North Dakota State Implementation Plan 


for 


Regional Haze 


Supplement No.1 


A Plan for Implementing the Regional Haze Program Requirements 


of 


Section 308 of 40 CFR Part 51, Subpart P - Protection of Visibility 


North Dakota Department ofHealth 

Adopted: r~l-ICJ 

Division of Air Quality 


Air Pollution Control Program 


North Dakota Department of Health 


918 East Divide Avenue 


Bismarck, North Dakota 58501-1947 


Telephone 701-328-5188 


Terry Dwelle, M.D., M.P.H.T.M. 


State Health Officer 


Terry O'Clair, P.E. 


Director 

APPROVAL PAGE 


North Dakota State Implementation Plan for Regional Haze 


Supplement No.1 


North Dakota Department of Health, Environmental Health Section, Division of 

Air Quality. 

Approval by the following North Dakota Department of Health Management 

Personnel: 

Terry L. 0' lair, P.E., Director Date 

Division ofAir Quality 

,P.., 

Environmental He_-..."... 

Datk I 

Adopted for the North Dakota Department of Health 

7 

Terry L. ,.D., M.P.H.T.M. Date 

State ealth Officer 

North Dakota Department ofHealth 
Table of Contents 

Supplement No.1 to North Dakota State Implementation Plan for Regional Haze 

Supplementary Cost Information 

Montana Dakota Utilities Cost Estimates 

North Dakota Department of Health CUECOST Model Spreadsheets (verification only) 

Appendix A.2.4 - Permit to Construct 

Appendix F.I - Public Participation Record 

F.I.l - Public Notice 

F .1.2 Affidavit of Publication 

F .1.3 - Invoice ofPublication 

F .1.4 Response to Public Comments 

Appendix J.l.S - National Park Service Consultation Comments on Supplement No. 1 and 

Department's Response 

Appendix J.3.3 - U.S. Environmental Protection Agency Comments on Supplement No.1 and 

Department's Response 
Supplement No. 1 

to 

North Dakota State Implementation Plan 

For 

Regional Haze 

August 2010 

North Dakota Department of Health 


Division of Air Quality 


Air Pollution Control Program 


918 E Divide Avenue 


Bismarck, North Dakota 58501-1947 

R.M. Heskett Station Unit 2 

The Department has finalized a Regional Haze SIP revision. During preparation of that SIP 

revision, there was a disagreement as to whether RM. Heskett Station Unit 2 was subject to the 

Best Available Retrofit Technology (BART) requirements. On November 25, 2009, Montana 

Dakota Utilities Co. (MDU), the operator of the station, supplied the NDDH a revised BART 

modeling protocol as necessary to complete a refined visibility impact analysis for Unit 2. The 

NDDH and EPA Region 8 reviewed and approved the modeling protocol in early December 

2009. MDU subsequently supplied the Department a report titled "Updated BART CAL PUFF 

Visibility Modeling Analysis for Montana-Dakota Utilities Heskett Station Unit 2," dated 

December 17, 2009, which set forth the refined visibility modeling analysis for RM. Heskett 

Station Unit 2. The modeling report concluded that the facility will contribute less than 0.5 

deciviews of visibility degradation in any Federal Class I area. The Department and EPA Region 

8 reviewed the modeling and subsequently determined that R.M. Heskett Station Unit 2 is not 

subject to BART requirements. Because of the additional modeling and review, the NDDH was 

unable to timely address Unit 2 under the Reasonable Progress portion of the original SIP 

revision. Since the question of BART applicability has now been resolved, this SIP supplement 

provides an analysis of R.M. Heskett Station Unit 2 under the Reasonable Progress requirements 

of 40 CFR 51.308( d)( 1). 

RM. Heskett Station Unit 2 consists of an atmospheric bubbling fluidized bed boiler that has a 

rated heat input of 916.5 x 106 Btulhr. The boiler serves a single turbine/generator that can 

produce approximately 78 megawatts of electricity. The facility primarily burns North Dakota 

lignite from Westmoreland Coal Company's South Beulah Mine near Beulah, North Dakota. 

The unit occasionally burns subbituminous coal and tire derived fuel. The plant had initial 

startup in 1963 and was converted from a spread stoker combustion unit to a bubbling fluidized 

bed unit in 1987. Currently, the bed material in the combustion unit is made up of sand. 

Table 9.S 

Sources Evaluated for Additional Control 

Source Owner Unit Type I Capacity 

Heskett Station MDU 2 EGU I 78MWe 

Table 9.6 

Remainin Sources Existing Conditions 

Current Current 

Control Emission Rate Control Eff. 

Source Pollutant Equipment (lb/106 Btu)* (%) 

Heskett 2 S02 None 0.91 N/A 

NOx None 0.36 N/A 

*Based on 2007-2008 data. 
Table 9.7 

Control Options Evaluated 

Estimated 

Control Control Eff. 

Source Pollutant Considered (%) 

Heskett 2 S02 WS+LJ. 96 

i WS 

CDS+L.I. 

95 

95 

SD+L.I. i 94 

CDS 92 

Spray Dryer 90 

i Limestone Injection 60 

NOx LDSCR 70-90 

TESCR 70-90 

SNCR 30-50 

Staged Combustion 20 

WS =Wet Scrubber 

LI = Limestone Injection 

CDS =Circulating Dry Scrubber 

SD = Spray Dryer 

LDSCR =Low Dust Selective Catalytic Reduction 

TESCR Tailend Selective Catalytic Reduction 

SNCR Selective Non-Catalytic Reduction 

Staged combustion combined with SNCR is not technically feasible for the Unit 2 AFBC due to 

staged combustion decreasing the temperature of the flue gas in the upper portion of the boiler. 

Also, there would be space constraints with the addition of overfire air ports and adding, and 

appropriately spacing, the urea injection for the SNCR system. 
------- --- ------

Source Unit Pollutant

Heskett 2 SOz 

NO" 

Control 


Technology 


WS+L.I. 


WS 


CDSlBag+L.L 


SDlBag+L.L 


CDSlBag 


SDlBag 


L.L 


LDSCR 


TESCR 


SNCR 


Staged Combustion 


Total 


Annualized Cost 


(st 

13,35],000 

12,302,000 

1l,945,000b 

10,864,000 

10,985,000b 

9,815,000 

1,050,000 

5,216,000 

6,049,000c 

1,424,000 

366,000 

Control 


Efficiency 


(%) 


96 


95 


95 


94 


92 


90 


60 


80 


80 


33 


20 


Emission 


Rate 


(lb/lO' Btu) 


0.036 


0.046 


0.046 


0.055 


0.073 


0.091 

0.364 

0.072 

0.072 

0.241 

0.288 

Emissions 


Reductions 


(tpy) 


2,582 


2,556 


2,556 


2,539 


2,475 


2,421 


1,614 


858 


858 


354 


215 


Table 9.8 

Control Options Cost 

a Costs provided by MDU unless otherwise noted. The MDU costs were in 2006 dollars which the Department adjusted to 2009 dollars. 


b Department estimate based on Leland Olds Unit 1. 


"-peQartment estimate based on cost estimate for M.R. Youn~ Station. 


Cost 


Effectiveness 


($Iton) 

5,171 

4,813 

4,673 

4,296 

4,402 

4,054 

651 

6,079 

7,050 

4,023 

1,702 
Table 9.9 

Visibility Improvement and 

Cost Effectiveness 

Source Pollutant 

Control 

Technology 

Emissions 

(TPY) 

Visibility 

Improvement 

(dv)* 

Visibility 

Improvement 

elo) 

Cost 

Effectiveness 

($/dv) 

Heskett 2 S02 

NOx 

NOx 

L.I. 

SNCR 

Staged 

Combustion 

1,076 

719 

858 

< 0.009 

< 0.009 

< 0.009 

<0.05% 

<0.05% 

< 0.05% 

> 116,667,000 

> 158,222,000 

> 40,667,000 

*The Department modeled one scenario for this source - 95% S02 control plus 40% NOx 

control. This scenario produced a 0.009 deciview improvement at TRNP and a 0.003 deciview 

improvement at LW A for the most impaired days. 

Time Necessary for Compliance 

The Department believes up to 6.5 years would be necessary for some of the control options (Le. 

scrubbers and selective catalytic reduction). Other options such as SNCR and limestone 

injection into the boilers could be accomplished within 2-3 years depending on outage schedules. 

The Department recognizes that limestone injection in the Unit 2 AFBC may potentially cause an 

increase in other pollutants for which a separate Permit to Construct, including a PSD permit, 

may be necessitated. If a related Permit to Construct is required, that permitting schedule may 

impact the timing ofthe contemplated S02 emissions reductions required by this Supplement. 

Energy and Non-Air Impacts 

All of the technologies will consume energy. However, the energy impacts would not preclude 

the selection of any of the technologies evaluated. 

Remaining Useful Life 

Table 9.10 

Remaining Useful Life 

Source Unit Startup Date 

Estimated 

Remaining Useful 

Life (yrs) 

Heskett 2 1963 20-40 

The remaining useful life of the source would not preclude the selection of any of the control 

options. 
Reasonable Progress Goals - Required Controls for Point Sources 

The costs to install a wet scrubber, circulating dry scrubber or a spray dryer, with or without 

limestone injection into the boiler, is considered excessive both on a dollar per ton basis and a 

dollar per deciview basis. The cost of limestone injection on a dollar per ton basis is reasonable; 

however, it provides virtually no visibility improvement (estimated at less than 0.009 deciviews) 

and the dollar per deciview cost effectiveness is excessive. 

The Department is not aware of SCR ever being installed on a fluidized bed boiler. A HDSCR is 

considered technically infeasible. The cost effectiveness of LDSCR, TESCR and SNCR is 

considered excessive both on a dollar per ton and dollar per deciview basis. The cost 

effectiveness ofstaged combustion, on a dollar per deciview basis is considered excessive. 

The Department concludes that the addition of emission controls at Heskett Unit 2 is not 

reasonable at this time. However, this source, as well as all other point sources, will be 

reevaluated during future planning periods. 

The estimated amount of improvement from operating limestone injection and staged 

combustion at Heskett Station Unit 2 is 0.006 deciviews improvement at TRNP and 0.002 

deciviews at L WA at a capital cost of 5.8 million dollars and an annualized cost of 1.4 million 

dollars. Combining these controls with the controls considered for the other Reasonable 

Progress sources, the combined capital cost is 249 million dollars with an annualized cost of 69 

million dollars. The combined cost effectiveness is over 616 million dollars per deciview at 

LWA and over 1.92 billion dollars per deciview at TRNP. For all sources evaluated individually 

and cumulatively, the cost ($/dv) is considered excessive. Therefore, no additional controls are 

proposed for the non-BART sources during this planning period. 
10.6.1.3 R.M. Heskett Station Unit 2 

In Section 9.5.1, it was concluded that requiring additional air pollution controls at R.M. Heskett 

Station Unit 2 was not reasonable. However, the Department and Montana-Dakota Utilities has 

reached an agreement whereby limestone injection into the boiler will commence within five 

years after EPA approves the Permit to Construct for Heskett Unit 2 as part of this Regional 

Haze SIP. A Permit to Construct will be issued and is included in Appendix A.2.4. The Permit 

to Construct requires at least 70% control of the potential S02 (coal-to-stack) or no more than 

0.60 Ibll06 Btu (12-month rolling average) emission rate. This will be a 34% reduction from the 

2007-2008 baseline emission rate or a 573 ton reduction from the 2000-2004 average emission 

rate. 

Although MDU and the Department have agreed to a reduction of S02 emissions at Heskett 

Station Unit 2, this source will be reevaluated for additional air pollution controls during future 

planning periods. 
Supplementary 


Cost Information 

Cost Estimates 

In order to estimate the cost of various control options for R.M. Heskett Unit 2, the Department 

used data provided by Montana Dakota Utilities (MDU), CUECOST Model output, calculations 

using EPA's Air Pollution Control Cost Manual, and data from other in-state BART analyses. 

MDU had drafted a BART analysis for this facility and provided cost excerpts for several 

technologies (copy attached). The costs were estimated using 2006 dollars, so the Department 

adjusted those costs to 2009 dollars using the Marshall and Swift Equipment cost index for the 

electric power industry. The Marshall and Swift Equipment cost index has increased 

approximately 13% from first quarter 2006 to fourth quarter 2009 (1219.2 to 1377.3). 

To verify the costs, the CUECOST model was run. The CUECOST model provides costs in 

1998 dollars so adjustment had to be made to have an apples-to-apples comparison. To adjust 

the CUECOST capital cost results, the Department reviewed available data from several cost 

indexes to arrive at an average value. 

Index 

1998 

Index 

Date of 

Available Data 

Recent 

Index 

Percent 

Increase 

I Engineering News - Record 

I Construction C.l. 

5920 1110 8660 46% 

Chemical Engineering Plant C.I. 390 2/09 532 36% 

Marshall and Swift Equipment 

. Cost C.l. 

1062 11109 1377 30% 

Consumer Price Index 162.2 10109 216.2 33% 

Avg. 36% 

Due to limited data on the increase of operation and maintenance costs, a 36% increase was also 

applied to O&M costs. 

For the circulating dry scrubber (CDS), data from the Leland Olds Unit 1 BART analysis was 

used. This data suggested a 12% higher annualized cost for a CDSlbaghouse than a spray 

dryerlbaghouse. For the various technologies, the estimated annualized costs from the various 

sources in 2009 dollars were: 

lTechnology MDU CUECOST 

Control Cost 

Manual 

I Wet Scrubber $12,302,000 $11,154,000 

SDlBaghouse $9,815,000 $12,212,000 

SNCR $1,424,000 $603,000 $645,000 

The MDU cost estimate for a wet scrubber is approximately 10% higher than the CUECOST 

model estimate and the spray dryer cost is approximately 20% less than the CUECOST model. 
Since these values are within the range of accuracy of the CUECOST model and EPA's Air 

Pollution Control Cost Manual of±30%, the MOU costs were used. 

