1 Reasonable Progress (RP) Four-Factor Analysis of Co ntrol Options For Montana-Dakota Utilities Company, Lewis & Clark Station, in Sidney, Montana

U.S. EPA Region 8 Air Program March 20, 2012

Executive Summary

This four-factor analysis documents the basis for d etermination of Reasonable Progress (RP) control options for control of sulfur dioxide (SO 2 ) and nitrogen oxide (NO

x ) emissions at Montana-Dakota Utilities Company (MDU), Lewis & Cla rk Station, an electric utility power plant in Sidney, Montana. The four-factor analysis consists of the following steps:

Step 1 – Identify All Available Technologies Step 2 – Eliminate Technically Infeasible Options Step 3 – Evaluate Control Effectiveness of Remainin g Control Technology Step 4 – Evaluate Impacts and Document Results: Factor 1: Cost of compliance Factor 2: Time necessary for compliance Factor 3: Energy and non-air quality environmenta l impacts of compliance Factor 4: Remaining useful life Step 5 – Select Reasonable Progress Controls

This analysis is based on the following submittals from MDU:

→ Response to Reasonable Progress Request for Inform ation Pursuant to Section 114(a) of the Clean Air Act, Montana-Dakota Utilities Co., Le wis & Clark Station, March 17, 2009 (“L&C Initial Response”)

→ Emissions Control Analysis for Lewis & Clark Stati on Unit 1, Prepared for MontanaDakota Utilities Co. by Barr Consultants, February 2011, Revised June 2011 (“L&C Emissions Control Analysis”)

→ Revised Emissions Control Analysis for Lewis & Cla rk Station, in Response to EPA Request of November 5, 2010, Montana-Dakota Utiliti es Co., June 14, 2011 (“L&C Revised Emissions Control Analysis”)

→ Response to EPA Questions of January 19, 2012, Reg arding Fuel Switch to Natural Gas, Basis for SCR Cost Calculation, and SDA Efficiency, Montana-Dakota Utilities Co., February 10, 2012 (“L&C Feb. 10, 2012 Response”)

→ Response to EPA Questions of February 15, 2012, Re garding Cost of Fuel Switch to Natural Gas, Montana-Dakota Utilities Co., February 27, 2012 (“L&C Feb. 27, 2012 Response”)2

Lewis & Clark Station is rated at 52 megawatts gros s output (48 megawatts net). The primary source of emissions consists of a single dry bottom , tangentially fired boiler, fueled with lignite coal, supplemented to a very small extent with natu ral gas (about 0.37% of total heat input in 2002). Maximum boiler heat input rate is 572 MMBtu per hour (corresponding to 48 MW net output). The lignite coal has an average heating v alue of 6,658 Btu/lb, sulfur content of 0.51% by weight, and ash content of 9.3% by weight. The natural gas has an average heating value of 1,200 Btu per cubic foot, and sulfur content of 0.0 2 grains per cubic foot. This Reasonable Progress analysis focuses on the boiler.

The boiler was constructed in 1957 and commenced op eration in 1958. Current particulate matter (PM) controls consist of a multi-cyclone dus t collector, installed in 1957, with design control of 75-80%, as well as a flooded disc wet sc rubber installed in 1975, which was designed for 98% PM control, with a nominal SO 2 control efficiency of approximately 15%, but which MDU says has achieved up to 60% control during cert ain operating conditions, mainly by the presence of calcium in the coal, but also by MDU’s addition of lime to the existing scrubber system when the coal has lower calcium and higher s ulfur content. Current NO

x controls consist

of low NO

x burners (LNB) and a close-coupled overfire air (CC OFA) system installed in 1996.

Estimated level of control is 33%. 1

With regard to expected life of the boiler and its emission control equipment, MDU states that there are currently no plans or schedule for removi ng the facility from service, 2 and that the remaining useful life of Unit 1 is not expected to significantly impact estimated costs. 3

MDU states that average hourly controlled emissions during 2007 were 47.1 lb/hr for PM (calculated from GE 2007 Particulate Matter Emissio ns Compliance Test Report), 227.29 lb/hr

for NO

x (calculations based on 2007 annual emissions inven tory data), and 306.39 lb/hr for SO 2 (calculations based on 2007 annual emissions invent ory data). 4 Assuming 8760 operating hours per year, these figures are equivalent to 206 tons/ yr for PM, 995 tons/yr for NO

x , and 1342 tons/yr for SO 2 . Actual emissions for 2002, listed in EPA’s Natio nal Emission Inventory, were 83 tons/yr for PM, 796 tons/yr for NO

x , and 781 tons/yr for SO 2 . For purposes of calculating control costs at Step 4 below, MDU used a “baseline ” of 801.7 tons/yr for NO

x and 1002.1 tons/yr for SO 2

. 5 EPA has used 802 tons/yr for NO

x and 1002 tons/hr for SO 2 in its analysis.

