should allow RGGI states to address the issue 

of banked allowances.

Response 35: The final emission guidelines provide for the banking of CO2 allowances, both 

within the interim and final plan performance periods, and from the interim plan performance 

period to the final plan performance period. The state plan types are discussed in section VIII.C. 

of the preamble to the final rule. Mass-based state plan approaches using emission budget trading 

programs are discussed in section VIII.J.2 of the preamble to the final rule. Section VIII.J.2 

discusses the treatment of banking of allowances under the emission guidelines.

The following are summaries of the specific public comments under this comment:

Commenters stated EPA should allow the RGGI states to address the issue of banked allowances 

as they prepare for compliance with the Clean Power Plan. Commenters said during the 2012 

RGGI program review process, the RGGI states devised a system of interim allowance 

adjustments 3 that deals with the private bank of allowances in such a way that it preserves the 

environmental integrity of the RGGI cap while ensuring that the value of privately held 

allowances is not diminished. Commenters said they recommend that EPA allow the RGGI states 

to replicate this approach in order to account for the private bank of allowances that exists as the 

region begins compliance with the Clean Power Plan in 2020. Commenters said in order to 

ensure that privately held allowances from years prior to 2020 do not inflate the RGGI cap, the 

RGGI "base budget" for years 2020-2029 will require a reduction equivalent to the private bank 

of allowances. Commenters said if, for example, the private bank consists of 50 million 

allowances at the end of 2019, each year's base budget during the ten year period from 2020-

2029 would be reduced by five million tons. Commenters said following the 2020-2029 interim 

compliance period, the RGGI states should be allowed to reassess the private bank of allowances 

and adjust the RGGI base budget accordingly for years 2030-2034 in order to preserve the value 

of privately held allowances. 
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5.10 TREATMENT OF NEW FOSSIL FUEL-FIRED EGUS

This section addresses comments on the Treatment of New Fossil Fuel-fired EGUs that are not 

affected units under section 111(d); in particular, comments on whether and under what 

circumstances emissions from new units are factored into compliance determinations and 

emission projections for mass-based and rate-based plans.

Commenters have raised a number of issues related to this subsection which are organized by 

topics (comments) below. Responses are provided for these topics.

Comment 1: Comments suggesting states that employ the rate-based plan should be allowed to 

include megawatts from new NGCC capacity in calculating compliance.

Response 1: New NGCC units are not allowed to be used to adjust CO2 emission rates at 

affected EGUs in state plans under a rate-based emission standard approach. Permitting new 

NGCC generation to qualify for ERCs would provide an incentive to shift generation from 

affected to non-affected sources (i.e., leakage). See section VII.C and VIII.K of the final rule 

preamble.

The following are summaries of the specific public comments under this comment:

Commenters stated that states should be free to include any measures they deem appropriate, 

consistent with the CAA, as part of their section 111(d) plan, and should be given wide latitude 

to decide how to address new NGCC capacity for purposes of calculating compliance under 

111(d) plans. Commenters noted that states that employ the rate-based approach should be 

allowed to include megawatts generated from newly constructed units in the denominator for the 

state's rate. Commenters also noted that states that employ the mass-based approach should not 

include emissions from newly constructed units in the program at all.

Commenters stated that states should be allowed the option of including new natural gas power 

plants as part of meeting rate-based requirements.

Commenters agreed with EPA that, under a mass-based plan, emissions from new NGCC would 

not and should not be accounted for when demonstrating compliance and that new NGCC units 

would not be affected units under Section 111(d). Commenters argued that under a rate-based 

plan, any emission rate reductions at affected EGUs, resulting from substitution of new NGCC 

generation for higher-emitting generation by existing EGUs, would also automatically be 

reflected in emission rate changes from affected EGUs and a state would not need to include 

enforceable provisions for new NGCC in its plan. Therefore emissions and generation from new 

NGCC capacity, commenters noted would not need to be accounted for when demonstrating 

compliance. Commenters argued that states should however have the discretion to allow an 

entity that must demonstrate compliance to include the emissions and generation from any new 

NGCC capacity in its demonstration without subjecting the new NGCC capacity to any Section 

111(d) requirements. Commenters suggested the accounting would be done by adding the 

emissions from any new NGCC capacity to the emissions of the affected units for which a 
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compliance demonstration is being made or by adding the MWh generated by any new NGCC 

capacity to the denominator of the equation that accounts for all other generation (or avoided 

generation) being used to calculate the entity's emission rate.

Comment 2: Comments suggesting states should be allowed to use beyond-compliance emission 

reductions from new units.

Response 2: New NGCC units are not allowed to be used to adjust CO2 emission rates at 

affected EGUs in state plans under a rate-based emission standard approach. Permitting new 

NGCC generation to qualify for ERCs would provide an incentive to shift generation from 

affected to non-affected sources (i.e., leakage). See section VII.C and VIII.K. of the final rule 

preamble of the CPP.

In mass-based states, there is a requirement for state plans to demonstrate how the state is going 

to address concerns regarding potential increased emissions from new NGCC units as a result of 

shifting generation from affected to non-affected sources (i.e., Leakage). The EPA is giving 

mass-based states several pathways to address new sources and potential leakage. See section 

VII.C and VIII.J of the final rule preamble of the CPP.

New NGCC units are not covered by section 111(d) requirements.

The following are summaries of the specific public comments under this comment:

Commenters suggested that EPA provide credit for any amount that a new EGU exceeds the 

performance levels established through CAA section 111(b), regardless of whether CCS is 

involved or what type of unit is involved. Commenters noted that, under a rate based limit, the 

credit would be obtained by including the new EGU as an affected EGU in the compliance 

calculation. Commenters stated that under a mass based limit, the new EGU would not be 

included as an affected EGU in the compliance calculation. However, commenters added, the 

tons emitted by affected EGUs would be reduced by an amount equal to the product of the 

amount the new EGU emission rate fell below its section 111(b) based performance standard and 

the generation of the new EGU during the compliance period.

Several commenters recommended the EPA allow states to use emission reductions achieved by 

new units under section 111(b) towards compliance with the section 111(d). Commenters noted 

that EPA should make clear that states are free to find and use other similar incremental emission 

reductions, in addition to the example provided by EPA regarding the installation of CCS on 

page 34,924 of the proposal.

Commenters stated that they agree with the proposed compliance measure of using NGCC 

generators to comply with existing source standards.

Commenters stated that GHG reductions from new plants covered under 111(b) that are reduced 

below emissions limits would be creditable towards reductions required for 111(d) plants.
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Comment 3: Comments suggesting lack of coordinated implementation on whether to include 

new generating units could distort electricity markets.

Response 3: In mass-based states, there is a requirement for state plans to demonstrate how the 

state is going to address concerns regarding potential increased emissions from new NGCC units

as a result of shifting generation from affected to non-affected sources (i.e., Leakage). States 

with mass-based emission standards have several options or pathways to address new sources 

and the potential for emission leakage. See section VII.C and VIII.J of the final rule preamble of 

the CPP. However, new NGCC units are not covered by section 111(d) requirements.

New NGCC units are not allowed to be used to adjust CO2 emission rates at affected EGUs in 

state plans under a rate-based emission standard approach. Permitting new NGCC generation to 

qualify for ERCs would provide an incentive to shift generation from affected to non-affected 

sources (i.e., leakage). See section VII.C and VIII.K of the final rule preamble of the CPP.

Because the EPA is taking steps to address the potential for leakage in mass- and rate-based 

states, we do not believe new generating capacity will result in a distortion of the markets.

The following is a summary of this specific public comment:

Commenters said that the states' discretion as to whether to include new generating units in their 

implementation plans could exacerbate market distortions, including between new and existing 

natural gas combined cycle (NGCC) units. Commenters indicated that states will have an 

incentive to either include or exclude new sources in their target depending on their rate goal 

relative to EPA's GHG standard for new generating units.

Comment 4: Comments suggesting states should count only net emission reductions from new 

sources towards 111(d) compliance.

Response 4: New NGCC units are not allowed to be used to adjust CO2 emission rates at 

affected EGUs in state plans under a rate-based emission standard approach. Permitting new 

NGCC generation to qualify for ERCs would provide an incentive to shift generation from 

affected to non-affected sources (i.e., leakage). See section VII.C and VIII.K of the final rule 

preamble of the CPP.

In mass-based states, there is a requirement for state plans to demonstrate how the state is going 

to address concerns regarding potential increased emissions from new NGCC units as a result of 

shifting generation from affected to non-affected sources (i.e., Leakage). The EPA is giving 

mass-based states several pathways to address new sources and potential leakage. See section 

VII.C and VIII.J of the final rule preamble.

The following is a summary of this specific public comment:

Commenters stated EPA should only permit states to count net carbon emission reductions from 

new carbon-emitting generation toward Section 111(d) compliance in order to prevent overcounting of emission reductions. Commenters indicated that states may choose to build new 
231

natural gas plants, convert existing coal plants to natural gas facilities, or increase the capacity 

utilization of existing natural gas facilities to comply with state targets, and that while this new 

generation may displace power from higher carbon-intensive sources, new carbon emissions will 

also be created. Commenters indicated that emissions from new sources must be factored in, 

otherwise net emission reductions may not be accurate. Commenters also said failing to account 

for emissions from new sources could create a perverse incentive to replace existing generation 

with equally carbon-intensive new generation, resulting in significant costs, but no actual 

reduction in carbon emissions, and potentially causing an increase in net emissions over time. 

Comment 5: Comments suggesting that the EPA should credit total emission reductions not 

incremental reductions from new low- or zero-carbon sources.

Response 5: Only measures installed after 2012 are eligible emission reduction measures in ratebased emission standard state plans. See sections V.A. and V.E. on the BSER and Building 

Block 3, and section VIII.K of the final rule preamble of the CPP on general eligibility 

requirements for resources used to adjust a CO2 emission rate.

New fossil fuel-fired units (i.e., NGCC and IGCC with CCS) are not allowed to be used to adjust 

CO2 emission rates at affected EGUs in state plans under a rate-based emission standard 

approach. Permitting new fossil generation to qualify for ERCs would provide an incentive to 

shift generation from affected to non-affected sources (i.e., leakage). See section VII.C and 

VIII.K of the final rule preamble of the CPP. Existing EGUs that retrofit CCS capacity are 

allowable measures, assuming they do not become modified or reconstructed units under section 

111(b). See section VIII.I of the final rule preamble of the CPP.

The following is a summary of this specific public comment:

Commenters supported being able to use new generation sources as a compliance option, 

however commenters were concerned that the treatment of CCS as a compliance option is treated 

less favorably than other types of new generation. Commenters said that it appears that new 

renewable energy generators would be allowed to fully count their emission reductions towards 

compliance with the existing source rule, but that not all other new zero- or low-emitting 

generation technologies are granted similar treatment. Commenters indicated that allowing only 

the incremental emission reductions that are below the new source limits from new fossil fuelfired generating units that incorporate CCS to count towards compliance is confusing and could 

discount the substantial emissions reductions that CCS project could deliver relative to 

uncontrolled coal or gas-fired EGUs. Commenters stated that reductions in CO2 should be treated 

equivalently across all compliance options and that EPA should promote all forms of new, clean 

generation.

Comment 6: Comments requesting clarification regarding if mass from new units is added to the 

mass-limit
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Response 6: In mass-based states, there is a requirement for state plans to demonstrate how the 

state is going to address concerns regarding potential increased emissions from new fossil fuelfired units as a result of shifting generation from affected to non-affected sources (i.e., leakage).

The EPA is giving mass-based states several pathways to address new sources and potential 

leakage, one of which is to take an adjusted emission performance standard that takes emissions 

from new units into account. See section VII.C and VIII.J of the final rule preamble of the CPP.

The following is a summary of this specific public comment:

Commenters asked if in the event that EPA chooses to include new units in the section 111(d) 

program whether the mass the state is allowed to emit will be increased by the amount the new 

unit would be allowed to emit under the NSPS.

Comment 7: Comments requesting clarification on how new units built after the effective date 

are treated for compliance purposes

Response 7: It depends on the type of state plan approach. New NGCC units are not allowed to 

be used to adjust CO2 emission rates at affected EGUs in state plans under a rate-based emission 

standard approach. Permitting new NGCC generation to qualify for ERCs would provide an 

incentive to shift generation from affected to non-affected sources (i.e., leakage). See section 

VII.C and VIII.K of the final rule preamble of the CPP.

In mass-based states, there is a requirement for state plans to demonstrate how the state is going 

to address concerns regarding potential increased emissions from new NGCC units as a result of 

shifting generation from affected to non-affected sources (i.e., Leakage). The EPA is giving 

mass-based states several pathways to address new sources and potential leakage. See section 

VII.C and VIII.J of the final rule preamble of the CPP.

The following is a summary of this specific public comment:

Commenters asked for clarification on when, if ever, NGCC units built after the effective date of 

the 111(d) rule would be subject to 111(d) instead of 111(b), and how emissions from those units

would be treated for compliance purposes.

Comment 8: Comments requesting clarification on how new fossil-fuel plants, new NGCC 

plants and nuclear generation are factored into compliance

Response 8: New NGCC units are not allowed to be used to adjust CO2 emission rates at 

affected EGUs in state plans under a rate-based emission standard approach. Permitting new 

NGCC generation to qualify for ERCs would provide an incentive to shift generation from 

affected to non-affected sources (i.e., leakage). See section VII.C and VIII.K of the final rule 

preamble of the CPP.
233

In mass-based states, there is a requirement for state plans to demonstrate how the state is going 

to address concerns regarding potential increased emissions from new NGCC units as a result of 

shifting generation from affected to non-affected sources (i.e., Leakage). The EPA is giving 

mass-based states several pathways to address new sources and potential leakage. See section 

VII.C and VIII.J of the final rule preamble of the CPP.

Nuclear capacity installed after 2012 (i.e., new, uprated, and under construction capacity) is 

considered an eligible measure. See section VIII.K of the final rule preamble of the CPP for how 

incremental generation from new and uprated nuclear power is addressed in relation to other 

sources and as approvable measure to include in rate-based state plans.

The following is a summary of this specific public comment:

Commenters asked if actions at new fossil-fuel plants could be credited towards compliance. 

Commenters asked specifically if new NGCC or nuclear generation could be added to average 

down the emission from coal-fired plants.

Comment 9: Comments requesting clarification on if new EGU generation is included in 2030 

generation estimates.

Response 9: The modeling of 2030 electricity generation does include new EGUs needed to 

meet increasing demand. Generation and CO2 emissions from new EGUs that are not covered 

under CAA section 111(d) are not included in the state goal calculations. For more details on 

state goal calculations see section VI and VII of the final rule preamble of the CPP.

The following is a summary of this specific public comment:

Commenters asked if in estimating the 2030 generation whether states may subtract generation 

from new fossil fuel EGUs that are planned to go on-line after 2020.

Comment 10: Comments requesting clarification on how to set the mass goal if new sources are 

included in compliance plans.

Response 10: In mass-based states, there is a requirement for state plans to demonstrate how the 

state is going to address concerns regarding potential increased emissions from new NGCC units 

as a result of shifting generation from affected to non-affected sources (i.e., Leakage). The EPA 

is giving mass-based states several pathways to address new sources and potential leakage, one 

of which is to take an adjusted emission performance standard that takes emissions from new 

units into account. See section VII.C and VIII.J of the final rule preamble of the CPP.

The following is a summary of this specific public comment:
234

Commenters stated that if EPA allows new generators to be included in compliance plans, EPA 

would add projected generation from those sources into generation from affected EGUs, which is 

multiplied by the rate goal to get the mass goal. Commenters indicated that total emissions and 

cost consequences of including new generators are not known ex-ante, since they depend upon 

whether states adopt rate or mass goals. Commenters also indicated that new natural gas 

combined-cycle and nuclear generators are particularly important.

Comment 11: Comments suggesting that new units subject to 111(d) that outperform NSPS 

targets should be allowed to use the margin over compliance to satisfy emission rate targets.

Response 11: The EPA disagrees with the commenter that emission reductions from new (or

modified or reconstructed) EGUs may be used as measures under the emission guidelines. New 

units are covered under the CAA section 111(b) final Standards of Performance for Greenhouse 

Gas Emissions from New Stationary Sources: Electric Utility Generating Units rule, which we 

are finalizing concurrently with this rulemaking. A key concern under the final emission 

guidelines for existing sources is leakage to new units that are not covered by the emission 

guidelines. Emissions leakage, or increased CO2 emissions due to increased utilization of 

unaffected sources, is contradictory to objectives of this rule and should, therefore, be 

minimized. Allowing affected EGUs to adjust their emission rates as a result of lower-emitting 

new NGCC units not covered under this section 111(d) rule would not mitigate leakage 

concerns, and could even exacerbate the situation. Consequently, new EGUs covered under the 

CAA section 111(b) rule are not allowable measures in state plans because the EPA believes it 

would result in increased emission leakage. See Section VIII.K.1.b of the final rule preamble of 

the CPP.

The following are summaries of the specific public comments under this comment:

Commenters argued that new units subject to 111(d) that outperform NSPS targets should be 

allowed to use the margin over compliance to satisfy existing unit emission rate compliance 

targets.

Comment 12: The commenters stated that EPA needs to provide a clear timeline for when new 

gas plants will become part of the existing fleet for purposes of 111(d) compliance.

The following are summaries of the specific public comments under this comment: 

The commenters stated that providing a clear timeline for when new gas plants will become part 

of the existing fleet for purposes of 111(d) compliance (assuming not accounted for in the target 

and compliance initially) is critical to utility resource decisions in the near term. The commenters 

stated that utilities and stakeholders need to have as much clarity as possible about the potential 

carbon regulatory implications of adding new gas generation. The commenters noted that 

certainty that new gas will become subject to carbon constraints in the future will help utilities 
235

and stakeholders work together to use diverse supply and demand--side resources to produce a 

clean and reliable electric system.

Response 12: New fossil fuel-fired units are covered under the CAA section 111(b) final 

Standards of Performance for Greenhouse Gas Emissions from New Stationary Sources: Electric 

Utility Generating Units rule, which we are finalizing concurrently with this rulemaking. New 

NGCC units are not affected EGUs under this CAA section 111(d) final rule. For the EPA's 

response to this comment see section V.A and V.D of the final rule preamble of the CPP. For 

more on standards for new fossil fuel-fired EGUs see the final section 111(b) rule for New 

Sources.
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5.11 CONSIDERATION OF A FACILITY'S "REMAINING USEFUL LIFE" IN 

APPLYING STANDARDS OF PERFORMANCE

This section discusses comments on the way in which the emission guidelines address the CAA 

section 111(d)(1) provision to consider a facility's Remaining Useful Life and "other factors" in 

promulgating section 111(d) regulations.

Commenters have raised a number of issues related to this subsection which are organized by 

topics (comments) below. Responses are provided for these topics. 

Comment 1: Comments requesting that states be required to analyze the remaining useful life of 

each existing source, and that the EPA consider recent pollution investments in analyzing 

remaining useful life. 

Response 1: The EPA has structured the guidelines to enable states to consider remaining useful 

life and other factors in designing their state plans and EGU emission standards.

Regarding the suggestion that the EPA require the state to demonstrate that it has analyzed the 

remaining useful life of each EGU, the EPA does not believe that section 111(d) authorizes EPA 

to issue such a mandate. The statute merely requires EPA’s guidelines to allow for state 

consideration of remaining useful life in regulating under section 111(d) In this respect, compare 

the language of 111(d)(1) (“permit the State” to consider remaining useful life) with 111(d)(2) 

(“Administrator shall” consider remaining useful life). In addition, section 116 of the Act allows 

states to impose more stringent requirements on affected EGUs than the minimum requirements 

of these guidelines, even after considering remaining useful life. However, the EPA anticipates 

that sources and states will discuss such issues in the context of plan development.

See section VIII.G.1 of the final rule preamble of the CPP for additional EPA response to this 

comment.

In regard to comments that the EPA itself should factor into the remaining useful life analysis

recent investments in pollution controls that EGUs have made to comply with EPA rules, the 

EPA observes that section 111(d) calls for the EPA’s guidelines to permit states to consider 

remaining useful life. The law would require the EPA to consider remaining useful life of 

sources in promulgating a federal plan to achieve the required emission reductions in the event 

that a state failed to submit an approvable plan; however, a federal plan is not part of this 

regulatory action.

The following are summaries of the specific public comments under this comment:

Commenters indicated that recent regulations with near-time deadlines, such as the Regional 

Haze and MATS Rules, have spurred electricity generators to make difficult decisions on 

whether to install controls or retire units, and that EPA should respect those decisions and factor 

the underlying agreements and significant expenditures triggered by other regulations into the 
237

remaining useful life analysis. Several commenters suggested that the following regulatory 

language be added as a fifth provision to 40 CFR section 60.5740(11), "supporting material" to 

include "materials demonstrating the state's analysis of the remaining useful life of the existing 

source to which such standard applies." Commenters indicated that this language would address 

situations where affected EGUs have made recent emission control retrofits or have significant 

remaining book life to minimize costs to customers while continuing to structure plans that meet 

EPA's 2030 emission targets.

Comment 2: Comments suggesting the EPA must uphold the authority and flexibility to 

consider remaining useful life, and the proposal does not properly provide for consideration of 

remaining useful life.

Response 2: The EPA agrees that the law requires the EPA’s guidelines to permit state in 

applying a standard of performance to any particular source under a section 111(d) plan to take 

into consideration, among other factors, the remaining useful life of the source to which the 

standard applies. The final guidelines meet this requirement as explained in preamble section 

VIII.G.1. and the legal memorandum

The following are summaries of the specific public comments under this comment:

Commenters indicated that EPA must uphold the authority and flexibility of CAA section 111(d) 

that allows state plans to consider the remaining useful life of the existing source, that the 

proposal did not do so, and/or that the rule is structured in a way that prevents consideration of

remaining useful life.

Comment 3: Comments suggesting that the proposal does not allow states to adjust performance 

standards to account for source-specific circumstances consistent with section 111(d).

Response 3: The EPA disagrees with the thrust of this comment, which was to argue that the 

statute does not permit the EPA to require states to achieve the goals. In fact, the statute merely 

says that EPA’s regulations shall permit states to take into consideration, among other factors, 

remaining useful life when applying standards of performance to any particular existing source. 

These emission guidelines satisfy that requirement, as detailed in the final rule preamble section 

VIII.G.1.

The following are summaries of the specific public comments under this comment:

Commenters noted that the inherent flexibility in section 111(d) allows states to evaluate the 

viability of control technologies on a case-by-case basis and consider other factors such that 

states could strike an appropriate balance between emission reductions and the economic 

interests of regulated facilities, their investors, and their customers by adjusting the generally 

applicable standards of performance to account for source-specific circumstances.
238

Comment 4: Comments suggesting that states should be allowed to consider remaining useful 

life in setting performance standards and provide relief for EGUs from the state goals.

Response 4: These comments are addressed in final rule preamble section VIII.G.1 and the legal 

memorandum.

The EPA adds that, contrary to commenters’ assertions, the EPA did not propose to bar states 

from considering remaining useful life on grounds that BSER already allows for its 

consideration. The EPA has revised the goals since proposal and believes that they are 

achievable. 

The following are summaries of the specific public comments under this comment:

Commenters said that a meaningful consideration of remaining useful life requires that EPA 

provide relief for EGUs from the state performance goals, that states are authorized by the CAA 

to make these types of decisions, and that EPA is ignoring the requirement that states be allowed 

to consider remaining useful life. Commenters said that the approach of imposing very strict 

state goals negates meaningful consideration of remaining useful life. Commenters said 

the approach of not allowing states to consider remaining useful life in setting standards of 

performance, because the BSER already allows for consideration of remaining useful life, 

contradicts the plain language of the CAA and is unsupportable both on a legal and policy basis.

Comment 5: Comments suggesting that state authority to evaluate remaining useful life allows 

deviation from the emission guidelines.

Response 5: The EPA understands that the law requires the EPA’s guidelines to permit a state, 

in applying a standard of performance to any particular source under a section 111(d) plan, to 

take into consideration, among other factors, the remaining useful life of the source to which the 

standard applies. The final guidelines meet this requirement as explained in final rule preamble 

section VIII.G.1. Subsection (d) of that preamble section explains why remaining useful life and 

other facility-specific factors do not warrant adjustments in the guidelines’ performance rates and 

state goals. Commenters misstate the language and structure of section 111(d)(1) and the Act.

First, section 111(d)(1) (unlike section 111(d)(2)) does not state that remaining useful life must 

be taken into account. Second, section 111(d)(1) does not provide direct authority to states to 

taken into consideration remaining useful life in any way that states wish. Third, EPA is not 

usurping state authority; instead EPA is promulgating emission guidelines under which states 

submit state plans, and these guidelines permit states to take into consideration remaining useful 

life. Finally, the notion that EPA cannot disapprove a state plan that fails to meet the 

requirements of these guidelines because of some supposed reservation of state authority is 

inconsistent with the structure of the Act and (for example) recent case law regarding EPA action 

on regional haze SIPs, as detailed in the legal memorandum. 

The following are summaries of the specific public comments under this comment:
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Commenters stated that the law is clear that the remaining useful life of EGUs must be taken into 

account. Commenters indicated that state authority to evaluate the remaining useful life cannot 

be usurped. Commenters stated that EPA cannot mandate that it will reject a state plan that 

deviates from the emission guidelines when it exercises its statutory authority to account for 

remaining useful life

Comment 6: Comments suggesting that states may set a less stringent standard through 

consideration of remaining useful life - proposal is inconsistent with the statute.

Response 6: The EPA understands that the law requires the EPA’s guidelines to permit a state, 

in applying a standard of performance to any particular source under a section 111(d) plan, to 

take into consideration, among other factors, the remaining useful life of the source to which the 

standard applies. The final guidelines meet this requirement as explained in final rule preamble 

section VIII.G.1. and the Legal Memorandum. The EPA agrees that a state may choose to 

provide a less stringent emission standard, otherwise modify, or postpone emissions standards 

for an individual facility so long as the state’s plan meets the requirements of this guideline.

EPA’s guideline does not dictate that a state require any particular plant to reduce operations.

The following are summaries of the specific public comments under this comment:

Commenters argued that the CAA gives states specific authority to take into account the 

remaining useful life of existing units, and quoted the following sentence from the CAA: "when 

applying a standard of performance to any particular source under a plan submitted... to take into 

consideration, among other factors, the remaining useful life of the existing source to which such 

standard applies." Commenters argued that the CAA does not limit states to providing less 

stringent standards to plants that only have a few years left to operate but also allows states to 

modify or postpone regulation of CO2 for plants that have long operating lives remaining or 

where applying the standards would result in an expensive, unwarranted plant closure that could 

compromise electric reliability and result in far higher consumer costs. Commenters stated that 

forcing plants with useful remaining operating lives to reduce operations, even to the point of 

becoming uneconomical or closing, is completely contrary to the statutory requirement that 

directs the EPA to take into account "the remaining useful lives of the sources in the category of 

sources to which such standard applies." Commenters stated that section 111(d)(2) also directs 

that the EPA procedural regulations "shall permit the state" to take "other factors" into account in 

addition to remaining useful life. Commenters stated that the EPA has inappropriately eliminated 

the statutory authority allowing states to take important factors into account concerning specific 

plant conditions in developing the state plan.

Comment 7: Comments suggesting that states could consider "remaining useful life" consistent 

with the statute if allowed to establish their own emission standards.
240

Response 7: The guidelines provide states the flexibility to establish their own emissions 

standards for EGUs and to alter the requirements and timing among different EGUs.

The following is a summary of this specific public comment:

Commenters indicated that states could exercise their statutory obligation to consider "remaining 

useful life" if they are allowed to establish their own performance standards and compliance 

schedules. 

Comment 8: Comments suggesting that the EPA does not have the statutory authority to deem 

the consideration of remaining useful life unnecessary.

Response 8: Commenters misconstrued the intended meaning of the statement in the proposal 

preamble. Section VIII.G.1 of the final rule preamble, especially subsection (c), explains how the 

guidelines permit states to consider remaining useful life and other factors in applying standards 

of performance to individual facilities in their state plans.

The following is a summary of this specific public comment:

With regard to the preamble language at 79 FR 34,925 that indicates that "the flexibility 

provided in the state plan development process adequately allows for consideration of the 

remaining useful life. . . and, therefore. . .separate application of the . . . provision by states in the 

course of developing and implementing their CAA section 111(d) plans is unnecessary" 

commenters stated that EPA does not have the statutory authority to deem this consideration 

"unnecessary."

Comment 9: Comments suggesting the different approach of these guidelines does not allow the 

EPA to alter state authority to account for remaining useful life.

Response 9: The EPA believes that these commenters’ statements do not accurately reflect the 

final guideline. The final guideline permits states to consider remaining useful life in applying 

emissions standards to individual EGUs as they design their state plans, as explained in final rule 

preamble section VIII.G.1. The EPA believes that the flexible approach taken in this guideline 

enables states to consider remaining useful life in ways that are not available when the EPA 

guideline establishes presumptive emissions standards for individual sources, and that therefore 

the EPA is finalizing its proposal that the provisions in 60.24(f) should not apply to the class of 

facilities covered by these guidelines, as explained in final rule preamble section VIII.G.1 and 

the legal memorandum.

The following are summaries of the specific public comments under this comment:

Commenters disagreed with EPA that the different nature of these emission guidelines from the 

usual presumptive standards allows EPA to alter state authority to account for remaining useful 
241

life. Commenters stated that the CAA provides EPA with no discretion to limit or prohibit states 

from taking remaining useful life and other factors into account in applying a standard of 

performance to individual sources.

Comment 10: Comments suggesting source-specific remaining useful life determinations from 

governing boards should be considered.

Response 10: These comments are addressed in final rule preamble section VIII.G.1 and the 

legal memorandum.

The EPA adds that, contrary to commenters’ assertions, the EPA did not propose to bar states 

from considering remaining useful life on grounds that BSER already allows for its 

consideration. The EPA has revised the goals since proposal and believes that they are 

achievable.

The following are summaries of the specific public comments under this comment:

Several commenters indicated that state and board utility regulatory commission determinations 

on remaining useful life should be discussed in the regulatory text and included as supporting 

information in the final rule. Commenters indicated that while the 1975 rule language could 

apply to older units, the remaining useful life of the newer units (such as those that incorporated 

BACT) should be analyzed individually by state plans. Commenters indicated that without 

recognition and discussion of unit-specific analysis in the EPA rule, prior determinations of 

remaining useful life and prior economic decision on electricity rates could be ignored, which 

could lead to unintended consequences, including stranded assets. Commenters said that state 

utility regulatory commission or FERC hearings on stranded assets may result.

Comment 11: Comments suggesting the proposal satisfies the remaining useful life provision.

Response 11: We agree with the commenter. Please see final rule preamble section VIII.G.1 for 

a detailed discussion of how the flexibilities in this rule permit states to take into consideration 

remaining useful life without relaxing state emission goals.

The following are summaries of the specific public comments under this comment:

Commenters indicated that the proposal satisfies the "remaining useful life" provision, and that it 

is appropriate for the "remaining useful life" to be considered as states design their plans and 

their demonstration of performance standard achievability. Commenters stated that the statute 

does not require that states have discretion to relax state emission goals. Commenters explained 

that the average state emission targets and flexible compliance options enable states to adjust for 

source-specific circumstances and fulfill the "remaining useful life" provision in a manner 

consistent with their "best system of emission reduction" analysis.
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Comment 12: Examples of regulatory options to address remaining useful life, including 

market-based systems and averaging programs.