For SNCR, the MOU cost is 2.4 times the CUECOST model. The Oepartment reviewed BART 

cost estimates from other small power plants to determine which estimate was appropriate. 

Based on the results below, the MOU estimate of annualized cost appears to be reasonable. 

Source 

Heskett 2 

Stanton 1 

North Shore #2 

J.E. Corette 

Taconite Harbor #3 

Avera e 

For low dust SCR, MDU used a capital cost factor of $250Ikw. This falls in the mid range of 

SCR costs as ERG reported for a high dust SCR at the PGE Boardman Plant. Estimates for 

Leland Olds 2 and Minnkota 1 and 2 range from approximately $335 - $700/kw for a low dust 

SCR. ERG, in their analysis for the Boardman plant also indicated that SCR costs have rapidly 

escalated since 2004. ERG also notes that they believe the CUECOST model does not 

accurately predict installed costs for major construction projects such as SCR. The Department 

also believes EPA's Air Pollution Control Cost Manual does not accurately estimate SCR costs. 

Therefore, MOU's cost estimate was used in this analysis although the estimate appears to be 

low based on the other estimates and ERG's analysis. 
Montana Dakota Utilities 


Cost Estimates 

"MONTANA-DAKOTA 


• UTILITIES ca 

ADMsIon d IIDIJ R/I$QUICeS Group, Inc. 

400 Nodh FowfI SI1eet 

Bismarck. ND.58501 

{701J222·79tXJ 

February 3, 20 to 

Mr. Tom Bachman 

North Dakota Department of Health 

Division ofAir Quality 

918 East Divide Avenue, 2nd Floor 

Bismarck, ND 58501-1947 

Re: 	 Montana-Dakota Utilities Co. - R.M. Heskett Station Unit 2 

Best Available Retrofit Technology (BART) Emissions Control Summary 

DeQJ'Mr. Bachman: 

In response to your recent request for additional information related to regional haze impacts for 

Heskett Station's Unit 2, please find enclosed a summary of relevant materials related to S02 and 

NOx BART controls that were historically evaluated for Unit 2. 

In anticipation of potential regional haze regulatory impacts to Unit 2, Montana-Dakota Utilities 

Co.. (Montana-Dakota) conducted a BART control eValuation in late 2005 and early 2006 that 

remained in draft form. The complete draft evaluation is rather lengthy. Recognizing your 

familiarity with the various control technology descriptions and impacts from reviewing BART 

analyses for North Dakota utilities, Montana-Dakota has excerpted information directly relevant 

to the S~ and NOx emissions control evaluation at Unit 2 and has provided this information in 

Attachment A. Minor corrections and updates have been made to the excerpted 2006 draft report; 

. however, the cost data have not been updated. Additional detail related to the background ofthe 

evaluation and conclusions may be provided upon request. 

We-understand thatthe North Dakota Department of Health may use this information in part to 

assess Unit 2 under the reasonable progress goals in its Regional Haze SIP. In doing so, please 

appreciate that the 2006 analysis may not reflect current regional haze policies. Nevertheless, itprovides a useful site-specific technical evaluation. 

Also recognizing that the control cost information may have changed since the evaluation was 

completed in first quarter 2006, Montana-Dakota has provided for reference a cost index table for 

the electrical power industry. The values shown below are from the Marshallimd Swift 

Equipment Cost Index and compare the cost between first quarter 2006 and fourth quarter 2009. 

The Vatavuk Air Pollution Control Cost Indexes (VAPCCI) was discontinued by EPA a few 

years ago. In lieu ofa site-specific cost update for the technicaJly feasible emission controls, the 

Marshall and Swift index provides a reasonable general estimate ofthe change in cost of 

equipment 
Mr. Bachman 

February 3, 2010 

Page 2 

MCJITANA-DAKOTA UTUJTlES CO. 

Marshall and Swift Equipment Cost Index';" Electrical Power Industry 

Year Quarter Index 

2006 QI 1219.2 

2009 Q4 1377.3 

Ifyou have any questions about this submittal or require additional information to complete your 

analysis, please contact me at 701-222-7844. 

Sincerely. f /}/..~ 

4 

Ms. Abbie Krebsbach 

$~ Environmental Manager - Power Production 

Ene. 

cc: Alan W~lte, Generation Manager 

Tony stroh, R. M. Heskett Statism Manager 

Joel Trinkle, Barr Engineering Company 
MaVTANA.lJAKGrA lJ77LI71ES CO. 

Atlilchment A 

Excerptsfrom 2006 BARTEvaiUlltlon at R.M. Heskett Station Unit 2 
ExcerptedR.M. Heskett Station Unit 2 ,(Main Boiler) Draft BART Analysis 

from May 2006 


Prepared for Montana-Dakota Utilities Co. by 


Sargent & Lundy and Barr Engineering Company 


1.0 " BART ANALYSIS FOR MAIN BOILER SULFUR DIOXIDE (S02) 

. Sulfur emissions from coal combustion consist prim81jly ofS~, with a much lower quantity ofS03 and 

gaseous sulfates. These compounds fonn as the organic and pyretic sulfur in the coal is oxidized' during 

the combustion proc~ss. For .pennitting and d~sign purposes, it is assumed that 100% ofthe fuel sulfur 

wiIlconvert to S02 during the combustion process, and that 1 % ofthe uncontrolled S02 will oxidize to 

S03 within.the fluidized combustion bed. 

The generation of S02 is directly related to the sulfur content and .heating value ofthe fuel burned. The 

sulfur content and heating value of coal can vary dramatically depending on the source ofthe coal. 

Heskett Unit 2 uses North Dakota lignite or a blend oflignite and Power River Basin (PRB) coal as its 

fuel source. Tabl,e 1-1 provides a summary oftbe lignite used at Heskett Unit 2, includingtbe heating 

value and sulfur content. 

Table 1-1 . 

Fuel Characteristics 

1.1 Step 1: Identify Available Retrofit S02 Control OPtions ' 

Several techniques can be used to reduce S02 emissions from coal combustion sources. S~ control 

techniques can be divided into pre-combustion strategies, combustion techniques, and post-combustion 

controls. S~ control options identified for potential application with at Heskett Unit 2 are listed in Table 

1-2. 
-- --

--

--

ExceIpted R.M Heskett Station's Unit 2 Draft BART Analysis 

Table 1-2 


S~ Control Options with Potential Application to a 


LigniteIPRB Fired AFBC Boner 


Pre-Combustion Controls 

Fuel Switching 

Fuel Washing and Benefication 

Combustion Controls 

Atmospheric Fluidized Bed Combustion (AFBC) 

Technology with Limestone Injection 

Post-Co~bustion S~ Control Teelmologies 

Wet Flue Gas Desulfurization 

Wet Lime Flue Gas Desulfurization 

Wet Limestone Flue Gas Desulfurization 

Dry Flue Gas Desulfurization 


Ash Reinjection Systems 


Spray Dryer Absorber 


Circulating Dry Scrubber 


, Dry Sorbent Injection 

1.2 Step 2: Eliminate TecbnleaUy Infeasible Retrofit OptioDS 

Results ofStep 2 of.the S02 BART Analysis (technical feasibility analysis ofpotential S02control 

technologies) are summarized in Table 1-3; 

Table 1-3 

Technical Feasibility ofPotential SOz Control Technologies 

ApprOLSOl ~ ,-


ConcJnUation:iil, 
 :'''_~ :":'r.SftviCe,on

Flue Gas AllliE . " .', '>'fHh~C~~bu.stlon Teclmlcally Feasible for 

Control Technology (ppmvd @VA 02l ,'t~'::~:~liJt;' ",: "',' $p~f ' H~,tt Vnit 21 

AFBCs have been No. Fuel switching would Fuel Switching - require significant boiler 

variety offuels. 

designed to burn a 

modifications and would not 

significantly reduce controlled 

S<h emissions from Heskett 

Unit 2. 

Washing has not No. Washed coal has not been Coal Washing X used in AFBC boilers. and will 

burned in AFBCs. 

been used on coal 

not significantly reduce 

controlled S~ emissions from 

Heskett Unit 2. 

Processed coal has No. Processed coal has not been Coal Processing X ,been demonstrated demonstrated on a long-term 

in PC boilers. basis in AFBC boilers. and is not 

commercially available as a 

retrofit technology. 

2 

Excerpted R.M Heskett Station's Unit 2 Draft BART Analysis 

.'C9I1."l-T~olo2Y 

Appl'GL 80:1 

ConeentraUon in 

Flue Gas 

(ppawd @3% (h) 

In Service on 

Emting 

ADC·BoUers 

Yes No 

.. 

In SentCC'.QD.'.· '. 

Othe:rcoin~oa': $o~1:. .;.'.: .., .. 

. ·.Ttdmteally Feasible for 

"'ttUait2? 

AFBC Boiler with 

Limestone Addition 

(1.5 to 2.0 cats ratio) 

approx. 180 . X 

. 

Yes. Heskett Unit 2 CUITeIltly . 

uses sand to sustain the 

combustion bed. The bOiler and 

associated material handling 

systems could be modified to 

utilize limestone. 

AFBC + Wet FGD approx.50 X Wet FGD has been 

used on coal..fired 

PC boilers. 

Yes, however, no commercial 

experience or operating history, 

and question about commercial 

availability. 

AFBC +Dry FGD 

(Spray Dry Absorber) 

approx.60 X Yes, however limited 

commercial experience. 

AFBC +Dry Sorbent 

Injection 

>60 X No. not technically practic8.J on a 

AFBC boiler because ofthe 

unreacted lime concentration 

already in the flue gas. 

AFBC + Circulating 

:Dry SCJUbbei 

approx.60 X CDS control 

systems are in use 

on a limited number 

ofcoal-fired units. 

Yes. however limited 

commercial experience. 

1.3 Step 3: Evaluate Control Effectiveness ofTechnically Feasible Technologies 


The control effectiveness ofeach technically feasible retrofit technology was discussed in Step 2. The . 


effectiveness ofeach retrofit technology identified as being technically feasible for S~ control are 


presented in Table 1-4 in descending order ofcontrol efficiency_ 


Table 1-4 


Summary ofTechnically Feasible 


Main Boner S02 Control Technologies 
 ' . ·".~_tlM CoDfro} Teelmology 

S~EmJssij)D:' 

Rate' '; :': 

nIL :'..:. 

. 

' " .frtoiD·.....um '.. ... , ::-~.~(t) 

AFBC with Limestone Addition plus 

WetFGD 

0.10 95% 

AFBC with Limestone Addition plus 

. D1yFGD (SDA or CDS) 

0.12 94% 

AFBC with Lim~stone Addition 0.35 83.3% 

AFBC with Sand 0.862 60% 

Potential Uncontrolled S02 (baseline) 2.10 

(1) Overall reduction efficiency takes into account S~ reduction in the AFBC and the post-combustion 

control system, and is based on an average uncontrolled S02 emission rate of2.10 lblMMBtu. 

3 
Excerpted R.M Heskett Station's Unit 2 Draft BART Analysis 

1.4 Step 4: Evaluate Impacts and Document the Results 

Step 4 ofthe BART determination requires an evaluation ofthe economic, energy, and non..;air-quality 

environmental impacts ofeach technically feasible retrofit technology. This evaluation should take into 

consideration the remaining useful life ofthe unit. Table 1-5 presents the capital costs and annual 

operating costs associated with building and operating each control system. A summary ofthe Step 4 

economic and environmental BART impact analysis is provided in Table 1-6. 

Table 1-5 


S02 Emission Control System 


. Cost Summary 


AFBe $5,333,000 $6,482,600 $11,815,600 Addition plus Wet 

FGD(l) 

$46,017,600 $588 $4,334,000 $5,270,800 $9,614,800

$3,780,000 $48 $356,800 $572,200 $929·,000

(I) Wet FGD capital costs include the cost ofmajor components and indirect installation costs such as foundations, 

mechanical erection, electrical, piping, and insulation for the FGD absorber tower, recycle pumps, induced draft fans, 

significant modifications to the existing stack, limestone receiving, limestone addition to the boiler, and FGD sludge handling 

systems. 

(2) Dry FGD capital costs include the cost of major components and indirect installation costs such as foundations, mechanical 

erection, electrical, piping, and insulation for the reaction vessel, induced draft fans, reactant injection system, stack 

modifications, lime handling system and solid waste handling system. Dry FGD capital costs also include costs associated 

with a tabrie filter bagbouse because particulate control is needed after the dry FGD and it would be impractical to fit the dry 

FGD system between the boiler and existing ESP control system. 

4 
Excerpted R.M Heskett Station's Unit 2 Draft BART Analysis 

Table 1-6 

Summary ofBART Impact Analysis 

. , 

.­ T-otal Average mcremental 

....0 . A.D.irUai , '.: Cost Cest 

'Connl 

Ttdmol9IY 

EmJsslolli 

(g,y) .. 

~~. 

'~7-) .,' .' 

',Coals' .,.cJI¥.ear) Effectiveness 

(Slton) 

EffectiVeness 

($/tonl E.mro.~.tItI:_Wlets·,,; 

AFBCwith 341 2,600 $11,815,600 $4,540 $12,760 Increased PM emissions 

Lirilestone and increased acid gas 

Injection plus Wet emissions, including 

FGD sulfuric acid mist 

Increased water me and 

wastewater treabnentJ 

discharge. 

AFBCwith 

Limestone 

409 2,532 $9,614,800 $3,800 $11,060 Increased water use, and 

increased PM emissions 

,lqjection plus Dry frOm handling lime 

FGD reagent 

AFBCwith 

Limestone 

1,194 1,747 $929,000 $530 - Potential increase in PM 

emissions from limestone 

Injection handling. potential 

impacts to fly ash 

resistivity and 

effectiveness of the ESP 

control system, and 

potential impacts to the 

existing solid waste 

management/disposal 

system. 

