MEMORANDUM TO THE DOCKET: 	Regarding the Application of the Work Allocation Methodology to the Dakota Spirit Ag Energy Proposed Ethanol Plant

DATE: 					August 31, 2012


Dakota Spirit AgEnergy ("Dakota") petitioned the Agency on October 15, 2011 to approve their generation of renewable fuel RINs (D-code 6), pursuant to 40 CFR § 80.1416. Through the petition process described under 40 CFR § 80.1416, Dakota submitted data to EPA to perform a lifecycle greenhouse gas emissions analysis of their production of ethanol. EPA has issued a technical notice in response to the petition submitted by Dakota. This memo supplements the notice and provides the steps and equations used in the lifecycle analysis.

Based on the information submitted by Dakota, EPA assumed that the associated upstream emissions, fuel transport, and co-product credits are the same as those modeled for the RFS2 final rule for corn ethanol production. Dakota will import steam from the adjacent Spiritwood Station power plant for its fuel production process. As a result, Dakota's emission analysis differs only in its fuel production emissions methodology.

Fuel Production Emissions
Fuel production emissions can be calculated (in terms of grams CO2e per gallon of ethanol produced) from the plant energy use and the GHG emission factor associated with energy use as follows:

Emissions (g CO2egal ethanol) = Energy Use btugal ethanolxGHG Emission Factor g CO2ebtu

Dakota's fuel production emissions consist of four major components:

   1) Process steam from Spiritwood power plant main boiler operating in CHP mode
   2) Process steam from Spiritwood power plant backup boiler operating in steam mode
   3) Electricity purchased from grid
   4) Natural gas to operate emission controls

Process steam is the largest component, consisting of close to 90% of Dakota's plant energy use, while electricity accounts for most of the remainder, and emission controls use an almost negligible amount of energy.  The emissions associated with purchased electricity use and onsite emission controls were derived from the energy use data from Dakota's petition and the GHG emission factors promulgated as part of the RFS2 final rule. The GHG emissions associated with process steam are described in the next section.

Process Steam Emissions
In the proposed Dakota plant process, thermal energy (steam in this case) for the process will be supplied from the Spiritwood Station power plant, located adjacent to Dakota. The Spiritwood plant maintains two boilers capable of providing steam to Dakota: a main boiler that operates on coal and a backup boiler that operates on natural gas. When the main boiler at Spiritwood is out of service (either due to planned or unplanned outages), the backup boiler at Spiritwood will provide steam to Dakota. Since the backup boiler operates in steam-only mode, its emissions will be comparable to an onsite boiler. Therefore, the backup boiler emissions were calculated using the backup boiler energy use provided in the Dakota petition and the natural gas GHG emission factor from the RFS2 final rule.

The main boiler will operate in a CHP configuration to provide electricity for the grid and steam for Dakota's production process. In this configuration, a portion of the steam driving the steam turbine generator will be extracted to meet Dakota's thermal energy needs.  In CHP mode, for each unit of fuel consumed in the boiler, there is a net reduction in the amount of electricity generated by the power plant.  Although the amount of electricity generated is reduced, the total fuel consumed and the resulting GHG emissions of the power plant remain unchanged. 

Work Potential Allocation Method
To determine the emissions associated with the extracted steam, the total emissions of the Spiritwood power plant need to be allocated to the power plant's power production and to the steam extracted for use at the biorefinery.  EPA's proposed allocation approach for this CHP configuration is the "work potential" method. The process for determining the steam GHG emission factor using the work potential allocation approach is summarized by the following steps:

1. Calculate the GHG emission factor for the Spiritwood power plant without any steam extracted;
2. Determine the amount of electricity that is not generated due to the extraction of steam for the Dakota plant; and
3. Apply the Spiritwood GHG emission factor from Step One to the amount of electricity not generated due to steam extraction and calculate the emission factor associated with the extracted steam.
	

