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RMB Consulting & Research, Inc.

5104 Bur Oak Circle Phone (919) 510-5102

Raleigh, North Carolina 27612 Fax (919) 510-5104

T E C H N I C A L M E M O R A N D U M

TO: Michalene Reilly, Hoosier Energy

Jay Holloway, Sutherland Asbill & Brennan LLP

FROM: Ralph Roberson, RMB

Rob Barton, RMB

DATE: March 17, 2015

SUBJECT: Supporting Analysis for Hoosier Alternative to Proposed Clean Power Plan

The following memo summarizes the methodology used to determine the emissions reduction 

associated with Hoosier Energy’s proposed alternative to EPA’s proposed Clean Power Plan 

(CPP).1 

This memo focuses on the procedures used to estimate the emissions reduction in 2030 and 

compares this reduction with EPA’s estimate in the proposed CPP. RMB assumed that all units 

that commenced commercial operation prior to 1978 would be retired by 2030 and all units that 

commenced operation after 1978 would remain in operation. 

METHODOLOGY

(1) Determination of Coal-Fired Emissions Database 

RMB created a new CO2 emissions database that contained annual average emissions data for all 

coal-fired units for the period 2003 – 2012. The database was similar to the EPA database used 

in the CPP rulemaking although it was comprised solely of data from the Clean Air Markets 

Division (CAMD) quarterly emissions files and included dates of commercial operation and CO2

emissions estimates (tons per year and lb/MWhg) based on gross generation.

2

 In RMB’s 

database, all CO2 emissions averages excluded substituted data and bias adjustment factors. 

RMB used gross generation data rather than net generation data to avoid the use of EIA net 

generation data, which was found to contain reporting errors that resulted in anomalous CO2

emissions rates in the EPA database. Although net and gross generation may differ 5-10 percent

depending on the plant, these differences are not relevant for this analysis because both RMB 

and EPA estimated mass reduction using a consistent basis (e.g. mass reduction = gross 

generation (MWhg) x CO2 emission rate (lb/MWhg) = net generation (MWhn) x CO2 emission 

rate (lb/MWhn).

 

1

79 Fed. Reg., 34,830 (June 18, 2014).

2 Annual averages were calculated based on the reported hourly values.
MEMORANDUM

February 2, 2015

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(2) Calculate 2030 Baseline Emissions for All Coal-Fired Units

RMB calculated baseline emissions for 2030 for all coal-fired units in the fleet. This estimate is 

based on unit-specific capacity factors, unit generator ratings, and historical CO2 emissions rates

(lb/MWhg). The 2030 capacity factor for each unit is based on the average capacity factor for the 

period 2003 – 2012. This assumption was based on “business as usual” where historical 

operation is representative of future operation. The CO2 emission rate is based on the average 

emissions rate (lb/MWhg) for the period 2003 – 2012. For any unit that was missing the average 

CO2 emission rate or capacity factor, the average value was applied for all units for the period 

2003 – 2012. RMB assumed that any unit that operated at any point during the 2003 – 2012 

timeframe would continue operating until 2030 (e.g. no unit shutdowns prior to 2030 – all 

reductions would occur in the year 2030). No new coal-fired generation is assumed for the 

period 2012 – 2030. Any new generation that is required during that time would be provided by

other sources (i.e. gas, renewable energy, nuclear) and/or demand-side reductions.

(3) Estimate Emissions Reduction Due to Unit Heat Rate Improvements

RMB estimated the emissions reductions associated with the proposed heat rate improvements 

for all coal-fired units in the fleet. RMB assumed an average heat rate improvement for all units 

of 2 percent.

3

 Because changes in heat rate correlate directly with CO2 emissions rate, RMB 

reduced the annual average CO2 emissions rates by the same percentage as the estimated heat 

rate improvement. The estimated emissions reductions were then calculated for those units that 

commenced commercial operation before and after 1978 using different methodologies. For 

those units that commenced commercial operation prior to 1978, the effects of the heat rate 

improvements were included in the estimated emissions reductions associated with the shutdown 

of these units in 2030 as described below. For those units that commenced commercial operation 

after 1978, the estimated emissions reductions were calculated by comparing the heat-rate 

adjusted emissions to the baseline emissions for the affected units. 

(4) Estimate 2030 Emissions Reductions Including Natural Gas Offset

RMB assumed that the lost generation due to shut down of pre-1978 units was replaced with 100

percent gas-fired generation. This scenario assumes that the required gas generation would be 

achieved by increasing the capacity of existing gas-fired units and by the construction of new 

combined cycle units. The CO2 emissions rate was assumed to be equivalent to a new combined 

cycle unit (1,000 lb /MWhg). 

RESULTS

The results show an estimated annual emissions reduction in 2030 of 750 million tons of CO2

with natural gas offset. These estimates provide a range of estimated reductions associated with 

the proposal. Actual reductions will be somewhere between these two estimates because

 

3 Estimated heat rate improvement. This compares to EPA’s assumption of 6% used in Block 1 reductions in the 

CPP.
MEMORANDUM

February 2, 2015

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replacement generation will include a combination of gas-fired and non-fossil fuel generation. 

These results compare with EPA’s estimated emissions reduction of 600 million tons of CO2 for

Compliance Option #1 using the regional compliance approach and 612 million tons using the 

state-level compliance approach.4 

 

4 Regulatory Impact Analysis for the Proposed Carbon Pollution Guidelines for Existing Power Plants and Emission 

Standards for Modified and Reconstructed Power Plants, US EPA, June, 2014.