AFBC with Sand' 2,941 -­ -­ -­ -­ Baseline . (baseline) 

Potential 7,165 -­ -­ -­ . -­ Uncontrolled S(h 

5 

Excerpted R.M Heskett Station's Unit 2 Draft BART Analysis 

2.0 BART ANALYSIS FOR NITROGEN OXIDES (NOS> 

The formation ofNOx is determined by the interaction ofchemical and physical processes occurring 

primarily within the combusti~n zone of the ~i1ers. There are two principal forms ofNOx designated as 

"thermal" NO. and "fuel" NOx• Thermal NO. formation is the result ofoxidation ofatmospheric nitrogen 

contained in the inlet gas in the high-temperature, post-flame region of the combustion"zOne. The major 

factors influencing thermal NO. formation are temperature, the concentration ofcombustion gases 

(primarily nitrogen and oxygen) in the inlet air, and residence time within the combustion zone. fuel NO. 

is formed by the oxidation ofnitrogen in the fuel. 

2.1 Step 1: Identify Avallable Retrofit NOx Control Options 


Potential NOx retrofit control options were identified based on a review ofavailable technical " 


information. Retrofit control options with potential application to Heskett Unit 2 are listed in Table 2-1. 


Table 2-1 


List ofPotentiany AvaDable Retrofit NOx Control Options 


:CtJ~~R~l~" ..' .•: ~ 

Combustion Controls 

Fluidized Bed Combustion (existing) 

Staged Combustion 

Low NO. Burners 

Flue Gas Recirculation (FGR) 

Burner Tempering (Water Injection) 

Post-Combustion Controls 

Selective Non-catalytic Reduction (SNCR) 

SNCR with Staged Combustion 

Selective Catalytic Reduction (SCR) 

High-Dust SCR 

LoW';.Dust SCR 

" Innovative Control Technologies 

Rotating Over-fire Air (ROF A) 

Boosted Over-fife Air (BOFA) 

ROFA + SNCR (RotamixTM) 

NOxStarTM 

Exxon Thermal DeNOxTM 

Pahlman Process 

Wet NO. Scrubbing 

LOTOxTM 

2.2 Step 2: Eliminate TechnieaJly Infeasible Retrofit Options 

Retrofit NO. control technologies can be divided into two general categories: (1) combustion controls, 

and (2) post-combustion controls. Combustion controls reduce the amount ofNO. that is generated in the 

boiler, while post-combustion controls remove NO. from the boiler exhaust gas. Retrofit control 

6 
Excerpted R.M Heskett Station's Umt 2 Draft BART Analysis 

technologies identified in Step 1 were evaluated for technical feasibility, including availability and 

applicability, for Heskett Unit 2. The results of Step 2 ofthe NOx BART detennination (technical 

feasibility analysis ofpotential NOx retrofit control technologies) are summarized in Table 2-2. 

Table2-1 . 

Teclmieal Feasibility ofPotential NOx Retrofit Control Technologies 

, " 

Atmospheric 

Fluidized Bed 

(AFBC) Combustion 

AFBCwith 

Additional Staged 

Combustion 

Low NOx Burners 

. Flue Gas 

Recirculation 

Buriler Tempering 

AFBC+ SNCR 

AFBC with Staged 

Combustion + SNCR 

AFBC + High Dust 

SCR 

AFBC+LowDust 

SCR 

Boosted Overfire Air 

(BOFA) and Rotating 

OverfJre Air (ROFA) , 

BOFAlROFAplus 

SNCR 

NOxStar1'M 

Exxon Thermal 

DeNOxTN 

PahIman Process 

ApproLN()~ 

ControDedNOx 

, Emission Rate 

, (J)pmvd@3~~2)' 

225 -235 

(0.326 IbIMMBtu) 

180-190 

(0.26 IbIMMBtu) 

150-160 

(0.22IblMMBtu) 

50-60 

(0.08 IblMMBtu) 

In Service on , 

Emtblg 

AFBCBoUers 

Yes N~ 

x 

x 

x 

x 

x 

x 

x 

x 

x 

x 

x 

x 

x 

x 

na 

na 

Not applicable to 

AFBC boilers 

Not applicable to 

AFBC boilers 

Not applicable to 

AFBC boilers 

yes 

yes 

No, combustion takes place within 

the fluidized bed in an AFBC. 

Ineffective because ofthe low 

combustion temperature in an 

AFBC boiler. 

No, low combustion temperatures 

within fluidized bed. 

yes 

May be applicable Not technically feasible for Heskett 

to PC units Unit 2. Temperature window 

needed for SNCR is not available 

within boiler. 

SCRcontrol 

systems have been 

installed on PC 

boilers 

SCRcontrol 

systems have been 

installed on PC 

boilers 

Demonstrated on 

coal-fired PC units 

Demonstrated on 

coal-fired PC unitS 

Demonstrated on 

coal-fued PC units. 

Demonstrated on 

coal-fired PC units. 

No. Technical limitations including 

rapid catalyst deactivation. Not 

demonstrated in practice on an 

AFBC. 

,Yes, but not demonstrated in 

practice. Requires flue gas re-heat. 

May not be commercially 

available. 

Included in the evaluation ofother 

staged combustion systems. 

Included in the evaluation ofother 

SNCR control sYstems. 

Not available as BART retrofit 

technology f()J' AFBC unit 

Included in the evaluation ofother 

SNCR control systems. 

Not available as BART retrofit 

technology for AFBC unit. 

7 
Excerpted RM Heskett Station's Unit 2 Draft BART Analysis 

InSemceon 

·:EiDJ$Sioil·.Rate . ;t£u1idWv._% ~ 

AFBCBollen 

Yes 

In Semceon 

ControUedNOx . APPrOLNOx 

Other 

Combustion 

Existing 

TeclmieiUy I'asude. No Sonrees? 'tQr.Besltett::,. i .~' .. '.:,

Not available as BART retrofit 

industrial boilers. 

x Demonstrated on

technolo . for AFBC unit. 

2.3 Step 3: Evaluate Control Effectiveness ofTechnically Feasible Technologies 

The control effectiveness ofeach technically feasible retrofit technology was discussed in Step 2. The 

effectiveness ofeach retrofit technology identified as being technically feasible and commercially 

available for NOx control at Heskett Unit 2 are presented in Table 2-3 in descending order ofcontrol 

efficiency.. 

Table 2-3 


Summary ofTechnically FeaslbJe 


Main BoUer NOx Control Technologies 


.. 

·r 

AFBC + Low Dust SCR . 0.08 82% 75%

AFBC+ SNCR 0.22 52% 33%

.AFBC + Staged Combustion 0.26 44% 20%

AFBC Combustion 0.326 3.5% 

Baseline NOx Emission Rate 0.463 

2.4 Step 4: E~luate Impacts and Document the Results 

Step 4 ofthe BART determination requires an evaluation ofthe economic, energy, and non-air-quaiity 

environmental impacts ofeach technically feasible retrofit technology. This evaluation should take into 

consideration the remaining useful life ofthe unit. Table 2-4 presents the capital costs and annual 

operatmg costs associated with building and operating each control system. A summary ofthe Step 4 

economic and environmental impact evaluations is provided in T~ble 2-5. 

Table 2-4 


NOs Emission Control System 


Cost Summary 


Control TechnolOlY 

Tot8ICapital 

Investment' 

($) 

Total Capital 

Investment. 

. ($lkW-net) 

Annual Capital 

Reeovery Cost 

($/year) 

AnnualOperatiBg 

Costs 

($/year) . 

·roid·Auual 

Costs ·~r) 

AFBC + Low Dust 

SCR 

$19,544,200 $250 , . $1,844,800 $2,770,700 $4,615,500 

AFBC+SNCR $3,590,000 . $46 $338,900 $921400 $1,260,300 

AFBC + Staged 

Combustion 

$1,313,000 $17 $144,200 $179,800 $324,000 

AFBC Combustion NA NA NA NA NA 

8 

Excerpted RM Heskett Station's Unit 2 Draft BART Analysis 

Table 2-5 

Summary ofBART Impact Evaluations 

lITom.-·.·-:·: --.-.·..,in Average .,~" .' AIi.ac . To'-I .Ai:m.UaI Cost 'Base";:.. L.~_.. Control Costs Elfedlveness '(lDYl:',~: .-. ~,: .:.:~ . ($Iy..-> . ($Iton) 


AFBC+Low 


TeclmO~ 

1,307 809 $4,615,300 $5,750 Increased CO and VOC 


DustSCR 
 emissions associated With reheating the flue gas. Increased 

S(h to S03 oxidation across 

the SCR, and increased 

. condensible PM emissions 

including H2S04• Ammonia 

emissions associated with 

ammonia slip may be a 

precursor to the formation of 

visibility impairing particles 

such as ammonium sulfate and 

ammonium nitrate. 

AFBC+SNCR 751 829 361 $1,260,300 $3,491 Ainmonia emissions associated 

with ammonia slip may be a 

precursor to the formation of 

visibility impairing particles 

such as ammonium sulfate and 

ammonium nitrate, 

AFBC + Staged 887 $1,440 Potential changes to flue gas 

Combustion 

693 225 $324,000 

characteristics may impact the 

unit's ability to capture 

mercury emissions. . 

AFBC 1,112 468 . Boiler modified to AFBC 

Combustion 

NA NA

configuration in 1987. 

(Baseline) 1,580 NA NA

9 

MOnlllJUl-Dakola Ulilities 

Heskett Unit 2 - BART Delerminalion 

May 30,2006 DRAFT 

BART Economic Evaluation - NOx 

Staged Combustion Details 

Co.t 

CAPtTAI. COSltl ($1 aaslt 

DiAle! Caplttl Cotla 

t.:1"tII 8aHd SNCR Cosb 

Duct ..'Oft 11/14 OiImpt,., 5360,000 

OfA !'on. $150.000 

I'un:ed lJrah F." Modir",,,llon. 590,000 

1n>lI'Ul1lCIlIS IJId ('.AlIlIfOb 5120,000 

Mille. Oftr Dir«1 capital ('.I)!.b S75,000 

TUIlII Oll1lC1 (OSI 5795.000 

lndiAlct Caphll COIla 

01 TOC. ealE: ePAl~s:/I8-C2.oo1. sllCllOli 4.2, 8tICI CUEOosI dellulc .lIIues 101 

En~.eMQ $119,000 1&.010 

(J/ 

SNCfl. 

TOC. 

_.aseCIlrom 

8aslo: EPAl4~.(lOI.

10% 10 15% 

Socllon 

10 _11OI"lfOI~

~..2. 8tICI CueOosl 

~ 

dell\lll ••luflIOO 

Cons1rUCbon 81'\11 Field E~I!$ S80.00c IO.O'lI, SNCfl. 1nC,.....s lrom 5\, 10 1~ 10 _Ilor .toItoll! __. 

ConIlae1or Fee$IPennllltt\g.'Mode~nll SSO.OOC 10.0'lI, '" TOC. -= TYPC:1I101 pellul.... co""o< $y\I1ems. 

Slal'l-\JllfTestWlQ S40,ooo 5.0% d TOC. BuI:l: Typc:81 SlIIIUII ccslS to< Of'/I $y\I_ 

d Toe. eMl$< T)'PICal ptllOlmlnceIHIingcosl101 OF/I ,syslemf (_2<1 

Penom>lIIICe Tes1lflO . 54o.OQ( 5.0% ClayS). 

(J/ TOC. -=ePAl4S219-G2.(lOi. St<:tIOt> ~.2, 1/1(1 ClJECosI <leIaull._ t:JI2O'Ioo 

ConIirlgenc:ie& $159.D!X 20.0'lI, 1101 SHCRI. CcinIIlsIel!I ...111 cOIIllrllIIflC1lO' 'eirdI! llRlIecl. 

Totllllnditeel C6P/Ij/ Com $SI8.D!X 

TOlal Capllal Cos.. 

T0111 CapllIll fnvlSlmen, (TCI) S1,313,OQ( 

TOIII Capilli InvHlme"l 1$.lkW·nel) 51 

Capl..1RecoIIery Fact ... ,,/11+1'1' III +It. I 0.1098 15 I~e 01 equlpmenl (y.ars) 

Annuaillecl Capital COlli 

leaphll Recover F.CIO' _ TOI.I C.pllalln"ealmelll) SI44~OO 7% ptela. marginal 'ele 01 ,elum on pnvale investmll1lf 

OPERATING CUli' li Bas s 

OPlr.llng .. Malnlenance Costs (besed on 90% capRclty laclor) 

Vallible O&M Coala 

.Urea RHoem COSI SO S NA 

WalerCost $0 $ NA 

Boilet Ellioer,cy Penah, 56,800 cosl .. S0-8Olmm Btu 

Aulliliaty Power Cosl $28,500 $ 4S Beud on auxiliary power requl«!ment 01 0.1'" (gtos&) al'\ll S45/MW". 

T01111 Valiable o.s: MCost $35.30( 

Fixed O&M COlli 

Assumed SlIgII1 increllse i" Ope'81O' nou" 10 accounllor inspecllo,>! 01 

Additional OpelllOlI pet shill O.12! tne 01'''' control ayslerro. 

3 'MIs/day. 365 daylllyev " $46/hou. IUIlII)< .. benefits) """d\ 1$ equal 

Operaling labOt 5$2,60( 10 an .nnueiOPeratOi COSI 01 $100,00Q/y1lll" 

SupeMSOI) Labor 57,90( 1~.0'!10 olope,al"'IlIllDO', OAOPS Chapler 2. page 2·29. 

EPAf45.2!S..()?.QOI,.1'\II used !tie Mal'IlIInance Oelaun FaCIO! to, SHeA 

Meinlen_ Materials SI9,7OC 1.5'1<0 (1.5'10 of Tolal CapllallrWUtmem) SediOtl4 . .2. 