Response 12: The EPA agrees that averaging and trading programs, and legally enforceable 

retirement dates at the end of a plant’s useful life, are examples of regulatory mechanisms that 

can help avoid unreasonable costs for EGUs with a limited remaining useful life. 

The following are summaries of the specific public comments under this comment:

Several regulatory options that address "remaining useful life" were suggested by commenters.

Commenters stated that market-based or averaging programs were recommended since these 

programs allow older, inefficient facilities to choose to operate for several years and comply 

through the purchase of allowances or through averaging with more efficient facilities. 

Commenters stated that a declining system-wide cap on emissions to the level of a new plant was 

suggested for states that use a system-wide mass-based approach, whereby market signals would 

determine whether aging systems actually retire or whether the required emission reductions are 

achieved from other plants that reduce their generation. 

The use of legally enforceable retirement dates that precede the end of the compliance period 

was suggested by several commenters. Commenters provided examples of coal plant retirement 

commitments in Regional Haze plans for Washington, Oregon, and Wyoming. Commenters 

indicated that these types of commitments should be allowed to achieve section 111(d) 2030 

goals. Commenters also noted that EPA has allowed regulated units to use retirement as a 

compliance tool in NPDES.

Comment 13: Comments suggesting that requiring compensating emission reductions is 

improper.

Response 13: The EPA disagrees with commenters’ characterization of the guidelines. These 

comments are addressed by section VIII.G.1 of the final rule preamble, particularly subsection 

(e) titled “Response to key comments on remaining useful life.”

The following are summaries of the specific public comments under this comment:

Commenters indicated that extracting further emission reductions from other sources to make up 

for the less stringent standards applied as a result of "remaining useful life" considerations is 

inconsistent with section 111(d). Commenters indicated that transferring a facility's emission 

reduction burden to another facility or requiring the reductions through external measures is 

impermissible. Commenters indicated that EPA has no authority to hold other sources to a 

standard that is "better than BSER" because of EPA's interpretation of how to account for 

remaining useful life.

Several commenters indicated that addressing any adjustments to a particular facility's 

requirements with "compensating emission reductions" is unprecedented, an improper restraint 

under section 111(d), and commenters said that EPA cited no legal authority to allow for this 
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deviation from its established framework. Commenters stated that Congress intended the 

consideration of remaining useful life to be undertaken with respect to the specific circumstances 

of individual sources, not a balancing exercise relating to the overall emissions reductions from a 

source category. Commenters noted that EPA allows states to utilize variances for individual 

sources, but not to "compensate" for such adjustments through tighter restrictions on other 

sources. Both commenters quoted language that focuses on individual units from 60.24(f) and 

preamble language in support of their position.

Commenters indicated that requiring a state to identify and impose additional obligations on 

another source beyond those required by the best system of emission reduction is unlawful. 

Commenters indicated that the consideration of remaining useful life and other relevant factors is 

a one-way ratchet that provides relief to sources that cannot achieve BSER, and that EPA turns 

that approach on its head by prohibiting a state from providing such relief to a specific facility 

unless it can identify another facility to "punish" by requiring additional emission reductions to 

offset that relief.

Comment 14: Comments expressed concerns that proposed state goals did not provide states 

with sufficient flexibility to allow for compensating emission reductions.

Response 14: In response to public comments, the EPA revised its approach to BSER and goalsetting in the final rule, as explained in final rule preamble sections V through VII. These 

changes will ensure that EGU performance rates and state goals are achievable considering cost. 

A more detailed response to concerns that states would not have adequate flexibility in practice 

to consider remaining useful life, and stranded assets, is included in final rule preamble section 

VIII.G.1, the legal memorandum, and the July 2015 docket memo titled “Stranded assets 

analysis.”

The following are summaries of the specific public comments under this comment:

Commenters indicated that extracting emission reductions from or over-controlling other EGUs 

or other entities assumes there is enough room within each state's goal to make such 

accommodations. Commenters provided more specific examples: 

• Commenters stated that the emission rates for Virginia are set so low that 

compliance options are extremely limited, and that Virginia is unable to take 

advantage of the 10-year averaging flexibility for the Interim Mandatory Goal.

• Commenters stated that even if all the building blocks were successfully 

implemented to the fullest extent in the commenter's service territory, the 

commenter's CO2 emission rate could not meet the proposed limit. Commenters 

indicated the entire state of Florida could not meet the limit utilizing the currently 

existing affected sources. 

• Commenters said that because the state of Arizona must re-dispatch all of its coalfired generation under building block 2 to comply with the state's interim goal, the 

state actually has no flexibility to consider the remaining useful lives of Arizona's 
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coal-fired fleet. Commenters stated that EPA's application of its building blocks 

and BSER to Arizona leaves insufficient room for the state to make any 

accommodations to consider the remaining useful life factor.

• Commenters said that as a consequence of EPA's flawed assumption that all 

emission reductions from Building Blocks 1 and 2 could be achieved at the start 

of the 10-year interim compliance period, almost all of the emission reductions 

that the rule ultimately requires must be achieved in the first year, which leaves 

Pennsylvania with little or no flexibility other than to rely on coal unit closures.

• Commenters said that the severity and early onset of emission reductions leave 

Oklahoma with no flexibility for implementing a portfolio of compliance options, 

and that Oklahoma will be forced to prematurely close coal-fired generating 

assets.

Commenters stated that even if the emission reduction targets in individual building blocks can 

be achieved in the abstract, there is no guarantee that they can be met in the aggregate, 

particularly with any significant margin for error.

Several commenters stated that the flexibility EPA grants the states to take into remaining useful 

life is illusory. Commenters noted that only a small fraction of the reductions presume that coal 

units continue to operate at present levels through their useful lives, and that the reductions from 

Building Blocks 2-4 come from substituting gas, renewable energy, nuclear energy, and energy 

efficiency for the output from the shutdown coal EGUs. Commenters stated that in practice, any 

meaningful consideration of remaining useful life would cause a state to miss its EPA-mandated 

emission reduction target. Commenters stated that the four building blocks are so stringent that 

they leave states with very little leeway to depart from the basic design set out be EPA.

Commenters also indicated that the flexibility EPA claims to give the states is nonexistent, and 

commenters noted that as a result, EPA's position that states need not deviate from the standards 

based on remaining useful life is unfounded. Commenters stated that the proposal does not 

provide states with a "range of options," that there is no flexibility in EPA's BSER, that there are 

no other options, and that each building block is so strict and burdensome that it does not provide 

states the ability to trade between requirements. Commenters stated that by using the building 

block system the CPP has restricted the flexibility of the states to address remaining useful life.

Commenters stated that some states will not be able to cut enough emissions to reach EPA's 

mandates, and that they should be allowed to maximize existing resources without fear of 

stranding any investments.

Comment 15: Comments stating the proposal was unclear how remaining useful life was taken 

into account in setting emission rates.

Response 15: The EPA’s definition of BSER and method for establishing EGU performance 

rates and state goals are described in preamble sections V through VII. The EPA structured the 
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guidelines to enable states, in designing their state plans, to consider remaining useful life of 

individual units in applying standards of performance to individual EGUs, as explained in final 

rule preamble section VIII.G.1. and the legal memorandum.The EPA affirms states’ ability to 

include non-BSER measures in final rule preamble sections V.A.1 and V.A.6, as well as in the 

preamble discussion of remaining useful life in section VIII.G.1. 

Commenters recommended that in establishing measures that will result in the closure or 

displacement of existing coal-fired EGUs, EPA must consider the remaining useful lives of those 

sources in compliance with section 111(d).

The following are summaries of the specific public comments under this comment:

Commenters indicated that the proposed rule did not provide adequate detail on how state 

emission rates were set taking into account the remaining useful life of a generating unit, and 

requested that the final rule include a clear option for states to take the remaining useful life of a 

unit into consideration when establishing state plans. Commenters requested that EPA affirm 

states' ability to include non-BSER measures in compliance plans.

Comment 16: Comments suggesting coal plant retirements will force rate payers to pay for the 

remaining life of a retiring plant and a replacement plant.

Response 16: In response to public comments, the EPA revised its approach to BSER and goalsetting in the final rule, as explained in preamble sections V through VII. These changes will 

ensure that the EGU performance rates and state goals are achievable considering cost. See also

final rule preamble section VIII.G.1 and the legal memorandum, which reference a July 2015 

docket memo titled “Stranded assets analysis.” The analysis shows that the national EGU 

performance rates in the final guidelines can be met without the retirement of affected EGUs 

before the end of their book life, and without the retirement of affected EGUs before the end of 

the book life of capital-intensive pollution control retrofits installed on those EGUs. Thus, the 

final CO2 performance rates and state goals provide state with sufficient flexibility to address 

stranded asset concerns.

The following are summaries of the specific public comments under this comment:

Commenters estimated that at least 90% of their States coal-based electric generating capacity 

will retire and rate payers will be forced to pay for the life that was remaining and for the 

replacement plant.

Comment 17: Comments suggesting states may establish a standard that is different than BSER 

based on remaining useful life - proposal inconsistent with statute.

Response 17: The EPA disagrees with the commenter. As explained in section VIII.G.1 of the 

final rule preamble, these guidelines differ from previous ones that set individual source
246

emission limits and allowed those limits to be relaxed on a case-by-case basis. However, the 

statute does not—contrary to commenter’s suggestion—explicitly require that states be permitted 

to relax limits as the means for taking into account remaining useful life. Instead, it says that the 

guidelines must permit states, in applying standards of performance, to take into consideration 

remaining useful life. We note that, even under the uniform rates, the possibility of trading does 

give relief to sources based on their remaining useful life. For additional detail, see final rule

preamble section VIII.G.1 and the legal memorandum.

The following are summaries of the specific public comments under this comment:

Commenters stated that EPA has failed to consider the CAA requirement that states are charged 

with developing a standard of performance, taking into account remaining useful life, for their 

individual units based on EPA's BSER determination. Commenters stated that when establishing 

a technology requirement through BSER, EPA must assure it is technically and economically 

achievable, and in turn states are afforded the ability to consider factors associated with 

remaining useful life, and when necessary establish a standard of performance that is achievable 

but different than the BSER. Several commenters indicated that states should be allowed to 

adjust the standard for an individual unit, rather than an average across all units, to account for 

remaining useful life.

Commenters said that EPA's proposed approach in addressing remaining useful life clearly 

violates the statute and indicated that EPA has overstepped its authority under section 111(d) 

since building blocks 2-4 do not constitute a system of emission reduction that can be applied to, 

implemented at, or undertaken by EGUs. Commenters said that the CAA explicitly requires a 

different kind of flexibility for remaining useful life that the proposed rule does not incorporated.

Commenters said that the problem with EPA's proposed rule is that section 111(d) requires states 

to apply standards of performance for affected sources to affected sources on a source-by-source 

basis, with the possibility of relief based on source-specific factors.

Comment 18: Comments suggesting the EPA's reasoning that states can rely on the proposed 

rules' general flexibility is flawed and results in stranded investments.

Response 18: The EPA is not relying on the inherent flexibility of the guidelines as a substitute 

for the requirement that states fully consider remaining useful life; the EPA is stating that the 

flexibility of the guidelines enables states to consider remaining useful life in designing their 

plans. Section VIII.G.1 of the final rule preamble of the CPP and the legal memorandum explain 

how the guidelines permit states to consider remaining useful life. These documents also 

demonstrate that the CO2 performance rates and state goals in the final emission guidelines leave 

states the flexibility in practice to consider remaining useful life, as well as the potential for 

stranded assets. See EPA’s July 15 memorandum titled “Stranded Assets Analysis,” which

shows that the national EGU performance rates in the final guidelines can be met without the 

retirement of affected EGUs before the end of their book life, and without the retirement of 

affected EGUs before the end of the book life of capital-intensive pollution control retrofits 
247

installed on those EGUs. Thus, the final CO2 performance rates and state goals provide state with 

sufficient flexibility to address stranded asset concerns.

The following are summaries of the specific public comments under this comment:

Several commenters stated that EPA cannot rely on the "inherent flexibility" in the proposal as a 

substitute for the requirement that states fully consider remaining useful life.

Commenters stated that EPA's assertion that failure of the rule to develop a remaining useful 

life provision can be addressed by states through the proposed rule's general flexibility is flawed 

because it does not allow any variation of performance standards when a state's emission 

standards would force the retirement of a resource 10 or 20 years before the end of its remaining 

useful life, thus stranding huge investments.

Comment 19: General comments regarding forced retirements and lost investments that would 

result, and inconsistency with the 20 year cost effectiveness timeframe used in other CAA 

programs.

Response 19: In response to public comments, the EPA significantly revised its approach to 

BSER and goal-setting in the final rule, as explained in preamble sections V through VII. These 

changes will ensure that EGU performance rates and state goals are achievable considering cost. 

A more detailed response to the concern that states would not have adequate flexibility in 

practice to consider remaining useful life, or stranded assets, is included in final rule preamble 

section VIII.G.1 and the legal memorandum. See also the July 2015 docket memorandum titled 

“Stranded assets analysis.” The analysis shows that the national EGU performance rates in the 

final guidelines can be met without the retirement of affected EGUs before the end of their book 

life, and without the retirement of affected EGUs before the end of the book life of capitalintensive pollution control retrofits installed on those EGUs. Thus, the final CO2 performance 

rates and state goals provide state with sufficient flexibility to address stranded asset concerns.

The following are summaries of the specific public comments under this comment:

Commenters expressed concern that recent investments in control equipment for CAA 

requirements will not be recovered before the units are shut down. Commenters indicated that 

EPA did not address the "remaining useful life" associated with early retirements of coal 

resources that will result from interim goals, and stated that interim goals need to allow a state to 

ensure the useful life of those investments. Commenters stated that in order to meet building 

block 2 emission reductions, numerous coal-fired EGUs will have to be retired at a high cost and 

before the completion of their remaining useful life.

Commenters stated that stranded assets or stranded investments are precisely the types of factors 

that Congress expected states to be able to consider in determining what standard of performance 

to apply to each specific facility, but that the proposed rule deprives states of that ability. 
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Commenters stated that the inability to adjust performance standards to account for remaining 

useful life will impose hardships and result in premature closures of coal-fired EGUs. 

Commenters indicated that for facilities that would otherwise retire during the interim 

compliance period or shortly after the final standards of performance take effect, it may not be 

economical to impose significant heat rate improvements. 

Commenters noted their investment of approximately $3.5 billion to upgrade existing units and 

stated that EPA did not account for the loss of these assets nor their potential impact on customer 

rates. Commenters stated that EPA must address these costs and allow states the latitude to 

design programs that do not result in the confiscation of assets or prematurely force retirements. 

Commenters said that EPA did not explain how it can override the discretion Congress vested 

in the states to avoid such adverse economic impacts. Commenters also stated that EPA has not 

discretion to deviate from the clear statutory terms.

Commenters noted that cost effectiveness of controls in EPA programs such as MATS and best 

available retrofit technology (BART) are based on operation of emission units at a high capacity 

factor over twenty-year, or longer, useful life estimates, yet in many instances compliance with 

the proposed emission guidelines will require shutdown of coal-fired units in much shorter 

timeframes. 

Several commenters stated that EPA has failed to adequately consider the impacts of forced 

closures well before the end of their remaining useful life, and the associated impacts on 

consumers, and the economy of stranded asset costs and electric reliability issues. Commenters 

stated that EPA's presumption that the issue of remaining useful life will arise infrequently is 

inaccurate primarily because EPA focuses on capital investments late in the useful life and fails 

to consider stranded assets. Commenters indicated that most coal-fired retirements will need to 

take place at the beginning of 2020 and will have more than 10 years of useful life remaining.

Commenters stated that stranded costs from early retirement must be included as costs of control 

that states can consider, and that limiting the states in this manner is arbitrary and capricious.

Commenters stated that EPA's discussion of remaining useful life is limited to upgrades 

associated with Block 1 compliance. Commenters stated that the issue is much broader than that, 

and that the CPP will require premature retirement of coal-fired generation regardless of whether 

a company plans to make upgrades to improve heat rates. Commenters indicated that they had 

spent significant sums to comply with regional haze and MATS rules in reliance on the ability to 

recover costs, and that the CPP may result in stranded capital investments. 

Commenters stated that the forced closures and drastic curtailment of operation is in direct 

contravention of Congress' intent in drafting Section 111(d). Commenters indicated that the costs 

that would have been recorded during the EGU's run life must still be absorbed by the utility's 

customers. Commenters stated that without revision, the proposed rule will result in stranded 

costs of approximately $3.8 billion (2020 dollars). Commenters asked that EPA consider the 

diminished capital value for merchant generators who have acquired coal-fired EGUs they lack 

the right to a constitutionally adequate rate of return.
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Comment 20: Comments providing specific examples of sources where stranded assets are of 

concern.

Response 20: In response to public comments, the EPA significantly revised its approach to 

BSER and goal-setting in the final rule, as explained in final rule preamble sections V through 

VII. These changes will ensure that EGU performance rates and state goals are achievable 

considering cost. A more detailed response to the concern that states would not have adequate 

flexibility to consider remaining useful life, in practice, is included in final rule preamble section 

VIII.G.1. and the legal memorandum See also EPA’s Stranded Assets Analysis Memorandum 

that shows that the national EGU performance rates in the final guidelines can be met without the 

retirement of affected EGUs before the end of their book life, and without the retirement of 

affected EGUs before the end of the book life of capital-intensive pollution control retrofits 

installed on those EGUs. Thus, the final CO2 performance rates and state goals provide state with 

sufficient flexibility to address stranded asset concerns.

The following are summaries of the specific public comments under this comment:

Commenters provided an example of the Coronado Generating Station in Arizona whose 

selective catalytic reduction (SCR) emission controls required by BART would operate only 

about two years before the 2020 shutdown of all coal-fired generation in Arizona. Commenters 

provided further details on the Coronado Generating Station and stated that the recently 

completed (between 2009 and 2014) air pollution control equipment upgrades on Units 1 and 2

cost approximately $470 million, and that the bond financings for this project were 

approximately 30 years with final bond maturity occurring in 2041. Commenters stated that the 

net book value, as of October 31, 2014 for Coronado Generating Station Units 1 and 2 is $630 

million. Commenters indicated that the performance standards described in the proposed rule 

will likely require Coronado to cease operations in 2020.

Commenters also expressed concern about Arizona, and stated that EPA's IPM outputs 

demonstrate that the integrated operation of the four building blocks would result in retirement of 

many additional sources, none of which have reached the end of their remaining useful life. 

Commenters stated that they own one of the four currently operating units at the Springerville 

Generating Station in Arizona, and that net book value, as of October 31, 2014 for the unit is 

$900 million. Commenters stated that the bond financing for construction of Springerville Unit 

4, which came on line only five years ago in December 2009 at a cost of $1 billion, was 

approximately 30 years with final bond maturity occurring in 2038. Commenters stated that EPA 

acknowledges that the useful life of a coal-fired unit operating to meet base load demand is 40 

years, and accordingly, EPA should expect that Springerville Unit 4 would remain operating as a 

baseload facility until at least 2049. Commenters also indicated that Springerville Unit 3 came on 

line in 2006 at a cost of $939 million, and that commenters have a 30-year power purchase 

agreement to purchase power from Unit 3 with anticipation that this unit would have a useful life 

of 40 years. Commenters cited Markal Scenario Analyses of Technology Options for the Electric 

Sector: The Impact on Air Quality, U.S. EPA, EPA/600/R-06/114 (Sept. 2006) and 

Documentation for EPA Base Case v.5.13 Using the Integrated Planning Model, U.S. EPA, # 

450R13002 (Nov. 2013) in support. Commenters stated that this is a significant and 

unreasonable burden for them.
250

Commenters said that Arizona has the sixth youngest coal fleet in the U.S., including two units at 

the Springerville Generating Station that are less than ten years old. Commenters stated that 

Arizona's energy infrastructure was developed around base-load coal plants in the northeastern 

portion of the state and neighboring states, which took decades to develop and will take a similar 

amount of time to change. 

Commenters noted that after shutdown of load-following units in West Virginia in 2013 and 

2015, the remaining base-load EGUs in West Virginia will have considerable remaining useful 

life. 

Commenters said that South Dakota has only one affected EGU as of January 8, 2014, and that 

North Dakota and Wyoming, where BART was required, cannot make reasonable adjustments 

under the proposal. Commenters noted that the Big Stone EGU in South Dakota is installing a 

$400 million scrubber (for the Regional Haze Program) and is the only coal-based EGU in the 

state, so there are no alternative ways to make the reductions required under the proposed rule, 

forcing a shutdown of the source and resulting in a stranded asset. Commenters said that Big 

Stone is expected to operate for at least another 30 years, and cited South Dakota's Regional 

Haze SIP (August 18, 2011). Commenters also noted that their ownership share of Big Stone is 

nearly 28% of its capacity resources, and that the majority of their customers are in North Dakota 

and rely on Big Stone.

Commenters identified the Laramie River Station with three EGUs in Wyoming with FIP 

requirements that would require a total investment of $750 million, or $250 million per unit. 

Commenters stated that the carbon dioxide reductions for Wyoming may require steep reductions 

in production that would make the units uneconomical to run. Commenters noted that the costeffectives calculations for all these controls were based on at least 20 years of operation.

Commenters noted that the state of Kansas has spent over three billion dollars on environmental 

compliance projects for their coal-fired generators, and the reduction or elimination of their use 

will result in significant stranded costs to Kansas ratepayers. Commenters stated the EPA should

exclude all of the Kansas coal-fired generation resources that have undergone environmental 

retrofits from the CPP to recognize the remaining useful life and eliminate stranded costs. 

Commenters indicated that utilities in Kansas and Missouri have recently made significant 

investments in control equipment that could result in stranded cost for customers. Commenters 

also indicated that additions of transmission assets in Kansas and Missouri to relieve congestion 

would be similarly impacted by reduced or eliminated generation.

Commenters indicated that billions of dollars of useful plant life in Virginia and West Virginia 

are likely to be stranded at a cost to residents and business that is not accounted for by the 

proposed regulation. The following coal-fired power plants were identified as being at risk for 

stranded assets: 

• Virginia City Hybrid Energy Center ("VCHEC"), placed in-service in 2012 at an 

initial capital cost of $1.8 billion; 

• Chesterfield Power Station, scrubbers placed in-service in 2011 and 2008 at an 

initial capital cost of $275 million; 
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• Clover Power Station, constructed and placed in-service in 1995 and 1996 at an 

initial capital cost of $1.2 billion, and with a planned service life of over 50 years;

• Appalachian Power Company's Amos and Mountaineer Power Stations with more 

than $2 billion in environmental controls from a 2007 Consent Decree including 

FGD systems for all four units, placed into service between 2007 and 2011;

• Dominion's Mount Storm generating facility with scrubbers and FGD systems.

Commenters noted the premature retirement of two facilities in Nevada would be required: the 

522 MW coal-fired North Valmy Generating Station with units not scheduled for retirement until 

2031 and 2025; and the 242 MW pulverized coal-fired TS Power Plant (TSPP) which is not 

scheduled for retirement until 2025. Commenters stated that TSPP commenced operations in 

2008 and as such is efficient and well controlled.

Commenters stated that retiring Tampa Electric Company's coal units would result in substantial 

stranded assets and costs to customers, that TEC has already achieved substantial CO2 reductions 

in a consent agreement with EPA under the NSR enforcement program, and that EPA's proposed 

rule does not account for this bold and early action. Commenters indicated that the projects are 

part of the billion dollar reduction recently completed and depreciated over the remaining useful 

life of the coal plant (beyond 2030) to minimize the impact to customers' bills. Commenters 

stated the proposal, if finalized in its current form, would require acceleration of the cost 

recovery and significant additional expense.

Commenters stated that life appraisal reports for the Seminole Generating Station units 1 and 2 

in Florida indicated that the units had a remaining useful life of 40 years, through 2045. 

Commenters indicated that this date corresponds to the end of the Seminole's wholesale power 

contracts with its members, and also covers the last loan related to emission control equipment at 

the station which matures in 2042. Commenters indicated that the stranded asset resulting from 

retirement of the units before the end of their useful life would cause the electric cooperative 

system's members to have to pay for both the stranded asset and the replacement capacity at the 

same time.

Commenters indicated that Colorado's Regional Haze State Implementation Plan, approved in 

2012, requires capital investments that for Colorado Springs Utilities increase the book value of 

the four affected units by hundreds of millions of dollars.

Commenters stated that EPA has ignored the problem that every aging plant eventually reaches 

the point at which costly environmental compliance upgrades or equipment investments cannot 

be recovered during the remaining useful life of the plant. Commenters stated that not every 

plant is ready for immediate retirement, although EPA notes that, of its study population of 884 

plants, TSD, p. 2-16, 233 EGUs "have announced they will retire before 2016." TSD, p. 2-35. 

Commenters previously advised EPA that premature closures would have significant financial 

consequences for Wyoming ratepayers. (Letter to Janet McCabe, December 16, 2013, posted at 

psc.state.wy.us, under "Hot Topics"). Commenters stated that EPA has also recognized the 

problem of remaining useful life in the regional haze context. Commenters stated that in a final 

determination dated January 10, 2014, EPA provided the option of either closing Dave Johnston 
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Unit 3 in 2027, when scheduled to be fully depreciated, or installing SCRs within five years. 

Commenters provided a list of the Wyoming plants subject to Section 111(d), with their 

December 2013 full depreciation dates and their operators, and also included a table that presents 

the retirement date and operator for 10 coal plants.

Comment 21: Comments regarding the sufficiency of the "toolbox of emission reduction 

methods" in the context of remaining useful life.

Response 21: In response to the comment that the toolbox is not “flexible enough,” the EPA 

observes that the "toolbox" of emission reduction methods goes beyond those included in BSER 

and beyond the list mentioned above by commenter. The EPA believes that section 111(d) does 

not allow for compliance through offsetting emissions reductions from sources in source 

categories other than the EGU category.

The EPA shares the goal of minimizing stranded assets. Although nothing in section 111(d) 

explicitly bars a guideline that results in some facilities becoming uneconomic before the end of 

their useful lives, the EPA nonetheless has striven to design the guidelines so as to give states 

flexibility to develop plans that allow power companies to recover their investments in 

generation units. 

In response to public comments, the EPA significantly revised its approach to BSER and goalsetting in the final rule, as explained in preamble sections V through VII. These changes, 

including moving the start date of the program from 2020 to 2022 and other important changes, 

ensure that CO2 performance rates and state goals in the final guidelines are achievable 

considering cost, and leave room for states to consider remaining useful life and stranded assets. 

A more detailed response to the concern that states would not have adequate flexibility to 

consider remaining useful life, in practice, is included in preamble section VIII.G.1. and the legal 

memorandum. See also the July 2015 docket memo titled “Stranded assets analysis,” which 

shows that the national EGU performance rates in the final guidelines can be met without the 

retirement of affected EGUs before the end of their book life, and without the retirement of 

affected EGUs before the end of the book life of capital-intensive pollution control retrofits 

installed on those EGUs. Thus, the final CO2 performance rates and state goals provide state with 

sufficient flexibility to address stranded asset concerns.

The following are summaries of the specific public comments under this comment:

Commenters stated that the "toolbox" of emission reduction methods (gas, nuclear, renewable 

energy, and energy efficiency) is not flexible enough to prevent stranded investments, and 

indicated that it results in CO2 emissions reductions by displacing generation from EGUs with 

remaining useful lives. Commenters noted that true offsets should have a place in the states' 

toolboxes, and that EPA should allow states to consider sources' remaining useful lives and other 

factors via a more relaxed standard or a longer compliance period.

Commenters stated they were troubled by EPA's nebulous reference to a "toolbox of emission 

reduction methods" because it brushes off empirical real-world cost concerns
253

about stranded assets, and disregards the relevance of state emission performance goals to the 

remaining useful life of affected EGUs.

Several commenters said that the emission reduction methods referred to by EPA are not 

sufficiently available to states impacted by accelerated coal-fired unit closures on a timeline that

would allow for them to compensate for closures by 2020. Commenters said that the problem is 

exacerbated by utilities having assets in multiple states that cannot be applied across state lines to 

achieve the reductions needed to meet individual state goals. Commenters stated that the need for 

compensating emission reductions will effectively eliminate many states' ability to consider 

remaining useful life for individual coal-fired EGUS, the outcome of which is arbitrary and 

capricious.

Comment 22: Comments suggesting heat rate targets should be recalculated to reflect remaining 

useful life.

Response 22: The EPA disagrees that the remaining useful life of particular facilities should be 

reflected in the CO2 emission rates and state goals established in the emission guidelines. Section 

111(d) requires that EPA’s emission guidelines permit the states to consider remaining useful life 

in applying standards of performance to particular affected EGUs, and does not call for facilityspecific remaining useful life considerations to be taken into account in determining the levels of 

emission performance that reflect the BSER.

The following are summaries of the specific public comments under this comment:

Commenters stated that EPA must explain how the fixed heat rate target values are designed to 

reflect remaining useful life, instead of only stating how the concept of a heat rate target 

accommodates compliance for units of various ages. Commenters stated that a source-specific 

formula that considers the potential for actual, sustainable, and cost-effective heat rate 

improvement over the remaining useful life of each affected EGU should be developed to 

recalculate the heat rate targets, and that ultimately, heat rate improvements must be determined 

on a unit-specific basis.

Comment 23: Comments suggesting that remaining useful life needs to be taken into account in 

setting interim goals and in Building Block 2. 

Response 23: The EPA disagrees that the remaining useful life of particular facilities should be 

reflected in the CO2 emission rates and state goals established in the emission guidelines. Section 

111(d) requires that EPA’s emission guidelines permit the states to consider remaining useful life 

in applying standards of performance to particular affected EGUs, and does not call for facilityspecific remaining useful life considerations to be taken into account in determining the levels of 

emission performance that reflect the BSER.
254

Regarding achievability of interim goals, the EPA disagrees with this comment. See final rule

preamble section V. Regarding the BB2 comments, the EPA disagrees. See final rule preamble 

section V and the GHG Mitigation Measures TSD.

The following are summaries of the specific public comments under this comment:

Commenters indicated that the interim goals are largely unachievable for many jurisdictions and 

that the remaining useful life of affected EGUs must be taken into account in making 

improvements to Building Block 2. 

Commenters also stated that if interim goals are adopted they should take into account the 

remaining useful life of existing facilities, recent environmental retrofits, and established early 

retirement dates, and that EPA should allow states to tailor their interim goals for their unique 

circumstances, or, at a minimum allow the phase-in of compliance tools over the entire 

compliance period.

Commenters requested that EPA allow states to specifically account for the remaining useful life 

of the original generation asset as well as any major upgrades in BB2.

Commenters stated that EPA must defer to state authority to determine the feasibility and timing 

of redispatch and integration of new generation considering the remaining useful life of existing 

EGUs.

Commenters stated that the emission reductions from BB2 are premised on the outright shut 

down or drastic reduction of production from coal-based plants, and that the possibility that there 

may be an unidentified strategy that could be used in lieu of coal plant retirements or reductions 

is not an adequate substitute for the statutory mandate that states be allowed to consider 

remaining useful life. 