As discussed in Section V.D.6.b. of EPA’s Federal R egister notice on the proposed Montana regional haze Federal Implementation Plan, the cont ribution from point sources to primary organic aerosols, elemental carbon, and PM2.5 at Mo ntana Class I areas is very small, and modeling tends to confirm that PM emissions from po int sources do not have a very large impact. Therefore, EPA is proposing that additiona l controls for PM are not necessary for this planning period.

1 L&C Initial Response, pp. 3-6; L&C Emissions Contr ol Analysis, p. 4.

2 L&C Initial Response, pp. 3-6.

3 L&C Emissions Control Analysis, p. 6.

4 L&C Initial Response, pp. 5-7.

5 L&C Emissions Control Analysis, pp. 14, 22.3

Reasonable Progress Evaluation of SO 2 Emissions

Current SO 2 control consists of a flooded disc wet scrubber wh ich was designed for 98% PM control, with a nominal SO 2 control efficiency of approximately 15%, but which has achieved up to 60% control during certain operating conditions, mainly by the presence of calcium in the coal, but also by MDU’s addition of lime to the exi sting scrubber system when the coal has lower calcium and higher sulfur content.

Step 1: Identify All Available Technologies

EPA has identified the following technologies as be ing available for SO 2 emission reductions beyond those achieved by the current control config uration at L&C Station:

1. Wet Lime Scrubbing/Optimization of Existing Wet PM Scrubber

2. Lime Spray Dry Absorber (SDA) and Baghouse

3. Dry Sorbent Injection (DSI) and Baghouse

4. Fuel Switch to PRB coal or to natural gas

The following is a description of each available te chnology.

Wet Lime Scrubbing/Optimization of Existing Wet PM Scrubber

Wet lime scrubbing involves scrubbing the exhaust g as stream with slurry comprised of lime (CaO) in suspension. The process takes place in a wet scrubbing tower located downstream of a PM control device to prevent the plugging of spray nozzles and other problems caused by the presence of particulates in the scrubber. The SO 2 in the gas stream reacts with the lime to form calcium sulfite (CaSO 3 •2H 2 O) and calcium sulfate (CaSO 4 ).

This control option is functionally equivalent to “ Lime Spray Forced Oxidation” (LSFO) in terms of concept and control efficiency. Forced ox idation is used in wet scrubbing systems to convert calcium sulfite to calcium sulfate (gypsum) . Air is blown through spent lime reagent to accomplish this reaction. This often takes place i n the bottom of the wet scrubber. Calcium sulfite is a watery compound and cannot be de-water ed. It is typically disposed in ash ponds.

Calcium sulfate is a solid and wet scrubber blowdow n can be run through a filter press for calcium sulfate recovery. After filtration, calciu m sulfate can be disposed of as a solid waste or it can be sold as a raw material for drywall produc tion. The use of forced oxidation has an impact on the method of scrubber waste disposal, bu t does not appreciably impact SO 2 removal. This wet scrubbing option at L&C Station would invo lve modification to the existing PM wet

scrubber to increase SO 2 removal efficiency. The modification would primar ily involve upgrade and optimization of the lime injection system. Exp ected total SO 2 emissions reduction would be approximately 70% on an annual basis, versus the es timated 60% control currently being achieved (about a 10% improvement). The scrubber l ime injection system would be upgraded to

achieve this additional removal. 6

6 L&C Emissions Control Analysis, pp. 13-17.4

Lime Spray Dryer Absorber (SDA) with Baghouse

Lime SDA is a dry scrubbing system that sprays a fi ne mist of lime slurry into an absorption

tower where the SO 2 is absorbed by the droplets. Once absorbed, the S O 2 reacts with lime to form calcium sulfite (CaSO 3 •2H 2 O) and calcium sulfate (CaSO 4 ) within the droplets. The SDA temperature must be hot enough to ensure that the h eat from the exhaust gas causes the water to evaporate before the droplets reach the bottom of t he tower. This leads to the formation of a dry powder, which is carried out with the gas and colle cted with a fabric filter baghouse. Spray dryer absorption control efficiency is typically in the 70% to 90% range, but can be as high as 95%. EPA used 85% control for this analysis. 7

To accommodate the SDA control option, the existing particulate scrubber at L&C Station would need to be abandoned in place and replaced with a n ew baghouse. This is necessary to ensure the required system residence time for a dry contro l option; otherwise, the achievable control efficiency would be significantly decreased. 8

Dry Sorbent Injection (DSI) with Baghouse

DSI involves the injection of a lime or limestone p owder into the exhaust gas duct work. The stream is then passed through a baghouse or electro static precipitator (ESP) to remove the

sorbent and entrained SO 2 . The process was developed as a lower cost FGD op tion because the mixing occurs directly in the exhaust gas stream in stead of in a separate tower. Depending on the residence time allowed in the system and gas duct t emperature, sorbent injection control efficiency is typically between 50% and 70%.