Mainlenance LabOr $l1,8OC 60.0-.. 01 maintenance matehals cost (S&L 0&'-1 'lI1im&18). 

TOIIII F,.fIII O&M Co6t $92.000 

II'\I!iAIct Oper.llnv COlt 

Properly Ta_ Sl3,IOC I"" otlOlQ/ cap)la! "'vestment. OAOPS Chapter 2, page 2·32. 

InSUtance St3,IOC 1% 0110\81 capilal inveslment. OAOPSChapte, 2, page 2·.32. 

Mministr8lion S2S.:3OC ~'I<o 01 100eI capilal investment. OAOPS Chaplet 2, page 2·32. 

Total /tI6IeI:t (.}pfttariflg Co6t $$2,5(x; 

TOIal Annual Opelltlrnl Call $119800 

TOTAl. ANNVAL COST 

Annualized Caplllli Cost $144,200 

Annual Operating COS! 5119.800 

TOI.I Annual Cost 5324,000 

Page B..6 
Montana-Dakota UliHlies 

Heskeu Unit 2 - BART .Determination 

May 30.::!006 DRAFT 

BART Economic EvaJuafion - NO" 

SNCR DetaiJs 

CAPITAL COSTS 

Dtrecl Caplll' COlli 

Urea BIRd 5.'iCR COl'" 

limStanp l Handlin: 

UIC« Il\I«tloa 

COIIII'OIsiMb«IraAir He:lter ModirlCl•• 

T0IIII OlftCl Coil, (l'lX'1 

COllI 

IS) . au" 

....dtln u.s.""...•• Cv_~010 lII1d~cote_~red 

$392.000 by SAL lOr ..... 1'"'1«:11. InCIudH lilt cote 0I ..........c:cmpan_1nd Incl_ 

$771PXJ Ins....cos.. SUCh u 1MCIhInIcIl_1IaII. ---.llIping._ 

$308.000 _lot... eNCR __SJSlIIb. _ syaIeIft. .... ON ~ 

.$703.000 NlAllltIIIaIiorI.1'Id conwll12.175.000 

1nd1rect CIp.... COllI 

EngkIterInIl 

ConllfVCllcn II'1d FM!1d E.~ 

ConIfador F..JPermft.in{llMoOelltlQ 

SlIlII-UplTeJung 

Performaoce Tesling 

ConlingenCleS 

TOIBI kraitecf Gap.tSl Cos. 

rI roc. Bull, El'l\I4S2/1H)Z.oD•• &et:IcI> 4.2. _ C1A!CoII ........ _. 

$326.00: 16.0% lnCT_eo IrOl'll 10"11. Ie 1~ Ie _OUnllllf IIIldft lnQineemo. III roc. "$/.I: &'PN4521B-OfoQ01. Section • .2.III1dC1A!COSICMI............ 

$218.00: 10.0'lI0 .......d • .­ 5'" 10 1~ 10 _ounllllf..uo&_. 

$218,00: 10.0% III TOC. Bal'" Typical 101 poIIuIiGn c","""I)'*'_. 

SI09.00c 5.0% III foc. B6s1s: TJpiC/il SlOIIu\l COSI$IO. SNCI'\ 

Sl09,OOC 5.0'lI0 .. TOC. BaSIS: T~aI ~~orma""'Ie$\l'Ig ~ote lOr SNCR 1_20 dtIyI). 

01 TOC. Basis: EPAi45Wo()I1·00I. Section U • ...., CUECos; ""...,1 ...... CI 2O'l.. 

543$.000 20.0'10 CorII..I.nt ";\1\ conlingency let •• llOm_1. 

$1.415.00<l 

TOIl' Capital COSII 

T(II8I CapitalltWestmerll crCi:,) 

TOIa' meslmenl (SIkW.....) 

Capilal Recovery Factor: 1('+ rt I I' +tf - , Annu.Uud Capita' Colla 

(C.."I'" Reco_ Factbt x Tolal Caplllll'nllUlmentJ 

$3,590,\10( 

54! 

0.0944 20 lIIe oIllQlJlpmen. (years) 

$838,9OIl 7% PlelaX marllina',ata ciI re'um on pllval. illve$uneftl 

OPEFtAT'NG CO$'fS aasls 

Operallng , Maintenance Cosu (IM'eeI on 90% capacity fadar) 

Vlltleble 0&11 Cot" 

Ulea Consumption 11tIIIv) 

U.ea RelQlfd'Cosl 

Wale, Cos. 

Boile, Efficiency Penally 

25 

Based on maltlmum hGa' hpUl. NOx removal rale (~). NH31N2 molal 

S5,8,101: $ 550 .allO IPPI'oxlmalely 2.0 (N$R). fII>(I S5SOIIon lor urea SClUlIOn. 

$1:301: S 1 Bas6d on urea feed ,a.e and $,n000 lIal. 

58.201: 0.'5% balkI, efflc:lency penafty, equivalent fuel cost G $O.IlImmBlu 

Auxiliary P_ Cotl &42.700 $ 45 Based on awrlliary powet requiremenl a! 0.15'" Igron, anCI S451MWh 

TOfBI VallatJle 0&11 Cos, 5570.300 

Fixed OaM Cotla 

AddI.1OI\1II ()pera\Ol1 per Shih 0.250 Base<I on S&l O&M e$lVnale 'or SNCR conIroi s~em. 

3 sttllslday. 365 aayslyear III: S48Ihour (Ulery + benellts) MlIcIt ~ tq\lIIl 

Operating l8llOl $105.11)( 10 an annual operalCl' COS. 01 SlOO.OOO/yeIll. 

Supel'llfSOry UIbor $ 15.eO( ,!;.O'!O 01 operating labor. OAOPS Chapler 2. page 2·29. 

EPA/4S2I8-Q2-00I. Maintenance OefalJl FaCIOI' lor &NCR !'.S'IIo 01 ToIaI 

Main.enance lrAeIerlais 553.90( 1.5% CapIIa'.nvestrnenl) Section ~.2. 

Man.enal1C4t Laboi $32.301: 60.0% 01 maintenance materialS COS. (Sal 0&... 81Ima'e,. 

Total Filled O&M Cost S207.10I: 

IndlrKl OJllf'lllnt COIIt 

PropenyT_ S3e.OOC ''110 oC 1oIe1.caplal i'N8s1rntnt. OAQPS ChIIpIer 2. P8\1112-32. 

Insurance $36.1lOO t'l' oIldel C8jlII., Inveslml\nt. OAOPS Chapter 2, P8\1112-32. 

AdmInillrallon S72.00c 2'l(. 01 101111 capilallnves\me(lt. OAQPS Chfi,t., 2, pagt2·32. 

TOII/lIInd/reI;f 0petII1rng CosI 5144,OOQ 

Total Annual Oper,lIno Cost $921400 

TOTAL ANNUAL COST 

AnnUIIUled Caplllll COG! $338,900 

Annua' Ope,.IInG Cosl $1121400 

Tcrt., Ann.-' Cost 51,2110,300 

PageB-7 
____ 

Monlana·Dakota Utilities 

Heskell Unit 2 - BART Determination 

May 30.2006 DRAFT 

BART Economic Evaluation - NO" 

Low-Dust SCR Details 

CAPITAL COSTS 

Direct Cap OSIS ­ R_IOf HOllIn" Mel IMlaUa..OD 


A..,1IlOIIIa HMdhn.1IIId Inject/OIl 


FI"" a.... HalldllnS:I>uc_t ami Fam e_... u.s.EPA"c-_·_~COSI"""~ 

Ak Pn:halct Modifleatl""" 
 DrS&l,IOI-prcjtoetS. ..-..<:osIGlIlIIjOfCOll1j)Ol'lQt1l.__ ~coRolIIGII ..~ ~IIIII"'I(."" I;!;,c. OIlIer DirecI (Apical co... 


EquipmetI C'ip\IIJ C.,.q SubtCIIA' _ano InkIIUCnfq ..I0I04111 sell _~."""" hIrIIIttlfIlYI*II, .... QIIIo
 ...... lntI_.. _~. 

1_1eI1'" " CQlltl'ol., T_ 

Fre I 


TfIUII /)(roJ CMI CTOCJ 


indirect Caphal CHIlI 
 OITOC. 1IaSII.: EPA..._.-.4.f.anoCVECosI __ 
 

__10'!00 102O'I\.104IO<:_Ior_ SCR.~ItIO''''''' 

E"",,"rin!l 15.0'li0_._. . oITOC, 1I1sts: EPN4~·DO'. _4.2.II'ICc.JfCosI __. 


eon.ltuC.on an<! Field EIipgn&_ 
 5.0'l0,_"'_5'I<.IOI0'!001O __"" __ 

ConlfllClOt F_ 10.0'% OIroc. 1I_:TrIlicIIlorpollullOn_.-. 


Slart.Up 1.0% olTDC. a":TypcfII-.._IOtSCR 
 

Petfotmanco TeslinlOl t.o'Ao 01 TOe. B_: TrIlicII pel!OIlN1nCellS*'ll «111101 SCII 1_01, I!O 1IIyI). 


01 roc. BUill: EPN4S2111.o2-OO1. Section 4,2•...,C\IEC<ltI 001.......... 0120'11. 


?O.O'\:. COIlIIaltl'llwlD\' tormrolilprejeet. 
 

lotal Capital COils 


T0Ia! ClplteiItllte$ImenI 


101a! C8p!IaIJ_(Slt.W-nel1 


CIpItei FIIClO" ~1+ I)': (1 +If'. I fOlI'OI~~1 no ..--...,... 1111"""""",___ Anmallucl Caplllll CoalS 

OPERATIH 

OpereUnll , M.I~_nCOl COila (DIlled on 90% capaCIty tectotl 

Vari.bIe elM COSI. 8...., an ......mum ..... input. NO>< __.... _~_NHUf2 .lIII001 

__~1.02. AllVllorQ 11Ij_ Rate \Iblhrl 
 i 400 SUed .........__. CIIPICiIl' ___, _ S<IOMon 'IIIQIIflCllll1.
 Atnmt:InII Rul!l"l Cos! 

6upp1emenlaly Hut (f.oheilitue gas) e e .. ,., an "".'1n!M \0 .... gao ..·hM"" """ I.... COOl fiI 581"",,11111 lor ..."'.. vu. a_an eihaust gIIS _ ,.... _ .......k1g ali!>llQlyll<lClly 01 !.liDO IIIIt lOt • 


C"IV_(lI31 !>,eoo-SCR. 


CateiyaI Replactment CO$I 250 __011 cOS! 01 ~13"'" ClIOIySIIle 01 4 ,.11<\. 
 

B_CWllr ........ tlrop_.1no8al.O.0IIS_~_ 

4S ....._ ann45/MW1l i

t 

f 

t 

Fl.'" OIM Co... 


ACId~ Ope.alon; .,.., IIIHI _Gtl.L06M_IOt$Cfl_III'~' 

_ 

~1IIIII'lIII1.-~. .._IIIItyGl~. S3UOoItourI~' _I-.lItqo/11lO.... 
 I

,

f I&.O'JI,"~IIIIIW. ~ClWtllWI.IIIIII"" 

1.s'11. CU£CoII~'~'_.ICRI'''''''IIII1IIIItGCOS1l. IQ,O'JI, 0I~___1S&l06Y.._), 

1% III"'~ ___• OAaPSClWtllWI,1IIIII241!. 

I 

r It. 111_-" OAQP&ChIpIIr 1.1IIIII1I4Il. 

2% O!_CfIIhI~ 0A0PS~1I. '.S!. 

TOIII Annual COSI t 

TOTAL ANNUAL COST 

Amuall:Md Capltll COli 

Coli 

Page B·8 
Montana·Dakota Ulilitie.!. 

Hcskell Unit 2 - BART DClerminalion 

May 30, 2006 DRAFT 

BART Economic E,'siuation - SOl 

Limestone with Dry FGD Control System 

Coal 

CAPfTAL COSTS lSI aaaia 

Direct C.pl1lll Coala 

Llme$lOll. Intect~ 10 CFB $2.800.000 

RtllilO"' fff<! S.)'l<Itm S5.986.ooo SO~R"""""'S,....,.. $1.725.00< Beaac go U.s.EPA.. CueeOSI WOIb/IeelS &ftd equlpmtnl COJI.~ pntpartCI SpruyDr)or.. $7.738.00< by S&~ Ie< _.,J!IOIICI$. Inc_!he CO:" 01 "'*' CO/IIpanen!S and ..... _ Po.... '''''' H:mlirl~ $)....... $2,155.00< 
 onsllll1allon co&Il ........s 10UIlllaIkWIs. mechank:al _Uon. eleCllleal. gipIng. Ina
 IOF_ 5827.00< insoIMIon.1ct 1M 6w. _lion _lSI. nICYCIe _ '-4nlhfIN...... 

W_/B~""I H.tndIlJlf S,....", $1.664,00< '*fIMnO. lime ba/1cIIII9. Ind aailOs MndIinO 5\1_ 

SuJ'Pt"' Eq.dj!mCnI SU·8.1lOC 

('h""".Y M,"'il\"",;'... 53.994.0()( 

II1!CIU<ied '!2 ... ICIW CIIQiIIIl cosl"" Ihe IIIbnt !lIe. beC...se !he dty FGO c_ 1Yt- _ Dol'-" by patlil!Ui1l1e conlrot. and n IS 1101 ~1I!y poss.IIJIIt 10 

1ocIIt. IN: dty FOD comroi a",..... _1IIIt bciIer III1dIM e..1inp ESP Fobnt FiIIilf.R.It"'.... S4.948.6OC 

101lJ1 PlJfChasetJ £qtHpmenl Cosl (PEe) $34 .085.6OC 

Indirect Capital COtIta 

Engineering $3.409.0OC 10,0% QlPEC Sootte:OAOPSM.!nuaICnap,erS. TallIt U.PIlQfl.27. 

