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**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 lifecy cle greenhouse gas emissions analy sis 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 eq uations used in the lifecy cle anal ys is. 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 analy sis differ s onl y in its fuel prod uction emissions methodology
. **Fuel Production Emissions** Fuel production emissions can be calculated ( in terms of grams CO 2e per gallon of ethanol produced ) from the plant energy use and the GHG emission factor associated with energy us e as follows : Emissions ( 

### ) = Energy Use × GHG Emission Fa ctor 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 P rocess steam is the largest component, consisting of close to 90% of Dakota’s plant energy use, while electricity account s for most of the remainder , and e mission controls use an almost negligible amount of energy
. The emissions associated with purchased electricity use and onsite emission controls w ere 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.2

**Process S**  **team Em**  **issions** In t he 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 maintain s two boilers capable of providing steam to Dakota : a main boiler that operate s on coal and a backup boiler that operate s on natural gas
. When the main boiler at Spiritwood is out of service (either due to planned or unplanned outages), t he backup boiler at Spiritwood w ill provide steam to Dakota. Since the backup bo iler operates in steam
- only mode, it s emissions will be comparable to an onsite boiler. Therefore, the backup boiler emissions were calculated us ing the backup boiler energy

use provided in the Dakota petition and the natural gas GHG emission factor from the RFS2 final rule. T he 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, f

or each unit of fuel consumed in the boiler , there is a net reduction in the amount of electricit y generated b y the power plant. Although the amount of electricit y generated is reduced, the total fuel consumed and the resulting GHG emissions of th e 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 emi ssion factor for the Spiritwood power plant without any steam extracted; 2. Determine the amount of electricit y 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 .3

Step One

– Calculate the GHG emi ssion factor for the Spiritwood power plant without any steam extracted The power - onl y emission factor for the power plant wa s calculated based on the steam flow and energy value data provided in Dakota’s petition. The CO 2 emission factor was based on the carbon content of the coal given b y Dakota , and the combustion CH 4 , combustion N 2 O, and upstream coal emission factors were the same as those used i n 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
- onl y mode has an efficiency for electricit y 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: CO 2 emission factor from coal combustion (g CO 2 /Btu)

. × × × . = 0 . 106927 2 / CH 4 emission factor from coal combustion (from 2010 RFS2 rule) (g CO 2 /Btu) 4 . 0 × 21 × × = 0 . 000084 2 / N 2 O emission factor from coal combustion (from 2010 RFS2 rule) (g CO 2 /Btu) 1 . 0 × 310 × × = 0 . 000310 2 / Upstream GHG emission factor (from 2010 RFS2 rule ) = 0 . 004171 2 / The GHG f

uel emission factor wa s first determined on an input basis as follows: GHG Emission Factor on input basis (g CO 2 e/ Btu input )

= +

= 0 . 106927 + 0 . 000084 + 0 . 000310 + 0 . 004171 = 0 . 1115 g CO 2 e Btu input The GHG f

uel 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
.4

GHG Emission Factor on output basis (g CO 2 e/MWh output )

= 0 . 1115 × 3412 × 1000 ÷ 31 . 3 %

= 1 , 215 , 961 g CO 2 e / MWh5

Step Two

– Determine the amount of electricity that is not generated due to the extraction of steam for the Dakota plant
. Th e amount of electricit y 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 (L PST) and the enthalpy drop over the LP ST . The mass flow rates and enthalp y drop were based on data provided in the Dakota petition
. T he amoun t of electricity not generated was determined to be 9.987 MW : Displaced Power (MW)

= ( ) × × ⁄



### = (
. . / ) × , ⁄ × . % ⁄ 

### ×

= 9 . 9876

Step Three

– Appl y 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 electricit y 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 CO 2 e/mmbtu steam : Steam emission factor (g CO 2 e/mmbtu steam)



### = ×

∗ ( )



### = , , × .

, / ∗ (
. / ) 

### × ×

= 53 , 175 2