MEMORANDUM

To: Carbon Power Plan for Existing Power Plants; Docket id: OAR-2013-0602

From: Region 5, EPA

Summary: The following questions were submitted to EPA prior to an 8/28/14 conference call 

between EPA and Michigan Department of Environmental Quality about the proposed carbon 

power plan for existing power plants.

Additional comments from Michigan submitted on August 21, 2014.
QUESTIONS FOR EPA ON 111(D) PROPOSAL

1. It does not appear EPA’s calculation of coal plant efficiency savings includes the 

degradation of efficiency at coal plants when they are cycled up and down to 

accommodate greater use of natural gas combined cycle generation. If not why not? The 

degradation is a fact that is cited in EPA’s own Technical Support Document “GHG 

Abatement Measures” pages 2-5. There EPA states:

“Operating an EGU as a baseload unit is more efficient than operating an EGU as a load 

following unit to respond to fluctuations in customer electricity demand.”

2. Please provide the exact calculation, including all corresponding data and assumptions, 

of the 2012 MI carbon Intensity ratio. It is important to understand how it is adjusted 

and how nuclear affects the target.

3. Michigan’s assigned natural gas rate of 810 lbs/MWh is not consistent with proposed 

111(b) requirements for new plants which are typically more efficient than existing 

plants. Please explain the basis for the assigned rate EPA used in the proposed rule.

4. EPA’s calculation includes 6% “at risk” nuclear which lowers Michigan’s goal to 1,161 

lbs/MWh instead of a goal of 1,183 lbs/MWh if there was 0% “at risk” nuclear. Why

does existing nuclear lower the target? This presents a penalty to states that have invested 

in zero carbon generation and a disincentive for any utility contemplating upratings at

existing nuclear plants.

5. How would electrical generation from hydro, biomass, and land-fill gas count toward 

meeting the goal?

6. Would Ludington Pumped Storage count as hydro? How should its generation be treated 

in reaching Michigan’s goal? Was the load represented by Ludington PS reflected in our 

state generation totals?

7. How can we accommodate unanticipated load growth in a mass-based system? Would 

mid-term corrections be permissible?

8. Would EM&V have to be harmonized with other trading states if Michigan decides to 

take a multi-state approach to meet 111(d)?

9. How do we determine/control dispatch of any fossil-fueled EGU when this is performed 

by the RTO (MISO) under an economic market-based system of dispatch?

10. How do we calculate retirements of EGUs during the compliance period for federal 

enforceability under 111(d)?

11. How will EPA guarantee that heat rate improvements will not be considered subject to 

NSR permitting considering that the EPA and DOJ made the opposite argument in United 

States v. DTE Energy Co., 711 F.3d 643, 644 (6th Cir. 2013) even though actual 

emissions did not increase?

12. Is it accurate to describe that RE prior to 2014 will not be counted towards our CO2 

reduction goal?
13. What is more important to EPA – the percent reductions Michigan obtains from a 2012 

baseline or the intensity targets?

14. How will EPA allow states flexibility accounting for units that are prevented from 

retirement due to reliability requirements?

15. Because the proposed rule relies heavily on natural gas generation to replace coal 

generation, will the EPA allow relief from its GHG limits if the price of natural gas 

increases significantly beyond assumptions used in EPA’s modeling?

16. With its firm and significantly reduced limits on future GHG emissions, does the 

proposed rule establish a de facto cap on population and industrial growth in many states? 

17. Because the rule may cause some states to mandate closure of some coal-fired power 

plants, has the EPA evaluated whether the rule is likely to jeopardize the future of public 

power in the United States given that public entities are generally not as well positioned 

to replace that generation as investor-owned utilities?

18. What is the EPA’s rationale for rejecting hydroelectric generation from every state’s 

renewable energy portfolio, while at the same time crediting all other renewable energy

in states that have much higher renewable energy capacity factors than other states? For 

example, Kansas has a great deal more potential for generating energy from wind than 

Virginia, but Virginia has a greater potential for hydroelectric generation than Kansas. 

Why is Kansas allowed to use all of its wind generation to satisfy the EPA’s GHG limit, 

but Virginia is not allowed to use any of its hydroelectric generation? 

19. Can EPA provide a sample conversion of a rate-based to a mass-based goal that relies on 

a portfolio approach?

20. Do energy efficiency measures require extensive monitoring or verification if the state 

employs a mass-based goal?

21. How can a state utilizing a mass goal successfully incorporate energy efficiency measures 

into their programs?

22. Will states have the option to count efficiency investments on the utility side of the meter 

towards meeting carbon limits? They are as effective as customer improvements. Utility

side of the meter improvements could provide additional advantages. Improvements to 

utility distribution could provide both carbon reduction and reliability improvements.

23. For the state plan, do final legislation, final rules, and other enforceable measures have to 

be in place or can they be proposed or draft requirements?

24. Please provide your rational for how heat rate improvements are going to be useful as 

part of the goal calculation in light of how to measure the improvements? Utility

comments to us have indicated that current methods used to estimate and report fuel heat 

input to EPA are not sufficiently precise to consistently detect a heat rate improvement of 

6% or less. We are also hearing that the 6% heat rate improvement is too high and 

expected heat rate improvements on coal-fired units are more in the neighborhood of 2 –

3%. So potentially any heat rate improvements may not be measureable, and therefore, 

not helpful in achieving Michigan’s goal.
25. How will measures purchased in conjunction with federal incentives (new furnaces, for 

example) or new appliance standards count?

26. How will MISO, which dispatches on a regional (not state-by-state) basis, be able to 

economically dispatch NGCC units over coal to the extent that Michigan maximizes the 

savings from building block II?

27. What happens 8 years out when a new source is no longer considered new? (see p. 34,908 

end of third column of FR version.)

28. How could a rate-based approach work in a regional cap-and-trade program?

29. What if a state meets the final goal, but does not continue meeting it at some point past 

2030?

30. Would EPA have the authority to administer EE programs if Michigan failed to achieve 

its 2030 goal?

31. What happens if a state does not meet the interim goal but does meet the final goal?

32. What are acceptable guidelines for forecasting electricity demand growth over the 

compliance period (2020 – 2029)? How will new plants be accounted for?

33. Under a mass based approach, if a coal plant is retired, are the total pounds of CO2 

adjusted downward? If a new plant replaces it, do the new CO2 emissions count? If so, 

wouldn’t this encroach on 111(b)?

34. Under a rate-based approach, if a coal plant is retired, are the numerator and denominator 

adjusted downward? If a new, more efficient plant replaces it, are the numerator and 

denominator adjusted upward? If so, wouldn’t this encroach on 111(b)?