Conslructlon and F'oeId E~ S3.409.00c 10,~ 01 PEe. $ou",.:OAOPS MaIIu.lChapte! 5. r_l.3. pagw 1·21. 

Contractot Fe~ S3A09.00c 10,0% 01 PEC. so.m:.: OAOPS. MI\...11 Cnapler5. Table U. PIlQf 1·27. 

Sian-Up $34I.00c 1.0% '" PEC. Sou",.: OAOPS Manuel Ch8Qltt. 5. T_ 1.3, PIll't 1-27. 

PertOlt1'\llllC(llesl$ $34I.00c 1.0% 01 PEC. Swu, OAQPS MlllUfI/ ChopiOf ~; T_ 1.3. _ 1-21 

S $1.023.00c 3.0% 01 PEe. Sou",« OAOPS Ma_ ChapIe> 5. T_ 1.3, PIlOt 1·27. 

101M Indirect Ct/pI(/1 Co.;sIS (IC) Sl',932,OOC 

TOlal Capital Coals 

lCllal Capilallnvestment $46,017 ,600 

TOIa! Caphallnvestmenl (Si1<W""etl SS8Il 

CapHaiRecovetVFadOt~~I+I)'·Jll.i)".' 0.0944 20 Y"'''. 

Annualized Capital Coala prelU ma1gin&f rele or retvrn .:)n pfNBIf in¥esunenl. InteteS' rill! uHd in OAOPS 

fCapltel Recover Factor. TOI8' Cepltalin_tment, 54,344,OOC 7", Ma.-(Cho,..o,2_ 2·1~~ 

. OPERATING COSTS BasiS 

()penollng & Malntenarice Coetll!b .. aed on 90'11. caPllClly 'Aclor) 

Variable O&M COII5 

6••.., or. "'........, .0" """,I. 802 "",,OVal rat. (1bIh.,. '.06 .'OicIliomolry,!IO'!oo 

Lime Reagent Cost SOO.IOC S 75 CaO. and reoctenl (OIl 01 $ 75110n lor ,,,". 

Wilier Cos! $28.5OC $ I Bea.., OIl 0.15 jll:lnllMWlI""'", $111000 gal 

6a$ec1 .......xim.... hea, input. S02 rem<>rIlI/8le (lb/II,). _ SSIlO~ """Ie 1:0$1. OispoHIcoat inc_lime .., ___~I... by. 

FOO WlI$te Disposal Cost $48.90( $ 5 ptOQIcII, !lUI "'" "",,uoe II)< ash. 

Autdllary Power Cost S313.3OC S 45 Bea.., en .....1181'): -..~menl 011 10'lir (nell and 'fSIMW. 

TOUII Vatfab.le 0&1.4 COS/$ $450.6OC 

Fixed O&M Coale 

ACKlitlonal QperatOl$ pel Sh't 0.75 6est(! 01\ 5&L O&M Hllmaillor dry FGO. 

3 .hiUS/dey, 36S caysJye., e $33.!iOIhou1 (Hlel')' + oene/'Il\ _h 11 equa; 10.' 

Operaling Labor $220.100 ........ _0101 181<1ty 01 570.OOOIrea', 

SUpeNi&Ot Labat $33.00c 1$,0% 01 cperaling labOr. OAOPS Chapter 2. pagw HlI. 

Mainlenance Materials. S1.704.3011 6.0% CUECosIMoitl_e Default Fec\or lor Itr>e $_ Orwet. 

Malmenance LabOf 51.022.600 00.0% 01 m""'_ m__COSI (SAL O&M esu"'lII&). 

T0UIi FIXed 0&1,1 Cost S2.980.00c 

Indf,.ct Operating Cost 

Property Tu. S400.00c 1% '" Io1aI cellilall'....t"' .... t OAOPS CtlaIl\lll2, _ 2·3:. 

tnsUlllllC8 $480,000 1% 0110l1li cepIIaIlt....tmeni. OAOPS CIlepIet 2. PIll't 2<:12. 

AdminiStration S920.00c ~,. Q/ to2' capilli! investment. OIIOPS Cllapter 2. page 2·32. 

TOUIi Indired Operl/Iing Cost $1.840.00c 

Total AMUIII ODer.ting COli SS,270.8OCl 

TOTAL ANNUAL COST 

AIInuali1ed capltat Coat $4,344.000 

AIInual Oper.tlng Coat SS.270.8Oll 

T 0l.1 AMUIII Coal $9614110Cl 

Page B·II 
Montana-Dakota Utitities 

Heskett Unit 2- BART Delermination 

May 30. 2006 	 DRAFT 

BART Economic Evaluation - SOl 

. -Net FGD Details 

COJI 


CAPITAL COSTS 1$1 
 Ba8Ia 

10111 PuR:hat<ed Equipllltni Co.IIPF.CI S6Ut3.3Gl . 

G_raI htililielo s&.&9t.3:U 

ElIIlnettlll& "- $6.691,3:U 	 TOUIICIIPIII ______IIIUSEPA-aCl.eCcelW---._ 

C~" St3.tll2.6n _ ... IO ........._._~DrS&l.IOI ~_pRljICIL 

TOIlIII'I..CIm 512,278.701 DinId ___.. ..COlIC .. map-COIIIfIO!**._IIIIy~_ 

......,-._ ..IICfIatIt:II-*>n 10' IlleFGO IOS(IItIer I~. r~ 

P'lllPI. iMIuC... 01IltIlnS. - ...... ima_handono· -......_ Total PIanI CoSI 111'C) ...1Prime ComrAClor'~ Markup S96.047.e6! 

101l11Osh~ITCEl '112.30$.581 ....1IaIIding ...... All"",. ra" l"1IIld!I DIiiq Con.w. IAFDCl $10.120,91 

TOIal Plant In..:_nUTPI) $ UXt.0426,4IH 


Preprodu.:lioo CO>lI> 53,747.141 


In_orvCaol!al $330,'11 


r",.1 c..,iltJl R«/I11,.,.,WI ITeR} $100,505,00( 


1."", OIpinilln~.oenl (S.\W • ~I) $20 


30_. 


A"nUIIllud Capllal Cosu 


Capkal ~...,. FlII'IOI" =II 1+ itIII + I)' • I 0.0806 

",eta>< mtrfnOlllll6 d "u. an pm.", _Ime... _UI roll ,_.,OAOPS 

lC.pllal. R«o"f' r..,lor, TOI.I (:IIpll.lln'·<!$I"",,,1I S8,S82,lIOe 7'!io ~1I!I1~lttlll/02·'S~ 

OPERA ING. COSTS II...

OpeIttIng I Ualntenlnca Co... Cb.uIGO 0II1IO'rt capacity 'actor) 

Variable O&M C~.I_ 

11...4 an m.,.;mum '-inpuI. S02 ......,... '.... '_1. 1.00.lul:h........,.._ 

LlIIKISI_ Augenl Cos. $620.10( $ 30 ca<:q3. -caoadIY _.,.,., _'OI_one. 


W_COSt 5270.20( 
 1IU"" ... ,.ogpmlJolW·gr_. _ClllllfCllr*..... and'''tooogoJ 1Iued ... _ ........... 502._,_,_1. __cftyIKIOI. 


___to'lloIi'y.an4.'_ ..... lf......... _. ~"_t""" 

.n;Iudes_WFGO """'_"""_""'_.,. un .. CPII FOO Waste Ois__ Cosl $344.0011 $ 'O......-~ _on._"'__-e.."'U",!ttO\l._(~,_._ 

-- AulcIlary PcMer COSt $l.an.4OC S 30 $3OI.IotW. 


TtJla/ Va....1»e 0&61 COS/$ So4.611,7O( 


Fixed O&M Costa 

()peJalOI'II pet sllifl 3.V 	 eo....... S&I. O&M _euo '''' _ FGO. ,sN!tsIda,. 386 0 m.-......., • benelbl w/IIeI1 .. _110 ... __'101' _1liiy 01 SlO.00<Vyei,. ~J.abol $880.40( 

Supervosot UIbo< 	 $132,IOC I Ul'llo 0I_4dIng 1IboI. OAQPS CttepIor 2.... 2-20. 

MaI_ MaIeIIaIs 	 $3.29$.70( 5.1l'IIo CUECoIt __00IauII f_1O' ~"'....... ac..- with ""OGd_
 6O.0'l. d m~__II _ (S&L 0&111 .._.,. Maltttenanct LlbCt 	 $1.977.40< 

T_F'ur~dO&MCo$l 56.211UOt 

1l1(li_1 Operallng COlt 


PlopettyT_ $659,10( 
 1'10 dIClalUjlhl ....... _ OAOPSCItopItft."o-t·3:/. 

$659.10( l'Ji.oI_',,*,",&I ...u_ OAOPSa.,...'.pegeH2. 

AominialtIIIioIl 

...."'-	 S1.318.3O( 2'110 olIOI'll C4...... IIWet_ OAOI'S CItaIItet t. DIM '.32­

TOU/I_ Opf/tlltin(l COSI 	 ~.63Uo( 

TOIII AmuII·ODetatIncr Coal 	 51UaUCII 

TOTAl. ANNUAl. COST 

AMwIlH c.pa.J COlI 

........... o-.tina COlt ,,1':::::: 

TOIII AnIlUll COlI I2a 111..7lII 

Page B-B 
North Dakota 


Department ofHealth 


CUECOST Model Spreadsheets 


(Verification Only) 

) 

I 

CUECost - Air Pollution Control Systems Economics Spreadsheet ! 

I 

APC Technology Choices 

Description Units Input 1 

FGDProcess Integer 1 

(1 - LSFO, 2 - LSD) 

Particulate Cootrol Integer 2 

(1- Fabric FDter.2 ­ FSP) 

NOxControl Integer '1 

• (l .. SCR, 2 .. SNCR, 3 == !NBs, 4 .. NOR) 

INPUTS 

DescriptioD UIIItI Input 1 

uts 

Location- Slate Abbrev. ND 

MW Equivalent ofFlue Gas to Control System MW 78 

Net Plant Heat Rate BtulkWhr 10,500 

Plant Capacity Factor % 90% 

Total Air Downstream ofEconomizet % 120% 

Air Heater Leakage % 12% 

Air Heater Outlet Gas Temperature OF 300 

lnIetAirTe OF 80 

Ambient Absolute Pressure In.olHa 29.4 

Pressure After Air Heater In. of H2O -12 

Moisture in Air IbIlb dry air 0.013 

Ash Split: 

. F1yAsh % 80%" 

BottomAsb % 20% 

Seismic Zone Integer l' 

Retrofit Factor . Integer 1.3 

(1.0" Dew, 1.3 -.medium, 1.6== difficult) 

SelectCoaI Integer . 7 

Is Se1eeted Coal. Powder River Basin Coal? Yes/No No 

Economic In1!.uts 

m-_.y"'Do"'" .. Year 1998 • I..ife (leveLization period) Years 30 

tion Rate % 3% 

After Tax Discount Rate (curient 5'1) % 9% 

AFDC Rate (current $'1) % 11% 

First-year Carrying Charge (cqmmt $'I) % I 22% 

Levelized C e (current S's) % 17% 

YlrSt-year Carrying Cbarxe (constant $'I) % 16% 

Levelized Carrying Charge (constant S's) % 12% 

Sales Tax % 6% 

&ca1ation Rates: 

Consumables (O&M) % 3% 

Capital Costs: 

Is Chem. EtIa. Coat IndeJt available? I Yes/No Yes 

If"Yos" input cost basis CE Plant Index. Integer 388 

If"No· input escalation rate. % 3% 

Construction Labor Rate SIhr S35 

Prime Contractor's Markup % 3% 

1000rating Labor Rate SIhr $30 

Power Cost MillsIk 25 

Steam Cost $11000 Ibs 3.5 

Limestone Fol'CItd Oxldtltloll fLSFO) IllDuts 

S02 Removal Required 

.~ 95% 

lJORatio act 125 

Design Scrubber with Dibasic Acid ... 2 

(I-YC5,2-DO) 

Heskett Unit 2. InpUf «. Calculation Summary 1 

Input Z 

2 

1 

2 

IDput2 

ND 

78 

10,500 

90% 

120% 

12% 

300 I 

80 

29.4 

-12 

0:013 

80% 

20% 

I 

1.3 

7 

No 

1998 

30 

3% 

9% 

11% 

22% 

17% 

16% 

12% 

6% 

3% 

Yes 

388 

3% 

S35 

3% 

530 

25 

3.5 

95% 

125 

I 

Input 3 Input 4 inputS 

0 0 0 

0 0 0 

0 0 0 

laput3 InpIlt4 InputS 

0 0 0 

0 0 0 

0 0 0 

0% 0% 0% 

0% 0% 0% 

0% 0% Q% 

0 0 0 

0 0 (j 

0 0 0 

0 0 0 

0 0 0 

0% 0% 0% 

0% 0% 0% 

0 0 0 

0 0 0 

0 0 0 

0 0 0 

0 0 0 

0 O. 0 

0% 0% 0% 

0% 0% 0% 

0% 0% 0% 

0% 0% 0% 

0% 0% 0% 

0% C/% 0%. 