Based on the particulate loading of the existing co ntrol system, DSI is expected to achieve removal efficiencies of less than the design range in combination with existing controls. EPA used 70% for this analysis, relying on MDU’s estima te of control efficiency. 9 This reflects a 10% improvement, versus the estimated 60% control c urrently being achieved.

To accommodate the DSI control option, the existing particulate scrubber at L&C Station would need to be abandoned in place and replaced with a n ew baghouse. Again, this is necessary to ensure the required system residence time for a dry control option; otherwise, the achievable control efficiency would be significantly decreased

. 10

Fuel Switching

Fuel switching is a control technology option. Ble nding of subbituminous Powder River Basin (PRB) coal is already employed at L&C Station, in i nstances where relatively poor lignite coal is provided to the plant. MDU’s boiler is currently p ermitted to blend PRB coal with the primary lignite fuel. 11 Therefore, EPA considers a switch to PRB coal as primary fuel to be an available

7 L&C Emissions Control Analysis, pp. 13-14; L&C Feb . 10, 2012 Response, p. 3.

8 L&C Emissions Control Analysis, p. 15.

9 Id., Appendix C.1, Table C.1-4.

10 Id., p. 15.

11 Id., pp. 8-10.5

SO2 control option, although, since there is no app reciable difference in the sulfur content (weight percent) of PRB coal versus lignite coal, t his option might yield only marginal SO 2 reductions. 12

Also, since MDU has provided data indicating that n atural gas is used to some extent (about 0.37% of total heat input to the boiler in 2002, by EPA’s calculations, based on information supplied by MDU), 13 EPA considers a fuel switch to natural gas as anot her available control option for SO 2 . Since pipeline quality natural gas has negligibl e sulfur content, EPA would expect a greater than 99% reduction in SO 2 . To supply sufficient natural gas to serve as pri mary fuel for the boiler, a new 22-mile pipeline from th e nearest connection point to L&C Station

would have to be constructed. 14

Step 2: Eliminate Technically Infeasible Options

Fuel Switch to PRB Coal as Primary Fuel

Although switching to coals with lower sulfur conte nt and higher Btu content represents a viable pre-combustion method of reducing SO 2 emissions, there are limitations to achievable ble nding. Switching to any fuel with an appreciably different composition and energy content would require boiler surface and other design changes. P revious test burns of PRB coal at the boiler confirm that the high flue gas temperatures, result ing from the use of PRB coal, cause significant fouling to boiler walls and other boiler surfaces. Due to the physical properties of PRB coal, coal mills and coal piping to the boiler would also need to be replaced, along with the addition of a railcar unloading system. A re-design of the exi sting boiler does not constitute a feasible retrofit control option.

Further, there is no appreciable difference in the sulfur content (weight percent) of the subbituminous coal supplement, and reduced calcium/ magnesium concentrations present in the

subbituminous coal would also result in less inhere nt SO 2 control. Finally, the on-site coal inventory is fairly limited (generally 2-3 days’ su pply of lignite), due primarily to lack of property to safely store additional inventory. 15 Therefore, a switch to PRB coal as primary fuel

is not considered further in this evaluation.

Step 3: Evaluate Control Effectiveness of Remaining Control Technology

A summary of emissions projections for the various control options is presented in Table 1 below. For all options, EPA relied on the estimate d control efficiencies, estimated emissions reductions, and emissions baseline provided by MDU. 16 The emissions baseline of 1,002 tons per year, which is the current actual controlled SO 2 emissions, was used in EPA’s analysis. Baseline emissions reflect average control provided by the alkaline materials present in lignite coal. MDU has equated the 1002.1 tpy baseline with use of the existing flooded disc wet

12 Id.

13 L&C Initial Response, p. 7.

14 L&C Feb. 10, 2012 Response, p. 2.

15 L&C Emissions Control Analysis, pp. 8-10.

16 Id., p. 14.6

scrubber to achieve 60% SO 2 control on a continuous basis. The control effici encies listed in the table below are the degree of control that is expec ted to be achieved on the baseline SO 2 emissions.

