1 Date : March 14, 2011

Subject: National Emission Standards for Ha zardous Air Pollutants (NESHAP) Beyond the Maximum Achievable C ontrol Technology (MACT) Floor Analysis for Coal- and Oil-fired Electric Utility Steam Generating

EGUs

From: Shelly Johnson, Stephen Boone

To: Bill Maxwell OAQPS/SPPD/ESG (D243-01) U.S. Environmental Protection Agency Research Triangle Park, NC 27711

Introduction

The purpose of this memorandum is to present the data and methodology used and the results of a beyond-the-floor (BTF) option analys is for the NESHAP source category “Coal- and Oil-fired Electric Utility Steam Generating Units” (referred to in this memorandum as “EGUs”). For the MACT floor analysis, the EPA defined five EGU subcategories. This memorandum presents the estimates of the incremental pollu tant emission reduction a nd cost that would be achieved by implementing a BTF option to control mercury (Hg) emissions from existing sources in the MACT Analysis Subcategory 2. Subcategory 2 is defined to include new and existing EGUs designed to burn a virgin nona gglomerating coal havi ng a calorific value (determined on moisture and mineral matter-free basi s) of less than 8,300 Btu/lb in an EGU with a furnace height-to-depth ratio of 3.82 or greater. The Hg emissions limit established as the MACT Floor for Subcategory 2 is 11.0 pounds Hg per trillion British thermal EGUs (lbs/TBtu).

The MACT floor analysis uses data collected in a nationwide survey of EGU owners and operators conducted by EPA in 2010 under the Information Collection Request For National
Emission Standards For Hazardous Air Pollutants (NESHAP) for Coal- And Oil-Fired Electric Utility Steam Generating Units (OMB Control No. 2060

‐ 0631). Individual EGU operating and air emissions data reported by respondents to the Information Collection Request (ICR) were compiled into a Microsoft Access software data base that serves as the data set used for this BTF option analysis (referred to in this memorandum as the “ICR data set”).

BTF Option Emission Limit Selection

The EPA selected a limit of 4.0 lbs Hg/TBtu for the BTF option. This Hg limit is equivalent to the level of emissions requi red under CAAA Section 112(d)(3) for new or reconstructed Subcategory 2 units. Hg emissions data compiled from the ICR data set indicates that this BTF option limit is equivalent to th e emission level achieved in practice (including emissions variability) by the best controlled similar source. The best controlled unit in Subcategory 2 is equipped with activated carbon injecti on (ACI) and a fabric filter (FF). This cost analysis assumes that all units within this subcategory will require capital investments in

fabric filters that are attribut able to the proposed MACT standa rd for PM (as a surrogate for nonHg metallic HAP). This analysis determines the marginal capital costs attributable to the BTF2 option requiring installation of ACI systems to re duce Hg emissions to 4.0 lbs per trillion Btu.

BTF Option Analysis Methodology

All data used to estimate the costs that w ould be incurred by the thirty EGUs within Subcategory 2 came from the data obtained from the ICR da ta set. The data were analyzed in the following steps:

Step 1 – Estimated current actual annual Hg emission rates for each existing EGU in Subcategory 2. Subsequently, the annua l emissions reductions necessary to achieve the MACT floor Hg emissions limit and the BTF option Hg emissions

limit were calculated for each of these EGUs.

Step 2 – Identified the Hg emissions control technologies already in place for each EGU using the ICR data set.

Step 3 – Determined annualized capital and operating costs for ACI controls from the

ICR data set.

Step 4 – Evaluated the ACI control component s that would need to be added to each EGU to meet the MACT floor Hg emission limit.

Step 5 – Evaluated the additional ACI control components that would need to be added to each EGU to meet the BTF option Hg emission limit.

Step 6 – Calculated the incremental differen ce between the total Hg emissions reduction and control cost for all existing EGUs in the subcategory to achieve the BTF option Hg emissions limit compared to the MACT floor Hg emissions limit.

BTF Option Hg Emissions Estimates

In order to determine the emissions reductio ns from the EGUs in Subcategory 2, each EGU’s current annual Hg emissions were compared to the EGU’s emissions at the MACT floor level and at the BTF option level. For each EGU, an emission factor (lb Hg/TBtu) was assigned based on EGU-specific stack test data from the ICR or from stack test data from the most similar EGU(s). The emission factor assigned to each EGU was either the EGU’s provided emission

factor or an estimate of the EGU’s emission factor based on the fuel fired, the boiler type and the

boiler’s control scheme. This emission factor was used to calculate the EGU’s actual annual pounds of Hg emissions. The calculation also included the EGU’s heat input capacity (MMBtu/hr) and the EGU’s average capaci ty factor for the last 3 years.