Commenters stated that because EPA assumes that all emission reductions associated with 

Blocks 1 and 2 can be implemented by 2020, states may need to identify other emission 

reductions that will ultimately prove unnecessary to achieve the final emission reduction targets, 

and that this approach strips the states of their right to account for the remaining useful life of 

existing sources.

Comment 24: Comments regarding considerations for units at the far end or beginning of their 

remaining useful lives.

Response 24: The EPA disagrees that the remaining useful life of particular facilities should be 

reflected in the CO2 emission rates and state goals established in the emission guidelines. Section 

111(d) requires that EPA’s emission guidelines permit the states to consider remaining useful life 

in applying standards of performance to particular affected EGUs, and does not call for facilityspecific remaining useful life considerations to be taken into account in determining the levels of 

emission performance that reflect the BSER.
255

The EPA shares the goal of minimizing stranded assets. Although nothing in section 111(d) 

explicitly bars a guideline that results in some facilities becoming uneconomic before the end of 

their useful lives, the EPA nonetheless has striven to design the guidelines so as to give states 

flexibility to develop plans that allow power companies to recover their investments in 

generation units.

In response to public comments, the EPA significantly revised its approach to BSER and goalsetting in the final rule, as explained in final rule preamble sections V through VII. These 

changes, including moving the start date of the program from 2020 to 2022 and other important 

changes, ensure that CO2 performance rates and state goals in the final guidelines are achievable 

considering cost, and leave room for states to consider remaining useful life and stranded assets. 

A more detailed response to the concern that states would not have adequate flexibility to 

consider remaining useful life, in practice, is included in final rule preamble section VIII.G.1 and 

the legal memorandum. See also the July 2015 docket memo titled “Stranded assets analysis,” 

which shows that the national EGU performance rates in the final guidelines can be met without 

the retirement of affected EGUs before the end of their book life, and without the retirement of 

affected EGUs before the end of the book life of capital-intensive pollution control retrofits 

installed on those EGUs. Thus, the final CO2 performance rates and state goals provide state with 

sufficient flexibility to address stranded asset concerns.

The following are summaries of the specific public comments under this comment:

Commenters noted that EPA should allow coal units with long, undepreciated remaining useful 

lives to be exempt from interim emission performance requirement, and relax the 2030 

requirement if the units are in compliance with the state implementation plan at the end of their 

useful lives. 

Commenters suggested that EPA should include a process for considering waivers of 

environmental upgrade requirements on plants late in their useful life to avoid significant shortterm costs on customers. Commenters referred to a situation at the Presque Isle Power Plant in 

Marquette Michigan.

Comment 25: Comments regarding delaying the effective date of emission requirements to 

mitigate impacts on coal EGUs.

Response 25: Under Section 111(d), standards of performance are to reflect the level of 

reductions achievable considering certain specified factors including cost. The EPA has 

determined that CO2 reductions from the EGU source category are achievable well before 2030, 

so starting the program as late as 2030 would not be justified. Also, the EPA disagrees that the 

remaining useful life of particular facilities should be reflected in the CO2 emission rates and 

state goals established in the emission guidelines. Section 111(d) requires that EPA’s emission 

guidelines permit the states to consider remaining useful life in applying standards of 

performance to particular affected EGUs, and does not call for facility-specific remaining useful 
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life considerations to be taken into account in determining the levels of emission performance 

that reflect the BSER.

The following are summaries of the specific public comments under this comment:

Commenters indicated that delaying the effective date of the emission rate requirements until 

2030, while not eliminating the inequities, would mitigate some of the most serious impacts on 

coal-based power plants.

Comment 26: Comments suggesting that economic useful life could be extended.

Response 26: The EPA appreciates receiving this comment. The EPA is not making a regulatory 

determination of the length of the useful life of an EGU in this rulemaking. The emission 

guidelines permit states to consider remaining useful life in applying a standard of performance 

to an individual affected EGU. The EPA will consider the reasonableness of the way in which a 

state considers remaining useful life and other factors in applying a standard of performance to a 

particular EGU in the context of evaluating state plans to determine whether they are 

satisfactory, i.e., whether they meet the requirements of the guidelines.

The following are summaries of the specific public comments under this comment:

Commenters stated, according to a recent Southwest Power Pool market study, the national 

average retirement age of coal-fired generation is 48 years. Commenters stated that in the 

Regional Greenhouse Gas Initiative (RGGI) region, almost 40 percent of the affected EGU coal 

fleet has been in-service for between 41 and 50 years; and an additional 36 percent of the RGGI

region's affected coal summer capacity is already operating well in excess of the national average 

retirement age. Commenters stated that by the beginning of the 2020 compliance timeframe, an 

even greater percentage of the RGGI region's coal fleet will be approaching the natural end of its 

industry-recognized useful life. Commenters indicated that these coal generation units could be 

retrofitted with emission controls, including efficiency investments that could significantly 

extend the economic useful life of the plants well beyond the normal retirement point.

Comment 27: Comments requesting the EPA to consider state legal restrictions on financial 

commitments for power plants that extend their operating life. 

Response 27: We disagree with the comment to the extent that it argues that the specific state 

laws below require the EPA to make changes to these emission guidelines. While the EPA has 

attempted to accommodate existing state law, the EPA is not required to.

The emission guidelines do not require a particular affected EGU to make heat rate 

improvements. Affected EGUs can comply through ERCs or allowances, and in addition to the 

building blocks (of which heat rate improvement is just one) there are other measures states can 

take (such as energy efficiency) aside from the building blocks to reduce CO2 emissions from 
257

affected EGUs. If a state determines that its preferred approach to implementing the emission 

guidelines is to not take advantage of reductions from heat rate improvements, that is the state’s 

prerogative, so long as the measures the state does choose to implement satisfactorily meet the 

requirements of these guidelines.

In determining BSER, feasibility is not assessed based on existing state law. To think otherwise 

is to misunderstand the basic cooperative federalism structure of section 111(d). To take an 

extreme example, consider a hypothetical state law that prohibits the state from submitting and 

EGUs from complying with an emission guideline. Under the commenters’ theory, EPA could 

not determine BSER to require any emission reductions whatsoever. For details of EPA’s 

authority to determine BSER, please see section V of the preamble and the Legal Memorandum.

The following are summaries of the specific public comments under this comment:

Commenters stated state law may affect compliance with CPP. Commenters stated that under 

California's Emission Performance Standard law (SB 1368), utilities are prohibited from making 

financial commitments that extend the useful operating life of power plants with an emission 

intensity of 1,100 lbs. CO2-eq/MWh or More and SB 1368 applies to investments anywhere in 

the country-not just in California. Commenters stated that even if additional equipment upgrades 

were available at power plants in which commenters or its members have an ownership interest, 

they would likely be prohibited from investing in those upgrades under California law; as a 

result, an additional 6 percent heat rate improvement at our coal-fired facilities in the western 

U.S. is not feasible. Commenters stated that EPA should include an analysis of the impacts of 

these regulations and adjust the interim and final emissions goals for states accordingly. 

Comment 28: Comments suggesting the CAA and its legislative history do not imply that 

emission reductions not achieved through consideration of remaining useful life must be made 

up by other sources. 

Response 28: Final rule preamble section VIII.G.1 is relevant to this comment, discussing the 

statutory framework and how the final emission guidelines permit states to consider remaining 

useful life. With respect to the second point, it is also nowhere implied in the Act that states are 

granted absolute discretion to take into consideration remaining useful life in any way the states 

see fit. The focus in the remaining useful life provision of section 111(d)(1) is on EPA’s 

regulations, which must permit states to take into consideration remaining useful life, as this 

guideline does. For a discussion of the legislative history and other relevant legal points, please 

see the legal memorandum. 

The following are summaries of the specific public comments under this comment:

Commenters quoted the 1977 House Committee Report's clarification of section 111(d): "The 

Administrator would establish guidelines as to what the best system for each such category of 

existing sources is. However, the State would be responsible for determining the applicability of 

such guidelines to any particular source or sources" and stated that nowhere in the CAA or its 

legislative history is it implied that if a state were to exercise such case-by-case flexibility when 
258

implementing section 111(d) Emission Guidelines, it must make up the shortfall in emission 

reductions from other sources.

Comment 29: Comments suggesting legislative history shows intent that states be allowed to 

consider remaining useful life in setting individual performance standards.

Response 29: The EPA disagrees with these comments. While section 111(d)(1) is clear that the 

EPA’s guidelines must permit states to take into consideration remaining useful life, it is silent 

on how the guidelines can do so. Section 111(d)(1) does not say that states must be given plenary 

authority to decide how to consider remaining useful life, nor does it say that the EPA cannot set 

reasonable boundaries for consideration of remaining useful life. There is therefore a gap in the 

statute that the EPA can reasonably fill. Please see the Legal Memorandum for details of the

EPA’s analysis of this provision and the legislative history.

The following are summaries of the specific public comments under this comment:

Several commenters examined the 1977 amendments to CAA sections 111(a) and (d), and 

quoted from the House Report of the Legislative History to the 1977 amendments and/or the 

House Conference Report on the 1977 amendments. Commenters noted that both sections 

111(a)(1) and 111(d)(1) were incorporated into the CAA in the 1977 amendments, and that 

Congress clarified through the definition of "standard of performance" that states must establish 

those standards for individual existing sources, and in section 111(d)(1) made clear its intent that 

states be allowed to consider remaining useful life in setting individual performance standards. 

Commenters referenced language in the 1977 House and House Conference Reports noting that 

the intent was for section 111(d) existing source standards to be based on the best available 

means of emission control (not necessarily technological) and must, unless the state decides to be 

more stringent, take into account the remaining useful life of the existing sources. (H.R. Rep. No. 

95-294, at 11, 187, 195 (1977); House Conf. Rep. 95-294, 1977 WL 16035 at 129.) 

Commenters concluded that the authority of the state to consider "remaining useful life" was 

considered to be an essential power that states were to have in determining standards of 

performance for existing sources. Commenters noted that this concept was similarly embedded 

in the PSD and regional haze programs at the same time. Commenters also concluded that EPA 

has no statutory authority to prohibit states, directly or indirectly, from regulating existing 

sources with due regard to their remaining useful life, their individual role in meeting local 

energy demands, and their importance in their communities. Commenters stated that section 

111(d) does not provide EPA with independent authority to restrict states' ability to incorporate 

remaining useful life and other factors into performance standards. 

Commenters indicated that EPA has no discretion to deviate from the clear statutory terms and 

cited Chevron in support (when Congress "has directly spoken to the precise question at issue," 

the court interprets and applies the statute without deferring to an agency interpretation.) 

Chevron, USA, Inc. v. Natural Res. Def. Council, Inc, 467 U.S. 837, 842 (1984). Commenters 

also referenced Medtronic, Inc. v. Lohr, 518 U.S. 470, 512 (1996) ("[W]here the language of the 

statute is clear, resort to the agency's interpretation is improper."), and Train v. NRDC, 421 U.S. 

60, 79 (1975) (EPA has "no authority to question the wisdom of a state's choice of emission 
259

limitations" when regulating existing sources). Commenters said EPA does not, as it claims, 

have the "discretion to alter the extent to which states may authorize relaxations to standards of 

performance that would otherwise apply." (79 Fed. Reg. at 34925.)

Commenters has claimed that EPA's justification for the technology forcing concepts in section 

111(d) BSER are found only in the new source arena. Commenters cited the District of Columbia 

Circuit decision Sierra Club v. Costle; arguing that it was only right that the costs of applying 

best practicable control technology be considered by the owner of a large new source of 

pollution.

Commenters noted that section 111(d) contains specific language requiring the Administrator 

and states to analyze the remaining useful life of each existing source.

Comment 30: Comments suggesting that the EPA's rationale for implementation of the 

emissions guidelines is faulty -- sections 111(d) and 111(b) analysis is in error.

Response 30: The EPA disagrees with this comment, which does not address the general 

approach taken in this rulemaking. First, we note that the performance rates do provide a 111(b)-

like standard of performance that is based on EPA’s determination of BSER. Furthermore, as 

explained in final rule preamble section VIII.G.1, states can take into consideration remaining 

useful life through trading, even if states adopt the performance rates as the standards of 

performance. We have provided additional flexibilities for states to consider remaining useful 

life through the other plan types. EPA is not bound to provide the same options for consideration 

of remaining useful life as are provided under the 1975 implementing regulations, as we are by 

rulemaking 40 CFR 60.24(f) inapplicable.

The following are summaries of the specific public comments under this comment:

Commenters commented on the discussion in section VIII.F.9.b of the final rule preamble of the 

CPP that stated that "remaining useful life and other facility-specific factors are [only] relevant 

for emission guidelines in which the EPA specifies a presumptive standard of performance that 

must be fully and directly implemented by each individual existing source within a specified 

source category," (the preamble goes on to indicate that such guidelines are more like 111(b) in 

their form). Commenters said that EPA's attempt to contrast section 111(b) standards of 

performance for new sources with section 111(d) standards of performance for existing sources 

fails because both provisions are based on the same definition of "standard of performance" at 

CAA Section 111(a)(1). Commenters compared section 111(b) (EPA shall establish "Federal 

standards of performance for new sources within [a] category") with section 111(d) (states shall 

submit plans establishing "standards of performance for any existing source ... to which a 

standard of performance under [section 111 (b)] would apply if such existing source were a new 

source").
260

Comment 31: Comments suggesting section 111(h) demonstrates Congressional intent not to 

close existing units.

Response 31: We disagree. Section 111(h) nowhere indicates that it is intended to address 

remaining useful life or is a means to avoid shuttering existing facilities. In fact, 111(h) is 

applicable to NSPS promulgated under 111(b), which undercuts the commenter’s theory, and 

111(h) does not mention remaining useful life as a consideration to be taken into account in 

promulgating a design, equipment, work practice, or operational standard. To the contrary, the 

limited scope of the phrase “not feasible to prescribe or enforce a standard of performance” 

shows it is inapplicable here. The phrase only applies to two situations: 1) a pollutant or 

pollutants cannot be emitted through a conveyance designed and constructed to emit or capture 

such pollutant; or 2) the application of measurement methodology to a particular class of sources 

is not practicable due to technological or economic limitations. Neither of those situations is 

present here.

The following are summaries of the specific public comments under this comment:

Several commenters indicated that section 111(h) in combination with the remaining useful life 

provision in section 111(d) demonstrates that the Clean Air Act did not intend to shutter existing 

facilities with remaining useful lives. Commenters stated that the Act anticipates that where 

improvements can be made to reduce emissions from a specific facility, such improvements shall 

be made; but where improvements are infeasible, relaxation of the standard is appropriate. 

Commenters said that to demand otherwise impermissibly treats existing sources like new 

sources, violating congressional intent to create two distinct classes of units, with a separate, 

more lenient standard governing existing sources.

Commenters stated that EPA's alternative interpretation is fundamentally inconsistent with the 

main purposes of the CAA and section 111. Commenters said the objective of the CAA was not 

to shut down or reduce utilization of existing power plants. Commenters said that it was to 

ensure that industry could continue to expand and provide economic value as it gradually 

reduced the amount of pollution per unit of economic output. Commenters said that this purpose 

can be seen in section 111's mandate that EPA consider costs and energy requirements in 

prescribing standards of performance. Commenters said that it is also evident in section 111(d)'s 

requirement that EPA permit states to take into consideration the "remaining useful life" of 

existing sources. Commenters said that if Congress had intended that EPA could simply order 

polluting sources to shut down or reduce production levels in order to reduce emissions, it would 

have had no need to require EPA to consider costs, energy, and the remaining useful life of 

sources in the regulation of those sources. Commenters said that the existence of these 

requirements is a clear indication that Congress intended that section 111 would not be used to 

require facilities to shut down or reduce production levels in order to achieve specific levels of 

air pollution.

Commenters stated that traditional "systems of emission reduction" at an affected source include 

complementary equipment modifications, operational changes, and add-on control technology. 

Commenters said that crucially, Section 111(d) makes clear that in determining BSER, one size 

does not fit all. Commenters said Section 111(d) specifically mandates that EPA "shall permit" 
261

states to consider source-specific factors such as "the remaining useful life of the existing 

source" "in applying a standard of performance to any particular source." Commenters said that 

EPA's emission guidelines and determination as to what constitutes the BSER must be consistent 

with this statutory framework.

Comment 32: Comments suggesting Part 60 Subpart B Regulations do not allow the EPA to set 

state-specific standards of performance:

Response 32: We disagree with these comments. First, we are not relying on the 1975 

implementing regulations as authority for our position on remaining useful life. In fact, as 

explained in final rule preamble section VIII.G.1, we are making 60.24(f) inapplicable to this 

guideline. As a result, the provisions in 60.24(f) are irrelevant to the issue raised by these 

commenters: whether this guideline permits states to consider remaining useful life.

We agree that the statute says “shall.” However, commenters are mistaken in claiming that the 

language after “shall” is unambiguous. In fact, it is silent as to how states should be permitted to 

take into consideration remaining useful life. Please see the discussion in preamble section 

VIII.G.1 and the legal memorandum.

Commenters misunderstand the nature of the implementing regulations. The preamble to those 

1975 regulations explained that we chose the term “emission guidelines” to emphasize that the 

guidelines are not directly enforceable against designated facilities. 40 FR 53340, 53341. Instead, 

the emission guidelines are binding on states that develop and submit plans under section 

111(d)(1).

We disagree with some commenters. The regulations explicitly provide for EPA to make 

60.24(f) inapplicable to particular emission guidelines. The statute is silent as to whether states 

must be given unfettered discretion to vary from the emission guidelines, but the language 

structure of the Act suggests that states are not. Please see the Legal Memorandum for additional 

discussion.

The following are summaries of the specific public comments under this comment:

Several commenters stated that the source of state authority to consider remaining useful life is 

the CAA, not EPA Part 60, Subpart B regulations. 

Commenters indicated that EPA improperly relies on 40 CFR sections 60.24(f) and 60.24 (c) as 

providing the "default structure" for implementing the remaining useful life provision of the 

CAA. Commenters said that EPA is twisting the words of these implementing regulations to 

override the plain words of the CAA, and is conflating the statutory requirement that it allow 

state consideration of remaining useful life with the regulations' allowance that states may apply 

less stringent emission standards provided the three conditions in the regulations are 

demonstrated. 

Commenters said that consistent with Step 1 in Chevron USA Inc. v. Natural Resources Defense 

Council, 467 U.S. at 842-843, the Agency's interpretation should not be given deference since 
262

Congress has clearly spoken. Commenters stated that section 111(d), unlike other sections of the 

CAA, provides virtually no specific guidance to EPA except that it "shall permit the State in 

applying a standard of performance to any particular source to take into consideration, among 

other factors, the remaining useful life of the existing source" (CAA section 111(d)(1)). Several 

commenters indicated that Congress' intent is made even more evident by the use of the term 

"shall" in section 111(d)(1). Commenters further stated that the term "shall" does not create any 

room for agency discretion, and cited two cases in support of the obligation created by the use of 

the term "shall." 

Commenters stated EPA cannot finalize the Proposed Rule because it arrogates to the Agency a 

function of setting state-specific standards of performance, that the statute and existing 

regulations make the exclusive province of the States. Commenters listed the contents of section 

60.22(b) paragraphs one through six as demonstrating the purely informational purpose and 

nonbinding nature of these guidance documents. Commenters stated that EPA's conspicuous use 

of the words "guidance" and "information" throughout the regulation demonstrates that 

"information" is all that EPA is authorized to provide the states. Commenters stated that the 

regulation does not authorize EPA to issue "guidelines" that contain binding state-wide emission 

reduction goals and that are thus "guidelines" in name only. Commenters indicated that EPA 

must revise the underlying rules through proper notice-and-comment rulemaking if EPA wishes 

to depart from its past rules and regulations by finalizing a rule that contains binding statewide 

emission reduction targets.

Commenters listed provisions within section 60.24(f) and indicated that the regulations (and 

statute) are clear that states must be provided flexibility to establish deviations from proposed 

emission guidelines, not within proposed emission guidelines.

Comment 33: Comments suggesting section 60.24(f) preceded CAA provision on remaining 

useful life and cannot authorize the EPA's position on remaining useful life.

Response 33: We agree that 40 CFR 60.24(f) was originally promulgated in 1975, before the 

1977 Amendments added the remaining useful life provision. However, we disagree with the 

remainder of the comments. First, we are not relying on the 1975 implementing regulations as 

authority for our position on remaining useful life. In fact, we are making 60.24(f) inapplicable 

to this guideline. Regardless of whether 60.24(f) (which we referred to but are not relying on as a 

“default structure”) adequately permits states to consider remaining useful life under other 

guidelines, what matters for this rulemaking is whether this guideline meets the statutory 

requirement, which it does for the reasons stated in preamble section VIII.G.1 and the legal 

memorandum. Thus, the argument that somehow EPA is relying on the 1975 implementing 

regulations to sidestep the statutory requirement is simply mistaken, and arguments about the 

appropriateness of 60.24(f) as a means of implementing the remaining useful life provision are 

moot. 

The following are summaries of the specific public comments under this comment:
263

Commenters stated that there are several flaws in the claim that the section 60.24(f) regulatory 

provision governs states' consideration of "remaining useful life" in establishing standards for 

existing sources. Several commenters noted that section 60.25(f) was established in 1975, before 

the 1977 CAA Amendments added the "remaining useful life" language. Commenters said that 

EPA's assertion that the regulation specifically addresses a later added requirement is 

nonsensical. Commenters stated that the 1975 regulations do not discuss consideration of 

remaining useful life other than a discussion of "economic hardship" and how "States will be free 

to vary from the levels of control represented by emission guidelines" (40 FR 53343). 

Commenters concluded that section 60.24(f) was promulgated as a means of allowing states to 

establish case-by-case less stringent emissions standards or longer compliance schedules, and 

was not and has never been a means for states to consider "remaining useful life" as set forth in 

section 111(d) and its legislative history.

Several commenters indicated that the 1975 regulations cannot be read to authorize EPA's 

position with respect to remaining useful life, and quoted from the preamble to the 1975 

regulations in support of their position. Commenters stated that section 60.24(f) which EPA 

relied on as the "default structure" for implementing remaining useful life requirements does not 

even contain the phrase "remaining useful life," and that EPA did not revise its regulations after 

the 1977 amendments to incorporate language that specifically implemented the remaining 

useful life requirement. Commenters said that EPA cannot rely today on its prior failure to enact 

required regulations as grounds to constrain the protections granted to states under the 1977 

amendments.

Comment 34: Comments suggesting the EPA's reading of section 60.24(f) ignores state 

primacy.

Response 34: The EPA disagrees with the commenters that the EPA's reading of section 60.24(f) 

ignores Congress' commitment to state primacy in the regulation of existing sources. First, the 

notion that states have plenary authority over the substance of state plans has been rejected 

repeatedly in the SIP context, as detailed in the legal memorandum. There is no basis in the 

structure or language of section 111(d)(1) to indicate that Congress expected anything other than 

the usual cooperative federalism scheme of the Act, and certainly Congress did not abrogate the 

EPA’s authority to supervise state plans. The reference to “primary responsibility” is simply a 

statement of how cooperative federalism works – states have the initial responsibility to develop 

and submit state plans, and the EPA will only step in if such plans are unsatisfactory or states fail 

to implement them. With respect to the language about variances, we are not making the 

provisions in 60.24(f) applicable to this guideline. 

The following are summaries of the specific public comments under this comment:

Commenters stated that EPA's reading of section 60.24(f) ignores Congress' commitment to state 

primacy in the regulation of existing sources. Commenters stated that EPA recognized state 

primacy in the initial promulgation of the 40 C.F.R. 60 Subpart B regulations which stated,

"States will have primary responsibility for developing and enforcing control plans under section 
264

111(d)" and that "States will also have authority to grant variances in case of economic 

hardship." 40 Fed. Reg. at 53343.

Comment 35: Comments suggesting revisions to section 60.24(f) post 1990 CAA Amendments 

are misinterpreted by the EPA and inappropriately relied upon. 

Response 35: We disagree. We are not basing our action on or claiming authority to address 

remaining useful life through the prefatory language “unless otherwise specified in the applicable 

subpart.” We are basing our action on the statute. As explained in final rule preamble section 

VIII.G.1, this guideline permits states to consider remaining useful life in numerous ways. The 

only import of the prefatory language is that it makes it unnecessary in this action to promulgate 

language in 60.24(f) making clear that those provisions are inapplicable to this guideline. This is 

already provided for in 60.24(f) – we are not reinterpreting those provisions and we are not 

reopening them for comment and judicial review.

Thus, commenters’ reference to the reasons the EPA originally added the language is beside the 

point. We are making the provisions in 60.24(f) inapplicable not because of anything in section 

129, but because this guideline already permits states to consider remaining useful life.

We have not construed the statute in such a way as to nullify the remaining useful life provision.

That is an exaggeration. That this guideline does not permit states to take into account remaining 

useful life in the particular way that the commenters would prefer does not mean that the 

guideline does not permit it at all.

The following are summaries of the specific public comments under this comment:

Several commenters noted that in the development of limitations for solid waste incineration 

units, EPA revised the 1975 section 60.24 regulations to allow for an exception to states' ability 

to consider remaining useful life. Commenters indicated that the regulation was amended 

because the MACT process as required by section 129 does not reserve a right for states to 

consider remaining useful life or other factors. Commenters noted that in 1995, EPA added the 

words "Unless otherwise specified in the applicable subpart" to section 60.24(f). Commenters

indicated that EPA bases its legal argument in the CPP proposal for restricting states' 

consideration of remaining useful life on those seven words. Commenters stated that the narrow 

history of that clause does not now give EPA discretion to ignore that section 111(d) requirement 

that EPA's regulations "shall" permit the state to consider remaining useful life. Commenters

said since the proposed rule now at issue does not involve municipal waste combustors, the 

operative flexibility granted states to consider remaining useful life and "other factors" for 

existing sources is not limited as in CAA Section 129(b)(1), EPA's effort to impose limitations 

arising from that statute on guidelines for EGUs is erroneous. 

Commenters quoted a 2008 DC Circuit court case (American Trucking Association) in support of 

its position that EPA may not construe a statute in a way that completely nullifies provisions 

meant to limit its discretion. 
265

Commenters said that if section 60.24(f) were interpreted to provide the level of discretion EPA 

proposes, then EPA's implementing regulations from 1975 and 1995 should be considered reopened and subject to judicial review. Commenters said, given the history and limited 

application of the revisions to section 60.24(f), EPA's drastic expansion of its purported 

discretion to deny States consideration of remaining useful life constitutes a new interpretation 

that could not have been anticipated when the language was originally promulgated in 1996.

Comment 36: Comments suggesting court decision in support of the EPA approach on 

remaining useful life.

Response 36: We agree that the EPA’s interpretation of the “remaining useful life” provision in 

the visibility program, both in the BART guidelines and in the SO2 backstop trading program, 

lend support to our position that this guideline appropriately permits states to take into 

consideration remaining useful life. For a brief comparison of the visibility provisions with 

section 111(d)(1), please see section VIII.G.1 of the final rule preamble of the CPP, and for a 

detailed discussion please see the Legal Memorandum. 

The following are summaries of the specific public comments under this comment:

Commenters agreed that the state plan development process adequately allows for consideration 

of the remaining useful life and provided an example of how the proposed rule provides that 

flexibility. Commenters also discussed how a 2005 D.C. Circuit Court decision in the Center for 

Energy and Econ. Dev. v. EPA case supports EPA's position that providing states with the 

flexibility to consider "remaining useful life" for specific sources by participating in emissions 

trading or other ways of shifting emissions reduction obligation is permissible under the statute

and is a reasonable interpretation. Commenters explained that the court rejected petitioners' 

argument that EPA lacked authority to permit states to comply with reasonable progress and 

BART through a regional emissions trading program. Commenters noted that CAA section 

169A(g)(1) directs EPA to consider the "remaining useful life" of affected source in determining 

reasonable progress and in applying BART, and that when EPA issued its Regional Haze Rule it 

included an emissions trading program or alternative measure option for states provided that 

such alternative would achieve better results than source-specific application of BART. Further 

details and references for the court decision were provided in the comment.

Commenters did not agree with statements provided by other commenters that the North Valmy 

coal plant in Nevada must continue to operate until at least 2025, and stated that there is no 

compelling economic or reliability reason for the plant to continue polluting beyond 2025, and 

that nearby geothermal or solar resources could help provide the necessary voltage.

Comment 37: Comments stating that the EPA cannot reject state plans that deviate from the 

emission guidelines as the result of accounting for achievability and remaining useful life.
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Response 37: The EPA disagrees with this comment, which misunderstands the structure of 

section 111(d)(1) and the Act generally. The remaining useful life provision is not a direct grant 

of authority to a state to consider remaining useful life in any way the state sees fit. It is instead a 

requirement that EPA’s regulations must meet, as these emission guidelines do for the reasons 

explained in final rule preamble section VIII.G.1 and the Legal Memorandum.

The following are summaries of the specific public comments under this comment:

Commenters stated that EPA cannot declare ex ante that it will reject as unsatisfactory the plan 

of any state that seeks to exercise its statutory authority to account for remaining useful life and 

other factors that may require a deviation from EPA's emissions guidelines. Commenters also 

stated that EPA effectively forecloses any possibility of altering a state's proposed emission 

reduction target to account for remaining useful life or any other relevant factors, even if a State 

can establish that EPA erred in its assessment of the states' ability to achieve one or more of the 

Building Blocks.

Comment 38: Comments suggesting the CAA gives states flexibility to address remaining 

useful life and EPA is violating states' statutory right.

Response 38: The EPA disagrees with comments that section 111(d)(1) is a grant of authority to 

states or creates a “state right” to consider remaining useful life in any way a state deems 

appropriate. Instead, the remaining useful life provision in 111(d)(1) is a requirement that the 

EPA’s guidelines must meet. Please see the legal memorandum for a detailed analysis of the 

requirement. 

We disagree that this guideline violates basic principles of cooperative federalism. The guideline 

provides states with flexibility to meet the guideline requirements in any number of ways. That 

the guideline does not permit states to take into consideration remaining useful life in any way a 

state wants does not violate cooperative federalism. The EPA has the authority to set basic 

requirements for consideration of remaining useful life in this guideline. To hold otherwise 

would violate basic principles of cooperative federalism by eviscerating the EPA’s role in the 

111(d) program.

With respect to the comment about 111(d)(2) requiring the EPA to take into consideration 

remaining useful life when promulgating a federal plan, we discuss that issue in our proposed 

federal plan rulemaking. This guideline permits states to take into consideration remaining useful 

life and therefore the EPA will be able to, in promulgating a federal plan, take into account 

remaining useful life as required under 111(d)(2). 

With respect to the comment about the “broken window fallacy,” the comment is purely 

rhetorical and contains no substantive issue. The EPA’s intent is to implement the CAA, not to 

require replacement of existing goods. 

The following are summaries of the specific public comments under this comment:
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Several Commenters (also emphasized that CAA section 111(d)(1) grants states the authority, in 

applying a standard to particular sources, to take into account the source's remaining useful life 

or other factors. Commenters stated that the flexibility to consider remaining useful life was 

unequivocally reserved to the states by Congress when it enacted Section 111(d), and this 

flexibility is reinforced by EPA's own implementing regulations. Commenters said that by 

setting overly stringent mandatory targets and no reasonable alternatives to comply with those 

targets, EPA has violated the states' statutory right to consider these factors in the design of the 

rule and deviate from the BSER requirements and resulting emissions limits.