0% 0% 0% 

0% 0% 0% 

0% 0% 0% 

0 0 0 

0 0 

0% =Fi 0% 

$0 $0 $0 

0% 0% 0% 

$0 $0 $0 

O· 0 .0 

0 0 0 

0% +=F 0% 

0 0 

0 0 

I 

l 

3/4/2010, 10:40 AM t 

t 
,CUECost . Air Pollution Control Systems Economics Spreadsheet 

Adiabatic Saturation T: Of 127 127 0 0 0 

Reagent Feed Ratio ~tor 1.05 1.05 0 0 0 

(Mole CaC031 Mole SOl removed) 

Scrubber Slurry Solids Concentration Wt%' 15% 15% 0"10 0% 0% 

Stacking, landfill, WaUboard Integer I I 0 . , 0 0 

(I .. stacking, 2 .. lautill, 3 - waUboanl) 

Number ofAbsorbers ' Integer I I 0 0 0 

(Max. Capacity '"' 700 MW per iabsoroer) 

. Absorber Material Integer I 1 0 0 0 

(1 =alloy, 2 .. RLCS) 

== 

Absorber Pressure Drop in. H2O I 6 6 0 0 0 

Reheat Required ? Jntcger I 1 0 0 0 

(l-yes,2-uo) , 

Amount ofReheat . OF 25 2S 0 0 '0 

. IReagent Bulk Storage Days 60 60 0 '0 0 

IReagent Cost (delivered) Sfton SIS $IS SO $0 SO 

laudftD Disposal Cost Sfton . $30 $30 ' SO $0 SO 

Stac.king Disposal Cost $/ton S6 $6 $0 $0 $0 

Cn:dit for Gypsum Byproduct $!ton S2 $2 $0 $0 $0 

Maintenance Factors by Area (% of lustaIled Cost) 

RcagentFeed % 5% 5% 0% 0% 0% 

S02 Removal % 5% S% 0% 0"10 0% 

~Handlin&. % 1=5% S% 0% . 0% 0"10 

I Byproduct % S% S% 0% 0% . 0% 

Support Equipment % S% 5% 0% 0%' 0% 

Contingency by Area (% ofJnstalled Cost) 

Reagent Feed %. 20% 20% 0% 0% 0% 

S02Removai % 20%. 20% 0"10 

+= 

0% 0% 

Flue Gas Handling ,% 20% 20% 0% 0% 0% 

Waste I Byproduct % 20% 20"10 0% 0% 0% 

Support Equipment % 20% 20% 0% 0% 0% 

General Facilities ~Area (% ofJnstalled Cost 

Reagent Feed % '= 10% 10% 0% 0% 0% 

, S02 Removal % 10% 10% 0% 0% 0% 

Flue Gas Handlinll % 10% 10% 0% 0% 0% 

Waste I Byproduct % 10% 10% 0% 0% 0% 

~ment % 10% )0% 0% 0% 0% 

by Area. (% oflustalled Cost 

Reagent Feed . % 10% I 10% 

=R% 

0% 0% 

S02 RemovaL % 10% 10"10 % 0% 0% 

Flue Gas Handling % 10% 10% 0% 0% 0% 

Waste I Byproduct % 10% . 10% 0% 0% 0% 

Support Equipment % 10% 10% 0% 0% 0% 

Lime Sl!.rar. D!l.er fLSDl InDUIs 

SOl Removal Required % 90% 90% 0% 0% 0% 

Adiabatic Saturation Temperature. OF 127 127 0 0 '0 

Flue Gas Approach to Saturation Of 20 20 0 0 0 

Spray Dryer Outlet T OF 147 147 0 0 0 

IReagent Feed Ratio Factor 1.02 1.02 0.00 0.00 0.00 

(Mole CaO I Mole IDIet S02) 

Recycle Rate Factor. , 8.2S S.2S 0 . 0 0 

fib recycle lib lime feed) 

Recyele Slurry Solids Coocentratlon Wt% 35% 35% 0% 0% 0% 

Number ofAbsorbers . Integer 2 2 0 0 0 

(Max. Capacity .. 300 MW per "P"'Y W"",, 

Absorber Material Integer 1 1 0 0 0 

(I .. aOoy, 2 - RLCS) 

in. H2O 5 5 0 0 0

iB'~S"- . 

Daj'll .t= 60 I 60 0 0 0 

ent Cost (delivered) $/ton . S6S I· S6S $0 SO SO 

Waste Disposal Cost Sfton S30. $30 SO $0 SO 

Maintenance Factors by Area (% ofJnstaDcd Cost) 

Reagent Feed % 5% S% 0% 0"10 

=+ 

0% 

. SOl Removal % S% S% 0% 0% 0% 

Flue Gas Handling % S% 5% 0% 0% 0% 

uct % S% 5% 0% 0% 0% . 

Support Equipment % S% 5% 0% 0% 0% 

Contingency by Area (% oflnstaUed Cost) 

Hesken Unit 2. (nput " Calculation Summary 2 3/4/2010. 10;40 AM 
CUECost -Air Pollution Control Systems Economics Spreadsheet 

Reagent Feed % 20% 20% 00'(' 

. S02 Removal % 20% 20% 0% 

Flue Gas Handling % 20% 20% 0% 

Waste / Byproduct % 20% 200,(, 0% 

Support Equipment % 20% 200,(, 0% 

Genaal Facilities by Area Of, oflDstalled Cost 

Reaaent Feed .% 10% 10% 0% 

S02Removal % Im=HO% 0% 

Flue Gas Handling % 10~ 10% 0% 

Waste / Byproduct % 10% 0% 0% 

Support t % % 10% 0% 

Fees by Area {% oflDslal1ed Cost 

Reagent Feed % 10% 10% 0% 

S02Removai % 10% 10% 00,(, 

Flue Gas Handliog % 10% 10% 0% 

Waste / Byproduct % 100,(, 10% 0% 

Support t % 10% 10% 0% 

l!llrliculate Conlrfl.llnl!.uts 

Outlet Particlllate EmIssIon Limit IbsIMMBtu 0.015 O. 0 

Fabric Filter: 

.Pressure ProP ill. H2O 6 6 0 

~ 2-Pube!Lj ~ 2 2 0 

-to-Cioth Ratio I ACFMlttl 35 3.5 0 

Bag Material (ROFF fiberglass only) Integer 2 2 0 

. (I - Fiberglass, 2 .. Nomex, 3 = Ryton) 

. Bag Diameter inches 6 6 0 

Bag Length .feet 20 20==t: 0 

Bag Reacb 3 3 0 

Compartments out ofServfce % 10% 10% 0% 

BagUCe Years 5 5 0 

Maintenance (% ofinstalled cost) % S% 5% 0% 

Contingency (% ofinstalled cost) % 20% 20% 0% 

. Oenaal Facilities ('Yo ofinstalled cost) % 10% 10% 0% 

Engineering Fees (% ofinstalled cost) % 10% 10% 0% 

ESP: 

Slrengtb of the electric field in the ESP .. E leV/em 10.0 10.0 0.0 

Plate Spacing in. 12 12 o· 

Plate Heigllt ft. 36 36 0 

Pressure Dro,!) iIl.~0=t==k 3 0 

Maintenance (% ofinstalled cost) 5% 00,(, 

Contingency (% ofinstalled cost) % 20% ·20% 0% 

Oeneral Facilities (% ofinstalled cost) % 10% 10% 0% 

Engineering Fees (% ofinstalled cost) % 10% 10% 0% 

NOx Control Inl!.ut!J 

ISelective Catalvdc Reduction {Scm. 

NH3JNOX Stoichiometric Ratio NH3JNOX 0.9 0.9 0 

NOX Reduction Efficiency Fraction 0.80 0.80 0.00 

InlctNOx lbaIMMBtu 0.36 0.36 0 

Space Velocity (Calculated ifzero) Ilhr 0 0 0 

OveraIJ Catalyst Life )'em 3 3 0 

Ammonia Cost Slton· 205.66 205.66 0 

CaIaly.st Cost SIft3 356.34 356.34 0 

Solid Waste Disposal Cost Slton 11,48 11.48 0 

Maintenance (% ofinstalled cost) % 15% I.S% 0.0% 

Contingency (% ofiDstalled cost) % 20% 

General Facilities (% ofinstalled cost) 50/0 20%=K I 5% 

Engineering Fees (% ofinstalled cost) % 1'0% 10% . 0% 

Number ofReactors . mteger 2 2 0 

Number ofAir Preheaters integer 1 1 0 

ISdledve NonCatlllvtk RUllctiDn (SNCRJ IlUJuls 

iaaeut I:Urea 2:AmmioDia 1 1 0 

Numberofmi~tor~b integer 3 3 0 

wci 0% 

0% 0% 

0% 0% 

0% 0% 

0% 00'(' 

0% . 0% . 

0% 0% 

0% 00/. 

0% 00'(' 

0% 0% 

0% 0% 

0% 00'(' 

0% 0% 

0% 00,(, 

0% 0% 

0 0 

0 0 

0 0 

0 0 

0 0 

0 0 

0 0 

0 0 

0% 0% 

0 0 

0% I 0% 

0% I 0% 

0% 0% 

0% 

0.0 0.0 

0 0 

0 0 

0 0 

0% 0% 

0% 0% 

0% 0% 

0% 0% 

0 0 

0.00 0.00 

0 0 

0 0 

0 O· 

0 0 

0 0 

0 0 

0.0% 0 

0% 0% 

0% 0% 

00'(' 0% 

0 0 

0 0 

0 0 

0 0 

I 

1 

t 

f 

Heskett Unit 2, Input lit Calculation Summary 3 3/4/2010,10:40 AM 
CUECost -AIr Pollution Control Systems Economics Spreadsheet 

Number 

NumberofLaace 

ofInjectors 

Levels 

integer 

integer 

18 

0 

18 

0 

0 

0 Q. 

0 Y.

Number ofLances inlqcr '0 0 0 0 o -

Steam or Air Injection for Ammonia integer I I 0 0 0 

NOX Reduction Efficiency Fraction 0.40 0.40 0.00 0.00 0.00 

InletNOx Elf 0.36 0.36 0 0 0 

NH3INOX Stoicbiomclric Ratio OX 

~;. 0 0 0 

Urea/NOX StoicbiomcIric Ratio OX 0 0 0 

Un:aCost SIton . 225 4.95 0 0 0 

Ammouia Cost SIton 205.66 205.66 0 0 O. 

Water Cost $11,000 gal 0.407 0.407 0 0 0 

Maintenance (% ofinstalled cost) % 1.5% 1.5% I 0.0% 0.0% 

eon.;.........,; \,.ofiustaJlcdcost). % 20% 0% 0% 0% 

0cDaal Facilities (% ofiastaIleCl cost) % 5% .5% 0% 0% 0% 

Fees (% ofiDilalled cost) % .10% 10% 0% 0% I 0% 

Low NOXB_TecllMion llUJua 

NOX Reduction Efficiency fraction 0.35 0.35 . 0.35 0.35 0,35 

BoilerTypc T:T-fired. W:Wall T T T T T 

L:I.ow. A:Average. . 

Retrofit Difficulty H:High. A A A A A 

Maintenance Labor r" ofiDstalIed cost) % 0.8% 0.8% 0.8% 0.8% 0.8% 

Maintenance Materials (%ofinstalled cost) % I.2Y. 1.2% 1.2% 1.2% 1.2% 

Natural fiB. Rebumln,l'1.l!l!Js. 

NOX Reduction Efficiency &action 0.61 0.61 0.61 0.61 0.61 

OM Rebum Fraction &:action 0.15. 0.15 0.15 O.IS 0.15 

Waste Disposal Cost $lton 11.48 11.48 . H,4s .1 1.48 11.48 

Natural OM Cost $/MMBtu 2.31 2.31 2.31 2.31 2.31 

Maintenance (% ofiDsllllled cost) % ==¥P.=t 1.5% 1.5% 1.5% l.S% 

Contingency (% ofinstalled cost) % 20% 20% 20% 20% 

General Facilities (% ofinsIalled Cost) -% 2% 2% 2% 2% 

Engineering Fees(% ofinstalled cost) . % 10% 10% 10% 10% 

I 

I 

Heskett Unit 2. Input'" Calculation Summary 4 3/4/2010.10:40 AM 
C~Cost •Aft Pollution Control Systems Economics Spreadsheet 

. SUMMARY OF COSTS I 

Description Units In~tl 

APe Technolot!1a 

NOx Control- SCR 

Particulate Control ESP 

SOl Control LSFO 

INOx Co1tl1'o1 Costs SCR 

Total Capital Requirement (TeR) S $10,027,752 

SlkW $128.6 

FIrst Year Costs 

FladO&M $ $174,883 

SlkW·Yr 2.24 

MilJ&lkWH 0.28 

$/ton NOx removed $152 

Yarlabil O&M $ $617062 

SlkW·Yr 7.91 

MillslkWH 1.00 

$/ton NOx removed $537 

Fixed CluJrgu $ $2,236,189 

SlkW·Yr 28.67 

MillslkWH 3.64 

$/ton NOx removed SI,945 

TOTAL $ S3 028133 

SlkW-Yr 38.8-2 

MillslkWH 4.92 

S/ton NOx removed $2634 

Level.lzed Current DoUan 

FixedO&M SlkW·Yr 3.0S -

MillslkWH 0.39 

$ItonNOitremoved $207 

Yariable O&M SlkW-Yr 10.n 

MilJ&lkWH 1.37 

$!ton NOx removed $730 

Fixed Chargu - S/kW·Yr 21.73 , MillslkWH 2.76 

$!ton NOx removed 51,474 

TOTAL SlkW-Yr 35.54 

MillslkWH 4.51 

$/ton NOx removed $2,411 

Levelhed Constant Donars 

FixedO&M S/kW-Yr 2.24 

MillslkWH 0.28 

$/tonNOxremoved S1S2 

Variable O&M S/kW-Yr 7.91 

MillslkWH 1.00 

$/ton NOx removed. $537 

FlxiI4 Cluugu S/kW-Yr 15.04 

MiIlsIkWH 2.71 

$/ton NOx removed $1,449 

TOTAL SlkW-Yr 25.19 

MilJ&lkWH 4.00 

$/ton NOx remQved . $2 138 

l.articul4U c.tJ{Jtroi Cert.! ESP 

rotal Capital RequirwentffCRl $ $896~,187 

SlkW SIIS 

First Year Costs 

FludO&M $ S3I6,128 

S/kW-Yr 4.0S 

MillslkWH 0.51 

$/ton PM removed SIS.0 

Variable O&M $ $46,923 

S/kW-Yr 0.60 

MiIlsIkWH 0.08 

$/ton PM removed $2.2 

lnputZ Input 3 

SNCR NOR 

PIFF PJFF 

LSD LSD 

SNCR NOR 

$1,553,228 fIN/A 

S19.9 IIN/A 

$87,020 lIN/A 

-1.12­ IINIA 

0.14 IINIA 

S151 IINIA 

$209,602 $0 

2.69 tlOIVIO! 

