MEMORANDUM

To: Carbon Power Plan for Existing Power Plants; Docket id: OAR-2-13-0602

From: Region 5, EPA

Summary: The following questions were submitted to EPA prior to an 8/27/14 conference call 

between EPA and WI DNR about the proposed carbon power plan for existing power plants.

Additional comments from Wisconsin.
Follow-up Wisconsin DNR Questions/Issues for EPA re: Clean Power Plan Proposed Rule

Updated August 20, 2014

Miscellaneous:

1. At a macro level, how does EPA envision the requirements for the GHG NSPS under 

111(b) for new sources, the “modified and reconstructed” proposal under 111(b) and the 

111(d) requirements playing together for permitting purposes?

2. Does EPA have state-specific compliance costing estimates available? If not, when will 

this information become available? 

3. (NEW) What is the legal justification for excluding actions by sources that are not 

affected units (e.g., industrial sources)? Under the NOx SIP call, industrial sources were 

allowed to opt into the program so that emissions reductions from these sources could be 

credited under that program. Why are industrial sources not allowed a similar “opt in” 

possibility for compliance? The one option that does appear available under the proposed 

rule is for industrial CHP units providing electricity to the grid may be used for 

compliance. Is this true? Is there a minimum monitoring requirement for such units?

4. (NEW) We understand that EPA does not intend to issue a model rule with a trading 

program or require participation in a cap-N-trade system. However, there is significant 

interest in EPA providing the infrastructure such as a CO2 / MWh tracking system such

as CAMD provides now for tracking allowances under the Acid Rain, NOx SIP call and 

CAIR/CSAPR systems. This system is already used to track CO2 emissions from the 

power plants. The states could then structure programs to allow trading that utilizes this

infrastructure. Are there barriers or legal impediments to EPA providing this 

infrastructure for national trading?

5. (NEW) Revising State Plans:

a. Currently, states can submit SIPs for federal approval and then make changes to 

these SIPs with federal approvals at a later date. Is there any prohibition to do the 

same with state plans under 111(d) after the initial submittal and approval of a state 

plan.

b. If the state can change a plan, can such a change include updating electricity load 

growth rates (based on better information) that were used in originally calculating 

mass caps under an approved plan.

Related to calculation of mass-based goals

1. Can EPA provide a clear, repeatable method to be used by all states to convert from an 

emissions rate to mass? 
2. The proposed rule language seems to indicate that the mass emission limitation is the 

result of multiplying the emission rate limit by the projected generation (w/o the rule in 

place) of the state’s fossil fuel fleet (units > 25 MW). Is this correct? For example, the 

Midwest Independent System Operator (MISO) is currently assuming a baseline growth 

in electricity load of 0.8% per year. Is it correct to use this type of best estimated 

value. Or does the projection of generation need to be based on EPA’s 0.35% growth 

rate after applying the EE building block. Do other building block type of actions need to 

be accounted for in some way? Another factor is whether the projection of generation for 

calculating a mass limit need to include units other than the fossil fuel plants (e.g. 

baseline renewable, nuclear, etc...)?

Related to use of existing state programs for compliance:

1. What would it mean to have state programs (e.g., RPS or EERS programs) become 

federally enforceable? What would be the consequences if one of these programs failed 

to meet the goals laid out in the state plan? Would there be any consequences for that 

program? Or would the state just be responsible for making up the difference?

2. Similarly, is EPA planning to set criteria for what kinds of renewable electricity may

count towards compliance or will EPA defer to decisions states have already made about 

this? (This relates to decisions such as whether to count biomass-derived power, cofiring of renewables and fossil fuels, thresholds for hydro power, the shelf life of RECs, 

etc.)

3. Which entity will certify individual renewable facilities as eligible for 111(d)? (i.e. EPA, 

states, program administrators of tracking systems).

4. Will the EPA establish avoided CO2 per MWh of renewable energy, or let states’ 

propose?

5. Related to energy efficiency: does EPA plan to allow “gross” energy efficiency savings 

(i.e., all avoided generation/emissions) to count towards compliance or would compliance 

be limited to “net” savings (i.e., only those measures that are believed to have occurred as 

a direct effect of the program)? Does EPA expect states to make an effort to exclude 

“free riders” from compliance? Some states have methods to make these estimates, but it 

is a somewhat subjective distinction to make and would be hard to do so consistently

between states.

Alternative approaches:

1. EPA discusses (on pages 313-320 of the prepublication Preamble) an alternative 

approach based on application of building block 1 accompanied by reductions in coal 

generation (indirectly determined through building blocks 2-4). Are there any
supplemental materials available that describe this approach in more detail? How does 

the overall goal determined by this approach differ from that proposed?

Questions answered by Region 5:

Miscellaneous

1. Can international trans-boundary renewables/hydro be used for compliance purposes? 

E.g., purchased hydro from Manitoba?

2. Time provided under the proposal for 111(d) plans is inadequate to develop rules and/or 

have statutory changes made. EPA may, therefore, have to FIP states. Please provide 

details on what EPA’s FIP will entail/contain.

3. What is the penalty for missing the date to submit a plan (other than a FIP)? Will other 

CAA sanctions apply?

6. Is there a mechanism for states to take credit for actions by sources that are not affected 

units (e.g., industrial sources)? For example, if a non-affected industrial source removes 

coal-fired boilers and replaces them with lower CO2 emitting natural gas fired boilers? If 

yes, please provide an explanation of how this can be done. (follow-up question added 

above)

Adjusting state goals

1. If a state decides to comply with a mass-based standard, would it be possible to adjust the 

goals in the future if the projections used to determine the goal prove to be way

off? Some reasons to make such adjustments might be an unanticipated, long drought 

that lowers production from hydropower or the severe failure and shutdown of a nuclear 

plant or some other EGU.

2. Would it be possible to base the goals in building block 1 on what is achievable at a state 

or regional level rather than what is achievable for the country as a whole?

Trading programs:

1. How does EPA envision using existing tracking systems for renewable energy certificates 

(RECs) such as M-RETS? Could states use these existing programs, which track RECs 

and allow entities to purchase RECs (representing MWh of renewable electricity), as a

way to demonstrate compliance with the renewable electricity parts of state goals?

2. If EPA allows use of M-RETS and other tracking systems for compliance, would it be 

possible to expand these systems to track and trade energy efficiency? Would EPA allow 

such an approach?
3. Does EPA envision needing separate trading systems for pounds of CO2 and for 

megawatt hours of electricity avoided/generated?

Existing state programs:

4. Does EPA plan to allow states to use tried and tested state approaches for estimating 

energy efficiency and renewable electricity impacts, as long as such programs meet some 

minimum requirements? For example, does EPA intend to let states who have developed 

rigorous ways to handle lifetime of EE measures to continue using their approach?