Several commenters said Congress intended section 111(d) to be a state-driven process, rather 

than be the subject of federal command-and-control dictate, and that the proposal is unlawful 

because it abrogates states' right under Section 111(d) to state-driven emission standards. 

Commenters cited section 111(d)(1)(A) in support, and said that it grants states the prerogative 

of "submit[ting] to the Administrator a plan which ... establishes standards of performance for ... 

existing source[s] .... " and that in so doing, Congress unquestionably intended for states to be 

the regulators exercising discretion in establishing emission standards, specifically authorizing 

states to consider such factors as the remaining useful life of a given source in the standardsetting process. Commenters stated that in contrast, Congress limited EPA's role to a subsidiary

procedural role prescribing regulations which shall establish a procedure for plan submission and 

determining whether a state's submitted plan is satisfactory, and cited section 111(d)(2). 

Commenters said, section 111(d) explicitly grants states the authority to act independently of 

EPA in developing their compliance plans. Commenters said that first, section 111(d) gives 

states, not EPA, the first opportunity to develop implementation and enforcement plans that are 

projected to achieve EPA's national emissions guideline, and that EPA can only reject state plans 

if it finds them unsatisfactory (i.e., the plans fail to satisfy section 111(d) requirements or section 

111(d) regulations). Commenters said that second, section 111(d) gives states the opportunity to 

address local conditions, including economic factors like the remaining useful life of regulated 

sources, and that this sensitivity to local conditions is central to regulating existing sources under 

section 111(d). Commenters said even if EPA finds a state plan unsatisfactory and acts to 

implement federal standards of performance in lieu of the state plan, EPA must still consider 

local state conditions (Commenters cited the section 111(d)(2) provision that requires EPA to 

consider the remaining useful life of regulated sources, in support of this statement.)

Several commenters indicated that EPA did not and cannot identify any statutory provision 

(other commenters said, any canon of statutory construction) that authorizes it to displace states' 

legal authority and would allow it to eliminate the statutory flexibility that Congress intended for 

the States to exercise. Commenters said that rewriting section 111(d) in such a fashion is flatly 

inconsistent with the principles of cooperative federalism on which the CAA is based. 

Commenters also stated that in dismissing its requirement to allow states to consider remaining 

useful life under the CAA, EPA is violating basic principles of cooperative federalism, and 

impinging on the states' rights to craft their own plans. 

Commenters noted that the CAA requires that EPA take remaining useful life (and other factors) 

into consideration in promulgating a standard of performance under a section 111(d) plan, and 

stated that accordingly, EPA does not have the legal authority to ignore the remaining useful 
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lives of affected sources when setting a state's goals or to replace consideration of this factor 

with a concept the Agency might prefer.

Commenters argued that CAA includes facility-preserving concepts intended to prevent EPA 

from falling prey to the broken window fallacy widely recognized in economics: the fallacy that 

destroying existing wealth somehow creates a positive gain through the mere replacement of 

existing goods.

Comment 39: Comments suggesting the federalism bar prohibits the EPA from using the SIP to 

force states to adopt specific control measures.

Response 39: The EPA disagrees with this comment. We have not dismissed the requirement 

that this guideline permit states to take into consideration remaining useful life, as explained in 

section VIII.G.1 of the final rule preamble of the CPP. This guideline does not require any 

specific control measures and gives states vast flexibility in meeting its requirements; please see 

the legal memorandum for a discussion of state flexibility. Thus, the cases cited by the 

commenters are inapposite. Commenters also do not point to any particular reason that states are 

effectively required to adopt specific control measures, nor do commenters identify any such 

measures. 

The following are summaries of the specific public comments under this comment:

Commenters noted that section 111(d)(1) directs EPA to prescribe regulations which shall 

establish a procedure similar to that provided by section 110, and that cases interpreting section 

110 emphasize a "federalism bar," which "prohibits EPA from using the SIP process to force 

states to adopt specific control measures." EME Homer City Generation, L.P. v. EPA, 696 F.3d 

at 29 (D.C. Circuit 2000). Commenters stated that under section 110, states must have "real 

choice with regard to the control measure options available to them" to meet their SIP 

requirements" (Michigan v. EPA, 213 F.3d at 687 (D.C. Circuit 2001)) and that these cases 

underscore the primacy of state discretion under the CAA to tailor an SIP to the state's particular 

circumstances. Commenters indicated that EPA's dismissal of the statutory requirement to allow 

states to consider remaining useful life because states can employ building blocks 2, 3 and 4 

rather than building block 1, is a decision that effectively forces states to adopt specific control

measures in violation of the "federalism bar."

Comment 40: Comments regarding the effect of not allowing states to account for the remaining 

useful life of affected EGUs on source owners is a takings under the Fifth Amendment.

Response 40: We explain our interpretation of remaining useful life in section VIII of the 

Preamble and Section IX of the Legal Memo. We explain there that the guidelines do permit 

states to consider remaining useful life and other facility specific factors. The guidelines are 

designed to permit trading and the creation of interstate emission markets. We view the 

remaining useful life consideration as primarily regarding a concern for facilities with relatively 
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short remaining useful lives and the potential that they may be required to install prohibitively 

costly pollution control devices (these guidelines to not impose such a requirement). 

Nonetheless, the agency also conducted a “stranded assets” analysis to determine if commenters’ 

concerns were correct that the rule would force widespread retirements of units with relatively 

long book lives. As explained in Section VIII.B.1 of the Preamble, we found that this need not be 

the case. This of course may depend on how states choose to design their state plans, but it 

cannot be said that this rule requires the result. Insofar as this comment asserts that this rule will 

necessarily effectuate a regulatory taking, see the discussion of the Just Compensation Clause in 

the Legal Memorandum accompanying the final rule.

The following are summaries of the specific public comments under this comment:

Commenters raised an issue under the Takings Clause of the Fifth Amendment associated with 

issuing regulations that would necessitate the closure of coal-fired EGUs and produce significant 

stranded assets. Commenters stated that under the Penn Central test, a court evaluates a 

regulatory takings claim by considering the regulation's economic effect on the landowner, the 

extent to which the regulation interferes with reasonable investment-backed expectations, and the 

character of the government action. Commenters cited Palazzolo v. Rhode Island, 533 U.S. 606, 

617 (2001) (citing Penn Central Transp. Co. v. New York City, 438 U.S. 104, 124 (1978)).

Commenters stated the economic effect on the owner would be substantial: the owner would 

likely be deprived of all economic benefits if it were forced to shut down a coal-fired EGU 

prematurely, and, such a premature retirement would interfere with the reasonable investmentbacked expectations of the facility owner. Commenters stated that when a coal-fired EGU is 

approved for construction, the owner has a reasonable investment-backed expectation that it can 

operate the facility for its entire useful life to recoup the substantial costs of construction, and 

that leaving an owner with stranded assets it cannot recover would interfere with those 

expectations. Commenters further stated that expenditures necessary to comply with federal 

environmental regulations such as MATS create further investment-backed expectations.

Commenters said that while EPA may be able to point to environmental benefits associated with 

prematurely shutting down coal-fired EGUs, it is doubtful that such benefits could offset the 

other factors in the Penn Central test. Commenters concluded that at a minimum, Section 111(d) 

must be read to authorize States to adjust their emission reduction targets to take into account the 

remaining useful life of affected EGUs. Commenters stated that without relief for their remaining 

useful life, many older EGUs will be forced to significantly reduce operations or retire and by 

forcing significant reductions in operation and retirements, the CPP is a regulatory taking of 

these units requiring government compensation.

Comment 41: Comments on October 30, 2014 Notice of Data Availability (NODA) in 

disagreement with use of book life to determine remaining useful life. 

Response 41: Contrary to statements of some commenters, the October 30 Notice of Data 

Availability did not discuss remaining useful life. Rather, the notice discussed stranded asset 

concerns and requested comments on book life in the context of seeking comments on the BSER 

determination.
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The emission guidelines permit states to consider remaining useful life of individual affected 

EGUs in designing their plans. In response to commenter concerns about the book life metric, 

the agency observes that the guidelines do not dictate that states use a particular definition of 

“remaining useful life.” The EPA interprets the provision as primarily concerned with facilities 

that have short remaining useful lives, and with retrofit costs. States also are free to consider 

stranded assets concerns in designing their plans. The EPA will consider the reasonableness of 

the way in which a state considers remaining useful life and other factors in applying a standard 

of performance to a particular EGU in the context of evaluating state plans to determine whether 

they are satisfactory, i.e., whether they meet the requirements of the guidelines.

For purposes of the EPA’s stranded assets analysis, described in a July 2015 memorandum to the 

docket, the agency used book life as an estimate of the time period in which coal-fired generation 

units are fully depreciated. Book life is the period over which long-lived assets are depreciated 

for financial reporting purposes. The agency estimated typical book life by researching financial 

statements of utility and merchant generation companies in filings to the Securities and 

Exchange Commission. The agency estimated the book life of coal-fired EGUs to be 40 years, 

and assumed a 20-year book life for pollution control retrofits. The book life of coal-fired EGUs 

(coal steam and IGCC) is twice as long as the debt life and the depreciation schedule used for 

federal tax purposes. Although the book life for environmental retrofits is often 15 years, the 

agency conservatively assumed 20 years in this analysis. While the analysis’ estimate of book 

life may not correlate with actual depreciation periods of every individual coal-fired EGU, it 

does reflect the expected depreciation periods for those facilities as a class, and thus the agency 

believes it is a highly reasonable means of assessing the degree of likelihood of “stranded assets” 

across the whole sector.

The analysis shows that the emission performance levels in the final guidelines can be met 

without the retirement of affected EGUs before the end of their book life, and without the 

retirement of affected EGUs before the end of the book life of capital-intensive pollution control 

retrofits installed on those EGUs. Thus, the final CO2 performance rates and equivalent state 

goals provide state with sufficient flexibility to address stranded asset concerns. For additional 

detail, see the July 15 docket memo titled “Stranded assets analysis.”

The following are summaries of the specific public comments under this comment:

Several commenters stated that book life is not an appropriate means of considering the 

"remaining useful life." Commenters indicated that it would be inappropriate for EPA to adopt a 

uniform (e.g., 40-year) remaining useful life for all existing coal-fired EGUs given the diversity 

among the sources. Commenters also said it would be inappropriate for EPA to adopt a uniform 

(e.g., 20-year) remaining useful life for major pollution control retrofit projects. Multiple 

commenters stated that each existing coal-fired EGU must be evaluated on a case-by-case basis 

to determine its remaining useful life. 

Commenters indicated that book life is an accounting concept that does not measure the 

remaining useful life of an EGU. Commenters also stated that book life is a ratemaking concept 

that concerns asset depreciation and does not describe the useful life of an asset. Commenters

stated that the useful life of an EGU asset extends well beyond the asset's book life.
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Commenters stated that adjustments in compliance may be necessary to account for the 

remaining useful life of coal-fired EGUs, and that the NODA does not sufficiently address this 

issue. Commenters stated that the brief comment period EPA has allocated for the NODA 

prevents commenters from providing any substantive comments on how remaining useful life 

could be incorporated into a final Section 111(d) rule.

Commenters stated that generating units subject to prudent ongoing maintenance and investment 

can achieve several decades of useful and economical service beyond an accounting book life.

Commenters said in reference to the 40-year book life referred to in footnote 6 of the NODA, 

that a 40-year remaining useful life directly conflicts with the commenter's state regulatory 

determines, which are referenced and outlined in the comment letter. Commenters presented that 

the remaining useful life numbers for their BACT controlled and new generation fleet range from 

32 to 50 years.

Comment 42: Comments on October 30, 2014 NODA providing suggestions on how to use or 

revise book life.

Response 42: The EPA disagrees that the remaining useful life of particular facilities should be 

reflected in the CO2 emission rates and state goals established in the emission guidelines. Section 

111(d) requires that EPA’s emission guidelines permit the states to consider remaining useful life 

in applying standards of performance to particular affected EGUs, and does not call for facilityspecific remaining useful life considerations to be taken into account in determining the levels of 

emission performance that reflect the BSER.

The response to comments on why remaining useful life is not a basis for adjusting state goals is 

earlier in this section (5.11) of the RTC document.

Regarding the suggestion that states adjust goals based on stranded assets considerations, the 

EPA disagrees. The EPA has determined that the CO2 performance levels and state goals are 

achievable considering cost. The basis for that conclusion is provided in chapters VI and VII of 

the final CPP preamble. Section VIII.G.1 of the final rule preamble of the CPP explains that the 

emission guidelines provide states with flexibility to consider facility-specific factors, and the 

July 15 memo to the docket titled “Stranded assets analysis,” also summarized in the preamble, 

shows that states have sufficient flexibility to address stranded asset concerns .

Regarding, the comment on a potential error in book life used for modeling, EPA disagrees. The 

book life is one of many financial assumptions included in the model for new investments, and is 

one of many variables impacting the model projections. 

The following are summaries of the specific public comments under this comment:

Commenters noted that it appears that EPA considered the remaining book life of certain coalbased units when calculating the available re-dispatch potential for a state. Commenters

indicated EPA should recognize remaining unit and pollution control book life when setting state 
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goals. Commenters also stated that it may be more appropriate to consider the depreciation 

schedule and capital improvements than book life alone. 

Commenters suggested two approaches:

• States could adjust goals to consider remaining useful life of the pollution control 

investment. For example, Regional Haze controls could be accounted for with a twenty 

year life at a baseline capacity factor.

• States could adjust goals to avoid stranded investment. States could evaluate investments 

in pollution control considering baseline capacity factors, the capital cost and the cost 

advantage of fuels.

Commenters said that they identified a potential error in the book life used for modeling a new 

coal-fired unit. Commenters stated that the data in EPA's integrated planning model for Texas 

has the Sandy Creek coal plant at only a 38% capacity factor in 2025 despite being about 13 

years into its useful life. Commenters indicated that in contrast EPA stated that a 40 year book 

life was used for modeling a new coal-fired unit.

Comment 43: Comments in support of October 30, 2014 NODA.

Response 43: Thank you for your comments. As described in sections V-VII of the preamble, 

there are significant changes since proposal in the way that the agency is determining the BSER 

and calculating emission performance requirements to ensure that the final CO2 emission rates 

and equivalent state goals are achievable considering cost. The final rates and goals leave 

flexibility in practice for states to consider remaining useful life and other facility-specific 

considerations. The agency concluded that it was not appropriate or necessary to adopt 

approaches that involve considering remaining useful life or other facility-specific considerations 

in the approach for calculating CO2 emission performance rates. Facility-specific factors can be 

considered in the state plan design process. Additionally, see the July 2015 docket memo titled 

“Stranded assets analysis” for a discussion of EPA’s analysis of the final rule, which finds that 

the final performance rates represent a level of generation and emissions across each 

interconnection that is consistent with the ability to operate affected EGUs through the end of 

their book life, considering both the age of each facility and recently installed capital-intensive 

pollution control retrofits.

The following are summaries of the specific public comments under this comment:

Several commenters stated that they are encouraged by EPA's acknowledgment in the NODA of 

utility concerns that the Proposed Rule fails to give owners the opportunity to fully take 

advantage of the remaining asset value of existing coal-fired generation. 

Commenters said that EPA is on the correct path in the NODA of incorporating the remaining 

useful life of affected units into the re-dispatch assessment. Commenters said this will greatly 
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reduce electric system reliability concerns, and allow for more logical transition to lowering the 

carbon intensity from existing EGUs.

Commenters said that EPA correctly acknowledged in its NODA that adjustments in compliance 

may be necessary to account for the remaining useful life of coal-fired EGUs.

Commenters stated that the proposal to use book life in the NODA to allow states to adjust the 

interim goal has merit, provided that major pollution control investments are included in this 

flexibility.
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5.12 DESIGN, EQUIPMENT, WORK PRACTICE, OR OPERATIONAL STANDARDS

This section addresses comments on whether state plans may contain design, equipment, work 

practice, or operational standards, and if those types of standards must be limited to the 

circumstances described in section 111(h) (i.e., when it is ‘‘not feasible’’ to prescribe or enforce 

a standard of performance.)

Commenters have raised a number of issues related to this subsection which are organized by 

topics (comments) below. Responses are provided for these topics.

Comment 1: Comments suggesting that emissions should be limited under section 111(h), and 

the EPA should require operations and maintenance practices to minimize heat rate variability.

Response 1: We disagree both that limiting emissions under section 111(h) is the better 

application of the CAA and the most defensible mechanism for regulation of carbon emissions 

under section 111 and that such standards may be promulgated only under section 111(h). CAA 

section 111(h) concerns the relatively rare situation in which an emissions standard, which 

entails a numerical limit on emissions, is not appropriate because emissions cannot be measured, 

due either to the nature of the pollutant or the nature of the source category. CAA section 111(h) 

provides that a design standard is appropriate under those circumstances, but only under those 

circumstances. In the context of the CPP, an emissions standard is appropriate, as described in 

detail in section III.B of the final rule preamble, and therefore CAA section 111(h) does not 

apply. Additionally, CAA section 111(h) applies only to standards promulgated by the 

Administrator, and therefore appears by its terms to be limited to CAA section 111(b) 

rulemakings for new, modified, or reconstructed sources, not CAA section 111(d) rulemakings 

for existing sources. See sections V.B .and VIII.D of the final rule preamble of the CPP. 

We also disagree that a work practice or operational standard can be promulgated as a standard

of performance for existing EGUs. See Section VIII.D of the final rule preamble of the CPP. 

However, we are finalizing that a state may elect to use emission standards for affected EGUs 

that result in a reduced CO2 lb/MWh emission rate for affected EGUs because of operational or 

other standards. The state would include in its state plan an emission standard that is the rate 

standard that results from the applicable operational or other standard. See section VIII.C of the 

final rule preamble of the CPP. 

The following are summaries of the specific public comments under this comment:

Commenters stated that a work practice or operational standard can be promulgated for existing 

EGUs using the authority in CAA section 111(h) when there is no demonstrated control 

technology for a particular pollutant. Commenters stated that because there is no adequately 

demonstrated control technology for reducing carbon dioxide from existing coal-fired EGUs, 

EPA should require the best technological system of continuous emission reduction, which in 

this case would be operation and maintenance practices that minimize heat rate variability and 

periodic review of available equipment upgrades to determine whether such upgrades would cost 

effectively improve heat rate and boiler efficiency. Commenters indicated that limiting emissions 
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under section 111(h) is the better application of the Act and the most defensible mechanism for 

regulation of carbon emissions under section 111. 

Commenters stated that EPA may not promulgate operational or work practice standards under 

section 111(d) because such standards may be promulgated only under section 111(h).

Comment 2: Comments supporting work practice-type standards in face of technical 

uncertainties in monitoring and emission projections.

Response 2: We disagree that a work practice or operational standard can be promulgated as a 

standard of performance for existing EGUs. See section VIII.D of the final rule preamble of the 

CPP. However, we are finalizing that a state may elect to use emission standards for affected 

EGUs that result in a reduced CO2 lb/MWh emission rate for affected EGUs because of 

operational or other standards. The state would include in its state plan an emission standard that 

is the rate standard that results from the applicable operational or other standard. See Section 

VIII.C of the final rule preamble of the CPP.

The following are summaries of the specific public comments under this comment:

Commenters supported the development of a work practice standard because of a lack of readily 

quantifiable reductions that can demonstrate achievement with a rate-based goal or emission cap, 

and lack of real-time heat rate measurement technology to assess improvements associated with 

particular operating practices or equipment upgrades. Commenters stated that improvements in 

building block 1 cannot be reliably projected or enforced, and that EPA must acknowledge these 

uncertainties and revise its criteria to accommodate a reasonable work practice standard.

Commenters also noted that a work practice standard could be used by states to evaluate future 

outage work and assure efficiency of existing fleets
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5.13 EMISSIONS AVERAGING AND TRADING

This section addresses comments on emissions averaging and trading, including comments on

cap-and-trade programs. These comments cover such topics as the potential advantages and

issues related to emissions trading programs, interstate trading of emission allowances, emission 

averaging. Also included are commenters’ recommendations regarding the design and 

implementation of these programs and suggestions regarding areas where EPA can provide 

guidance and support to states considering incorporating a trading program into their state plan. 

Commenters have raised a number of issues related to this subsection which are organized by 

topics (comments) below. Responses are provided for these topics. 

Comment 1: Numerous commenters supported emissions trading programs and noted that this 

approach has been demonstrated by the Regional Greenhouse Gas Initiative (RGGI) and 

California’s cap-and-trade program.

Response 1: Commenters note many benefits of emission trading programs. The EPA has 

implemented several of these programs and agrees with commenters’ statements.

The following are summaries of the specific public comments under this comment:

Many commenters supported emissions trading programs. Commenters supported emissions 

trading programs because they believe these approaches provide greater flexibility for achieving 

state CO2 goals, are the most cost effective way to reduce emissions, and would be beneficial to 

power consumers. Commenters argued this degree of flexibility is needed because many EGUs 

will not be able to make even the required heat rate improvements, while the other building 

blocks are by definition beyond the control of individual electric generating units (EGUs).

• RGGI WORKS: Commenters noted that existing market-based emission trading 

programs, such as RGGI and the California program, have successfully 

demonstrated that trading programs are an efficient, cost-effective method 

achieving emission reductions. Commenters noted that the nine states 

participating in the Regional Greenhouse Gas Initiative have together reduced 

carbon pollution in the region by over 40 percent from 2005 to 2012. Commenters 

noted that the new RGGI cap of approximately 78 million tons in 2020 is more 

than 50 percent below 2005 levels and the net benefits of RGGI were 

approximately $1.6 billion in the first compliance period. Commenters observed 

that the true cost of RGGI has never been revealed. Studies have failed to capture 

the costs of transmission upgrades or reliability must run orders. Commenters 

asserted RGGI might be the least bad means of attaining compliance with the 

Clean Power Plan.

• CALIFORNIA'S PROGRAM WORKS: Commenters also mentioned California's 

economy-wide greenhouse gas (GHG) emissions cap. Commenters noted that 
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California has already held four successful allowance auctions and the cap and 

trade program is projected to reduce emissions by 25 percent from 2006 to 2020. 

Commenters claimed that California's utility sector greenhouse gas emissions 

have declined with emissions from in-state and imported power falling by 16 

million metric tons, or 16 percent, from 2005 to the 2010-12 averaging period 

(from 108 million metric tons CO2e to 91 million tons CO2e). By 2025, California 

expects to cut utility sector emissions to below 80 million metric tons CO2e, a 

roughly 25 percent reduction from 2005 levels in that sector, with already low 

emissions compared to other states.

Commenters stated they support market solutions as the best and most efficient means to drive 

emission reductions at the lowest cost to the economy, and they agree with and support 

maintaining the Agency's interpretation that

"the definition of 'standard of performance' is broad enough to allow states to 

implement the proposed EPA guidelines by incorporating emissions averaging 

and trading provisions, including both emission rate programs, in which sources 

may average or trade those rates, and mass emission limit programs, in which 

sources may buy and sell mass emission allowances (and, under certain 

circumstances, offsets)." 

Commenters supported allowing multi-year averaging to demonstrate compliance and cited 

RGGI as having a 3-year compliance period. However, the commenters stated there are several 

effective steps the Agency could take to improve states' ability to design plans that can fully 

utilize this valuable tool: 

• Provide presumptive mass based standards for each state;

• Provide central, harmonizing standards and compliance infrastructure for states to 

voluntarily utilize; 

• Enable "out of sector" greenhouse gas emission reductions to be used to demonstrate 

compliance with a State's compliance goal; and 

• Ensure adequate time is available for market design and formation.

Commenters supported allowing states to join regional trading initiatives as an additional tool by 

which to implement the carbon dioxide reductions required to meet their goals.

Commenters stated, to address greenhouse gas emissions from existing power plants, the States 

support EPA's proposal to allow states to utilize trading programs. Commenters said, cap-andtrade programs are well suited to reducing greenhouse gas emissions because such programs 

ensure compliance with emission limitations and such emissions do not pose the type of "hot 

spot" concerns that toxic pollutants such as mercury do. The commenters also discussed the 

success of RGGI.

Commenters also stated EPA may consider scenarios in which emissions reductions attributable 

to renewables generation and increased end-use energy efficiency would be credited on the basis 
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of CO2 emissions avoided, with such credits to be used by covered facilities to achieve 

compliance with the emission guidelines. [See, e.g., Natural Res. Def. Council, Closing the 

Power Plant Carbon Pollution Loophole: Smart Ways the Clean Air Act Can Clean Up 

America's Biggest Climate Polluters (Mar. 2013).] Commenters said, in considering these 

scenarios, EPA should evaluate and articulate any methodology to be used to determine credit 

eligibility.

Comment 2: Many commenters noted that cap-and-trade programs are efficient, simple to 

implement, and easy to enforce.

Response 2: The EPA has implemented several cap and trade programs in the final rule, and 

agrees with commenters’ opinions. Most covered sources under the Clean Power Plan final rule 

have had experience with trading and monitoring and reporting since 1995 with the Title IV Acid 

Rain Program, a national program to reduce sulfur dioxide emissions from power plants. 

Commenters are correct to point out the success of such programs in achieving emission 

reductions in a cost-effective manner and that the equipment and protocols to comply are readily 

available and in most cases, already in place. The simple and straightforward manner of 

accounting for compliance has also been a benefit. Aside from the benefits to public health and 

welfare, resource savings for both sources and government have also been demonstrated. 

Sections V and VIII of the CPP final rule preamble address emission trading at length, 

specifically in section VIII, see VIII.J.3 for mass-based trading approaches and VIII.K.2-4 for 

rate-based approaches. Note also that concurrent with this final rule, the EPA is proposing a 

Federal Plan with model rules that states may consider in developing their plans.

The following are summaries of the specific public comments under this comment:

Commenters stated that trading systems are an efficient and easy way to ensure compliance. 

Commenters believe that an emissions cap is a good approach for monitoring and verifying 

compliance. For states that rely on a suite of policies to reduce emissions, commenters stated that 

an emissions cap is a simple but rigorous method of ensuring and verifying that the policies 

achieve the emission reductions. 

• Commenters noted that even though the required emission reductions are 

achieved on a regional basis, the point of compliance is with the source because 

sources cannot emit more than the number of allowances they hold. 

• Commenters noted that the measurement of CO2 emissions at sources covered by 

the cap can be accomplished using existing emissions monitoring equipment and 

protocols already in place at these sources. Commenters noted that covered 

sources report CO2 emissions in accordance with 40 CFR Part 75. 

• If a source does not have adequate allowances to cover its emissions, commenters 

stated that enforcement can be taken directly against that source. Because of the 

simple and straightforward nature of determining whether the cap is met, 
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Commenters believed budget trading programs obviate the need for EPA or states 

to conduct a complex analysis to determine whether a state meets its compliance 

requirements.

Commenters stated that California's Global Warming Solutions Act (GWSA) allows an 

economy-wide cap-and-trade program across sectors to achieve carbon reductions. Commenters 

said the GWSA recognizes that for some energy-intensive industrial sources, stringent 

requirements in California, either through inclusion in a cap-and-trade program or through 

source-specific regulation, have the potential to create a disadvantage for California facilities 

relative to out-of-state competitors unless those locations have similar requirements. If 

production shifts outside of California, emissions could remain unchanged or even increase.

Commenters said maintaining sector-specific requirements will help safeguard against such 

complications.

Comment 3: Commenters believed that market-based programs provide greater electricity 

reliability than other approaches.

Response 3: The EPA encourages states to work closely with RPOs in developing state plans

that implement the emission standards. Section VIII.G.2 of the CPP final rule preamble discusses 

reliability. See also the TSD on resource adequacy and reliability in the docket to the CPP final 

rule.

The following are summaries of the specific public comments under this comment:

Commenters believed Regional Transmission Organizations (RTOs) should dispatch electric 

generating units (EGUs) according to complex mathematical models with the goal of minimizing 

costs and emissions (or water use or some other resource constraint). Pricing carbon may be a 

more viable solution to meeting carbon emissions standards than environmental dispatch, but 

absent Congressional action the legal authority for RTOs or groups of states to act in a way that 

is envisioned by the CPP is uncertain. Commenters stated that market-based emissions credit 

trading programs are the most efficient pathway to ensuring compliance costs are appropriately 

tied to economic dispatch priorities. "Baking" compliance costs of various generators into their 

market bids allows both economic and environmental attributes to be accounted for in a single 

merit-order dispatch schedule and greatly simplifies electricity market rules and operations.

Commenters believed that a market based trading program would help mitigate any localized 

system reliability concerns, since power plants in areas with high electricity demand would be 

able to purchase allowances from facilities in states with better access to natural gas redispatch. 

Comment 4: Commenters preferred market-based programs that are based on mass-based limits

because they believed they would be easier to implement and states and utilities are familiar with 

other mass-based programs, such as the Acid Rain and CAIR trading programs.
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Response 4: In the CPP final rule preamble, the EPA finalized both mass-based limits and ratebased performance standards. Section VIII describes state plan approaches including rate- and 

mass-based approaches with which states can elect to comply. Section VIII also addresses massbased emission standards with a market-based emission budget trading program. Specifically, 

see VIII.J.3 for mass-based trading approaches and VIII.K.2-4 for rate-based approaches. Section 

V addresses the legal justification of including emissions trading within the best system of 

emission reduction (BSER). Note also that concurrent with this final rule, the EPA is proposing a 

Federal Plan with model rules that states may consider in developing their plans.

The following are summaries of the specific public comments under this comment:

Commenters believed that a mass-based allowance system has advantages over a rate-based 

system. 

• A mass-based allowance system automatically accounts for: 1) improved 

efficiency at the plant level, 2) reduced demand resulting from demand-side 

energy efficiency improvements, 3) load shifting to lower CO2 emitting 

generation, and 4) and the deployment of renewable (zero-emitting) energy 

sources. 

• A mass-based allowance system parallel EPA's Acid Rain and CAIR trading 

programs; states have no experience with rate-based trading systems. The federal 

agency could establish state CO2 budgets, based on application of site-specific 

BSER. States could then allocate their budgets to their facilities using whatever 

methodology they choose (e.g. auction or historical activity). States would then 

have the option of allowing their sources to participate in an intrastate or interstate 

trading program.

Comment 5: Commenters supported trading programs because they believed they would 

provide an incentive for states to preserve their existing nuclear power plants.

Response 5: The EPA is not finalizing increased generation from new nuclear capacity as a 

component of the BSER in building block 3 in the CPP final rule preamble. The EPA is also not 

finalizing the proposal to include a component representing preserved existing nuclear 

generation in the BSER. See section V of the CPP final rule preamble for a discussion of nuclear 

generation and the final building block 3. Generation from new nuclear units and capacity 

uprates at existing nuclear units would still be able to help sources meet emission rate-based 

standards of performance through the creation of credits, as discussed in section V.A of the final 

rule preamble, and would help sources meet mass-based standards of performance through 

reduced utilization of fossil generating capacity leading to reduced CO2 emissions at affected 

EGUs. See section V of the CPP final rule preamble for a discussion on the legal justification of 

including emissions trading within the best system of emission reduction (BSER).
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The following are summaries of the specific public comments under this comment:

Commenters stated that this approach provides states with a strong incentive to preserve the 

existing nuclear fleet because the premature retirement of a nuclear plant and its replacement by 

natural gas-fired facilities would result in substantially increased carbon emissions, higher 

allowance prices, and higher electricity prices.