0.34 #OIVto! 

$365 #OIVtol 

S346,370 fIN/A 

4.44 IINIA 

0.56 fIN/A 

$603 flN/A 

S642992 tlN/A 

8.24 fIN/A 

'1.05 IINIA 

$1 118 IINIA 

l.S2 lIN/A 

0.19 lIN/A 

$206 IINIA 

3.66 #OIVto! 

0.46 . #OIV/O! 

S496 ·tlOIVIO! 

3.37 lIN/A 

0.43 IINIA . 

$457 fIN/A 

8.54 fIN/A 

1.08 IINfA . $1,159 tINIA 

1.12 #N/A 

0.14 fIN/A 

S151 flN/A 

2.69 tlOIV/O! 

0.34 tlOIVlO1 

$365 #OIV/O! 

. 2.33 fIN/A 

0.42 tINIA 

$449 fIN/A 

6.13 tINIA 

0.90 tINIA 

$965 tINIA 

PIFF PJFF 

S9,87SJ'1 tlOIV/O! 

$127 NOIV/OI 

$348J.34 i#OIVIOI 

4.47 tlOIV/O! 

0.57 i#OIVIO! 

$3.8 1#DIVtol 

$23~002 . i#OIVIO! 

2.99 tlOIVIO! 

0.38 #OIVIOI 

$2.5 1#DIV/o! 

Input 4 

NOR 

PJFF 

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NOR 

fINIA 

fINIA 

fINIA 

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tINIA 

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#OIVIOI 

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#OIVIOI 

fINIA 

fINIA 

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fINIA 

fIN/A 

tINIA 

fINIA 

fINIA 

#OIVIO! 

tlOIVIO! 

1I0IV/01 

fINIA 

fIN/A 

fIN/A 

fIN/A 

fIN/A 

fIN/A 

fINIA 

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tlOIVIO! 

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fINIA 

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tloIVIO! 

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Input 5 

NOR 

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LSD 

NOR 

lIN/A 

fINIA 

fIN/A 

IINIA 

IINIA 

tINIA 

SO -

#OIVtol 

tlOIVto! 

tlOIV/OI 

flN/A 

fINIA 

IINIA 

fINIA 

flN/A 

IINIA 

IIN/A 

fIN/A 

IINIA 

IINIA 

tiN/A 

tlOIVIO! 

tlDIVto! 

#OIVIO! 

IINIA 

lIN/A 

fIN/A 

#NIA 

IINIA 

. tlNlA' .. 

#N/A 

flN/A 

tINIA 

#OIVIO! 

tlOIVIO! 

. #OlVtol 

tINIA 

tINIA 

tINIA 

tINIA 

tINIA 

tINIA 

PJFF 

tlOIV/O! 

tlOIVIO! 

NOIV/O! 

tlOIVIO! 

tlDIVIO! 

tlDIV101 

tlDIV/OI 

tlDIVIO! 

#OIVto! 

#OIVIO! 

f 

I 

I 

I 

CUECOST3, Inpul & Calculation Summary 2/8/2010,9:58 AM 

i 
CUECost - Air Pollution Control Systems Economics Spreadsheet 

Fixed Charges 

TOTAL 

Levellzed CurreDt DoUan 

FixedOcIM 

Variable O&M . 

Fixed CIuzrgu 

TOTAL 

Levellzed Conrtant DoUan 

FludOcIM 

Variable O&M 

Fixed Charges 

TOTAL 

S02 Control Costs . 

Total Capital Requirement (TCR) 

Flrrt Year Carts 

FludOcIM 

Variable OcIM , 

Flud Charges 

.. 

TOTAL 

Levellzed CurreDt DoUan 

FludOcIM 

Variable O&M 

Fixed Charges 

TOTAL 

Levellzed Connant Dollan 

FiudOcIM 

$ $1,998,568 

$/1cW-Yr 25.62 

MilWkWH 3.2S 

S/ton PM removed $9S.0 

S S2,361,619 

SIkW-Yr 30.28 

MillsIkWH 3.84 

$/ton PM removed $112.2 

SlkW-Yr S.S2 

MillsIkWH 0.70 

Slton PM removed $20.4 

$IkW-Yr 0.82 

MilWkWH 0.10 

Slton PM removed $3.0 

$/1cW-Yr 19.42 

MilIsIkWH 2.46 

.. $Iton PM removed $72.0 

SlkW-Yr 2S.7S 

MilWkWH 3.27 

$/ton PM removed $9S.4 

$/kW-Yr· 4.0S 

MilWkWH O.SI 

Slton PM removed $IS.0 

SlkW-Yr 0.60 

MillslkWH 0.08 

Slton PM removed S2.2 

SlkW-Yr 13.44 

MillslkWH 2.42 

S/ton PM removed $70.8 

SlkW-Yr 18.10 

MillsIkWH 3.01 

Slton PM removed S88.0 

LSFO 

$ $48,800,638 

$IkW S626 

S $2,691,290 

$IkW-Yr 34.S0 

MilWkWH 4.38 

S/tOn S02 removed S3S0.4 

$ S903,322 

SIkW-Yr 1l.S8 

MilWkWH 1.47 

Slton S02 removed S117.6 

S S10,882,S42 

$IkW-Yr 139.S2 

MilWkWH 17.70 

Slton S02 removed $1,416.9 

$ $14,477,IS4 

$IkW-Yr 18S.60 

MillsIkWH 23.S4 

Slton S02 removed $1,88S 

SlkW-Yr 46.9S 

MillslkWH S.96 

Slton S02 removed $476.8 

$IkW-Yr IS.76 

. MillsIkWH 2.00 

Slton S02 removed $160.1 

$IkW-Yr 10S.73 

Mills/kWH 13.41 

$/ton S02 removed SI,073.8 

SIkW-Yr 168.4S 

MillsIkWH 21.37 

Slton S02 removed SI,71O.7 

SIkW-Yr 34.50 

$2,202,176 

28.23 

3.S8 

$23.8 

S2,783,SI2 

3S.69 

4.S3 

$30.1 

6.08 

0.77 

$S.I 

4.07 

0.S2 

$3.4 

21.40 

2.71 

$18.1 

31.S4 

4.00 

$26.6 

4.47 

0.S7 

$3.8 

2.99 

··0.38 

S2.S 

14.81 

2.67 

$17.8 

22.27 

·3.61 

S24.0 

LSD 

S37,S64,351 

S482 

$2,092,480 

26.83 

3.40 

$287.6 

$1,828,714 

23.4S 

2.97 

.$2S1.3 

S8,376,850 

107.40 

13.62· 

$I,IS 1.3 

$12,298,04S 

JS7.67 

20.00 

$1,690.. 

36.SI 

4.63 

$391.3 

31.90 

4.0S 

$342.0 

81.39 

10.32 

$872.5 

149.80 

19.00 

SI,605.9 

26.83 

fIOIVIO! 

mIV101 

/lDIV/o! 

fIOIVIO! 

#lDIV/o! 

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fIOIV/O! 

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#DIYIO! 

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LSD 

UN/A 

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. /lDIY/O! 

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. #DIV/o! 

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. #lDIV/O! 

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I 

I

• 

f 

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f 

~COST3, Input & Calculation SummaJY 2 2/8/2010,9:58 AM 
CUECost -Air Pollution Control Systems Economics Spreadsheet 

MillslkWH 4.38 .3.40 #NUMI ##NUM! ##NUM! 

$/ton S02 removed $350.4 $287.6 II'I'IUMI ##NUMI ##NUM! 

J'ariable O&M $/kW-Yr (1.58 23.45 IIDIVIO! #DIVIO! #DIVIOI 

MillslkWH 1.47 2.97 IIDIVIOI mlVlO! nDIVIO! 

$/ton SOl removed $111.6 $251.3 #DIVIO! IIDlVlO! nDlVlO! 

Fixd Charges W-Ye" 

MillsIkWH 

73.20 

13.19 

56.35 

(o.tS 

t#NIA 

t#NIA 

fIN/A 

t#NIA 

t#NIA , 

t#NIA 

$Iton SOl removed $1,055.9 S8S8.0 

flNUMI tR= t#NIA t#NIA 

TOTAL .$/kW-Yr 119.l9 106.62 flNUMI 

MillsIkWH 19.03 (6.53 #NUMI f#NUM! flNUM! 

$/ton S02 removed $( 5l4.0 SI.396.9 tlNUMI f#NUM! tlNUMI 

ctlEcosn, Input «. Calculation Summary 3 2/8/2010,9:58 AM 
Appendix A.2.4 


Permit to Construct 

ENVIRONMENTAL HEALTH SECTION 

Gold Seal Center, 918 E. Divide Ave.

NORTH DAKOTA Bismarck, NO 58501-1947 

DEPARTMENT of HEALTH 701.328.5200 (fax) 

www.ndhealth.gov 

July 22, 2010 FILE 

Ms. Abbie Krebsbach 


Environmental Manager 


Montana Dakota Utilities Co. 


400 N Fourth Street 


Bismarck, ND 5850 I 


Re: 	 Heskett Station Unit 2 Limestone Injection Project 

Dear Ms. Krebsbach: 

Enclosed is a Pennit to Construct which establishes sulfur dioxide emission limits for the R.M. Heskett 

Station Unit 2. A public comment period was held regarding the Pennit to Construct and other elements 

of the North Dakota Regional Haze State Implementation Plan Supplement No. 1 from June 10 through 

July 11,2010. The only significant change to the draft Pennit to Construct was a revision of the language 

in the first sentence under Section II, Pennit Conditions. This sentence was revised to indicate that the 

limits are only effective if, and when, EPA approves those limits as part of the North Dakota Regional 

Haze SIP. 	 . 

Please advise the Department within 15 days after completing the project to allow for an inspection by the 

Department. Compliance with the emission limits in the Pennit to Construct must be achieved as 

expeditiously as possible but not later than five years after the Environmental Protection Agency's 

approval ofthose limits as part of the North Dakota Regional Haze SIP . 

. In addition, within 12 months after commencing operation of the new andlor modified equipment, a 

penn it revision application for the project for a significant modification to the Title V Pennit to Operate 

must be submitted to the Department. 

Ifyou have any questions, please contact Tom Bachman of my staffat (701)328-5188. 

Sincerely, 

Terry L. OtClair, P.E. 


Director 


Division ofAir Quality 


TLOIfB:saj 

Ene: 

xc: 	 Gail Fallon, EPA Region 8 


Custer District Health Unit, Mandan, ND 


Environmental Health Division of DMslonof Division of Division of 

Section Chiefs Office Air Quality Municipal Facilities Waste Management Water Quality 

701.328.5150 701.328.5188 701.328.5211 701.328.5166 701.328.5210 

Printed on recycled paper. 
ENVIRONMENTAL HEALTH SECTION 


~~ Gold Seal Center, 918 E. Divide Ave. 
NORTH DAKOTA Bismarck, ND 58501-1947 


~~ DEPARTMENT of HEALTH 701.328.5200 (fax) 


www.ndhealth.gov 

AIR POLLUTION CONTROL 


PERMIT TO CONSTRUCT 


Pursuant to the Air Pollution Control Rules of the State of North Dakota (North Dakota Administrative Code 

Article 33-15, Chapter 3j-15-14 and Chapter 33-15-25), the North Dakota Department of Health hereby grants a 

Pennit to Construct for the following source: 

I. General Information: 

A. Permit to Construct Number: PTCI0028 

B. Source: 

I. Name: R.M. Heskett Station Unit 2 

2. Location: Mandan, North Dakota, Morton County 

3. Source Type: Fossil-fuel fired steam electric unit with a nominal generating capacity of 

916.5 million British thenna! units per hour (106 Btu/hr). 

C. Owner/Operator: 

I. Name: Montana-Dakota Utilities Co. 

2. 	 Address: 400 N Fourth Street 


Bismarck, ND 58501-4092 


II. Permit Conditions: 

This Pennit to Construct establishes sulfur dioxide emission limits for R.M. Heskett Station Unit 2 if, and when, 

EPA approves those limits as part of the North Dakota Regional Haze SIP. While this Pennit to Construct 

authorizes the construction and initial operation of new or modified air pollution control equipment and process 

changes to reduce sulfur dioxide emissions, the pennittee may be required to apply for a Prevention ofSignificant 

Deterioration (PSD) pennit to authorize any significant net emissions increase of particulate matter, PMIO and/or 

PM2.s, that will result from the installation of the new or modified pollution control equipment and the process 

changes. 

Environmental Health Division of Division of Division of Division of 

Section Chiefs Office Air Quality Municipal Facilities Waste Management Water Quality 

701.328.5150 701.328.5188 701.328.5211 701.328.5166 701.328.5210 

Printed on recycled paper. 
Page.£ of2­ PenIrit~o. 10028 

If new emission units are created, a new Permit to Construct may be required in accordance with ~DAC 

33-15-14-02. The source shall be operated in accordance with the terms ofthis Permit to Construct, any required 

PSD permit and the Title V Permit to Operate until a revised Title V Permit to Operate is issued. The source is 

subject to all applicable rules, regulations, and orders now or hereafter in effect of the North Dakota Department 

of Health and to the conditions specified below: 

A. 	 Special Conditions: 

1. 	 Emission Limits: The term "12-month rolling average," as used in this penIrit, shall be 

determined by calculating an arithmetic average ofall operating hourly rates for the current 

month and the previous 11 months. A new 12-month rolling average shall be calculated 

by the 30th day following the end ofeach month. Each 12-month rolling average rate shall 

include start-up, shutdown, emergency and malfunction periods unless those periods are 

exempt by this permit. The 12-month roJling average emission rate is calculated from 

average monthly values as follows: 

If demonstrating compliance with the limit in Condition II.A.l.a( I), calculate the 

S02 removal efficiency for the month as determined by the outlet S02 emissions 

measured by the continuous emissions monitoring system (CEMS) and compare to 

the average sulfur input to the boiler. The average monthly sulfur input to the 

boiler shall be based on the amount of fuel combusted in the boiler and the average 

ofthe coal sulfur concentration samples measured during the month. 