Table 1

Summary of MDU Lewis & Clark SO 2 Reasonable Progress Analysis Control Technologies

Control Technology Control

Effectiveness (%) Emission

Reduction (tpy) Remaining

Emissions (tpy) Fuel Switch to Natural Gas 99+ 1002 negligible SDA with baghouse 85 1 850.3 151.8 DSI with baghouse 10 100.2 901.9 Existing scrubber mod. 10 100.2 901.9

1 Table C.1-3 of Appendix C.1 of the L&C Emissions C ontrol Analysis lists a design control efficiency of 95% for SDA with baghouse, but page 1 4 of the Analysis lists an expected reduction of 850.3 tpy from a baseline of 1,002.1 tpy, which is equivalent to 85% reduction. EPA asked MDU why there are varying control efficie ncies for SDA in MDU’s analysis. MDU replied on Feb. 10, 2012 that 95% control was a ssumed to be consistent with SDA evaluations compiled by the Federal Land Managers, and represents a screening level assumption.

Step 4: Evaluate Impacts and Document Results

Factor 1: Cost of compliance

Table 2 below provides a summary of estimated annua l costs for the various control options.

Table 2 Summary of MDU Lewis & Clark SO 2 Reasonable Progress Cost Analysis

Control Option Control

Effectiveness (%) Tons SO2

Reduced

from

Baseline Capital

Cost ($) Annual Cost

of Capital ($) (CRF=.0944) Annual

O&M Cost ($) Total

Annual Cost ($) Average Cost

Effectiveness ($/ton reduced)

Fuel

switch to
nat. gas 99+ 1002 18,000,000 1,699,200 20,219,894 21,919,094 21,875

SDA with baghouse 85 850.3 65,979,566 6,228,004 3,827,052 10,055,056 11,825

DSI with baghouse 10 100.2 15,389,568 1,452,775 1,387,959 2,840,734 2 8,350

Existing

scrubber

mod. 10 100.2 270,000 25,488 113,149 138,637 1,3837

EPA has relied on costs provided by MDU for these c ontrol options. For calculating the annual cost of capital, a 7% interest rate and 20-year equ ipment life were used by MDU, yielding a Capital Recovery Factor of 0.0944, same as specifie d in the Office of Management and Budget’s Circular A-4, Regulatory Analysis, available at:

http://www.whitehouse.gov/omb/circulars_a004_a-4/

.

The high annual cost of a fuel switch is due partly to the need to construct a new 22-mile natural gas pipeline, and partly to the large difference in cost of natural gas versus lignite coal. Natural gas would cost about five times as much as lignite coal to fuel the boiler. 17

The costs for SDA and DSI include installation of a new baghouse, to replace the existing particulate scrubber, which would be abandoned in p lace. The need for a new baghouse was explained earlier in this report.

The “Annual O&M Cost” consists of all direct and in direct costs listed by MDU in its detailed cost analyses, with the exception of capital cost r ecovery (annual cost of capital).

Factor 2: Time necessary for compliance

For the option involving a fuel switch to natural g as as primary fuel, EPA estimates that several years would be needed to secure the necessary right s-of-way and install a new 22-mile pipeline that MDU has stated would be needed to provide a su fficient supply of natural gas. 18 For the SDA-with-baghouse and DSI-with-baghouse control opt ions, EPA relied on an estimate from the Institute of Clean Air Companies (ICAC) that approx imately 30 months is required to design, build and install SO2 scrubbing technology. 19 For the option involving modification to the existing scrubbing system, EPA relied on MDU’s esti mate of 6 to 12 months to conduct an optimization study to evaluate scrubber capabilitie s and identify operational constraints. 20

Factor 3: Energy and other non-air quality environm ental impacts

A fuel switch to natural gas as primary fuel could significantly increase the demand for natural gas in the region and could increase natural gas pr ices for other consumers of natural gas in the region, as well as create impacts associated with m ore production of natural gas in the region.

For the SDA-with-baghouse control option, as well a s for the DSI-with-baghouse control option, energy impacts would include a blower requiring inc reased energy use and an associated indirect

CO 2 emissions increase. For the option of modifying t he existing wet scrubber system, no appreciable energy impacts are expected. There is, however, a potential for additional water consumption and wastewater generation. 21

17 L&C Feb. 27, 2012 Response lists the annual cost o f lignite coal at $5,754,232, versus $25,974,126 fo r natural gas. The cost differential is $20,219,894. The ca pital cost for a new 22-mile pipeline is estimated at $18,000,000.

18 L&C Feb. 10, 2012 Response, p. 2.

19 Report from Bradley Nelson, EC/R Inc., to Laurel D ygowski of EPA, Four-factor Analysis of Control Opt ions for MDU L&C Station, July 3, 2009, p. 5.