Comment 6: Commenters asserted that a rate-based trading program would be too complex and 

that a mixture of rate-based and mass-based trading programs around the country would be 

difficult to affectively administer, arguing that it would be difficult to link rate-based trading 

programs with mass-based trading programs.

Response 6: In order to provide states with the greatest number of options and flexibility in 

meeting the performance rates, the emission guidelines finalize both mass- and rate-based 

approaches, which each could be implemented through trading programs. Section V addresses 

the legal justification of including emissions trading within the best system of emission reduction 

(BSER) and section VIII of the CPP final rule preamble discusses emission trading approaches. 

In the final rule preamble, the EPA provides approaches in the emission guidelines for how a 

rate-based trading program and a mass-based trading program would be implemented but does 

not project linking rate and mass trading states. States have options and flexibility to choose to 

implement mass-based goals or rate-based goals or performance rates under the CPP final rule.

Specifically in section VIII, see VIII.J.3 for mass-based trading approaches and VIII.K.2-4 for 

rate-based approaches. Note also that concurrent with this final rule, EPA is proposing a Federal 

Plan with model rules that states may consider in developing their plans.

The following are summaries of the specific public comments under this comment:

Commenters asserted that rate-based trading systems are more complex and that a patch-work of 

mass-based and rate-based systems around the country would prove extremely difficult to 

administer effectively. Commenters cautioned that research suggests enabling linkage between a 

state with a rate-based program and a state with a mass-based program will increase emissions 

relative to a scenario without linkage. Commenters stated the rate-based systems increases trade, 

depresses prices, and increases production; interstate linkage compounds changes. Commenters 

stated the research includes a discussion of available measures for ensuring that overall 

emissions do not increase due to linkage including, requiring states with rate-based programs to 

convert to mass-based standards prior to trading.

Comment 7: Commenters asserted that market based programs are good for 

consumers, employment, and the environment and noted that these advantages of a market-based 

program had already been demonstrated by Regional Greenhouse Gas Initiative (RGGI) had 

demonstrated.
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Response 7: The EPA agrees with commenters. As discussed in sections V and VIII of the CPP 

final rule preamble, the EPA concurs with commenters that emission trading lowers overall 

costs, adds flexibility, and makes it easier for sources to address pollution control objectives. 

Congress and the EPA have selected emission trading approaches when addressing national and 

regional pollution from the utility power sector contributing to problems such as acid 

precipitation and interstate transport of ozone and particulate matter. States will have every 

opportunity to design their section 111d plans to allow the affected EGUs in their respective 

jurisdictions to employ emissions trading approaches to achieve the standard of performance 

established in those plans.

The following are summaries of the specific public comments under this comment:

Commenters suggested that revenues from cap and trade programs can be used to fund 

renewable energy and energy efficiency programs. Commenters noted that states participating 

RGGI are investing revenue from allowance auctions in energy efficiency, clean and renewable 

energy, greenhouse gas abatement, and direct bill assistance programs. Commenters stated these 

investments in energy efficiency have helped six of the nine RGGI states rank in the top ten most 

energy efficient states, according to the American Council for an Energy Efficient Economy. 

Commenters also noted that Massachusetts invests approximately 90 percent of its RGGI 

proceeds in energy efficiency and as a result has been ranked the number one energy-efficient 

state for the last three years. Commenters stated an independent study by The Analysis Group 

found that RGGI states have realized a $1.6 billion net benefit from the first three years of the 

program due in large part to the energy efficiency investments that have reduced consumer 

electricity spending and increased economic activity (see 

http://www.analysisgroup.com/uploadedFiles/Publishing/Articles/Economic_Impact_RGGI_Rep

ort.pdf). Commenters stated the same study also found that the region would see a net increase of 

16,000 jobs due to these energy efficiency investments and other auction revenue spending. 

Commenters said participating states have found that RGGI captures the benefits of 

complementary state policies and has resulted in significant changes across the electricity system 

to reduce emissions. Commenters also said these include investments by power companies to 

make existing units more efficient, shifts across the electricity system to greater use of cleaner 

fossil-fuel generation sources, reduction of electricity load growth through demand-side energy 

efficiency strategies, and replacement of fossil-fuel generation with increased renewable energy.

Commenters compared the RGGI-driven CO2 emission reductions to the emission reductions 

that would result from the Existing Source Performance Standard and stated that calculations 

showed that the RGGI reductions are the greater of the two, underlining the contention that 

RGGI can be an adequate compliance mechanism.

Commenters noted that in 2012 RGGI states invested 73 percent of auction revenue in energy 

efficiency programs that are expected to save $1.8 billion on electricity bills over the lifetimes of 

the measures. Commenters also stated that between 2009-2012 RGGI auctions generated $912 

million or $33 per capita spread throughout the region, which was allocated as follows: 65 

percent to energy efficiency, 17 percent to direct bill assistance, 6 percent to clean and renewable 

energy, and 6 percent to GHG abatement. Commenters suggested that Coal-heavy states that join 
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regional programs could decide to direct auction revenue to worker retraining and economic 

diversification, and should be encouraged to do so. 

Commenters argued that participation in RGGI should fully satisfy EPA's current proposal, but 

acknowledged additional technical support materials will need to be provided to demonstrate 

equivalency. However, commenters took issue with the post-2030 reductions and contended that 

RGGI targets, which caps emissions then requires a 2.5 percent per year reduction from 2015 to 

2020, is more reasonable.

Comment 8: Commenters noted that trading programs could accelerate emission reductions.

Response 8: The EPA agrees with the commenters. Historically, evidence exists that trading 

programs provide cost-effective opportunities to make reductions early and sooner than might 

otherwise have happened. For instance, the Title IV Acid Rain program, established by the 

CAAA of 1990, had a national goal of 10 million tons of SO2 by the year 2010. Title IV was 

implemented by a mass-based cap and trade program which achieved the 10 million ton cap by 

2007. See sections V and VIII of the CPP final rule preamble for a discussion of emission 

trading.

The following are summaries of the specific public comments under this comment:

Commenters believed a trading program would allow EPA to accelerate the reduction of 

greenhouse gas emissions. Commenters suggested a 30% reduction in five to seven years and a 

50% or greater reduction by 2030 may be possible if a trading program is adopted.

Comment 9: Commenters expressed concern that that cap-and-trade programs may undermine 

economic planning due to price volatility of carbon allowances.

Response 9: Emission trading programs are discussed in section V and throughout section VIII 

of the CPP final rule preamble. Specifically in section VIII, see VIII.J.3 for mass-based trading 

approaches and VIII.K.2-4 for rate-based approaches. Economic impacts of the final rule are 

addressed in section XI of the CPP final rule preamble. Markets are inherently volatile but 

experience in the US with over 20 years of cap and trade programs and regional CO2 programs in 

the Northeast and California does not reflect the problems in the EU that the commenters raise.

The following are summaries of the specific public comments under this comment:

Commenters were concerned cap and trade programs may undermine economic planning due to 

volatility in the price of carbon allowances. Commenters specifically noted the volatility in the 

allowance prices in the European Union's Emission Trading System (ETS). Commenters noted 

that the price reached 47 Euros in 2008 and dropped to below 10 Euros in 2013. Despite 

intervention of the ETS, prices continued to fall and in March 2014 prices fell to 3.71 Euros, 

triggering stop-loss shutdowns. Commenters noted that the ETS has allowed some companies to 
284

reap windfalls due to the over allocation of allowances. Commenters also noted that the ETS has 

experienced problems with fraud. Commenters noted the spot marked had to be shutdown in 

2011 after a group of Eastern European hackers infiltrated the system, which cost European 

governments 5 billion Euros.

Comment 10: Commenters recommended the EPA evaluate allowance prices under the RGGI to 

determine impact on fuel diversity and determine whether third-party market participation is 

appropriate.

Response 10: EPA has not made an analysis of RGGI allowance prices and fuel diversity. In the 

US cap and trade markets, including the Acid Rain program, regional NOx and ozone programs, 

and RGGI and California GHG programs, anyone can purchase allowances and participate in the 

markets.

The following are summaries of the specific public comments under this comment:

Commenters observed that allowances purchased by RGGI - EGUs in 2013 and through June of 

2014 has declined. Commenters asked EPA to evaluate: 1) how the trend is impacting fuel 

diversity and 2) if third party (i.e., investors) market participation is appropriate.

Comment 11: Several commenters thought oversight of emissions trading was important; some 

recommended the EPA facilitate interstate trading by providing assistance with allowance 

tracking, measurement and verification, etc.

Response 11: The EPA is committed to working with states to provide support for tracking of 

allowances or credits to help implement multi-state trading or other multi-unit compliance 

approaches. See section VIII.K.3 of the CPP final rule preamble for discussions on allowance 

tracking and evaluation, measurement and verification.

The following are summaries of the specific public comments under this comment:

Several commenters were concerned that a cap and trade programs must include sufficient 

monitoring, verification, and enforcement controls to ensure compliance. Commenters believe 

EPA should facilitate interstate trading and ensure that other interested states are able to realize 

these types of benefits by providing assistance with tasks such as allowance tracking and auction 

administration. Commenters recommended the EPA develop a credit tracking system for states 

that wish to enter into trading programs that exchange emission reduction credits as valid 

compliance instruments and assist states with evaluation, measurement and verification (EM&V) 

for trading credits for energy efficiency programs. 

Commenters believed that if states have a good track record of administering trade programs, for 

example the RGGI states, then it may be appropriate for the EPA to delegate its authority 
285

provided the EPA includes robust requirements for monitoring, verifying and enforcing trading 

programs.

Commenters encouraged the EPA to provide the infrastructure for CO2 and MWh tracking and 

trading systems that states can choose to use (on an "opt-in" basis) for compliance with this rule. 

Commenters stated that such infrastructure could be similar to the system that Clean Air Markets 

Division (CAMD) provides now for tracking allowances under the acid rain, NOx SIP call and 

CAIR/CSAPR programs. Commenters noted that this system is already used to track CO2

emissions from power plants, and states could choose to structure programs to allow trading that 

utilizes this infrastructure.

Comment 12: Commenters recommended the EPA provide additional guidance to states 

wishing to implement a market-based trading program.

Response 12: See section VIII of the CPP final rule preamble under state plan approaches. The 

emission standards state plan approach covers both a rate-based approach and a mass-based 

emission standard with a market-based emission budget trading program. The state measures 

state plan type also addresses emission trading programs. Multi-state plans including multi-state 

coordination on rate-based emission trading programs and mass-based emission trading 

programs are further covered in section VIII of the CPP final rule preamble. Specifically in 

section VIII, see VIII.J.3 for mass-based trading approaches and VIII.K.2-4 for rate-based 

approaches. Note also that concurrent with this final rule, the EPA is proposing a Federal Plan 

with model rules that states may consider in developing their plans.

The following are summaries of the specific public comments under this comment:

Commenters asked that EPA give states additional guidance on how to implement a flexible 

market mechanism. Carbon fees and allowance trading both are statutorily authorized 

implementation tools. Commenters believed that this guidance would reduce states' uncertainty 

and encourage the adoption of efficient approaches.

Comment 13: Several commenters recommended the EPA provide a model rule for an interstate 

emissions trading program that could be adopted by states.

Response 13: The EPA is proposing a federal plan concurrently with this CPP final rule which 

states could use as a model rule. Both rate-based and mass-based trading are addressed in the 

proposed federal plan.

The following are summaries of the specific public comments under this comment:

Commenters recommended the EPA provide a model rule for an interstate emissions credittrading program that could be easily adopted by states. Commenters believed a model rule would 

help states establish appropriate trading and ceiling policies that complies with the section 111(d) 

guidelines. 
286

Commenters noted that a similar approach was taken by the Agency for the NOx SIP Call and 

that states that included the model rule in their SIPs enjoyed a streamlined SIP approval process, 

while sources involved in the program "reaped substantial cost savings and increased compliance 

flexibility." Commenters also described the basic elements of the NOx SIP Call, which are 

equally appropriate for the CPP, and recommended that the EPA include an allowance "setaside" for new fossil EGUs in any model CO2 budget-trading program in an amount necessary to 

account for projected growth through 2030. 

• Commenters stated that states participating in the model program would be 

required to include emissions from new fossil-fired generation under the cap, and 

allowances to such units would be allocated only from the new-source set-aside so 

that state budget cap would not be increased.

• Commenters noted that states could decide how to allocate the set-aside 

allowances (e.g., auctioned to new units, allocated based on a new source 

emission standard established under section 111(b), or some other method) and 

that unused allowances in the set-aside could be returned each year to the state's 

general allowance pool for existing units or retired.

• Commenters recommended the EPA provide states with incentives to adopt massbased allowance trading systems with an emissions cap. Commenters believed the 

EPA could structure voluntary incentives for emission allowance trading in a 

number of ways, including: (a) creating a complete mass-based trading system for 

voluntary adoption by states, similar to that employed in the NOx SIP Call; or (b) 

providing detailed guidance to states wishing to (1) create new regional massbased allowance trading systems, or (2) join existing systems such as RGGI or the 

California Global Warming Solutions Act Program, or (3) trade allowances with 

other states that have non-identical (but mass-based) implementation plans.

• Commenters recommended the CO2 budget-trading program should also address 

unit retirements. A reasonable approach would allow states, participating in the 

allowance trading program, to permit units that retire (or announce retirement) 

following the submission date for the state's 111(d) plan to retire before 2030 to 

retain their allowances until 2030, and those that retire during or after 2030 would 

not retain any allowances post-retirement. This would provide units with an 

incentive to retire prior to 2030, but would take full environmental advantage of 

those retirements starting in 2030.

Comment 14: Commenters recommended the EPA provide guidance for multi-state plans.

Response 14: See section VIII.C.5, VIII.J.3, and VIII.K.4 of the CPP final rule preamble on 

state plan approaches, multi-state coordination of mass-based emission trading programs, and 

multi-state coordination of rate-based trading programs, respectively. These subsections discuss

multi-state plans that addresses multi-state coordination through joint emission goals; multi-state 

coordination among states retaining individual state goals; multi-state coordination on rate-based 
287

emission trading programs; multi-state coordination on mass-based emission trading programs; 

multi-state plans that address a subset of EGUs in a state; and legal issues regarding multi-state 

plans.

The following are summaries of the specific public comments under this comment:

Several commenters recommended the EPA provide guidance to states wishing to implement 

mass-based allowance trading programs, including providing assistance to states wishing to 

develop multi-state trading programs. Commenters stated that the EPA could allow states to 

build on existing mass-based allowance programs, such as RGGI and the California Global 

Warming Solutions Act program.

Commenters noted, however, that these existing programs would have to be adapted for the 

section 111(d) guideline by removing the offsets in the RGGI program and limiting the sources

who could trade allowances in the California program.

Commenters stated that several states could establish a trading system without adopting identical 

trading plan provisions. Commenters believed that such as approach could appeal to states that 

want to take advantage of a mass-based allowance trading but do not agree on all aspects of a 

single trading program. Commenters noted, however, that the EPA would need to ensure that the 

trading program provisions of each state were compatible, capable of practical implementation, 

did not compromise the integrity of the section 111(d) requirements, and would meet the CPP 

state targets in the aggregate for all of the participating states.

For such cases, commenters recommended EPA's guidance specify the minimum criteria for the 

program, including rules for banking, borrowing, and a comparable price cap. Commenters

stated that the trading programs must include a cap on total emissions, that "self-correcting" 

provisions be structured around a single interim compliance period, and allow for banking within 

this period in accordance with the program's allowance allocation processes.

Commenters believed a model CO2 budget-trading program should also address unit retirements. 

Commenters noted that retirement of existing high-emitting units can be a substantial source of 

overall system emission reductions, but that benefit can be compromised if retiring units are 

permitted to retain their original allowance allocation indefinitely. Commenters stated that 

requiring allowances to be immediately retired upon unit retirement could provide a disincentive 

for those units to retire in a timely fashion. Commenters believed that a balanced approach would 

allow states participating in the allowance trading program to permit units that retire (or 

announce retirement) following the submission date for the state's 111(d) plan and retire before 

2030 to retain their allowances until 2030, and those that retire during or after 2030 would not 

retain any allowances post-retirement. Commenters stated using this approach provides units 

with an incentive to retire prior to 2030, but would take full environmental advantage of those 

retirements starting in 2030.

Commenters argued the EPA's proposed multi-state trading program is unnecessarily complex 

and stated that trading programs should not require states to complete a complicated interstate 

compact or memoranda of understanding. Commenters stated if a state has an approved section 

111(d) plan, then that state should be able to trade credits (i.e., emissions or energy) with any 
288

other state that also has an approved plan without having to create any additional agreement. 

Absent this simplified approach, commenters believed states with less stringent emission 

reduction goals may be unlikely to pool their requirements with states subject to more stringent 

goals.

Comment 15: Commenters recommended carbon sequestration by agriculture be incorporated 

into cap-and-trade programs.

Response 15: Measures that reduce CO2 emissions outside the electric power sector may not be 

counted toward meeting a CO2 emission performance level for affected EGUs or a state CO2

goal, under either a rate-based or mass-based approach, because all of the emission reduction 

measures included in the EPA’s determination of BSER reduce CO2 emissions from affected 

EGUs. See section VIII.K.1 of the CPP final rule preamble. Examples of measures that may not 

be counted toward meeting a CO2 emission performance level for affected EGUs or a state CO2

goal include GHG offset projects representing emission reductions that occur in the forestry and 

agriculture sectors, direct air capture, and crediting of CO2 emission reductions that occur in the 

transportation sector as a result of vehicle electrification. We note, however, that the final 

emission guidelines allow state measures like emission budget trading programs to include outof-sector GHG offsets. For example, both the California and RGGI programs allow for the use of 

allowances awarded to GHG offset projects to be used to meet a specified portion of an affected 

emission source’s compliance obligation.

The following are summaries of the specific public comments under this comment:

Commenters believed carbon sequestration through agriculture should be incorporated into cap 

and trade programs by adding "Agricultural Carbon Credits" to the Cap and Trade program. 

Commenters believed the soil is the world's second largest and the most accessible carbon sink 

for carbon sequestration. Commenters noted that recent research suggests that a two percent 

increase in world soil organic matter could sequester all of the excess carbon dioxide in the 

atmosphere within ten years. Commenters stated proven agricultural techniques for increasing 

the percent organic matter of soil, include intensive rotational grazing of grassland, along with 

cover crops and minimum tillage for arable lands. Commenters argued that these farming 

techniques are readily available from any County Extension Office, as well as numerous sources 

online. Commenters believe that Agricultural Carbon Credits would provide the incentive needed 

to encourage ranchers and farmers to adopt these practices. Commenters stated the carbon 

content of soils can be determined from common soil test results. By adding Agricultural Carbon 

Credits to the Cap and Trade program, commenters believed the EPA would promote a cost 

effective method of moving carbon from the atmosphere back to the soil where it is needed to 

feed the people. 

Comment 16: Commenters recommended carbon sequestration by forests be allowed in state 

plans to encourage investment in forests by states and utilities.

Response 16: Measures that reduce CO2 emissions outside the electric power sector may not be 
289

counted toward meeting a CO2 emission performance level for affected EGUs or a state CO2

goal, under either a rate-based or mass-based approach, because all of the emission reduction 

measures included in the EPA’s determination of BSER reduce CO2 emissions from affected 

EGUs. See section VIII.K of the CPP final rule preamble. Examples of measure that may not be 

counted toward meeting a CO2 emission performance level for affected EGUs or a state CO2

goal include GHG offset projects representing emission reductions that occur in the forestry and 

agriculture sectors, direct air capture, and crediting of CO2 emission reductions that occur in the 

transportation sector as a result of vehicle electrification. We note, however, that the final 

emission guidelines allow state measures like emission budget trading programs to include outof-sector GHG offsets. For example, both the California and RGGI programs allow for the use of 

allowances awarded to GHG offset projects to be used to meet a specified portion of an affected 

emission source’s compliance obligation.

The following are summaries of the specific public comments under this comment:

Commenters maintained the final rule should include forest offsets. Commenters stated forests 

can sequester carbon dioxide back into soil, produce biomass and durable products. Commenters 

stated these benefits can be achieved through a system of direct investment by States and/or 

EGUs at costs in the range of $10-20/ton which is lower than projected costs of emissions 

reductions within EPA's four building blocks. Commenters said state compliance mechanisms 

within a SIP could generate revenue to partially or entirely fund forests, and that alternatively, 

states can provide mechanisms to work with landowners or developers.

Comment 17: Commenters recommended the EPA establish set-asides for Tribes for interstate 

emissions credit trading programs.

Response 17: For areas of Indian country with affected EGUs where a tribe has not applied for 

TAS and submitted any needed plan, if the EPA determines that a CAA section 111(d) plan is 

necessary or appropriate, the EPA would have the responsibility to establish the plans. Tribes are 

not required to implement section 111(d) plans and no tribe has yet sought TAS eligibility for 

this purpose. See section XII.F of the CPP final rule preamble for a summary of description of 

the implications of the rule for tribes, as well as the consultation and coordination process the 

EPA has engaged in with Tribal governments. The agency is proposing to find that it is 

necessary or appropriate to implement a section 111(d) federal plan for the affected EGUs 

located in Indian country. CO2 emission performance rates for these facilities were finalized in 

the emission guidelines in the CPP final rule. See section VII. Tribes generally may seek 

“treatment as a state” (TAS) and submit a tribal plan to implement CAA programs, including 

programs under section 111(d), and this proposed finding does not preclude tribes from doing 

that. However, tribes are not subject to the deadlines applicable to state action under the emission

guidelines and in the absence of a federal plan, CO2 emissions from these EGUs could go 

unregulated. EPA did not propose tribal set-asides as part of the final rule but tribes will have the 

opportunity to comment on the federal plan proposal that is concurrent with this final rule.

The following are summaries of the specific public comments under this comment:
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Commenters recommended the EPA establish a Tribal set-aside as part of an interstate emissions 

credit trading program. Commenters noted that a similar approach was taken by the Western 

Regional Air Partnership (WRAP), where an annual SO2 tribal set-aside of 20,000 tons was 

made available to Indian Tribes within the nine-state region. Commenters asserted that a setaside would help to ensure equitable treatment for tribal economies and prevent barriers to future 

economic development. 

Commenters stated the integrated nature of the electricity grid, in which these jurisdictions do 

participate means that actions taken there do enable reduced utilization of designated facilities 

elsewhere on the grid. The question that remains is how CO2 emissions avoided through low- or 

zero-carbon energy generation and energy efficiency measures in these jurisdictions could be 

used to adjust or credit CO2 emission rates in states covered by the CPP. [SNPRM, 79 Fed. Reg. 

at 65,496.] Commenters' explained that states, and tribal or territorial areas without designated 

facilities must make a submittal to certify that there are no designated facilities within the 

pertinent areas, and where relevant, must make clear the intention with respect to the future of

any already retired designated facilities. To the extent that EPA finalizes a regional approach to 

BSER based on the potential for building block 3 and 4 resources in these jurisdictions to reduce 

CO2 emissions from designated facilities, the jurisdictions must submit plans or statements 

certifying or confirming the resources available or projected to reduce utilization of designated 

facilities in other states. And, Commenters expressed that, should a state, tribe, or territorial area 

seek allowances under any mass-based allowance trading compliance system, there must be 

some basis for tracking the renewable or their low- or zero-carbon resources within their 

boundaries, which can be provided by such plan or certification.

Comment 18: Several commenters asked for clarification on whether emission offsets could be 

used in a cap-and-trade program and whether entities other than utility boilers could particulate 

in such programs. 

Response 18: See section VIII of the CPP final rule preamble. Measures that reduce CO2

emissions outside the electric power sector may not be counted toward meeting a CO2 emission 

performance level for affected EGUs or a state CO2 goal, under either a rate-based or mass-based 

approach, because all of the emission reduction measures included in the EPA’s determination of 

BSER reduce CO2 emissions from affected EGUs. Examples of measure that may not be counted 

toward meeting a CO2 emission performance level for affected EGUs or a state CO2 goal include 

GHG offset projects representing emission reductions that occur in the forestry and agriculture 

sectors, direct air capture, and crediting of CO2 emission reductions that occur in the 

transportation sector as a result of vehicle electrification. We note, however, that the final 

emission guidelines allow state measures like emission budget trading programs to include outof-sector GHG offsets. For example, both the California and RGGI programs allow for the use of 

allowances awarded to GHG offset projects to be used to meet a specified portion of an affected 

emission source’s compliance obligation.

The following are summaries of the specific public comments under this comment:
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Commenters requested clarification on whether emission "offsets" generated by energy 

efficiency improvements and power generated by renewable energy (i.e., building blocks 3 and 

4) would be eligible to participate in a cap and trade market. Commenters also asked whether an 

affected EGU can use an offset to demonstrate compliance with emission performance or the 

offset can only be used in complying with emission limits.

Commenters argued that any offsets would enable those facilities to continue emitting and would 

increase emissions of co-pollutants without a corresponding decrease in emissions from other 

facilities covered by the program. Commenters noted that environmental justice communities 

could be impacted by increases in co-pollutant reductions if offsets are allowed. Commenters 

also noted that certain offsets, such as those resulting from biological carbon sequestration, 

would complicate emissions monitoring, as these projects are difficult to verify.

Commenters stated that distributing the legal obligation to hold allowances among entities other 

than power plants only complicates the administration and enforcement of a trading program. 

Commenters argued that these out-of-sector offsets have been demonstrated. Commenters stated 

The California Global Warming Solutions Act of 2006 ensures the reliability of out-of-sector 

offsets is through the concept of "additionality." Commenters stated CARB's program has 

withstood challenge on the grounds that the additionality standard was insufficient (see San 

Francisco Sup. Ct. filing Mar. 27, 2012).

Commenters recommended the EPA accommodate a diversity of trading program designs, 

including economy-wide trading programs; specifically "umbrella" policies that include emission 

reductions from complementary programs, such as renewable portfolio standards, emission

reduction programs directed at other pollutants, as well as fuel switching and power plant energy 

efficiency.

Comment 19: Commenters recommended emission allowances for trading programs be 

auctioned rather than allocated by the state to avoid windfall profits for utilities and to raise 

revenue for addressing environmental justice concerns.

Response 19: See section VIII of the CPP final rule preamble for a discussion on emission 

trading programs. An emission budget trading program establishes a combined emission standard 

for a group of emission sources in the form of an emission budget. Emission allowances are 

issued in an amount up to the established emission budget. Allowances may be distributed to 

affected emission sources through a number of different methods, including direct allocation to 

affected sources or auction. States are able to establish auctions for distribution of allowances, as 

is done in the RGGI and California GHG programs.

The following are summaries of the specific public comments under this comment:

Commenters recommended states auction allowances for cap and trade programs because they 

believe that requiring sources to pay for the right to pollute forces them to internalize these costs, 

reduces the potential for windfall profits, and the revenues can be used to address environmental 

justice concerns. 
292

Comment 20: Commenters expressed concern that power plants will “buy their way out of 

compliance” if allowed to use trading programs.

Response 20: The CPP final rule is a national program that has established source categoryspecific CO2 emission performance rates for electric steam generating units and combustion 

turbines. The EPA has translated these performance rates into equivalent state-level rate-based 

and mass-based CO2 goals in order to maximize the range of choices that states will have in 

developing their plans. The EPA has also finalized three interim performance periods, each with 

its own milestone, as well as an interim goal (wherein the state must demonstrate it has met its 

interim goal on average over the eight years of the period), and a final goal. States must 

demonstrate starting in 2025 that reductions are occurring as reflected in the state’s 111d plan. 

EGUs must also achieve the final CO2 performance rates or equivalent statewide goal by 2030 

and maintain that level subsequently. Trading programs are an approach to compliance that 

afford cost-effectiveness and flexibility but also achieve needed reductions. See sections VIII.J 

and K of the CPP final rule preamble for a discussion of mass-based and rate-based trading, 

respectively.

The following are summaries of the specific public comments under this comment:

Commenters were concerned that some companies "will buy their way out of compliance" if 

states are allowed to use market-based trading programs.

Comment 21: Commenters were concerned emissions trading programs would increase the 

costs of energy production.

Response 21: This has not been the EPA’s experience. The now historic Title IV Acid Rain 

Program, which Congress authorized in the 1990 CAAA, was the most successful, cost-effective 

national emission reduction program promulgated to date. It reduced sulfur dioxide from power 

plants across the country under a cap and trade program that allowed sources to adjust 

operations, install pollution control equipment, switch fuels to meet requirements, and other 

flexibilities which kept the electric system stable and reliable and was cost effective. Most 

important, it achieved huge reductions earlier and faster than anticipated, delivering health 

benefits to the public and improved air quality. Ultimately, the 2010 cap of 10 million tons of 

SO2 nationwide was met in 2007. By putting a cost on pollution, trading programs encourage the 

most cost-effective and efficient units to operate. Regarding brokers and middle men, EPA does 

not regulate such markets. Regarding transaction costs, the EPA addressed perceptions about 

transaction costs in a previous proposal (that uses a cap and trade program) to which we refer the 

commenter: see 75 FR 45316, August 2, 2010. This section of the Transport Rule (CSAPR) 

preamble describes a literature search on transaction costs that the EPA performed. We found no 

indication that transaction costs have been a problem. The EPA further determined that there is 

enough competition among the dozen or so brokerage houses that any attempt at charging fees in 

excess of market standards will be bid down through competition. See section XI of the CPP 

final rule preamble for a discussion of the impacts of the final rule, such as energy impacts, 
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compliance costs, and economic and employment impacts. Also see the RIA in the docket for the 

CPP final rule for a discussion of costs and benefits of the final CPP rule. For discussions on 

trading in the CPP final rule, see sections V and VIII of the CPP final rule preamble. Specifically 

in section VIII, see VIII.J.3 for mass-based trading approaches and VIII.K.2-4 for rate-based 

approaches. Note also that concurrent with this final rule, EPA is proposing a Federal Plan with 

model rules that states may consider in developing their plans.

The following are summaries of the specific public comments under this comment:

Commenters opposed emissions trading because they believe it does not reduce emissions and 

increases the costs of energy production and energy use by creating additional brokers and 

middle men in the price setting transaction process.

Comment 22: Several commenters were concerned that emissions trading programs would 

increase pollution in economically disadvantaged communities, including Tribal areas.

Response 22: The EPA disagrees with these comments and has worked hard throughout the 

proposal and final rule promulgation process with stakeholders, tribes, and vulnerable

communities to address issues of concern including environmental justice. See section IX of the 

CPP final rule preamble on community considerations as well as sections XII.F and J. For 20 

years EPA has implemented emission trading programs addressing criteria pollutants, starting in 

1995 with the Congressionally-mandated Title IV Acid Rain program. Throughout these years, 

we have addressed issues of concern regarding trading. We have found no evidence that trading 

causes increases in emissions, localized impacts, or other disproportionate impacts on vulnerable

communities. Historically we have seen the greatest reductions under our cap and trade programs 

in the states with the highest emissions. Independent analyses by organizations such as the 

Environmental Law Institute, Resources for the Future, and Environmental Defense Fund, as 

well as Massachusetts Institute of Technology, have found that trading has not created “hot 

spots”. Additionally, the Clean Air Act provides “backstops” for federal regulations in that states 

and localities have the authority under Title 1 to address persistent air quality problems. States 

and localities may impose stricter limits on sources to address specific local air quality concerns. 