Once each EGU’s current annual Hg emissions were calculated, the annual Hg emission

levels at the MACT floor and BTF option were calculated for each EGU based on the same EGU specific data. Subsequently, th e annual Hg reductions between current rates and MACT floor

were calculated and those between the MACT floor and the BTF option were calculated.

For this analysis it is assumed that an AC I control system consists of the use of the activated carbon injectors and delivery system in conjunction with a fa bric filter (FF). The analysis assumed that if the EGU has other partic ulate matter (PM) controls in place (i.e. a coldside electrostatic precipitator) a new FF would need to be installed at the facility to comply with the non-Hg metallic HAP standard for PM. Theref ore, each EGU was evaluated to determine if the EGU had ACI or FF controls. The Hg emissi ons control scenarios of importance for this3 analysis were as follows:

1. EGU with ACI and FF (ACI + FF)

2. EGU with ACI (ACI)

3. EGU with FF (FF)

4. EGU with neither control (none)

Each EGU within Subcategory 2 was classified into one of the four Hg emissions control scenarios. The necessary installation of add itional controls for an EGU was dependent on the EGU’s current Hg emissions and the current cont rols. For EGUs already equipped with ACI + FF, no additional capital costs for controls were in cluded in the cost estimate, and the cost of any additional Hg removal necessary to meet the Hg MACT floor or the BTF option was calculated based on additional ACI operating costs. For the EGUs currently with only ACI, FF installation and operating costs were attribut ed to the MACT floor for non- Hg metallic HAP and the BTF option costs were also calculat ed based on additional ACI operating costs. For EGUs currently equipped only with FF, ACI capita l and operating costs were incl uded in the cost estimate for each MACT emissions level. Similarly, the cost BTF option cost estimate for EGUs currently

with neither control included AC I capital and operating costs with the cost of the FF attributed to the non-Hg metallic HAP MACT standard.

BTF Option Control Cost Estimates

The ACI control cost values we re calculated from cost info rmation (provided by facilities currently operating ACI systems) in the EGU ICR data set. In order to ca lculate the cost of the BTF option, an operating cost was determined ba sed on the amount of Hg removed, and a capital cost based on EGU size was determined. Overall, the ICR data set contains 122 EGUs for which any cost data on ACI controls were reported. Thes e EGUs were filtered to include a total of 16 EGUs that provided capital and operating costs a nd sufficient Hg emissions data to determine the Hg removal attributable to the project. Of these 16 EGUs, only one EGU was within the Subcategory 2.

For this analysis, all 16 EGUs were used to determine capital costs. It was assumed that the capital cost for each control system was indepe ndent of the amount of Hg removed. Each of these capital costs was determined on a heat-inp ut-capacity basis to take into account the equipment for larger EGUs and controls being mo re costly. Each EGU’s control system capital cost was converted from the reported base year dollars to July 2010 dollars using the applicable Chemical Engineering Plant Cost Index (CEPC I) factors. Then, each cost was annualized by applying the capital recovery fact or (CRF). The assumed interest rate was 7% and the assumed period was 20 years. The CRF value used for the analysis is presented in4 Table 1. The remaining capital cost value ap plied was annualized do llars per heat-inputcapacity in million British thermal units per hour ($/MMBtu/hr). The values for each EGU’s cost were averaged for the control scenario. Since no EGU provided capital cost data for a FF only, the capital cost for an ACI was subtracted from the capital cost for an ACI and FF.

The operating cost was determined solely from the lignite facility. Since the initial Hg content differs greatly between lignite and subbitu minous fuels and the operating cost is based on Hg removed, it was not assumed that the data from the two fuel types could be integrated. The operating cost was calculated on a basis of pounds of Hg removed. This was calculated using the final emission factor achieved and the per cent reduction. The amount of Hg removed was calculated taking into account th e EGU’s capacity factor and heat input. Then, the operating cost, which was provided on an annual basis, was converted to July 2010 dollar values using the

CEPCI factors. To calculate cost per pound of Hg removed, the annual operating cost was divided by the pounds of Hg removed ($/lb Hg re moved) reflecting the differences between the current Hg emission rate and the MACT floor.

BTF Option Analysis

In order to determine the marginal costs and impacts for the BTF option Hg emissions limit, a cost was first calculated for the subcateg ory to achieve the MACT floor level. Then, an incremental cost was calculated for the subcateg ory to reduce emissions from the MACT floor level to the BTF option limit. If any EGU did no t meet the MACT floor, the capital cost for the installation of any control equipm ent the EGU did not already have was associated with reaching MACT floor. In addition, the operating costs to get the EGU from the current emission rate to the MACT floor was multiplied by the additional pounds of Hg to be removed.