20 L&C Emissions Control Analysis, p. 17.

21 L&C Emissions Control Analysis, p. 16.8

Factor 4: Remaining Useful Life

EPA has determined that the default 20-year amortiz ation period is most appropriate to use as the remaining useful life of the facility. Without com mitments for an early shutdown, EPA cannot consider a shorter amortization period in its analy sis.

As mentioned earlier in this report, MDU has no pla ns or schedule for removing the facility from service, 22 and MDU has stated that the remaining useful life of Unit 1 is not expected to significantly impact estimated costs. 23

Step 5: Select Reasonable Progress Controls

EPA has considered the following four factors: the cost of compliance; the time necessary for compliance; the energy and non-air quality environm ental impacts of compliance; and the remaining useful life of the source. The costs per ton of pollutant reduced are excessive for the three most expensive options. EPA is also taking in to account the size of the facility, the baseline Q/D of the facility, and the potential reduction in Q/D from the controls. Based on costs of compliance, the small size of MDU L&C, and the rela tively small baseline Q/D, EPA proposes to eliminate the more expensive control options (fu el switch to natural gas, SDA with baghouse, and DSI with baghouse). The most cost-effective co ntrol option (existing scrubber modification)

would reduce SO 2 emissions by 100 tpy, which equates to a 5.5% redu ction in overall emissions

of SO 2 + NO

x for this facility, or a reduction of Q/D from 29 t o 27. Based on the costs of compliance, the relatively small size of MDU L&C, t he baseline Q/D, and the modest reduction in Q/D, EPA finds it reasonable to eliminate this o ption. EPA therefore proposes to not require

additional SO 2 controls for this planning period. 24

Reasonable Progress Evaluation of NO

x Emissions

Current NO

x controls consist of LNBs and a CCOFA system, with estimated control efficiency

of 33%.

Step 1: Identify All Available Technologies

EPA has identified the following technologies as be ing available for NO

x emission reductions beyond those achieved by the current control config uration at L&C Station:

1. Fuel Switch to PRB coal or to natural gas

2. Selective Catalytic Reduction (SCR) with Separated Overfire Air and New Low-NO

x Burners (SOFA/LNB)

22 L&C Initial Response, pp. 3-6.

23 L&C Emissions Control Analysis, p. 6.

24 As explained in Section V.D.6.b of EPA’s Federal R egister notice on the proposed Montana regional haze Feder al Implementation Plan, Q/D means the quantity of a so urce’s combined SO 2 and NO

x emissions, in tons per year, divided by the distance in kilometers from the sour ce to the nearest Federal Class I area.9

3. Selective Non-Catalytic Reduction (SNCR) with SOFA/ LNB

4. SOFA/LNB

5. SNCR

Fuel Switching

EPA considers fuel switching to PRB coal or to natu ral gas, as primary fuel for the boiler, as an

available control for NO

x , for the same reasons as described in the SO 2 analysis above. With regard to a potential switch to PRB coal, higher he at content of coal can yield lower NO

x emissions in lb/MMBtu. The lignite coal used at L& C Station has an average heating value of 6,435 Btu/lb. 25 PRB coal typically ranges from 8,000 to 8,500 Bt u/lb and therefore could be expected to have lower NO

x emissions than lignite coal, per ton of coal fired . Similarly, natural gas could be expected to produce lower NO

x emissions than lignite coal. EPA used a 65% reduction in its analysis. 26

Selective Catalytic Reduction (SCR)

SCR is a post-combustion gas treatment technique th at uses a reducing agent in the presence of a catalyst, to reduce NO and NO 2 to molecular nitrogen, water, and oxygen. Ammonia (NH 3 ) is commonly used as the reducing agent. Ammonia is va porized and injected into the flue gas upstream of the catalyst bed, and combines with NO

x at the catalyst surface to form an ammonium salt intermediate, which then decomposes t o produce elemental nitrogen and water. The catalyst lowers the temperature and activation energy required for the chemical reaction

between NO

x and ammonia. The catalyst contains an active phas e such as vanadium pentoxide

on a carrier such as titanium dioxide.

Typical SCR applications operate within the tempera ture range of 650 to 800 o F. The addition of ammonia is typically at a stoichiometric ratio of 1 :1 with NO

x molecules. In the presence of the SCR catalyst, this ratio is optimal for NOx reducti on while minimizing the amount of ammonia slip which can result when un-reacted ammonia is pr esent in the system. Technical factors that impact the effectiveness of SCR include the catalys t reactor design and location, catalyst design, catalyst activity, SCR operating temperature, sulfu r concentrations of the flue gas, and ammonia injection system design and operations.