These limits must be met regardless of a source’s accumulated allowances or credits. States and 

sources across the nation are familiar with the EPA’s cap and trade programs and under the CPP 

can build on these programs. However CO2 is different from the criteria pollutants such as NOx 

and SO2 that we regulate. CO2 is a global pollutant in that the location of its emission does not 

affect the location of the environmental harm it causes. See the proposed rule and section II of 

the CPP final rule preamble for more information on the characteristics of CO2 pollution.

The following are summaries of the specific public comments under this comment:

Commenters expressed concern that cap and trade approach would potentially increase 

emissions of other pollutants (e.g., SO2, NOx, VOC, air toxics) in some areas. Commenters were 

particularly concerned that a cap and trade program would create "hot spots" of air toxic 

emissions in economically disadvantaged areas, areas with high minority populations, and areas 
294

with low income communities. Commenters stated that the proposed rule currently contains no 

systems to ensure that greenhouse gas reductions occur in communities that would benefit the 

most from co-pollutant reductions. Commenters recommend provisions be included in the final 

rule to mitigate the disparate impacts of a cap and trade program. Commenters suggested the 

EPA identify high priority pollution zones where polluters would pay a higher price for their 

greenhouse gas emissions or impose other provisions that would provide a strong incentive for 

industries to reduce emissions in disadvantaged areas impacted by a cap and trade program. 

Commenters argued that any flexible approaches will not apply, and are not transferrable to, 

emissions of hotspot pollutants from power plants. Commenters recommended that once a capand-trade program is in place, state regulators should monitor facilities located in or surrounding 

these communities to ensure compliance with their obligations under the program and 

communities should be encouraged to report any actions by facilities that they believe are in 

violation of these requirements.

Commenters were concerned about impacts on tribal areas and recommended the EPA require 

the following provisions in approvable state implementation plans: 

• restrictions on allowance allocations and offsets for individual EGUs that have the worst 

health impacts on nearby communities due to their high-levels of co-pollutants; and 

• include controls to ensure reductions in co-pollutants near Tribal lands.

Comment 23: Commenters recommended cap-and-trade programs include stringent 

requirements regarding allocation of allowances to ensure states do not over-allocate allowances.

Response 23: See section VIII of the CPP final rule preamble for multiple discussions on trading 

programs under the different state plan approaches. Section V.A also discusses the role of 

emission trading. Specifically in section VIII, see VIII.J.3 for mass-based trading approaches and 

VIII.K.2-4 for rate-based approaches. Note that in the course of the 8 year interim compliance 

period, the CPP final rule requires states to report to the EPA 3 times, starting in 2025, to 

demonstrate compliance with the stated goals in their approved state plan. In developing state 

plans, states that decide to implement emission trading programs, for instance on a mass basis,

would have a mass-based goal or budget of allowable emissions during the compliance periods. 

States would not be able to allocate allowances greater than the budget. For state plans to be 

approvable by the EPA, states have to demonstrate that they will attain the performance rates or 

mass-based or rate-based equivalent state goals. The EPA can enforce against violating EGUs if 

actual CO2 emission performance exceeds a state plan’s specified level for an interim period step 

or final plan reporting period by 10% or more. The RECLAIM program differs from the regional 

and national trading programs the EPA has developed and implemented. The RECLAIM trading 

program was established to address local air pollution problems; it does not permit banking to 

deal with short term price volatility that results from endogenous or exogenous factors; it overallocated allowances in the early years allowing for an increase in emissions over historical 

levels for many sources; it has a very substantial administrative review process of reviewing all 

transactions that impacts confidence in the markets and transparency; it did not incentivize 
295

technological innovation; and has a limited/small number of participants due to its local nature.

EPA does not find the RECLAIM program analogous to the national program set forth in this 

final rule.

The following are summaries of the specific public comments under this comment:

Commenters recommended the cap adopted by states implementing cap and trade programs 

should be stringent enough to ensure the state goal is met and should not over-allocate 

allowances. Commenters supported the approach taken by California's AB32 program, where the 

cap in 2013 was set at 2 percent below the emissions level forecast for 2012, was decreased by 2 

percent in 2014, and will be reduced by 3 percent annually from 2015 to 2020. As an example of 

the problems that may occur if states over-allocate allowances, commenters noted that the 

RECLAIM trading program for criteria pollutants in which large utilities opted to purchase 

allowances instead of adopting control technology and the program consequently failed to 

produce expected emissions reductions. 

Comment 24: Commenters expressed concern that trading programs would promote business as 

usual and could provide "windfall" profits for some companies.

Response 24: We do not anticipate the same issues, including “windfall profits,” that 

commenters are concerned about which have occurred in the past in other countries, such as the 

EU ETS, but which have been subsequently resolved. Section VIII.C of the CPP final rule 

preamble describes state plan approaches and addresses emission budget trading programs under 

the state measures plan type as well as rate-based emission trading programs. States may choose 

to adopt source category-specific CO2 emission performance rates in lieu of other approaches. 

However, the EPA believes that the requirements for state reports on the state plan program’s 

performance, implementation milestones, and status updates during the interim compliance 

period and at the final goal and beyond, should ensure the reductions the rule requires. For 

instance, there are 3 interim reporting periods, starting in 2025. The final goal is in 2030. The 

EPA can enforce against any EGUs that are violating by 10% or more a state plan’s specified 

level for an interim period step or final plan reporting period. 

The following are summaries of the specific public comments under this comment:

Commenters argued carbon trading programs tend to reward the heaviest polluters with 

"windfall profits" when they are granted enough carbon credits to match historic production. 

Commenters further believed that carbon trading encourages business-as-usual, tends to 

discourage less expensive long-term structural changes, and encourages use of cheap "offset" 

carbon credits from less developed countries where they may be generated by local polluters at 

the expense of local communities. Commenters stated the same argument, they believe, can be 

made against emission averaging. 

Commenters agreed that emissions averaging and trading are allowable under section 111(d) but 

stated that an averaging and trading programs do not justify a more stringent BSER 

determination by the EPA.
296

Commenters questioned whether new source categories could be added to an EGU cap and trade 

program. Commenters believed that states would have to set up separate cap and trade programs 

for different categories because allowances for one source category would not be fully fungible 

with allowances from other source categories.

Commenters maintained a cap-and-trade system will impose an unnecessarily large burden on 

consumers and it will substantially impair the competitiveness of any jurisdiction that adopts it. 

Commenters stated revenue generated from a cap-and-trade auction would not benefit consumers 

because industry would lobby for a set-aside of free allowances allocated by a political or 

administrative process. Commenters described one emission trading system that minimizes the 

cost increase to consumers; emissions trading combined with an intensity constraint. 

Commenters said States require all sources to comply with the same carbon intensity constraint, 

and there is no fixed pool of allowances to be allocated, and no central authority need collect any 

tax or pay any subsidy. Commenters stated that determining the targets for the states may require 

national coordination and safety valve mechanism to prevent price spikes. Commenters stated 

EPA used this approach to control lead in gasoline in 1982.

Comment 25: Commenters supported restrictions being placed on areas where allowances can 

be traded to avoid emissions increases in areas with disadvantaged communities.

Response 25: The EPA disagrees that allowance trading causes increased emissions in areas 

with vulnerable communities. In the CPP final rule, states are required to demonstrate interaction 

with vulnerable communities in the development of their state plans prior to submitting those to 

the EPA for approval. Additionally, section VIII.E discusses the consequences if actual emission 

performance does not meet the CO2 emission performance rates or state CO2 emission goal – in 

essence, in some cases the EPA can enforce against an EGU that exceeds a state plan’s specified 

level by more than 10% in an interim period step reporting period or final plan reporting period. 

The EPA has established three interim reporting periods starting in 2025 and the final goal 

reporting period in 2030 and subsequently thereafter which should enable the agency and the 

public to know if there are areas where reductions are not being achieved. For 20 years the EPA 

has implemented emission trading programs addressing criteria pollutants, starting in 1995 with 

the Congressionally-mandated Title IV Acid Rain program. Throughout these years, we have 

addressed issues of concern regarding trading. We have found no evidence that trading causes 

increases in emissions, localized impacts, or other disproportionate impacts on vulnerable

communities. Historically we have seen the greatest reductions under our cap and trade programs 

in the states with the highest emissions. Independent analyses by organizations such as the 

Environmental Law Institute, Resources for the Future, and Environmental Defense Fund, as 

well as Massachusetts Institute of Technology, have found that trading has not created “hot 

spots”. States and sources across the nation are familiar with EPA’s cap and trade programs and 

under the CPP can build on these programs. However CO2 is different from the criteria pollutants 

such as NOx and SO2 that we regulate. CO2 is a global pollutant in that the location of its 

emission does not affect the location of the environmental harm it causes. See the proposed rule 
297

and section II of the CPP final rule preamble for more information on the characteristics of CO2

pollution. The RECLAIM program differs from the regional and national trading programs EPA 

has developed and implemented. The RECLAIM trading program was established to address 

local air pollution problems; it does not permit banking to deal with short term price volatility 

that results from endogenous or exogenous factors; it over-allocated allowances in the early 

years allowing for an increase in emissions over historical levels for many sources; it has a very 

substantial administrative review process of reviewing all transactions that impacts confidence in 

the markets and transparency; it did not incentivize technological innovation; and has a 

limited/small number of participants due to its local nature. The Clean Air Act provides 

“backstops” for federal regulations in that states and localities have the authority under Title 1 to 

address persistent air quality problems. States and localities may impose stricter limits on sources 

to address specific local air quality concerns. These limits must be met regardless of a source’s 

accumulated allowances or credits.

The following are summaries of the specific public comments under this comment:

Commenters supported spatial restrictions on trading of allowances to prevent unacceptable 

pollutant concentrations in certain areas. Commenters stated that this approach would avoid 

"emission hot spots," particularly in areas with disadvantaged communities. Commenters noted 

that this approach is used in the Los Angeles Regional Clean Air Incentives Market 

("RECLAIM") program, which prohibits sources in the downwind zone from trading allowances 

with zones in the upwind zone. Commenters also suggested states should not prohibit trading but 

instead should discourage trading between sources outside the zone and those inside the zone.

Commenters noted this can be accomplished by requiring a greater number of allowances per ton 

of emissions or charging higher allowance prices for sources located within these zones.

Comment 26: Commenters disagreed with those who suggested emissions trading programs 

would result in emission hot spots because the environmental impacts of increased CO2

emissions are global.

Response 26: The EPA agrees with commenters that CO2 is a global pollutant in that the 

location of its emission does not affect the location of the environmental harm it causes. For 20 

years the EPA has implemented emission trading programs addressing criteria pollutants, starting 

in 1995 with the Congressionally-mandated Title IV Acid Rain program. Throughout these 

years, we have addressed issues of concern regarding trading. We have found no evidence that 

trading causes localized impacts. Historically, we have seen the greatest reductions under our cap 

and trade programs in the states with the highest emissions. Independent analyses by 

organizations such as the Environmental Law Institute, Resources for the Future, and 

Environmental Defense Fund, as well as Massachusetts Institute of Technology, have found that 

trading has not created “hot spots”. States and sources across the nation are familiar with EPA’s 

cap and trade programs and under the CPP can build on these programs.

The following are summaries of the specific public comments under this comment:
298

Commenters noted that one potential drawback of allowance trading systems over broad 

geographic regions is that they do not ensure similar emission reductions throughout the affected 

region because some sources may choose to use allowances to emit above the required emission 

level, while other sources emit below the level. Commenters noted that this creates the potential 

for certain areas to experience decreases in emissions, while other areas experience increases in 

emissions. However, commenters believed this would not be a problem in the context of the 

CPP, because CO2 impacts are not localized. 

Comment 27: Commenters recommended the EPA encourage regional cap-and-trade programs

to link with other programs, as has already occurred with the California and Quebec trading 

programs.

Response 27: The CPP final rule establishes several approaches, options, and flexibility for 

states in developing state plans to implement their standards. See sections V and VIII for 

discussions on trading. Section VIII.J addresses considerations for mass-based emission trading 

approaches while section VIII.K addresses considerations for rate-based approaches. Section 

VIII also covers multi-state coordination and multi-state plans. The EPA encourages state 

partnerships and coordination in achieving the goals in the emission guidelines.

The following are summaries of the specific public comments under this comment:

Commenters recommended the EPA encourage states and regional programs to links their cap 

and trade programs. Commenters noted that the California program has already been linked with 

the Quebec program and that studies of how to link the California program with RGGI have also 

been undertaken by "Resources for the Future."

Comment 28: Some commenters recommended states adopting cap-and-trade programs should 

include provisions to protect minority and low income communities.

Response 28: The EPA has been engaged vulnerable communities throughout the entire CPP 

development, proposal, and final promulgation process. We have conducted trainings and 

webinars for communities and also have participated in a number of in person meetings and 

conference calls for communities and stakeholders representing communities. Community 

concerns are addressed in section IX of the CPP final rule preamble and in section XII.J. In the 

CPP final rule, states are required to demonstrate interaction with communities in the 

development of their state plans prior to submitting those to the EPA for approval. Furthermore, 

the agency provides recommendations on how states can engage meaningfully with communities 

in sections VIID-E and IX.B. Additionally, section VIII.E discusses the consequences if actual 

emission performance does not meet the CO2 emission performance rates or state CO2 emission 

goal – in essence, the EPA can enforce against an EGU that exceeds a state plan’s specified level 

by more than 10% in an interim period step reporting period or final plan reporting period. The 

EPA has established three interim reporting periods starting in 2025 and the final goal reporting 
299

period in 2030 and subsequently thereafter which should enable the agency and the public to 

know if there are areas where reductions are not being achieved. The EPA also discusses 

community concerns in, among other areas, section I under outreach and resources for 

stakeholders; section II under stakeholder outreach and consultations; section IX on community 

considerations; section XI on impacts of the final rule; and sections XII.F and J. Recognizing 

that low-income communities are often under-represented in RE and EE investment, EPA is 

providing additional incentives to encourage such investments that benefit low-income 

communities. EPA is providing a Clean Energy Incentive Program to reward early investments 

in certain renewable energy (RE) and demand-side energy efficiency (EE) projects that generate 

carbon-free MWh or reduce end-use energy demand during 2020 and 2021. State participation in 

the program is optional. 

The following are summaries of the specific public comments under this comment:

Commenters recommended the EPA require states adopting cap and trade programs to include 

provisions that will ensure protection of minority and low income communities. Commenters

noted that California's AB32 rule included provisions that required the California Air Resources 

Board (CARB) to: (1) consider the potential impacts on disadvantaged communities during the 

development of the program; and (2) establish an environmental justice advisory committee 

comprised of representatives from communities that have significant exposure to air pollution. 

Commenters believed the EPA should incorporate similar steps into the final rule. Commenters

also suggested the EPA consider undertaking a targeted outreach program for these communities 

and provide financial resources so that these communities can participate in the development of 

cap-and-trade programs. 

Commenters suggested the EPA require states adopting a cap-and-trade program complete an 

environmental impact review as part of their program. This environmental impact review,

commenters stated, should include a cumulative impact assessment that follows existing 

methodologies and EPA guidelines. Commenters believed this analysis will help design the 

trading program in a manner that avoids the creation of emission hotspots and that distributes the 

benefits from trading to these communities. 

Commenters stated that a portion of the revenues from allowance auctions should be used to 

address the reduction of co-pollutants in environmental justice communities, such as targeted 

investments in demand-side energy efficiency, renewable energy, and in projects to revitalize 

environmental justice communities. Commenters noted that in California SB 535 and AB1532 

mandates the California Department of Finance to allocate 25 percent of AB32 auction revenues 

to projects that provide benefits to vulnerable communities, with at least 10 percent to be spent 

directly in communities identified as disadvantaged based on geographic, socioeconomic, public 

health, and environmental pollution. Commenters stated that the bill includes a requirement to 

develop a three year investment plan with public participation in the program ensured by the 

requirements to hold two public workshops and one public hearing. Commenters further noted 

that where investment programs are adopted, the EPA should require the state to submit detailed 

information that shows that the earmarked funds are being used in projects that benefit 

environmental justice communities. 
300

Commenters acknowledged that increases in emissions in areas near environmental justice 

communities would occur as the result of a cap and trade program, but recommended state 

regulators monitor facilities located in or near these communities for co-pollutant emissions and 

required reporting of any increases in co-pollutant emissions that result from the cap and trade 

program. Commenters also stated that environmental justice communities should be encouraged 

to report any actions by facilities that they believe are in violation and should have access to the 

facility's trading transactions and emission levels. 

Commenters supported a cap and trade program because they believe it will also benefit public 

health through reducing emissions of co-pollutants.

Comment 29: Commenters recommended the EPA allow averaging across power plants owned 

by the same company. 

Response 29: The EPA does include averaging in the CPP final rule. See section VIII of the CPP 

final rule preamble and also the Rate-based Program Accounting TSD in the docket for the CPP 

final rule. The use of averaging or aggregation approaches would have to be authorized in the 

111(d) state plans covering all the participating affected sources and would have to meet 

conditions set out for such approaches in section VIII. Specifically, see sections VIII.C and K.

The following are summaries of the specific public comments under this comment:

Commenters asked whether it is permissible for subsidiaries owned by the same parent 

company to demonstrate compliance by averaging emissions across power plants owned by the 

same parent company. Commenters stated these companies gave the example of Berkshire 

Hathaway Energy Company, which owns several entities in Illinois, including MidAmerican 

Energy Company (which is a joint owner of the Quad Cities Nuclear Power Station), 

MidAmerican Wind (owner of the Bishop Hill II wind facility), and MidAmerican Renewables 

with its subsidiary Cordova Energy Company (which owns the Cordova Energy Center).

Commenters believed the Berkshire Hathaway Energy-owned encompasses the flexibility 

intended by EPA, it should be able to comply by aggregating the Cordova Energy Center 

emissions, the renewable generation from Bishop Hill II wind farm, the applicable generation 

from the parent company's share of Quad Cities Nuclear Power Station, and the energy 

efficiency savings achieved by MidAmerican Energy Company for Illinois customers. 

Commenters requested the EPA the final rule allow such averaging is an acceptable practice 

between affiliates to demonstrate compliance with their obligations under Section 111(d).

Comment 30: Commenters supported emissions trading between Tribes and States.

Response 30: EPA agrees with commenters. The EPA encourages partnerships and coordination

between tribes and states.

The following are summaries of the specific public comments under this comment:
301

Commenters suggested creating a Trading Partnership with the Navajo Nation under federal rule 

and laws by which tribes may be treated in the same manner as states for purposes of the 40 CFR 

sections 49.1-49.11. Commenters believed support for such a partnership exists among non-tribal 

stakeholders and noted that EPA's proposed rule allows tribes to be designated as a state for the 

purposes of a multi-state trading. Commenters attached a map of a multi-state carbon trading 

platform involving the Navajo Nation and noted that non-tribal and tribal stakeholders have 

already formed a working group to develop a state-tribal trading relationship.

Comment 31: Commenters recommended the EPA allow states adopting trading programs to 

award allowances for emission reductions made prior to 2020.

Response 31: Many commenters supported providing incentives for states to deploy CO2-

reducing investments, such as RE and demand-side EE measures, as early as possible. The EPA 

recognizes the value of such early actions, and in this final rule is providing states with discretion 

to credit reductions from the activities, implemented from 2013 onward, in the context of both 

mass-based and rate-based plans. See section VIII.C and VIII.J and K in the CPP final rule 

preamble for details.

The following are summaries of the specific public comments under this comment:

Commenters recommended the EPA allow states to award allowances for early emission 

reductions of at least 20 percent below baseline that were accomplished between the submission 

date for the state's section 111(d) plan and 2020, for use in meeting the interim goals until 2030. 

Commenters stated that the allowances could be retired by 2030 and would be limited in amount 

to 5% of a state's total allocation.

Comment 32: Commenters noted the potential advantages of a regional cap-and-trade program 

for the upper Midwest states, indicating that such a program could significantly reduce emissions 

while also generating revenue that could be used by states to invest in EE, RE, and other 

programs.

Response 32: The EPA finds the analysis that commenters submitted to be in line with our 

expectations of how states can take the initiative and develop their own approaches to meeting 

the goals of the final rule within the options and flexibilities provided. The EPA has provided in 

the final rule source category-specific CO2 emission performance rates and equivalent statewide 

CO2 emissions performance goals that are mass-based or rate-based in order to provide 

flexibility and options for states in developing plans to meet the rule’s goals. A program such as 

that outlined by commenters appears to be within the emission guidelines established by the EPA 

in the CPP final rule.

The following are summaries of the specific public comments under this comment:
302

Commenters supported regional trading programs and submitted a paper describing an initial 

analysis they had completed of a hypothetical cap-and-trade program for the seven states in the 

Upper Midwest (Illinois, Indiana, Iowa, Michigan, Minnesota, Ohio and Wisconsin). 

Commenters stated the hypothetical program would be similar to the RGGI program and would 

set binding caps beginning in 2020 based on each state's CO2/MWh goal. For Wisconsin, 

commenters stated the cap would be 35 million tons calculated by assuming statewide electricity 

demand grows at 0.25% from now until 2020 and multiplying 1,376 lb/MWh target by 

approximately 50 million MWh generated by power plants covered by EPA's Clean Power Plan. 

For all seven states, commenters calculated a regional cap all seven of 440 million tons in 2020, 

which would then decline to 343 million tons in 2030 (an annual decline of 2.7% for each state).

In their analysis, commenters assumed that each state would set an allowance price floor of 

$10/ton that escalates at 2% annually. Using these data, commenters estimated $7 billion would 

be raised through the sale of allowances between 2020-2030, and CO2 emissions would decrease 

from an estimated 41.4 million tons in 2012 to 27.4 million tons in 2030. Commenters stated that 

Wisconsin's cumulative CO2 emissions from 2015-2030 under the BAU scenario are estimated at 

just over 468.1 million tons, compared to 342.3 million tons estimated under the cap-and-trade 

compliance scenario, a 26% reduction. Commenters also noted that the revenue could be used to 

fund renewable energy projects, clean transportation initiatives, demand side efficiency 

programs, and rebate programs for low-income households. 

Comment 33: Commenters recommended states be allowed to implement trading programs that 

cover both new and existing EGUs.

Response 33: See section VIII of the CPP final rule preamble. State plans may include emission 

budget trading programs that include affected EGUs as well as other non-affected emission 

sources. Under a program that applies to affected EGUs and other emission sources, compliance 

by affected EGUs with the emission standard – a requirement to surrender emission allowances 

equal to reported emissions – will not assure that a state’s CO2 mass goal is achieved. As a result, 

a further demonstration is required in the plan that compliance by affected EGUs with the 

program will result in CO2 emissions from affected EGUs that are at or below a state’s CO2 mass 

goal.

The following are summaries of the specific public comments under this comment:

Commenters recommended the EPA allow states that choose to implement a regional cap-andtrade program to include both existing and new EGUs.

Comment 34: Comments requesting that the EPA should clarify that one or more RGGI states 

can exceed their specific emissions targets as long as the RGGI states as a whole reduce their 

emissions below required levels.

Response 34: Section VIII.D.2 of the final rule preamble discusses design elements of emission 

budget trading programs with broader scope and additional compliance flexibility programs, 
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such as RGGI, and Section VIII.J.2 of the final rule preamble discusses the use of emission 

budget trading programs

The following are summaries of the specific public comments under this comment:

Commenters stated, RGGI permits emissions allowances to be traded between participating 

states. Commenters said, EPA should clarify that one or more RGGI states can exceed their 

specific emissions targets as long as the RGGI states as a whole reduce their emissions below 

required levels. 

Commenters stated that it is critically important for the smooth functioning of the RGGI program 

in the future that EPA not promulgate any restriction on the fungibility of RGGI allowances 

among states even if it means that the sum of allowances held by affected units within one or 

more states within the RGGI program might exceed that states' budget. Commenters stated that 

EPA must acknowledge that the RGGI cap applies to the region as a whole and not to any one 

state within the region. Commenters added that within that framework, EPA should retain the 

authority to find a state out of compliance should the generators within that state fail to procure 

the required number of allowances to cover their emissions. Commenters stated that EPA is 

correct in assigning states no obligation of enforcement over other states.

Comment 35: Comments related to the loss of local co-benefits related to multi-state trading 

programs.

Response 35: Section VIII.D.2 of the final rule preamble discusses design elements of emission 

budget trading programs with broader scope and additional compliance flexibility programs, 

such as RGGI, and Section VIII.J.2 of the final rule preamble discusses the use of emission 

budget trading programs

The following are summaries of the specific public comments under this comment:

Commenters stated, while multi-state trading programs have worked well in other states to 

reduce carbon emissions cost effectively (for example, EPA cites the "RGGI" program operated 

by the Northeast states), commenters had concerns about the loss of local co-benefits associated 

with such programs. Commenters said, Indiana has a number of aging coal-fired units that could 

continue operation if sources can purchase carbon credits from another state. Commenters said, 

one solution would be to require a minimum standard of performance for all EGUs prior to 

allowing credits from out-of-state.

Comment 36: Comments expressing opposition to BSER based on emission trading.

Response 36: We disagree with the commenters. The EPA has implemented several cap and 

trade programs in the final rule. Most covered sources under the Clean Power Plan final rule 

have had experience with trading and monitoring and reporting since 1995 with the Title IV Acid 
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Rain Program, a national program to reduce sulfur dioxide emissions from power plants. These 

programs have been successful in achieving emission reductions in a cost-effective manner and 

that the equipment and protocols to comply are readily available and in most cases, already in 

place. The simple and straightforward manner of accounting for compliance has also been a 

benefit. Aside from the benefits to public health and welfare, resource savings for both sources 

and government have also been demonstrated. Sections V and VIII of the CPP final rule 

preamble address emission trading at length, specifically in section VIII, see VIII.J.3 for massbased trading approaches and VIII.K.2-4 for rate-based approaches. 

The following are summaries of the specific public comments under this comment:

Commenters expressed strong concern that the draft 111(d) standard incentivizes development 

and continuation of carbon trading systems rather than meaningful investments in efficiency and 

renewable energy sources. Commenters said, all such existing trading systems fail to achieve 

their stated goals due to poor construction and gaping loopholes and disproportionately target 

communities impacted by extraction and environmental justice concerns. Commenters said, this 

sort of business-friendly approach buttresses the false narrative that given proper incentives the 

existing energy system will change its ways and reduce emissions drastically. Commenters said, 

history and common sense show this to be a farcical ideal. Commenters said, only by 

implementing systemic change and building a new energy sector will the world succeed in 

meeting continued development goals while adequately mitigating and adapting to the ravages of 

climate disruption.

Commenters stated that the rule should not allow States to use cap-and-trade programs to meet 

the emissions targets. Commenters said, cap-and-trade is designed to benefit big corporate 

polluters who can decide for themselves how to limit their emissions based on profit motive. 

Commenters said, this makes it cheaper for the dirtiest power plants to simply pay for permits 

instead of cleaning up pollution.

Commenters stated, EPA has considered cap-and-trade type regulations before under 111(d), 

notably the now-vacated Clean Air Mercury Rule (CAMR). Commenters said, furthermore, a 

Part 60 regulation that is not unit-specific, can result in the undesirable inconsistency of 

emissions increases at an emissions unit. Commenters said, environmental petitioners argued 

heavily against this application of the Clean Air Act in CAMR, and it would apply here too. 

Commenters said, in this case, however, EPA not only would allow emissions increases at an 

individual unit as long as a state goal was met, but actually require increases at the unit level due 

to a potential misunderstanding or inappropriate application of re-dispatching.

Commenters stated, trading and/or emissions averaging approaches should not be considered as 

the BSER. Commenters said, the BSER on which a Section 111(d) standard of performance is 

based can only derive from reductions that are attainable "inside the fence" at the affected 

source. Commenters said, once the performance standard is set, the affected utility may, with 

state approval, exercise flexible options to satisfy its obligations to reduce CO2 emissions. 

Commenters said, this could include emissions averaging or offsetting among affected EGUs or 

with other generation sources, as well as other actions. Commenters said, in no case should a 

State be required to achieve emission reductions that exceed those required by aggregating 
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individual EGU obligations within the State; nor should an EGU be obligated to achieve 

reductions that exceed its individual obligations.

Comment 37: Comments suggesting the emissions cap should not increase with new RE/EE 

Projects

Response 37: Sections V and VIII of the CPP final rule preamble address emission trading at 

length, specifically in section VIII, see VIII.J.3 for mass-based trading approaches and VIII.K.2-

4 for rate-based approaches.

The following are summaries of the specific public comments under this comment:

Commenters stated that states should not increase their cap each time new generation comes 

online or new efficiency projects are deployed, regardless of how rate based standards are 

converted to mass-based standards. Commenters suggested that states that have adopted massbased standards could incentivize RE or EE projects with free allowance allocations or auction 

revenue without modifying the state cap. Commenters believed that this approach would 

preserve environmental integrity while promoting projects that contribute to emission reductions 

from existing power plants
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5.14 STATE-SPECIFIC IMPLEMENTATION CONSIDERATIONS

This section addresses comments that discuss State-specific Implementation Considerations. 

Comments in this section address a variety of topics on state and region-specific issues that 

affect ability to comply including: concerns with inability to import power from other regions; 

geographic and administrative barriers to developing gas transmission infrastructure; 

complications with using energy efficiency for compliance due to the nature of the local utility 

structure; concerns about receiving credit for EE measures already in place; compliance options 

where there are limited existing coal-fired units; requests for compliance extensions; and 

requests for technical assistance.

Commenters have raised a number of issues related to this subsection which are organized by 

topics (comments) below. Responses are provided for these topics.

Comment 1: Comments stating that Alaska does not have a statewide electric transmission 

system, and does not have the transmission infrastructure in place to dispatch natural gas 

generation to replace its coal generating capacity. 

Response 1: The EPA has determined that Alaska will not be subject to the final CPP’s BSER.

Because the EPA does not possess all of the information and analytical tools needed to quantify 

the BSER for the two non-contiguous states with otherwise affected EGUs (Alaska and Hawaii) 

these emission guidelines do not apply to those areas, and those areas will not be required to 

submit state plans on the schedule required by this final action. Therefore, the EPA does not need 

to address the specific concerns of the commenters.

The following are summaries of the specific public comments under this comment:

Commenters stated that Alaska does not have a statewide electric transmission system to 

facilitate the use of Building Blocks 2, 3, and 4. Commenters advocated that Alaska should be 

exempt from the rule due the high cost of compliance. Commenters (State Legislature) stated 

that if Alaska is not exempted, then they need 5 more years to comply in order to achieve the 

reductions needed on coal-fired plants. Commenters explained in detail why Alaska does not 

have the transmission infrastructure in place to dispatch natural gas generation to replace its coal 

generating capacity. Commenters also pointed out that replacing coal-fired capacity would 

conflict with the spirit of a consent decree with EPA regarding Healy Unit #2 and would strand 

investments to upgrade the unit using a USDA loan. Commenters also stated that the isolated 

nature of Alaska's utility sector means that EPA's rationale for BSER does not apply to Alaska, 

because the state would not have the degree of compliance flexibility that other states would 

have, and EPA has not provided a rationale for including the state in the rule given the unique 

characteristics of the utility industry in the state. Commenters also expressed that state resources 

would be better served by investing in more basic infrastructure such as drinking and wastewater 

systems in remote villages.