Step One  -  Calculate the GHG emission factor for the Spiritwood power plant without any steam extracted 

The power-only emission factor for the power plant was calculated based on the steam flow and energy value data provided in Dakota's petition. The CO2 emission factor was based on the carbon content of the coal given by Dakota, and the combustion CH4, combustion N2O, and upstream coal emission factors were the same as those used in the 2010 RFS rule. For consistency, all values were represented on a lower heating value (LHV) basis. 

Based on the Dakota petition, the coal combusted in the boiler has a carbon content of 44%, a higher heating value (HHV) of 7450 Btu/lb, and a LHV of 6844 Btu/lb.  The Spiritwood power plant in power-only mode has an efficiency for electricity production of 28.7% on a HHV basis, which converts to an efficiency of 31.3% on a LHV basis.  Each emission factor was calculated taking the following steps:

CO2 emission factor from coal combustion (g CO2/Btu)

      0.44 lb Clb coalx44 lb CO212 lb Cxlb coal6844 Btux453.6 g CO2lb CO2=0.106927 g CO2/Btu 

CH4 emission factor from coal combustion (from 2010 RFS2 rule) (g CO2/Btu)

      4.0g CH4MMBtux21 g CO2eg CH4x1 MMBtu1 x106 Btu=0.000084 g CO2e/Btu 

N2O emission factor from coal combustion (from 2010 RFS2 rule) (g CO2/Btu)

      1.0g CH4MMBtux310 g CO2eg CH4x1 MMBtu1 x106 Btu=0.000310 g CO2e/Btu 

Upstream GHG emission factor (from 2010 RFS2 rule) =0.004171 gCO2e/Btu

The GHG fuel emission factor was first determined on an input basis as follows:

GHG Emission Factor on input basis (g CO2e/Btu input)

      =GHG emissions from coal combustion+GHG upstream emissions 
            =0.106927+0.000084+0.000310+0.004171=0.1115  g CO2eBtu input

The GHG fuel emission factor on output basis can be determined from the factor developed on an input basis by using the efficiency of electricity production at the Spiritwood plant.

GHG Emission Factor on output basis (g CO2e/MWh output)

      =0.1115  g CO2eBtu inputx3412 BtukWhx1000kWhMWh/31.3%  
      =1,215,961 g CO2e/MWh


Step Two  -  Determine the amount of electricity that is not generated due to the extraction of steam for the Dakota plant.

The amount of electricity not generated due to steam extraction is determined with the mass flow rate of steam extracted from the process prior to the steam entering the low-pressure steam turbine (LPST) and the enthalpy drop over the LPST. The mass flow rates and enthalpy drop were based on data provided in the Dakota petition. The amount of electricity not generated was determined to be 9.987 MW:

Displaced Power (MW)

      =Enthalpy of extracted steam-LPST exit enthalpyxSteam flowratexGenerator efficiencyBtukWhConversion Factor 

      =1230.3 -1068.0 Btu/lbx211,000lbhrx99.5%3412 BtukWhx1 MW1000 kW 

      =9.987 MW


Step Three  -  Apply the Spiritwood GHG emission factor from Step 1 to the amount of electricity not generated due to steam extraction and calculate the emission factor associated with the extracted steam.
 
The GHG emission factor of the emissions associated with the extracted steam was then calculated with the Spiritwood "No CHP" emission factor calculated in Step One above and the amount of electricity not generated due to steam extraction calculated in Step Two above. We determined the emission factor for the imported process steam to be 53,175 g CO2e/mmbtu steam:

Steam emission factor (g CO2e/mmbtu steam)

      =GHG Emission Factor xDisplaced Power Steam flowrate *Enthalpy of extracted steam-Condensate return enthalpy 
      
      =1,215,961 g CO2eMWhx9.987MW 211,000 lb/hr *1230.3-148 Btu/lbx1 x106 Btu1 mmBtu 
      
      =53,175 gCO2emmbtu steam