For the marginal cost to get to the BTF limit, the EGU was assumed to have all controls necessary for the EGU to achieve the MACT. For example, if an EGU was above the MACT floor and had to install ACI to meet the Hg MACT floor, then for the BTF Hg option, only ACI operating costs (to reduce emissions from the Hg MACT floor to the BTF limit) would be considered. However, if an EGU with just a FF met the MACT floor, but not the BTF option limit, the methodology assumed that the EGU would have to incur costs to install ACI and the operating costs to reach the BTF option limit. Th e current controls and additional controls for MACT and BTF are displayed on Table 5.

Using this methodology, the unit-specific an alyses were completed to determine additional controls and operating measures, Hg emission reductions , and the associated capital and operating costs. The estimated cost for each EGU was determined, and then the Hg

reductions and total costs were summed for MACT and the increment to the BTF limit.

The capital costs are summarized in

Table 2. The annualized capital cost for an ACI system was $108 per MMBtu/hr of heat input capacity. The annualized operating cost was determined to be $14,867 per pound of Hg removed, as shown in Table 3.

The specific EGU costs for MACT floor and the BTF option are shown in Table 5. Of the 30 EGUs, all units met the MACT floor emis sion level. Of the 30 EGUs, two EGUs would meet the BTF option limit without any additional controls. Taking into account the controls to be added to the EGUs for MACT compliance, 18 EGUs are expected to add FF to comply with the non-Hg metallic HAP standard, 20 EGUs are exp ected to add ACI, and 3 EGUs are expected5 to incur increased operating cost s associated with the additiona l activated carbon usage required

to achieve the BTF limit.

Energy impacts on Subcategory 2 due to incr eased auxiliary loads on induced draft (ID)

fans and other electrical loads asso ciated with installation of the fa bric filter are attributed to the non-Hg metallic HAP standard. The total energy costs for Subcategory 2 were estimated based solely on the relatively low auxiliary loads fr om activated carbon injection systems and the associated cost data for nominally rated 500 MW units using EPA’s Coal Utility Environmental Cost (CUECost) Model for sorb ent injection. The total annual costs of energy usage for operation of ACI were estimated as $2,300 per year.

Non-air quality environmental impacts were estimated based on the requirement to dispose of spent activated carbon in landfills. The analysis assumed that this material could be disposed of with the combustion by products as non-hazardous waste. The cost per ton of carbon disposed was estimated at $2/ton based on info rmation in the CueCost Model, and the carbon usage per mass of Hg removed was estimated based on information published by the Center for Air Toxic Metals at the University of North Dakota Energy & Environmental Research Center (EERC). The total costs of the non-air environm ental impacts for Subcategory 2 were estimated as $12,000. Non-air quality health impacts were evaluated, but no incremental health impacts

were attributable to installation of fabric fi lters and ACI, because these technologies do not expose electric utility employees or the public to any additional health risks above the risks attributable to current utility operations involvi ng compressed air systems, confined spaces, and exposure to fly ash.

The overall additional costs for the BTF opti on for Subcategory 2 are shown in Table 6. For the subcategory to reach MA CT, no additional costs are incurre d as the data displays that each unit currently meets the MACT floor. Fo r the existing EGUs in Subcategory 2 to implement the BTF option, the additional annual cost was estimated at an additional $70,186,000 and an additional 4,040 lb/year of Hg is removed or $17,375 per lb of Hg removed.6 Table 1: Capital Recovery Factor

Equation 1: Capital Recovery Factor

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ሺ ૚൅ܑ ሻ ܖ െ ૚ ൌ ૙. ૙ૢ૝૝

Table 2: Annualized Capital Cost

Table 3: Annualized Operating Cost

Table 4: Itemized Operating Costs i 0.07 interest rate

n 20 year period

CRF= 0.0944

$/(MMBtu/hr) per year

ACI 108

ACI + FF 3,771

FF 3,663

$/lb Hg removed per year Operating cost 14,867

Energy costs 27 $/(MMBtu/hr) per year

Non

‐ air environmental and health costs 4,000 $/ton Hg removed7Table 5: Subcategory 2 EGUsBTF Option Impacts Estimates8 Table 6: Subcategory 2 Incrementa l Hg Emissions Reduction and Cost Estimates for BTF Option

Beyond

‐ the

‐ Floor Total Annualized Costs (Capital + Operating)

Additional mercury reductions for BTF limit, lb/yr 4,040

Energy costs included in total cost, $/yr $2,300

Non

‐ air environmental and health costs included in total, $/yr $12,310

Total capital and operating costs for BTF limit, $/yr $70,185,739

Total annualized capital and operating cost per lb of Hg removed $ 17,375