Commenters stated that their utilities have actively educated their customers about measures to 

reduce energy consumption. At some point, commenters contended the reasonable cost options 
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for reducing energy consumption will be exhausted and therefore EPA's assumption that 

declining trends will be maintained at the same pace indefinitely is irrational. Commenters stated 

that Alaska has implemented EE programs within the state which have resulted in upgrades to 

over 37,000 residencies with an annual savings of the equivalent of 932 GWh of electricity. 

Commenters noted that most of these residences are not interconnected with their EGUs and 

what is being saved is fuel oil or firewood consumed in relatively inefficient residential units. 

Commenters determined that the emphasis of demand side energy programs needs to be placed 

on the space heating needs of their residents since space heating is a health and safety concern 

that simply has to have priority over other potential demand side energy efforts. Commenters

stated that their efforts have probably resulted in, and will continue to result in, a greater 

reduction in total carbon dioxide emissions than the goal established by the EPA for Alaska 

under the building block 4. Commenters requested that EPA exempt Alaska from building block 

4 rather than try to force the state to divert limited resources into efforts that are unlikely to be as 

effective at reducing carbon dioxide emissions.

Comment 2: Comments suggesting municipal and cooperative units that are part of TVA cannot 

import power from other regions.

Response 2: Even if EE/RE resources cannot be implemented in the state itself, the EPA is 

providing states with maximum flexibility to achieve their emission standards or CO2 state goals 

in the final emission guidelines. For example, states can enter into multi-state plans, multi-state 

coordination while retaining their individual state goals and emission budget trading programs.

Rate-based programs can use or purchase ERCs generated from eligible resources (e.g., demand 

side energy efficiency and renewable energy) and do not need to implement these resources 

within their state, under ceratin state plan types. These flexibility provide enough latitude for all 

states to comply with this rule. See section VIII.C of the preamble final rule for details on 

different state plan approaches.

While the EPA is not requiring states to join and/or form regional market-based programs, we 

note that such programs can be helpful for many reasons, including features that support 

reliability. Market-based programs allow greater flexibility for affected EGUs both in the shortterm and long-term. Under a market-based program, affected EGUs have the ability to obtain 

sufficient allowances or credits to cover their emissions in order to comply with their emission 

limits.

The following is a summary of the specific public comment:

Commenters stated that the rule is not feasible for TVA because of the unique structure of the 

TVA power system. Commenters claimed that the municipal and cooperative utilities do not 

have access to transmission services from any source other than TVA and therefore cannot 

import power from other regions.
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Comment 3: Comments suggesting the complexities of the western grid structure, including the 

large amount of federal and tribal land with governing authorities that need to be involved in 

decision making, create significant barriers to implementing the CPP.

Response 3: The Western states have a good track record working together for regional 

compliance, for example, the regional haze program and Grand Canyon visibility transport 

commission. The Western Electric Coordinating Council coordinates reliability throughout the 

region. The EPA is providing states with maximum flexibility to achieve their emission 

standards or CO2 state goals in the final emission guidelines. For example, states can enter into 

multi-state plans, multi-state coordination while retaining their individual state goals and 

emission budget trading programs. Certain rate-based state plans can use or purchase ERCs 

generated from eligible resources and do not need to replace resources within their state. This

flexibility provides enough latitude for all states to comply with this rule. See section VIII.C of 

the preamble of the final rule for details on the different state plan approaches.

In addition, if states have approporate justification, such as; a state’s required schedule for 

legislative approval and administrative rulemaking, the need for multi-state coordination in the 

development of an individual state plan, or the process and coordination necessary to develop a 

multi-state plan they can seek extension beyond 2016. See section VIII.E of the preamble of the

final rule for details on state plan submittal and timing. 

The following are summaries of the specific public comments under this comment:

Commenters assert the western grid structure is complex and creates significant barriers to

developing, approving, and implementing regional compliance approaches. Commenters

explained that outside of California and the Dakotas, there is no Regional Transmission 

Organization (RTO) or Independent System Operator (ISO), but rather 38 electricity-balancing 

areas that are responsible for managing the western grid. Commenters stated that moreover, 

western states have a vast amount of both tribal and federally managed public lands overlaying 

state boundaries; and these tribal governing authorities and Federal Land Managers (FLMs) must 

either direct, or be engaged in, the public processes needed to obtain approvals for new 

renewable and natural gas generation resources, new or expanded transmission lines, and new or 

expanded natural gas infrastructure. Commenters observed that federal agencies have a poor 

track record of timely permitting and delays could impact a state's ability to comply with its plan. 

Commenters stated that Idaho will have problems meeting the emission limits because federally 

managed lands cover more than 63% of the state. Commenters said that EPA calculated RE 

potential without considering the various restrictions on federal land. Commenters stated that as 

a result, they will have problems in obtaining the necessary permits for renewable energy 

projects and for transmission lines to move electricity from low carbon sources. Commenters 

gave a current example of a transmission line that is taking 14 years to construct due to delays by 

the Bureau of Land Management.

Comment 4: Comments requesting clarification regarding compliance options for utilities that 

own only a single coal-fired EGU.
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Response 4: See section V.A of the final rule preamble of the CPP for EPA’s response to the 

comment associated with compliance options for owners of a single coal-fired EGU. Also see 

final rule preamble section VIII.G for information on geographic eligibility for RE and EE 

measures, and section VIII.C of the final rule preamble of the CPP on multi-state coordination 

for EPA’s response to this comment.

In the CPP final guidelines for state plans to limit CO2 from affected EGUs, however, the 

agency does not specify presumptive performance rates that each individual EGU is to achieve in 

the absence of trading. Instead, these guidelines provide collective performance rates for two 

classes of affected EGUs (steam generating units and stationary combustion turbines), and give 

states the alternative of developing plans to achieve a state emission goal for the collective group 

of all affected EGUs in a state. These flexibilities will accommodate the concerns regarding 

individual units. 

The following are summaries of the specific public comments under this comment:

Commenters stated that the rule provides unique compliance problems for utilities like Missouri 

River Energy Services and Texas Municipal Power Agency who own only a single coal fired 

power plant. Commenters requested clarification on compliance options: 1) Does the utility 

receive credit for actions taken by its member cities regarding renewable energy and demand 

side energy efficiency; 2) Does the utility receive credit for a coal-to-gas switch if a member city 

installs a gas unit; and 3) What if the power plant is located in one state and serves customers in 

another?

Commenters stated some states have a heavy reliance on coal. Commenters investigated 

compliance scenarios to quantify the impact of coal fired power plant retirements, and stated that 

closing one unit at the Utah's largest coal fired power plant would reduce the compliance gap to 

341 and if both units were closed the gap would shrink to 256 lbs/MWH.

Comment 5: Comments stating that Rhode Island has no coal generation, so they will likely 

comply through a regional mass-based plan and enhance RE and EE and continue participating 

in RGGI. 

Response 5: States are not required to implement the building blocks set in the EPA’s BSER 

determination. The EPA is providing states with maximum flexibility to achieve their emission 

standards or CO2 state goals in the final emission guidelines. For example, states can enter into 

multi-state plans, multi-state coordination while retaining their individual state goals and 

emission budget trading programs. Certain rate-based state plans can use or purchase ERCs 

generated from eligible resources (e.g., EE/RE). This flexibility provides enough latitude for all 

states to comply with this rule. See section VIII.C of the preamble of the final rule for details on 

the different state plan approaches states can use to comply with the final emission guidelines. 

The following is a summary of the specific public comment:
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Commenters stated that the State of Rhode Island cannot utilize building blocks 1 and 2 because 

the state has no coal generation. Commenters stated the state anticipates that they will comply 

through a regional, mass-based compliance plan and rely on enhancing their current energy 

efficiency and renewable programs and continuing to participate in RGGI.

Comment 6: Comments stating that Guam requests technical support from the EPA to develop 

the SIP and in coordinating CPP goals with other environmental regulations, and requests an 

extension to the plan submittal deadline.

Response 6: Many commenters have asked the EPA to extend the time for final state plan 

submittals. We are revising the requirements in the proposal as follows. The EPA is requiring an 

initial plan by September 6, 2016 and is providing until September 2018 for state to submit a 

final plan if an extension until that date is justified. This should give states ample time to develop 

final plans, including resolving any related legal issues regarding the inclusion of new NGCC in 

state plans. See section VIII.E of the final rule preamble for the EPA’s response regarding plan 

submittal deadlines.

The EPA regions will continue to be the entry point for territories to ask technical and policy 

questions. We intend to continue to work actively with states and tribes to provide information 

and technical support that will be helpful to them in developing and implementing their plans.

See section I.A.4 of the final rule preamble of the CPP for EPA’s response to this comment 

regarding technical support. 

Because the EPA does not possess all of the information and analytical tools needed to quantify 

the BSER for the two non-contiguous states with otherwise affected EGUs (Alaska and Hawaii) 

and the two U.S. territories with otherwise affected EGUs (Guam and Puerto Rico), these 

emission guidelines do not apply to those areas, and those areas will not be required to submit 

state plans on the schedule required by this final action.

The following is a summary of this specific public comment:

Commenters stated that the goals are achievable if they get technical support from EPA Region 

9, but because of inexperience with preparing SIPs, requested an extension to the 1-year deadline 

for SIP submittal (Commenters is Guam Power Authority). Commenters requested help in 

coordinating the CPP goals and timetable with other environmental regulations. Commenters 

asked for more time in the compliance schedule so that legal issues such as "including new 

NGCC units as part of BSER for existing units" can be resolved and state resources will not be 

wasted.

Comment 7: Comments suggesting the EPA has vastly underestimated the regulatory and 

electrical system changes needed in Texas to implement the 111(d) guideline and the time 

needed to make the changes.
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Response 7: States are not required to implement the building blocks set in the EPA’s BSER 

determination.

The EPA is providing states with maximum flexibility to achieve their emission standards or 

CO2 state goals in the final emission guidelines. For example, states can enter into multi-state 

plans, multi-state coordination while retaining their individual state goals and emission budget 

trading programs. Certain rate-based state plans can use or purchase ERCs generated from 

eligible resources and do not need to replace resources within their state. This flexibility provides

enough latitude for all states to comply with this rule. See section VIII.C of the preamble to the 

final rule for details on the different state plan approaches states can use to comply with the 

emission guidelines.

If states have appropriate justification, such as; a state’s required schedule for legislative 

approval and administrative rulemaking, the need for multi-state coordination in the development 

of an individual state plan, or the process and coordination necessary to develop a multi-state 

plan they can seek extension beyond 2016. See section VIII.E of the final rule preamble for the 

EPA’s response to the comment about deadlines for submission of the state plan.

The following are summaries of the specific public comments under this comment:

Commenters stated that the EPA has vastly underestimated the regulatory and electrical system 

changes needed to implement the 111(d) guideline and the time needed to make the changes. 

Commenters said Texas could not submit a state plan before 2017 at the earliest. Commenters

stated that it would be especially difficult for Texas to comply in the proposed timeframe 

because of the unique nature of their electricity markets. Commenters pointed out that a large 

portion of the state operates in a competitive wholesale and retail electric market (ERCOT) 

contained within the state, while other portions of the state operate within 3 distinct competitive 

wholesale markets overseen by the Federal Energy Regulatory Commission (FERC) and 

traditional cost-of-service regulated retail markets (SPP, MISO, and WECC) that are regulated 

by the PUC. Commenters provided detailed information about the Texas' unique and complex 

electricity market," which is designed to provide competitive electricity markets.

Commenters stated that Texas law, the PUC rules, and the ERCOT market protocols do not 

provide the authority to require heat rate improvements or the re-dispatch of natural gas plants 

required by the 111(d) guideline. Accordingly, commenters stated that to implement the 111(d) 

rule, substantial revisions would have to be made to Texas law, PUC rules, and the ERCOT 

market rules; and these changes could not be made by June 2016. Commenters stated that the 

ability to obtain a one-year extension is not feasible for Texas because the TCEQ could not 

prepare the initial plan stipulated in the proposed rule, because TCEQ cannot bind a future Texas 

Legislature to pass the laws necessary to implement the 111(d) plan. Commenters also pointed 

out that the Texas Legislature meets only every other year, and the 2015 session will be finished 

before the section 111(d) guidelines are published. Commenters added that even after the 

Legislature amends Texas law, commenters listed 25 state regulations that would have to be 

revised. Afterward, Commenters stated that amendments would need to be made to the market 

rules for ERCOT, SPP, and MISO; and then IT systems would need to be redesigned.

Commenters stated that making all the necessary changes likely would require several years.
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Comment 8: Comments suggesting phase-in periods for NGCC re-dispatch under Building 

Block 2 are necessary for Texas.

Response 8: The EPA has made changes to the BB2 assumption in the final rule. See sections 

V.A.3 and V.D of the final rule preamble of the CPP for EPA’s response to this comment.

We carefully reviewed information submitted to us regarding the feasible timing of various 

measures and identifying concerns that the required CO2 emission reductions could not be 

achieved as early as 2020 without compromising electric system reliability, imposing 

unnecessary costs on ratepayers, and requiring investments in more carbon-intensive generation, 

while diverting investment in cleaner technologies. The record is compelling. To respond to 

these concerns and to reflect the period of time required for state plan development and submittal 

by states, review and approval by the EPA, and implementation of approved plans by states and 

affected EGUs, the EPA is determining in this final rule that affected EGUs will be required to 

begin to make reductions by 2022, instead of 2020, as proposed, and meet the final CO2 

emission performance rates or equivalent statewide goals by no later than 2030. The EPA is 

establishing an eight-year interim period that begins in 2022 and goes through 2029, and which 

is separated into three steps, 2022-2024, 2025-2027, and 2028-2029, each associated with its 

own interim goal. Affected EGUs must meet each of the interim period step 1, 2, and 3 CO2 

emission performance rates, or, following the emissions reduction trajectory designed by the 

state itself, must meet the equivalent statewide interim period goals, on average, that a state may 

establish over the 8-year period from 2022-2029. These additional flexibilities give states more 

time to comply with the emission guidelines of this final rule and address the natural gas pipeline 

and reliability concerns raised by the commenters. 

The following is a summary of the specific public comment:

Commenters supported increased dispatch of NGCC units but stated that the 70% re-dispatch of 

all NGCC generation in Texas by 2020 is too high and too fast to be successfully implemented in 

the ERCOT market, because this level could require significant investments in additional electric 

transmission and natural gas pipelines to alleviate potential reliability concerns. To address this 

problem, commenters recommended phase-in periods for the implementation of the NGCC redispatch called for under Building Block 2, which would not require Texas to achieve the full 

implementation of Building Block 2 until 2029.

Comment 9: Comments suggesting the structure of the utility industry in Texas complicates 

compliance, and Texas does not have the natural gas infrastructure to deliver sufficient quantities 

of natural gas.

Response 9: The CPP final guidelines include three approaches that states may adopt for 

purposes of implementing the BSER, any one of which a state may use in its plan. These are: 1) 

establishing standards of performance that apply the subcategory specific CO2 emission 
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performance rates to their affected EGUs, 2) adopting a combination of standards and/or other 

measures that achieve state-specific rate-based goals that represent the weighted aggregate of the 

CO2 emission performance rates applied to the affected EGUs in each state, and 3) adopting a 

program to meet mass-based CO2 emission goals that represent the equivalent of the rate-based 

goal for each state. 

States do not need to implement the same BSER methodology as the EPA used to set the 

emission guidelines in the final rule. The EPA is providing states with maximum flexibility to 

achieve their emission standards or CO2 state goals in the final emission guidelines. For example, 

states can enter into multi-state plans, multi-state coordination while retaining their individual 

state goals and emission budget trading programs. Certain rate-based state plans can use or 

purchase ERCs generated from eligible resources and do not need to replace resources within 

their state. This flexibility provides enough latitude for all states to comply with this rule. See 

section VIII.C of the preamble of the final rule for details on different state plan approaches 

states can use to comply with the emission guidelines. 

The following are summaries of the specific public comments under this comment:

Commenters stated that due to the unique structure of the electric utility industry in Texas, the 

rule as proposed is not feasible in Texas. Commenters stated that Texas electricity generating 

companies are not vertically integrated utilities, and thus the EPA's assumption that building 

blocks 2, 3, and 4 may be undertaken by the affected EGUs themselves is not valid for Texas. 

Commenters added the Texas market is restructured into generation and distribution utilities that 

are regulated separately. Commenters added, for example, generation utilities cannot exert 

control over transmission infrastructure or demand-side energy efficiency programs. 

Commenters also stated some energy efficiency activities in Texas are subject to PUC regulatory 

oversight whereas other energy efficiency measures are subject to the authority of the Texas 

Legislature. 

Commenters also stated that most of Texas is served by ERCOT, which is a closed intrastate 

grid. Therefore, commenters stated utilities in the ERCOT regions cannot participate in interstate 

strategies because most Texas utilities cannot reduce coal generation by importing power from 

low carbon sources in other states and cannot participate in interstate trading. Commenters stated 

that compliance in Texas would result in significant stranded assets and reduced fuel diversity.

Commenters stated that building block #2 is not feasible in Texas because Texas does not have 

the natural gas infrastructure to deliver sufficient quantities of natural gas.

Commenters explained the size of the Texas utility market and its unique competitive design.

Comment 10: Idaho requested more time to meet the RE standard given time delays associated 

with installing transmission lines across federal lands, and requested EPA assistance in working 

with federal land managers.
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Response 10: See section VIII.E of the preamble to the final rule for details on plan submittal

and timing. The EPA will work with states and stakeholders and other federal agencies as 

appropriate.

The following is a summary of the specific public comment:

Commenters stated that the EPA must adjust the timeline for implementation of its RE 

requirements to allow for necessary transmission and for RE projects to be permitted and built. 

Commenters requested EPA assistance in working with federal land management agencies.

Comment 11: Request for meeting with the EPA to address questions and concerns.

Response 11: To provide interested stakeholders with a better understanding about the rule 

requirements, the EPA will continue to work with states, tribes, territories, and stakeholders to

provide information and address questions about the final rule. The agency will host (or partner 

with appropriate groups to co-host) a number of webinars about various components of the final 

rule; these webinars are planned for the first two months after the final rule is issued. See 

sections I.A.4 and XII.E of the final rule preamble for details regarding stakeholder outreach.

The following is a summary of the specific public comment:

Commenters (trade group for New York State energy service providers) requested a follow-up 

meeting to clear up remaining questions and concerns given the complexity of the rule and the 

unique features of the New York electric system.

Comment 12: Comments stating that renewable resources that do not use synchronous machines 

coupled with long distances of power transmission create technical challenges in West Texas.

Response 12: Commenters have provided a few different mitigation measures that could 

mitigate potential reliability issues and states there is enough time to implement these mitigation 

measures at a reasonable cost. See section VIII.G.2 of the final rule preamble for details on how 

the EPA is handling reliability issues.

The following are summaries of the specific public comments under this comment:

Commenters stated that there are technical challenges with integrating a large amount of 

renewable resources in West Texas, primarily due to two factors: 1) renewable resources in West 

Texas are located far from load centers requiring their power be transmitted over long distances; 

and 2) most renewable resources use power electronic based devices and not synchronous 

machines. Together, these factors induce power system challenges not previously observed on a 

large scale.

As an example, commenters stated that the combination of long transmission lines and a lack of 

synchronous generation machines by wind turbines can lead to high/low voltage collapse, and 
315

system instability. Commenters stated the solutions to these challenges include the installation of 

synchronous generation, synchronous condensers, and new transmission lines.

Commenters stated another challenge of transferring power over long distances is handling the 

reactive losses in long transmission lines. Commenters stated that often these reactive losses 

become more limiting than the inherent thermal capability of a transmission conductor for long 

transmission lines. Commenters stated the solutions to this challenge include installing dynamic 

reactive compensation devices, building transmission lines at higher voltages (i.e. 500 kV or 765 

kV), constructing more transmission lines, or installing series compensation on transmission 

lines; and each of these solutions has drawbacks. Commenters stated that: (1) dynamic reactive 

devices are expensive and provide only limited benefit for long transmission lines, and (2) 

construction of higher voltage transmission lines is often opposed by the public because of rightof-way issues and the aesthetic impact.

Commenters stated that ERCOT chose to handle this challenge primarily by installing series 

compensation devices. Commenters stated that, in 2009, a wind generation resource in Texas 

experienced sub-synchronous oscillations of its control system with a series compensation 

device, and that this event caused significant damage to both the wind generation resource and 

the series compensation device. Commenters stated that mitigation measures must be put in place 

to prevent this from happening.

Comment 13: Comments stating Texas has made greater reductions than California in carbon 

dioxide emissions but is being asked to make disproportionate changes in carbon dioxide 

generation and in its renewable portfolio without credible explanation by the EPA.

Response 13: See section V.E. of the preamble to the final rule and the EPA’s CO2 Emission 

Performance Rate and Goal Computation TSD for CPP Final Rule for details on the EPA’s 

rationale for renewable energy BSER determination and how the EPA has changed the 

renewable enery assumptions under BSER in the final rule.

The EPA received many comments suggesting that the EPA should recognize early actions for 

the emission reductions they provide prior to the performance period. The EPA recognizes the 

validity and importance of these perspectives, and as a result, the final rule contains two 

provisions that enable states to incentivize early investments in zero-emitting generation and 

demand-side EE. 

First, states adopting rate-based plans may award ERCs to qualified providers that implement 

any eligible projects from 2013 onward for the quantified and verified MWh of generation or 

savings those projects provide in 2022 and subsequent years. Affected EGUs may use ERCs 

issued under each of these provisions for compliance with their assigned emission standards or 

bank the ERCs for use in any compliance period. In a mass-based context, similar efforts will be 

inherently reflected in the affected EGUs stack emissions in 2022 forward. For more details on 

this treatment of early actions, see section VIII.K of the preamble to the final rule.
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Second, the EPA has developed the Clean Energy Incentive Program, an optional program 

designed to reward investment in certain RE and demand-side EE projects that commence 

construction after the effective date of this rule and that generate MWh or reduce end-use energy 

demand during 2020 and 2021. Under this program, states may set aside allowances from their 

interim targets or generate early action ERCs (as defined in section VIII.K.2 of the final rule 

preamble), and allocate to eligible projects allowances or ERCs equivalent to each MWh 

generated or avoided. For more details on this program, see section VIII.B.2 of the preamble to 

the final rule. 

The following are summaries of the specific public comments under this comment:

Commenters charged that the 111(d) rule has a disproportionate and unfair impact on Texas. 

Commenters stated that EIA and U.S. Census data show that, from 2000 to 2010, Texas, the 

second most populous state in the United States, has reduced its carbon dioxide emissions by 

8.05%, while over the same time period, California, the most populous state, has reduced its 

carbon dioxide emissions by only 4.36%. Commenters stated that, on a per-capita basis, 

California reduced its carbon dioxide emissions by 15.49% over the same time period while 

Texas has reduced its carbon dioxide emissions by nearly 24% on a per-capita basis, while 

transitioning to competitive (and very successful) wholesale and retail markets. Commenters

stated that Texas's heavy investment and remarkable transformation is penalized by a final target 

of 791 lbs. of CO2/MWh, which could not even be met by a state-of-the-art combined cycle 

power plant with existing technology. Commenters stated that Texas produces 11% of the 

electricity in the United States, but its proportion of total carbon dioxide reduction required by 

the 111(d) by 2030 is 17.87%; and EPA offers no reasonable explanation for the disparate, 

seemingly punitive, treatment of Texas under the proposed rule.

As another example of unfair treatment, commenters stated that Texas's renewable energy 

mandate under 111(d) far exceeds the requirement for any other state. Commenters said that the 

rule would require Texas to add 52 million MWh of renewable energy by 2030 and that this 

renewable energy mandate far exceeds the renewable energy requirement for any other state. 

Commenters said that Texas, already the nation's largest renewable energy producer, would be 

required to increase its renewable portfolio by 153% over the next 8-14 years, while the next 

largest renewable energy producer, California, would only be required to increase its renewable 

energy portfolio by 37%. Commenters said that the required increase in Texas's renewable 

energy fleet required under the rule would be greater than the increases of 29 states combined 

and would be larger than the present day wind and solar fleets of every country in the world, 

except for the U.S. Commenters believed that EPA has offered no credible or reasonable 

explanation for this disparate treatment of Texas.

Comment 14: Comments stating the EPA must consider state-specific variations and capabilities 

in establishing guidelines. 

Response 14: See section V.A. of the final rule preamble regarding changes in the interim 

deadlines for the EPA’s response to the comment regarding states’ ability to meeting interim 

deadlines. See section I.A.4 of the final rule preamble for the EPA’s response to the comment 
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regarding considering state variations in developing the CPP. See sections I.A.3, V.A, and VII.A 

and of the final rule preamble for the EPA’s response to the comment regarding providing states 

flexibility. 

See the CO2 Emission Performance Rate and Goal Computation TSD for CPP Final Rule for the 

EPA’s response to the comments about baselines. 

In addition, the EPA is providing states with maximum flexibility to achieve their emission 

standards or CO2 state goals in the final emission guidelines. For example, states can enter into 

multi-state plans, multi-state coordination while retaining their individual state goals and 

emission budget trading programs. Rate-based programs can use or purchase ERCs generated 

from eligible resources. This flexibility provides enough latitude for all states to comply with this 

rule. See section VIII.C of the preamble to the final rule for the various state plan approaches 

states can adopt to comply with the final rule.

The following are summaries of the specific public comments under this comment:

Commenters stated that some of their member states are very concerned about their ability to 

meet the proposed (especially interim) targets, grid reliability, and the cost of the rule due to 

state-specific regional, geographic, economic, and power generation and regulation differences 

and due to the wide range of options proposed by the EPA. Cost, timing, and energy generation 

impacts will likely differ from state to state depending on legislative and administrative factors 

and differences in each state's energy portfolio and connections, or lack thereof, to the larger 

grid. Commenters stated that the EPA must:

• consider variations in states' ability to implement the various proposed options;

• account for variations in state implementation costs; and

• structure final guidelines to "provide the maximum flexibility possible that is still

consistent with underlying statutory objectives".

Regarding baselines for setting state goals and determining compliance, commenters stated that 

baselines must be representative of actual performance related to the goals of the rule and must 

not, for example, work against states or entities that took early action contributing to the goal. 

Commenters stated that the EPA also must consider significant year-to-year variations that have 

occurred, and will continue to occur, e.g., anomalies in hydropower generation and plant outages 

have had an undue influence on the baseline in some states; and the EPA should work with those 

specific states to make needed adjustments in the final rule.

Comment 15: Comments stating that Kentucky is concerned that neighboring states will raise 

electricity prices on Kentucky ratepayers.

Response 15: The EPA disagrees with Kentucky’s assessment because it is difficult to assess the 

impacts of the rule until it is known how Kentucky and states within the same grid region will 

comply with the final CPP. It’s important for the EPA to point out that if Kentucky doesn’t put a 
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CO2 price on electricity generation and other states do in their region, then Kentucky would be 

able to provide more generation to other states at a lower cost. The impacts to rate payers will 

depend upon the choice Kentucky makes relative to their neighbors, Kentucky’s rate payers 

could benefit from the rule, depending on the choices made within and outside of Kentucky.

The EPA is providing states with maximum flexibility to achieve their emission standards or 

CO2 state goals in the final emission guidelines. For example, states can enter into multi-state 

plans, multi-state coordination while retaining their individual state goals and emission budget 

trading programs. Rate-based programs can use or purchase ERCs generated from eligible 

resources. This flexibility provides enough latitude for all states to comply with this rule. See 

section VIII.C of the preamble to the final rule for the various state plan approaches states can 

adopt to comply with the final rule.

The following are summaries of the specific public comments under this comment:

Commenters were concerned that their rate payers will be subject to higher electricity prices 

because of actions that neighboring states take to comply with the rule. Commenters pointed out 

that Kentucky has some electric utilities that are operate a part of two different regional 

interconnections and two large utilities that are not part of a multi-state construct. Commenters

pointed out that whether or not Kentucky chooses to be a part of a multi-state collaborative for 

rule compliance, other states might place a price of carbon into their dispatch system, and as a 

result Kentucky ratepayers will be subject to market forces that will result in higher prices 

because of the actions in other states.

Comment 16: Comments stating Florida’s limited import capacity, unique geography and 

electricity needs, and the low percentage of households with natural gas service foreclose many 

of the proposed regional options. 

Response 16: The EPA is providing states with maximum flexibility to achieve their emission 

standards or CO2 state goals in the final emission guidelines. For example, states can enter into 

multi-state plans, multi-state coordination while retaining their individual state goals and 

emission budget trading programs. Rate-based programs can use or purchase ERCs generated 

from eligible resources and do not need to replace resources within their state. This flexibility 

provides enough latitude for all states to comply with this rule. See section VIII.C of the 

preamble to the final rule for the various state plan approaches states can adopt to comply with 

the final rule.

Also, see Section VIII.G.2 on details regarding the EPA handles reliability issues. 

The following are summaries of the specific public comments under this comment:

Commenters noted that Florida has unique characteristics of weather, geography, customer base, 

and high reliance on electricity for cooling and heating that must be carefully considered to 

ensure Florida's electricity supply is cost-effective and reliable. Commenters noted that they have 

the highest number of cooling degree days of any state, a large population of senior citizens 

with about 89% of Florida's electricity customers are on fixed incomes, and only about 7% of 
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households have natural gas service. As a peninsular state, commenters noted limit Florida's 

interconnections and transmission capabilities for importing electricity and natural gas. 

Commenters stated that the transmission capability for import energy to Florida is limited to 

3,800 megawatts, which is just 6.6% of Florida's summer capacity. This limited import capacity,

commenters believe forecloses many of the proposed regional options included in the proposal.

Commenters pointed out also that their coal generating capacity assets are located in northern 

Florida and gas assets are in south Florida; so EPA has not considered the effect of massive load 

shifting on intrastate reliability and system control areas. 

Commenters stated that Florida has limited ability to import high-voltage electric transmission 

from nearby states given its peninsular geography. Commenters stated that they currently import 

only 8 percent of their power from other states. Given this difficulty, commenters believed that 

importing electricity would do little to help Florida achieve the proposed goal.

Comment 17: Comments stating that Michigan, Montana, Texas and West Virginia submitted 

reports on the feasibility and cost of reducing carbon emissions in their states and asked for the

EPA to consider the findings. 

Response 17: The EPA provides a response regarding the MISO report and reliability issues in 

Section VIII.G.2 of the preamble of the final rule.

If states have approporate justification, such as; a state’s required schedule for legislative 

approval and administrative rulemaking, the need for multi-state coordination in the development 

of an individual state plan, or the process and coordination necessary to develop a multi-state 

plan they can seek extension beyond 2016. See section VIII.E of the final rule preamble for the 

EPA’s response to the comment about deadlines for submission of the state plan.