SCR technology is commonly described by the SCR rea ctor’s location within the flue gas path. There are three main locations for SCR systems at u tility boilers: high-dust SCR (“HDSCR”), low-dust SCR (“LDSCR”), and tail-end SCR (“TESCR”). HDSCR is located closest to the boiler, and is “upstream” of all other pollution co ntrol devices (in terms of the path of flue gas

25 L&C Feb. 27, 2012 Response. MDU cited typical hea t content of 6.436 Btu/lb for lignite coal, based o n 2009- 2011 average from FERC Form 1/EIA 923 reports.

26 The AP-42 emission factor for natural gas is 170 l b/MMSCF. MDU’s February 27, 2012 letter to EPA sta tes that annual natural gas consumption, if natural gas is u sed as primary fuel, would be 3,283 MMSCF. This yi elds 279 tons per year of NO

x emissions. Baseline NO

x emissions used by MDU in its June 2011 analysis, w ith lignite coal as primary fuel, are 802 tons per year. Switching to natural gas would therefore represent a potential 6 5% reduction in

NO

x emissions.10

from the boiler until it exits the utility station’ s flue). LDSCR is located downstream of the particulate matter control device. TESCR is locate d downstream of both the particulate matter

and SO 2 control devices. Installation of LDSCR and TESCR is often not the preferred location due to economic reasons. The temperature of the fl ue gas stream is often too low in these areas for proper operation of SCR. Flue gas reheat is ty pically required, which involves using either plant steam or duct burners to raise the flue gas t emperature to acceptable SCR operating
temperatures.

On some installations, regenerative SCR is installe d. Regenerative SCRs have extra equipment and operating costs associated with reheating the f lue gas downstream of the pollution control equipment. The heat recovery aspect of RSCR would diminish the need for reheat steam or supplemental fuel compared to traditional LDSCR or TESCR. Similar to TESCR and LDSCR, an operator must weight these extra costs compared to the benefit of exposing the SCR to a cleaner gas stream. Operators typically choose the HDSCR configuration when possible, to avoid the extra operational costs and equipment ass ociated with flue gas reheat. EPA analyzed for HDSCR, following clarification from MDU about w hich version of SCR is appropriate. 27

SCR has been demonstrated to achieve high levels of NO

x reduction, in the range of 80% to 90% (or higher) control, for a wide range of industrial combustion sources, including PC, cyclone, and stoker coal-fired boilers and natural gas-fired boi lers and turbines. For its SCR analysis, EPA included SOFA and LNB upstream of the SCR controls, on the basis that these controls are much less expensive than SCR and would enable the SCR sy stem to use less reagent. EPA’s calculations reveal that a control system consistin g of SCR + SOFA/LNB would be more costeffective than SCR alone, and would also achieve a higher level of control than SCR alone. EPA

has used 87.5% control as its estimate for the comb ined SCR + SOFA/LNB system. 28

Selective Non-Catalytic Reduction (SNCR)

SNCR involves the non-catalytic decomposition of NO

x to nitrogen and water. An NO

x reducing agent, typically ammonia or urea, is injected into the upper reaches of the furnace, through injection nozzles at the cyclone inlets. SNCR requi res much higher reagent use than SCR because it does not rely on a catalyst. Reagent is typically added at a stoichiometric ratio from

between 1.5:1 and 2:1 to achieve desired control wh ile also minimizing ammonia slip. Because catalyst is not used to drive the reaction, temperatures of 1600 to 2100 o F are required.

Typical NO

x control efficiencies for SNCR range from 40% to 60 %. NO

x removal efficiency varies depending on inlet NO

x concentrations, fluctuating flue gas temperatures, residence time, amount and type of nitrogenous reducing agent, mixi ng effectiveness, acceptable levels of ammonia slip, and presence of interfering chemical substances in the gas stream. Vendorguaranteed NO

x reduction rates are in the 50% range to limit ammo nia slip to 10 ppm. EPA used 38% for SNCR alone, and 50% for the control option of SNCR with SOFA/LNB.

27 L&C Feb. 10, 2012 Response, p. 2. MDU clarified t hat it believes the costs presented for L&C Station are most representative of a high-dust SCR system.