The following are summaries of the specific public comments under this comment:

Commenters submitted reports about the feasibility and cost of reducing carbon emissions in 

their states and asked EPA to consider the findings in preparing the final rule. Commenters stated 

the report attached by Michigan is a MISO report on the proposed rule. Commenters considered 

the collective impact of six environmental regulations (i.e., MATS, CSAPR, Regional Haze, 

Cooling Water Intake Structures, Coal Ash Regulations, Clean Power Plan) and concluded that 

the impact would be retirement of up to 8,700 MW of coal-fired capacity; and stated modeling 

assumptions were based on a survey. Commenters stated these closures would strain ERCOT's 

ability to integrate new intermittent renewable generation resources leading to a delay in 

achieving compliance with the proposed Clean Power Plan limits. 

Commenters discussed preliminary modeling results which suggested that if all non-retired coal 

plants are dispatched with the same capacity factor, the 2030 rate limit would not be met; 

however, the limit would be met if the cleanest plants were dispatched first. Commenters stated 

dispatch decisions are complicated, trigger grid reliability considerations, require coordination 

among parties both within and outside of the state to plan and execute, and have important 
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impacts to ratepayers and utilities. Commenters also stated the dispatch scenarios highlight the 

importance of interstate coordination in the state planning process.

Comment 18: Comments requesting a longer period for compliance for Texas.

Response 18: If states have appropriate justification, such as; a state’s required schedule for 

legislative approval and administrative rulemaking, the need for multi-state coordination in the 

development of an individual state plan, or the process and coordination necessary to develop a 

multi-state plan they can seek extension beyond 2016. See section VIII.E of the final rule 

preamble for the EPA’s response to the comment about deadlines for submission of the state 

plan.

The following are summaries of the specific public comments under this comment:

Commenters requested a longer period for compliance for Texas, such that their coal fleet can 

have a reasonable transition time until disputed natural gas fired plant permits can be issued and 

new wind projects can go operational.

Comment 19: Comments stating that Virginia ranks low in EE and RE initiatives and has 

significant opportunity for improvement.

Response 19: The EPA agrees there is significant opportunity for states like Virginia. Many 

affected EGUs are already planning on deploying significant amounts of RE according to their 

integrated resource plans (IRPs). A recent study of IRPs, included in the docket for this 

rulemaking, shows this trend. For instance, Dominion plans for over 800 megawatts of wind and 

solar in their 2015 to 2029 planning period. Duke Energy Carolinas’ IRP has no plans for new 

coal, but describes plans for roughly 1,250 megawatts of additional RE by 2021, and 

approximately 2,150 megawatts by 2029. A significant portion (1,670 megawatts) of the planned 

RE is solar. We appreciate the commenter’s information and data. See section V.E. of the 

preamble to the final rule where the EPA addresses the feasibility of renewable energy 

deployment under EPA’s determination for BSER. 

The following are summaries of the specific public comments under this comment:

Commenters claimed that Virginia's State Corporation Commission exaggerated the potential 

cost of the proposed rule and it should be acknowledged that Virginia has significant 

opportunities for compliance. Commenters stated in a recent independent survey of the 32 largest 

investor-owned utility holding companies, Dominion Resources (Virginia's largest utility) ranked 

at the bottom for energy efficiency gains and American Electric Power (the parent of 

Appalachian Power Company, Virginia's second investor-owned utility) ranking 23rd.

Furthermore, commenters stated Virginia is near the bottom and had enormous potential for solar 

and wind. Commenters stated Dominion Resources ranks 30 out of 32 for renewable energy 
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sales, and American Electric Power ranks 24 out of 32. Commenters contended PJM said that it 

can handle 30% solar and wind without reliability concerns.

Comment 20: This comment addresses a number of issues specific to Tennessee: Tennessee 

does not have a single entity or traditional PUC responsible for overseeing all utility EE and 

valuing or crediting demand-side EE; TVA’s EE measures cannot be readily attributed to and 

credited to individual states; demand-side EE costs in proposal do not consider how utility EE 

programs are funded in Tennessee. A general concern is also expressed about forcing EE into 

CAA environmental regulations.

Response 20: The EPA recognizes that one of the major approaches available for achieving CO2

emission reductions from the electric power sector is demand-side EE. The EPA continues to 

believe that significant emission reductions can be achieved by affected EGUs by the use of such 

measures cost effectively and that such measures are likely to represent an important component 

of state plans.

The EPA has decided not to include demand-side EE (building block four) in the BSER of this 

final rule and, therefore, does not need to address the comments related to setting EE targets in 

BSER. This determination is discussed in section V.A.3.d of the final rule preamble.

Even though demand-side EE is not being included in the BSER in this final rule and, thus, not 

included in the determination of emission performance rates, the final rule provides states the 

flexibility to use demand-side EE measures in their state plans for compliance to meet the 

emission guidelines set forth in the final emission guidelines, provided they meet the applicable 

requirements established in section VIII.K of the preamble to the final rule.

The final rule provides maximum flexibility to comply with the EPA’s emission guidelines. For 

example, states can enter into multi-state plans, multi-state coordination while retaining their 

individual state goals and emission budget trading programs. Rate-based programs can use or 

purchase ERCs generated from eligible EE/RE and other resources for compliance. This

flexibility provides enough latitude for all states to comply with this rule. See section VIII.C. of 

the preamble to the final rule for the various state plan approaches states can adopt to comply

with the final rule.

The following are summaries of the specific public comments under this comment:

Commenters stated a number of different EE measures have been or are currently available in 

Tennessee and are offered by utilities (TVA and its local power companies), the public sector, 

private organizations, and businesses to public, commercial, industrial, and residential end-use 

customers. While the diversity of programs and opportunities within Tennessee is encouraging, 

commenters stated the current decentralized nature of EE efforts throughout the state and the 

absence of a traditional state PUC role in the context of the majority of electricity production in 

Tennessee, results in no single or readily-identifiable entity taking full responsibility for 

overseeing all utility EE efforts. Commenters stated additionally, Tennessee does not have an EE 
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resource standard or other EE policy mechanism that may provide centralized, consistent efforts 

to value and credit EE programs both inside and outside the utility context.

Commenters agreed EE is a cost effective way to reduce demand and a means to reduce carbon 

emissions. However, commenters were concerned the EPA is requiring states to act in a role that 

is unprecedented. Specifically, commenters were concerned the proposed guidelines will force 

EE programs to be incorporated into traditional environmental regulation under the CAA and 

require them to deliver emissions reductions in a way they have not historically been required to 

do. Commenters stated that this approach will impact the perception of EE, its relative cost, and 

usefulness. Given the unique nature of EE, commenters argued the EPA's approach to crediting 

EE programs within state compliance plans poses considerable challenges and provided the 

following examples for Tennessee:

• Tennessee has not yet developed a mature, comprehensive EE program structure 

nor does it have a PUC specifically charged with managing EE program 

performance within the utility sector. Commenters believed the proposed 

guidelines inappropriately assume states already have a structure for valuing and 

crediting demand-side EE programs and noted that because Tennessee does not 

already have such a structure the work that must be done to establish the ability to 

value and credit these programs for the purposes of a state compliance plan is 

significant.

• EPA establishes EE targets on a state-by-state basis but electricity and EE are not 

bound by state borders - particularly in Tennessee. Commenters explained that 

TVA, the primary electricity provider within Tennessee, plans, generates, and 

distributes electricity throughout a multi-state system, rather than on a state-bystate basis. Commenters believed that it will be a cumbersome and complex to 

dissect TVA's EE programs so that they can be treated and credited on a state-bystate basis.

• Commenters asserted that demand-side EE program costs as used in the proposed 

guidelines do not adequately take into consideration how the majority of current 

utility EE programs are funded within Tennessee. Commenters stated that the 

TVA Act requires TVA to charge power prices necessary to pay for the electricity 

system's operations, maintenance, and administration, provided that power is sold 

at rates as low as are feasible and therefore, TVA does not have an EE rate 

recovery mechanism like many other utilities.

Commenters recommended the EPA consider these challenges in finalizing the guidelines and 

develop guidance and support materials to address some of these concerns as they relate to EE. 

Commenters stated that failure to take these issues into account would not only discredit EE 

measures as a low-cost and environmentally-friendly means of compliance in meeting state 

emissions targets, but also result in reduced flexibility for states.
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Comment 21: Comments stating that Arizona's limited gas supply is an obstacle to replacing 

coal-fired power plants and makes the electricity grid more susceptible to natural gas pipeline 

service interruptions.

Response 21: The EPA does not prescribe how a state must meet the emission guidelines, but if 

a state chooses to take the path of meeting a state goal, these final guidelines identify the 

methods that a state can or, in some cases, must, use to demonstrate that the combination of 

measures and standards that the state adopts meets its state-level CO2 goals. While the EPA 

accomplishes the phase-in of the interim goal by way of annual emission performance rates, 

states and EGUs may meet their respective emission reduction obligations “on average” over that 

period following whatever emission reduction trajectory they determine to pursue over that 

period. 

The combination of multiple ownership and types of operational control adds to the complexity 

of electricity dispatch, but all affected EGUs, regardless of ownership and type of control, can 

use Building Block 2 to comply with the final rule. The principal difference among the differing 

entities lies in the types of methods that are available for the affected EGU owner to bring about 

the shift in generation that will make use of this building block for compliance. There are several 

alternatives to accomplish this result: the owner of the higher-emitting affected EGU may also 

own, or have affiliates that own, lower emitting generation and thus reduce its own generation 

and use its control over these other EGUs to increase their generation; an EGU may be able to 

reduce its generation and buy replacement power from the market that is lower emitting; or the 

EGU may be able to reduce its generation and procure generation from a separately-owned 

lower-emitting EGU. These alternatives will be available in states with either rate or mass-based 

state plans without any change in their general form

For further response to this comment see Section V.D of the final rule preamble of the CPP 

where EPA describes the rationale for Generation shifts among affected EGUs and the CO2

Emission Performance Rate and Goal Computation TSD for CPP Final Rule for further details 

on the final methodology for building block 2 and how the EPA changed assumptions for 

Arizona.

The following are summaries of the specific public comments under this comment:

Commenters were concerned that Arizona's limited gas supply is an obstacle to replacing coalfired power plants and makes the electricity grid more susceptible to natural gas pipeline service 

interruptions.

Some commenters were concerned that the EPA's assumptions regarding Arizona's power 

generating capacity are based on annual power consumption rather than peak demand, which 

fails to account for the times during the year that the system operates at full capacity to supply 

electricity during hot summer months. While it appears there is unused available natural gas 

capacity in the system already, commenters said that the reality is that Arizona experiences 

extreme heat in the summer months, and all available capacity is necessary to meet the spikes in 

demand that occur during that time. Although the capacity is not used year round, commenters 

said that it is an essential element of the overall power system in Arizona. Commenters said that 
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the power supply capacity assumptions for Arizona must take into consideration the unique 

climate and resulting demands on the system.

Comment 22: Comments from Wyoming requesting clarification regarding demand-side EE and 

RE and how retirements are factored into generation calculations. 

Response 22: The baseline inventory the EPA uses relies on historical data and does not 

incorporate anticipated future retirements. The EPA and most commenters supported this 

treatment as they viewed those scheduled retirements (and corresponding emission reductions) as 

an alternative compliance flexibility based on already scheduled reductions. If the state is 

implementing a rate-based plan than it could use eligible RE and demand-side EE to adjust the 

emission rates for compliance. This adjustment would only be applied to the affected units that 

are still in operation and it apply to the current emission rate of the affected units. For details on 

the specific calculations for adjusting the emissions rate see Section VIII.K.2 of the preamble to 

the final rule.

The following are summaries of the specific public comments under this comment:

Commenters also asked if, by 2020, Wyoming has been obliged to prematurely retire a large 

portion of its coal fired EGUs, how would the Block 3 and 4 savings anticipated between 2020 

and 2029 either apply to the retired generation, or apply to the remaining generation. 

Commenters explained that some Wyoming wind generation is not associated with either 

Wyoming EGU operators or local distribution in Wyoming and asks should those Block 3 hours 

apply to Wyoming Block 1 generation, and if so, on a proportionate basis. Further, should those 

Block 3 hours apply to Block 1 generation in another state and should they simply be ignored. 

Comment 23: Comments suggesting requiring Nebraska and Kentucky to meet emission goals 

will impose significant challenges and the states may not be able to meet the goals in the 

expected timeframe.

Response 23: States are not required to implement the building blocks set in the EPA’s BSER 

determination. The EPA is providing states with maximum flexibility to achieve their emission 

standards or CO2 state goals in the final emission guidelines. For example, states can enter into 

multi-state plans, multi-state coordination while retaining their individual state goals, and 

emission budget trading programs. Certain rate-based state plans can use or purchase ERCs 

generated from eligible resources (e.g., EE/RE). This flexibility provides enough latitude for all 

states to comply with this rule. See section VIII.C of the preamble to the final rule for details on 

the different state plan approaches states can use to comply with the final emission guidelines. 

See section VII.E of the preamble to the final rule for details on plan submittal and timing. The 

EPA will work with states and stakeholders and other federal agencies as appropriate.

The following are summaries of the specific public comments under this comment:
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Commenters stated that requiring Nebraska and Kentucky to meet emission goals will pose 

significant challenges and these states may not be able to meet the goals in the expected 

timeframe. Flexibility to use all the building blocks in a compliance plan may be limited, making 

it difficult to achieve the results the EPA is anticipating with this proposal.

Comment 24: Comments suggesting that Idaho not be subject to a performance goal.

Response 24: See section V.E. of the preamble to the final rule and the EPA’s CO2 Emission 

Performance Rate and Goal Computation TSD for CPP Final Rule for details on the EPA’s 

rationale for renewable energy BSER determination and how the EPA has changed the 

renewable energy assumptions under BSER in the final rule.

The following are summaries of the specific public comments under this comment:

Commenters stated Idaho should not be subject to a CO2 emission performance goal because 

Idaho's generation mix reflects BSER and its carbon profile is already very low, citing that 

Idaho's 2012 CO2 emission level was next to the lowest emission level in the country, second 

only to the emission level of Vermont, the one state that the EPA does not require to meet a goal. 

Idaho's carbon profile is low because Idaho has no in-state coal generation and that Idaho's two 

NGCC plants (including one that just started operating in mid-2012) already comply with the 

NSPS that the EPA has proposed under CAA Section 111 (b). Commenters stated that these 

sources thus already employ BSER under Section 111(d).

Comment 25: Comments responding to the four major questions in “Considerations in the 

Design of a Program to Reduce Carbon Pollution from Existing Power Plants.”

Response 25: We appreciate this information. No response to this comment is necessary.

The following are summaries of the specific public comments under this comment:

Commenters offered the following responses to the four major questions in EPA's 

"Considerations in the Design of a Program to Reduce Carbon Pollution from Existing Power 

Plants": 1. What is state and stakeholder experience with programs that reduce CO2 emissions in 

the electric power sector? Kansas has no specific regulatory requirements for sources to report 

CO2 emissions or CO 2 emissions reduction for inventory or control purposes. Kansas relies on 

EPA's greenhouse gas reporting program as a source for CO2 emissions data. 
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5.15 OTHER

This section contains comments regarding the state plan that do not fit the topic area of other 

sections in chapter 5. The comments in this section generally include comments requesting 

certain issues be covered in the state plans, such as regional electricity markets, development of 

transmission and energy infrastructure, least-cost dispatch, consumer protections, and 

environmental and climate justice considerations. Commenters asked for guidance on 

incorporating certain considerations into a state plan, requested that local governments be 

involved in designing and implementing the state plan, and requested that EPA not make the 

eligibility of reductions contingent on state requirements.

Commenters have raised a number of issues related to this subsection which are organized by 

topics (comments) below. Responses are provided for these topics. 

Comment 1: Comments recommending collaboration with local governments in developing and 

implementing state plans.

Response 1: The EPA agrees with commenters that consultation and coordination with local 

governments and cities will be an important component in the development and implementation 

of many state plans. In the final emission guidelines’ state plan development process, there are 

various opportunities for input from local governments prior to initial plan submittal, prior to 

complete plan submittal, and when the EPA proposes to act on a state plan and publishes a notice 

in the Federal Register. This includes a requirement that states provide an opportunity for public 

engagement on their state plans. See section VIII.D.2 of the final rule preamble of the CPP. 

Additionally, one of the justifications for seeking an extension for plan submittal is for states 

who wish to actively engage with communities, including low income communities and 

communities of color, throughout the state plan development process beyond the public 

participation requirements of 40 CFR 60.27. See section VIII.E.2 of the final rule preamble of 

the CPP. 

The final emission guidelines provide flexibility for states to pursue policies to reduce carbon 

pollution that:

• continue to rely on a diverse set of energy resources; 

• ensure electric system reliability;

• provide affordable electricity; 

• recognize investments that states and power companies are already making; and 

• tailor plans to meet their respective energy, environmental and economic needs and goals, 

and those of their local communities. 
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The final emission guidelines also allow states to build on their existing progress, and the 

progress of cities and towns, in addressing GHGs, and minimizes additional requirements for 

existing programs where possible. We therefore disagree with commenters that the EPA should 

include a mechanism to “reward” states based on the quality of partnerships with local 

governments and program implementers. To ensure the coherence of state plan requirements and 

to maximize the flexibility for states in developing their state plans, the EPA will approve state 

plans that meet the requirements and include the components listed in the final guidelines and are 

not including a mechanism to reward states for anything additional. 

We acknowledge the EPA’s limited outreach specifically to cities and local governments during 

the proposal phase. Because states are the EPA’s co-regulators, the EPA has primarily focused 

outreach efforts on states. We intend to engage with local governments on strategies and to 

support states in working with and considering local governments during their plan development 

and implementation. To provide local governments, communities (including low income 

communities and communities of color), and other stakeholders with an understanding of the rule 

requirements, and to provide efficiencies where possible and reduce the cost and administrative 

burden, the EPA will continue outreach throughout the plan development and submittal process.

The following are summaries of the specific public comments under this comment:

Commenters recommended that Federal agency and state CPP initiatives should be supported 

through local government implemented and managed programs. Commenters pointed out that 

coordination and support with local government is key for implementing all aspects of CPP 

BSER, but especially for energy efficiency programs and for incorporating greater use of power 

from renewable energy sources. Commenters believed that the agency should and can more 

effectively partner itself with local governments to achieve CPP goals. Commenters stated that 

extensive planning is required of states, and it makes sense for states and local governments to 

comprehensively address local circumstances that could compromise the electric system and 

reliability. Commenters pointed to environmental factors such as heat and drought and severe 

weather events that could impact utilities that would need to be addressed on a local level. 

Commenters believed that state plans should incorporate collaboration with local government.

Commenters suggested that the agency should use a mechanism in reviewing state plan adequacy 

which rewards consistent behavior on a continuous improvement basis, and that a similar 

mechanism can reward the quality of partnerships with local governments and program 

implementers. Commenters referred to hundreds of initiatives implemented in cities and regions 

that were developed with support of the Administration's Partnership for Sustainable 

Communities program, and this program was presented as an example of a 

mechanism that might be developed and used in reviewing state plans and to encourage actions 

that could be counted toward emission reduction goals.

Commenters noted that outreach in support of the rule shows only one specific effort aimed at 

cities and local governments out of hundreds listed, and are suggesting that this is not enough.

Commenters noted that these ideas are consistent with recommendations included in The White 

House State, Local and Tribal Leaders Task Force on Climate Preparedness (WHTF) and EPA's 

statements contained in the Federal Register announcement of the CPP. Precedent for 
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implementation of CPP initiatives at the local level is supported by the following examples given 

by the commenters:

• stipulation in the CAA (1990) that control of criteria pollutants is implemented at 

the metropolitan level;

• the U.S. EPA launched Green Infrastructure Collaborative among government 

agencies, NGOs, and other private sector entities to advance green stormwater 

infrastructure; and

• National law that allows for the allocation of disaster response funding targeted to 

counties and principle cities.

Further, commenters believed that electrical demand reduction will come from larger numbers of 

smaller sources (e.g., buildings, mobile sources and improvements induced in both these sectors 

by better land use) in local place-based settings; rates and energy efficiency programs for 20

percent of the population is controlled by publicly-owned and rural electric utilities; and it was 

noted that cities and communities are independently adopting climate protection goals. 

Commenters provided examples of successful carbon reduction programs implemented at the 

local level including:

• The Chicago energy efficiency program that led to significant State level GHG 

reductions through the closing of 3 coal powered plants, and

• Locally implemented energy efficiency initiatives through Federally supported 

local programs such as the Better Buildings Neighborhood Initiative;

• Property Assessed Clean Energy (PACE) programs, an innovation founded by 

MIP member the City of Berkeley CA and proliferated nationally in hundreds of 

communities with the support of enabling legislation in over 20 States since.

• Local governments that have already adopted climate protection goals: Arlington, 

Chicago, Dubque, El Paso, Portland and Multnomah Counties, and San Antonio.

Commenters strongly recommend that the rule provide a platform for this kind of collaboration, 

and include these ideas into State plans, to help implement the Clean Power strategy. 

Commenters suggested that operationally, the rule should reward states and utilities that ensure 

effective implementation at the local level through partnerships, and that co-leverage actions 

intended to reduce emissions, increase climate resilience and that do so cost-effectively with the 

maximum potential local value creation and value capture to ensure growing public support.

Comment 2: Comments on including interests of regional markets and development of 

transmission and energy infrastructure in development of state plan.

Response 2: We agree with commenters that the interest of regional markets should be 

considered in developing state plans. States share grid regions, impacts from plan 
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implementation will be regional in nature and multiple analyses indicate that regional approaches 

could achieve state goals at lesser cost than individual state plan approaches. The EPA is not 

requiring states to develop transmission and energy infrastructure, but note that to the extent that 

meeting final rule requirements results in upgrades in transmission efficiency and infrastructure, 

the outcome could be that the system is more robust and faces fewer risks to electric reliability. 

See Section VIII.C.5 of the final rule preamble of the CPP.

We agree with commenters that we should consider the interaction of other regulations and 

agencies with the CPP, particularly FERC. See Sections I.A.2 and II.C.3 of the final rule 

preamble of the CPP. See Section VIII.G.2 of the final rule preamble of the CPP for a discussion 

of the final guidelines’ protection of reliability. For a discussion of resources available to states 

in designing state plans, see section VIII.H. 

The following are summaries of the specific public comments under this comment:

Commenters recommended that the EPA ensure that the interest of regional markets and the 

development of transmission and energy infrastructure should be represented in the development 

of state compliance plans. Commenters noted that the EPA must consider whether the 

complicated applications of MATS, the CPP, and FERC would impact the planning and 

development of transmission and energy infrastructure, and should coordinate with FERC for 

consideration of whether changes to market rules would be needed to support reliable 

implementation of the state plans. Commenters noted that the EPA could leverage existing 

planning resources and studies that consider electric reliability as well as emissions reductions, 

such as the Eastern Interconnection Planning Collaborative, as support for states to consider in 

the development of CPP compliance plans.

Comment 3: Comments on including considerations of the electricity markets and least-cost 

dispatch in state plans.

Response 3: We agree with the commenters that states should be allowed to develop state plans 

that mesh with the operation of existing electricity markets. We encourage states to cooperate 

regionally, as regional cooperation in planning and reliability assessments is an important tool to 

meeting system needs in the most cost-effective, efficient, and reliable way. See Section VIII.C.5 

of the final rule preamble of the CPP.

We also note that the final guidelines support emissions trading, which provides a way for states 

to set standards of performance that realize the required emissions reduction without requiring 

any form of “environmental dispatch” because, as many existing trading programs have shown, 

monetization of the environmental constraint is consistent with a least-cost dispatch system. See 

Section V.A.2.f of the final rule preamble of the CPP. For discussion of the EPA’s consideration 

of “economic dispatch,” see Section V.D.1 of the final rule preamble of the CPP.

The following are summaries of the specific public comments under this comment:

Commenters requested that EPA allow for State Implementation Plans that mesh with the 

operation of competitive wholesale electricity markets, considering parts of the country that have 
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had electricity industry restructuring and those that have not. Commenters stated that the rule 

must recognize the importance of centralized least-cost dispatch, and allow for direct 

monetization of emission reductions and compliance costs as inputs to these competitive 

markets.

Comment 4: Comment requesting guidance to consider conditional exemptions, 

subcategorization, and alternative compliance mechanisms.

Response 4: In response to comments that the EPA must establish the Best System of Emission 

Reductions (BSER) specifically for affected sources, rather than by means of merely setting 

state-specific goals, the final guidelines express the BSER by establishing performance-based 

CO2 emission rates that are uniform across each of two source categories (fossil fuel-fired 

electric steam generating units and stationary combustion turbines) for the affected EGUs 

covered by the guidelines. We cannot emphasize enough that, while the final guidelines now take 

a source-specific approach in setting CO2 emission performance rates, this does not change the 

fact that each state’s goal is tailored to its particular sources, and it in no way alters or curtails the 

flexibility inherent in the proposal’s state-specific goals approach, which the final guidelines 

retain. Thus, to maintain the proposal’s flexibility for states, the guidelines continue to define 

state planning and implementation obligations through state-level goals, which we have 

calculated by translating the source category-specific CO2 emission performance rates into 

equivalent statewide rate-based and mass-based CO2 goals.

Given this, we agree with commenters that state plans may exempt a utility or unit from 

contributing to the reductions needed to meet the state goal, subcategorize by utility type within a 

state plan, and establish more than one compliance option within a state. See Section VIII of the 

final rule preamble of the CPP.

The following are summaries of the specific public comments under this comment:

Commenters requested that EPA provide guidance for states to consider conditional exemptions, 

subcategorization of utilities, and alternative compliance mechanisms in state plans. Commenters

stated that their utility's carbon intensity equation already meets or exceeds what is expected of a 

utility or unit to achieve as a result of the proposed rule. For these reasons, commenters stated 

that a state plan should be authorized to conditionally exempt a utility or unit based on specific 

findings at the state level that the integration of the utility or the unit would cause 

disproportionate financial hardship while not substantively aiding the state in meeting the goals 

of the CPP. Commenters also requested that the EPA should expressly clarify the ability of a 

state to subcategorize by utility type within a state plan, in order to better reflect the obligations 

that will accrue to each utility based on the assets it owns, its ownership structure, the authority 

of the state EPA to require actions, and how it engages in electric markets. Commenters also 

requested that EPA clarify that states may establish more than one compliance option within a 

state such that utilities with different ownership structures, assets and obligations may choose to 

aid the state in meeting its obligations to comply with the CPP in the most efficient manner 

possible.
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Comment 5: Comment stating that environmental and climate justice should be considered in 

state plans.

Response 5: In the state plan development process for the final guidelines, there are various 

opportunities for public input prior to initial plan submittal, prior to complete plan submittal, and 

when the EPA proposes to act on a state plan and publishes a notice in the Federal Register.

Additionally, one of the justifications for seeking an extension for plan submittal is for states 

who wish to actively engage with communities, including overburdened communities, 

throughout the state plan development process beyond the public participation requirements of 

40 CFR 60.27. See Sections VIII.D-E and IX.B of the final rule preamble of the CPP. 

The following are summaries of the specific public comments under this comment:

Commenters stated that environmental and climate justice issues must be a part of the state 

implementation planning process. Commenters urged that environmental leaders be involved in 

the process. Commenters requested that affected communities be engaged throughout the 

process. Commenters urged that public resources must be made available to communities as they 

transition to cleaner forms of energy. 

Comment 6: Comments recommending ways to ensure that state plans include consumer 

protections.

Response 6: We disagree with the commenters that the final guidelines should require state 

plans to include a mechanism to protect consumers by constraining residential rates. (We also 

disagree with the commenters’ characterization of the requirement that determination of BSER 

include consideration of non-air quality health and environmental impacts. See Section V.A.1.c 

of the final rule preamble of the CPP.) Instead, the final guidelines provide states with flexibility 

to design plans that reduce costs to consumers, minimize stranded assets, and spur private 

investments in renewable energy and energy efficiency technologies and businesses.

Regarding the commenters’ specific recommendations, the final guidelines provide ample 

latitude for states and utilities to rely on demand-side EE in meeting emission reduction 

requirements. We are providing resources to assist states in developing their plans; see Section 

VIII.H of the final rule preamble. The final guidelines include requirements for state and EGU 

reporting and verification; see Sections VIII.D.2 and VIII.F of the final rule preamble of the 

CPP. The EPA will publicly disclose state plans and progress by proposing and taking final 

action on each state plan submittal in the Federal Register and provide an opportunity for notice 

and comment. When a state plan submittal is approved by the EPA, the EPA will codify the 

approved 111(d) state plan in 40 CFR part 62. See Section VIII.D.3 of the final rule preamble of 

the CPP. The final guidelines require public participation and certification of a hearing on each 

state plan, including encouraging states to particularly focus on low-income and other vulnerable

communities; see Section VIII.D.2.a.6 of the final rule preamble of the CPP. We are also 

offering an additional incentive to remove current barriers to implementing RE and demand-side 
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EE programs in low-income communities through a Clean Energy Incentive Program; see 

Section VIII.A.2 of the final rule preamble of the CPP.

We disagree with the commenters that energy efficiency measures should be required for a state 

plan to be approved. See Section V.A.3.d of the final rule preamble of the CPP for a discussion 

of why we are not finalizing the proposed Building Block 4, demand-side energy efficiency 

measures, as part of BSER.

The following are summaries of the specific public comments under this comment:

Commenters recommended that EPA require that each state plan include a mechanism to protect 

consumers by constraining residential rates. Commenters argued that while a state could 

conceivably force onto residential consumers any increased costs from reducing emissions, these 

actions would not meet the definitional requirement that BSER include non-air quality health and 

environmental impacts. Commenters recommended three ways in which EPA could ensure that 

state plans include consumer protections: 

• by emphasizing cost-effective energy efficiency, and helping states share information to 

implement successful programs that save energy and money; 

• mandating transparency and data collection as part of each implementation plan, and 

publicly disclosing states plans and progress in a manner that is accessible to the average 

consumer; and 

• requiring consumer participation and oversight to ensure fairness for consumers. 

First, Commenters asserted that EPA should not approve a state plan as meeting the BSER if 

robust energy efficiency measures are not included.; Commenters also noted that for state plans 

where customer participation is required, such programs should include a strategy for achieving 

high participation rates, especially among low-income ratepayers. Commenters stated that EPA 

must hold states accountable by requiring transparency, analysis, and data to compare how states 

are serving consumers through the state plans; specifically, commenters recommended that EPA 

require states to report on utility bill impacts, include impacts for low-income ratepayers and 

strategies to mitigate them. Commenters also stated that customer participation in the 

development of state plans would hold states, utility boards, and utilities accountable for costeffective investments and programs that reduce emissions while maintaining affordability. 

Commenters also requested that EPA require as part of BSER that consumer interests be 

considered in addressing variables that can raise residential rates, such as increased infrastructure 

costs, low participation rates in EE programs, higher rates of return for utility shareholders, or 

higher fixed charges or surcharges on bills. Commenters noted that EPA could require public 

notice and comment, economic analysis from a consumer standpoint, or a requirement that each 

state plan includes actions that ensure that efficiency programs and any changes to rate design 

will help lower bills for residential ratepayers and low-income residents.