28 MDU NOx control cost analysis by US EPA Region 8 f or SCR, SOFA/LNB, and SCR + SOFA/LNB, Summary Spreadsheet, March 7, 2012.11

L&C Station is a member of Midwest Independent Tran smission System Operator (MISO) and, as such, is operated as called upon, based on energ y demand and price. Generally, combustion systems on boilers are not optimized for low load o peration, including associated NO

x emissions. This is important because the efficiency of many ai r emission controls cannot be guaranteed at low load operating conditions. This is especially true for SNCR. Therefore, to reflect actual emission reductions on cost per ton basis, an SNCR scenario at low load operation is also presented in EPA’s analysis, using a 23 MW capacity as the low load operational case. Based on a preliminary SNCR engineering assessment that incl udes the temperature, residence time, and

the current level of NO

x control, an emissions reduction of approximately 1 5% to 30% would be expected at low load conditions. Relying on estima tes from MDU, EPA used 16% for its analysis. 29

Separated Overfire Air (SOFA)

SOFA diverts a portion of the total combustion air from the burners and injects it through separate air ports above the top level of the burne rs. SOFA is the typical NO

x control technology used in coal-fired boilers and is primarily geared to reduce thermal NO

x . Staging of the

combustion air creates an initial fuel-rich combust ion zone for cooler combustion. This reduces the production of thermal NO

x by lowering combustion temperature and limiting th e availability of oxygen in the combustion zone where NO

x is most likely to be formed. SOFA technology is compatible with the existing LNB and would replace the existing CCOFA system

Low NOx Burners (LNB)

LNB technology utilizes advanced burner design to r educe NO

x formation through the restriction of oxygen, flame temperature, and/or residence time . LNB is a staged combustion process that is designed to split fuel combustion into two zones. In the primary zone, NO

x formation is limited by either one of two methods. Under staged air ric h (high fuel) condition, low oxygen levels limit flame temperatures, resulting in less NO

x formation. The primary zone is then followed by a secondary zone in which the incomplete combustion products formed in the primary zone act as reducing agents. Alternatively, under staged fu el lean (low fuel) conditions, excess air will reduce flame temperature to reduce NO

x formation. In the secondary zone, combustion prod ucts formed in the primary zone act to lower the local o xygen concentration, resulting in a decrease in

NO

x formation. Low NO

x burners typically achieve NO

x emission reductions of 25% to 50% as compared to uncontrolled emissions.

LNB are currently used at L&C Station. Based on th e currently achieved emission rates, a combined reduction in the range of 30% to 40% would be expected with the addition of SOFA and new LNB. Relying on estimates from MDU, EPA us ed 38% for its analysis. 30

Step 2: Eliminate Technically Infeasible Options

EPA considers fuel switching to PRB coal to be tech nically infeasible, for reasons already

described in the SO 2 analysis above.

29 L&C Emissions Control Analysis, pp. 21-22.

30 Id., pp. 19, 22.12

Step 3: Evaluate Control Effectiveness of Remaining Control Technology

A summary of emissions projections for the various control options is provided in Table 3 below.

EPA relied on information from MDU for estimated co ntrol efficiencies, expected emission reductions, and baseline emissions, with the except ion of the control option consisting of HDSCR + SOFA/LNB, for which EPA performed its own a nalysis. 31

The control efficiencies listed in the table below, other than for the SNCR low-load scenario, are the degree of reduction that is expected to be achi eved on actual controlled baseline NO

x emissions of 802 tons per year. Similarly, the emi ssion reductions in tons per year in the table

are reductions from baseline emissions. For the SN CR low-load scenario, the baseline emissions, control efficiency and emissions reducti on are those that correspond to low-load boiler operation (23 MW).

Table 3 Summary of MDU Lewis & Clark NOx Reasonable Progres s Analysis Control Technologies

Control Option Control

Effectiveness (%) Emission

Reduction (tpy) Remaining

Emissions (tpy)

HDSCR + SOFA/LNB 87.5 693 109 Fuel switch to natural gas 65 523 279

SNCR + SOFA/LNB 50 401 401

SOFA/LNB 38 301 501

SNCR 38 301 501 SNCR (low load) 16 58 298

Step 4: Evaluate Impacts and Document Results

Factor 1: Cost of compliance

Table 4 below provides a summary of estimated annua l costs for the various control options. EPA relied on MDU’s cost figures, with the exceptio n of HDSCR + SOFA/LNB, for which EPA performed its own cost calculations and estimated t he control efficiency, using a combination of EPA’s OAQPS Control Cost Manual and control cost sp readsheets from EPA’s Integrated Planning Model. (MDU had calculated the capital co st of SCR alone at $38,976,000, the total annual cost at $6,984,376, and cost effectiveness a t $9,680.)

31 MDU NOx control cost analysis by US EPA Region 8 f or SCR, SOFA/LNB, and SCR + SOFA/LNB, Summary Spreadsheet, March 7, 2012.13 Table 4 Summary of MDU Lewis & Clark NO

x Reasonable Progress Analysis Control Technologies

Control Option Control

Effectiveness (%) Tons NOx

Reduced

from

Baseline Capital

Cost ($) Annual Cost

of Capital ($) (CRF=.0944) Annual

O&M Cost ($) Total

Annual Cost ($) Average Cost

Effectiveness ($/ton reduced)

HDSCR +

SOFA/LNB 87.5 693 22,351,427 2,109,975 1,251,990 3,361,965 4 ,853

Fuel switch
to nat.gas 65 523 18,000,000 1,699,200 20,219,894 21,919,094 4 1,934

SNCR with

SOFA/LNB 50 401 4,531,000 427,694 666,268 1,093,962 2,729

SOFA/LNB 38 301 2,195,000 207,192 157,354 364,546 1 ,213
SNCR 38 301 2,433,000 229,658 531,996 761,654 2,533

SNCR (low load) 16 58 2,433,000 229,658 336,015 565,673 9,817

For annual cost of capital, EPA used 7% interest ra te and 20-year equipment life, yielding a Capital Recovery Factor of 0.0944, as specified in the Office of Management and Budget’s Circular A-4, Regulatory Analysis, available at:

http://www.whitehouse.gov/omb/circulars_a004_a-4/

.

For each control option, the “Annual O&M Cost” cons ists of all direct and indirect costs, with the exception of capital cost recovery (annual cost of capital).

Factor 2: Time necessary for compliance

For combustion modifications such as SOFA and/or LN B, furnace penetration would be required and, as such, would need to align with a major outa ge. The next planned outages is spring of

2018. 32 Therefore, it might not be possible to ensure tha t SOFA and LNB could be installed within the first planning period for regional haze requirements under the CAA. If HDSCR + SOFA/LNB is the chosen control option, the construc tion schedule could extend into many months. If SNCR is the chosen control option, inst allation would likely be much quicker. For the option involving a fuel switch to natural as pr imary fuel, several years might be needed to secure the necessary rights-of-way and install a ne w 22-mile pipeline that MDU has stated would be needed to provide a sufficient supply of natural gas. 33

Factor 3: Energy and other non-air quality environm ental impacts

A fuel switch to natural gas as primary fuel could significantly increase the demand for natural gas in the region and could increase natural gas pr ices for other consumers of natural gas in the region, as well as create impacts associated with m ore production of natural gas in the region. Other control options, however, would have minimal energy impacts.

32 L&C Emissions Control Analysis, p. 26.

33 L&C Feb. 10, 2012 Response, p. 2.14

Depending on HDSCR installation in relation to exis ting controls, ammonia slip can generally

cause additional ammonia to be emitted to air or wa ter. As ammonia is both a visibility impairing air pollutant and a wastewater regulated pollutant, air emissions and water discharges can be impacted. This is also a potential SNCR imp act. Also, spent catalyst from SCR produces an increase in solid waste. Finally, for combustio n modifications (SOFA and/or LNB), there is a potential for increased CO emissions from the boile r. During normal operation at L&C Station, CO levels are currently on the order of 20 ppm. Ge nerally, CO performance guarantees are in the 100 ppm to 200 ppm range for LNBs. 34

Factor 4: Remaining useful life

EPA has determined that the default 20-year amortiz ation period is most appropriate to use as the remaining useful life of the facility. Without com mitments for an early shutdown, EPA cannot consider a shorter amortization period in its analy sis. As mentioned earlier in this report, MDU has no plans or schedule for removing the facility from service, and MDU has stated that the remaining useful life of Unit 1 is not expected to significantly impact estimated costs.

Step 5: Select Reasonable Progress Controls

EPA has considered the following four factors: the cost of compliance; the time necessary for compliance; the energy and non-air quality environm ental impacts of compliance; and the remaining useful life of the sources. EPA is also taking into account the size of the facility, the baseline Q/D of the facility, and the potential red uction in Q/D from the controls. Based on costs of compliance, the small size of the facility, and the relatively small baseline Q/D, EPA proposes to eliminate the more expensive control options (fu el switching to natural gas and HDSCR + SOFA/LNB). For similar reasons, taking into accoun t costs in the low load scenario, EPA proposes to eliminate SNCR and SNCR + SOFA/LNB. Fi nally, for the most cost effective option (SOFA/LNB), emissions reductions would be fa irly small (300 tpy), which would result in approximately 16.6% reduction in overall emissio ns of SO 2 + NO

x for this facility, or a reduction of Q/D from 29 to 24. Based on the costs of compliance, the relatively small size of MDU L&C, and the modest reduction in Q/D, EPA finds it reasonable to eliminate this option. EPA therefore proposes to not require NO

x controls for this planning period.

34 L&C Emissions Control Analysis, pp. 19, 23, 24.