If demonstrating compliance with the limit in Condition II.A.I.a(2), provide the 

outlet S02 emissions as measured and calculated by the CEMS. 

a. 	 The permittee shall not discharge or cause the discharge of sulfur dioxide (S02) 

into the atmosphere from Unit 2 in excess ofeither: 

(l) 	 30.0% of the S02 equivalent reaching the inlet of the boiler (70.0% 

reduction) on a 12-month rolling average basis, or as an alternative; 

(2) 	 0.60 pounds per million British thermal units (lb/106 Btu) on a 12-month 

rolling average basis. 

b. 	 The permittee shall conduct an optimization study to establish the highest sustained 

sulfur (S02) removal efficiency achievable by adding limestone to the bed material, 

taking into account any technical, operational, and reliability considerations, other 

pollutant emissions and environmental impacts, and cost effectiveness. 

(1) 	 Within 180 days of initial start-up of the limestone injection system, the 

penIrittee shall submit a protocol that describes the parameters to be 

monitored/measured during the study and provide a schedule for 

completion of the study and report. 

(2) 	 Upon Department approval of the test protocol and schedule, the 

. optimization study shall 	be completed and a report submitted to the 

Department within the schedule approved in the study protocol. 
Page l ofJ..... 

Pennit No. 10028 

(3) 	 If the study results indicates that sulfur (S02) removal beyond the limits in 

Condition II.A.I.a( I) and ILA.l.a(2) is achievable, after taking into account 

technical feasibility, operational and reliability consideration, other 

pollutant emissions and environmental impacts, and cost effectiveness, the 

pennittee shall apply for a Pennit to Construct to make the new S02 limit 

federally enforceable. The pennittee shall begin complying with the new 

limit as outlined in the new, or amended, Penn it to Construct. 

c. 	 The S02 emission limits apply at all times including startup, shutdown, emergency 

and malfunction. 

2. 	 Compliance Date: Compliance with the emission limits and other requirements of this 

permit is required as expeditiously as practicable but in no event later than five years after 

the U.S. Environmental Protection Agency (EPA) approves this pennit as part of the 

Regional Haze SIP. For purposes of establishing the first month ofthe 12-month rolling 

average limits in Condition ILA.I., the pennittee shall begin monitoring for compliance 

within five years of EPA approval of the SIP, as described above, or within six months 

after initial startup ofthe limestone injection system, whichever is earlier. 

3. 	 Continuous Emission Monitoring System (CEMS): The emissions from Unit 2 (main 

stack) shall be measured by continuous emission monitors (CEM) for S02, C02, and flow. 

The monitoring requirements under Condition n.A.4 shall be the compliance 

determination method for S02. 

4. 	 Monitoring Requirements and Conditions: 

a. 	 Requirements: 

Testing and monitoring protocols used to demonstrate compliance with the 

emission limits of Condition ILA.1 above shall he as follows: 

Table 1 


Monitoring Requirements by PollutantIParameter 


I 

b. 	 Emission Monitoring Conditions: 

(1) The monitoring shall be in accordance with the following applicable 

requirements ofChapter 33-15-06 of the North Dakota Air Pollution t 

! 

! 

,

, 

i 

,I 

! 

PollutantlParameter 

Monitoring 

Requirement (Method) Condition Number 

S02 (inlet) Coal Sampling Data 4.h.(6) 

S02 (outlet) CEMS 4.b.(l), 4.h.(2), 4.b.(3), 4.b.(4) & 

4.b.(6) 

CO2 CEMS 4.b.(I), 4.b.(2), & 4.b.(3) & 4.b.(4) 

Flow Flow Monitor 4.b.(1), 4.b.(2), & 4.h.(3) & 4.b.(4) 
PageA..ofL 

Pennit No. 10028 

Control Rules and the Acid Rain Program. Emissions are calculated using 

40 CFR Part 75. 

(a) 	 Section 33-15-06-04 of the North Dakota Air Pollution Control 

Rules, Monitoring Requirements. 

(b) 	 40 CFR 72 and 40 CFR 75. 

(2) 	 The Department may require additional performance audits ofthe CEMS. 

(3) 	 When a failure of a continuous emission monitoring system occurs, an 

alternative method, acceptable to the Department, for measuring or 

estimating emissions must be undertaken as soon as possible. The 

procedures outlined in 40 CFR 75, Subpart D for substitution are 

considered an acceptable method for the emission rate limit. Timely repair 

of the emission monitoring system must be made. 

(4) 	 The permittee shall maintain and operate air pollution control monitoring 

equipment in a manner consistent with the manufacturer's recommended 

procedures, or a site-specific QAlQC Plan required by 40 CFR 75. The 

permittee shall have the QAlQC Plan available on-site and provide the 

Department with a copy when requested. 

(5) 	 Within 180 days of initial startup ofthe equipment required to meet the S02 

limits, conduct an emissions test to measure particulate emissions, using 

EPA Test Method 5, 5B or Method 17 in 40 CFR Part 60, Appendix A. 

Other test methods may be used provided they are approved, in advance, by 

the Department. 

(6) 	 The requirements in 40 CFR 60, Appendix A, Method 19, Section 12.5.3 

shall be used to determine overall reduction of S02 emissions based on 

outlet CEMS data and inlet coal sample analysis. Section 12.5.3.2 shall be 

used to calculate the inlet S02 rate. In place of the ASTM D 2234 

requirements of 12.5.2.1 of Method 19, coal sample collection will be 

conducted at least daily when the boiler is in operation to generate the 

average monthly inlet S02 emission rate. Coal sample analysis shall occur 

at least weekly whenever samples are collected during that week. Daily 

samples within a calendar week may be combined to form a composite 

sample that is analyzed for the required parameters. 

For purposes of determining compliance with the S02 percent reduction 

requirement, the reduction efficiency shall be determined as follows: 

% Reduction Inlet SO~ Rate-Outlet S02 Rate x 100 


Inlet S02 Rate 


Where: The Inlet S02 Rate is in units oflb/l06 Btu or lblhrand the Outlet 

S02 Rate is in the same units as the Inlet S02 Rate. 
Page 2. of.l 

Permit No. 10028 

5. 	 Recordkeeping Requirements: 

a. 	 The permittee shall maintain compliance monitoring records for Unit 2 as outlined 

in Table 2 - Monitoring Records, that includes the following information: 

(1) 	 A copy of the sample analysis report(s), including the date that the sample 

analysis was performed; the company, entity, or person that performed the 

analysis; and the testing techniques or methods used. 

(2) 	 The records ofquality assurance for emissions measuring systems including 

but not limited to quality control activities, audits and calibration drifts as 

required by the applicable test method. 

(3) 	 A copy of all field data sheets from the emissions testing. 

(4) 	 A record shall be kept of all major maintenance activities conducted on the 

emission units or air pollution control equipment. 

(5) 	 Records shall be kept as to the type of fuel usage. 

Table 2 

Monitoring Records 

PollutantlParameter Compliance Monitoring Record 

S02 outlet (Ib/l 0° Btu & lblhr) CEMS Data 

S02 inlet (lb/l 0° Btu) Coal Sampling Data 

CO2 CEMSData 

Flow Flow Monitor Data 

b. 	 In addition to requirements outlined in Condition 1I.5.a., recordkeeping for Unit 2 

shall be in accordance with the following applicable requirements of Chapter 

33-15-06, Chapter 33-15-14 ofthe North Dakota Air Pollution Control Rules and the 

Acid Rain Program: 

(1) 	 Section 33-15-06-05 of the North Dakota Air Pollution Control Rules, 

Reporting and Recordkeeping Requirements. 

(2) 	 40 CFR 72 and 40 CFR 75 as incorporated by NDAC 33-15-21-08.1 and 09. 

c. 	 The permittee shall retain records of all required compliance monitoring data and 

support information for a period of at least five years from the date ofthe compliance 

monitoring sampling, measurement, report, or application. Support information 

includes all maintenance records of the emission units and all original strip-chart 

recordings/computer printouts and calibrations of the continuous compliance 

monitoring instrumentation, and copies of all reports required by the permit. 
Page~of.l 

Pennit No. 10028 

6. 	 Reporting: 

a. 	 Reporting shall be in accordance with the following applicable requirements of 

Chapter 33-15-06 and Chapter 33-15-14 of the North Dakota Air Pollution Control 

Rules and the Acid Rain Program: 

(1) 	 Section 33-15-06-05 of the North Dakota Air Pollution Control Rules, 

Reporting and Recordkeeping Requirements. 

(2) 	 40 CFR 72 and 40 CFR 75 as incorporated by NDAC 33-15-21-08.1 and 09. 

(3) 	 NDAC 33-15-14-06.5. 

b. 	 Quarterly excess emissions reports for Unit 2 shall be submitted no later than the 

30th day following the end ofeach calendar quarter. Excess emissions are defined 

as emissions which exceed the emission limits for Unit 2 as outlined in Condition 

ILA.I.a(t) or (2). Excess emissions shall be reported for the following: 

Parameter 	 Reporting Period 

S02 % reduction 	 (Monthly and 12-month 

rolling average) 

or 

S02 Ib/I06 Btu at outlet 	 (Monthly and 12-month 

rolling average) 

c. 	 The pennittee shall submit a semi-annual report for all monitoring records required 

under Condition II.A.5 on fonns supplied or approved by the Department. All 

instances of deviations from the pennit must be identified in the report. A 

monitoring report shall be submitted within 45 days after June 30 and December 31 

of each year. 

d. 	 The pennittee shall submit an annual compliance certification report within 45 days 

after December 31 of each year on fonns supplied or approved by the Department. 

e. 	 For emission units where the method ofcompliance monitoring is demonstrated by 

either an EPA Test Method or portable analyzer, the test report shall be submitted 

to the Department within 60 days after completion ofthe test. 

f. 	 The pennittee shall submit an annual emission inventory report on fonns supplied 

or approved by the Department. This report shall be submitted by March 15 of 

each calendar year. Insignificant units/activities listed in this pennit do not need 

to be included in the annual emission inventory report. 

g. 	 The pennittee shall notify the Department within 15 days of the actual startup date 

ofthe equipment required to meet the S02 permit limit. 
Page.lof.l 

Permit No. 10028 

B. 	 General Conditions: 

1. 	 This pennit shall in no way pennit or authorize the maintenance of a public nuisance or 

danger to public health or safety. 

2. 	 The pennittee shall comply with all State and Federal environmental laws and rules. In 

addition, the pennittee shall comply with all local building, fire, zoning, and other 

applicable ordinances, codes, rules and regulations. 

3. 	 All reasonable precautions shall be taken by the pennittee to prevent and/or minimize 

fugitive emissions during the construction period. 

4. 	 The pennittee shall at all times, including periods of startup, shutdown, and malfunction, 

maintain and operate Unit 2 and all other emission units including associated air pollution 

equipment and fugitive dust suppression operations in a manner consistent with good air 

pollution control practices for minimizing emissions. 

5. 	 Any duly authorized officer, employee or agent ofthe North Dakota Department ofHealth 

may enter and inspect any property, premise or place at which the source listed in Item I.B. 

of this pennit is or will be located at any time for the purpose of ascertaining the state of 

compliance with the North Dakota Air Pollution Control Rules and the conditions of this 

pennit. 

6. 	 The conditions of this pennit herein become, upon the effective date of this pennit, 

enforceable by the Department pursuant to any remedies it now has or may in the future 

have, under the North Dakota Air Pollution Control Law, NDCC Chapter 23-25. Each 

and every condition ofthis pennit is a material part thereof, and is not severable. 

FOR THE NORTH DAKOTA 

DEP ARTMENT OF HEALTH 

Date:__....... 7+~....;;Z-2.'-=..j .....I--=I=()'--__ ~L¢.ocL: T~rry L. O'C r, P.E. 

DIrector 

Division of Air Quality 
Appendix F.l 


Public Participation Record 

Notice of Intent 


to Amend the 


State Implementation Plan 


for Air Pollution Control 


Relating to the Reduction ofRegional Haze 


The North Dakota Department of Health has prepared a supplement to the State Implementation 

Plan (SIP) for the Control of Air Pollution for the State of North Dakota which addresses 

Regional Haze (visibility impairment) in the Federal Class I areas. The supplement addresses 

requirements for the R.M. Heskett Station Unit 2. The requirements will reduce regional haze in 

Theodore Roosevelt National Park (TRNP) and Lostwood Wilderness Area (L WA). The 

supplement includes a Permit to Construct for R.M. Heskett Station Unit 2 which establishes 

sulfur dioxide emission limits which are intended to improve visibility impairment in TRNP and 

LWA. 

A copy of the proposed supplement may be reviewed at the Department's website at 

www.ndhealth.gov/AO/RegionaIHazel. A copy of the proposed supplement may be obtained by 

writing to the North Dakota Department of Health, Division of Air Quality, 918 E Divide 

Avenue, 2nd Floor, Bismarck, ND 58501-1947 or calling (701)328-5188. Written comments may 

be submitted to the above address from June 11, 2010 through July 11,2010. A public hearing 

will be held only if there is a request from the public for a hearing. Any request for a public 

hearing must be submitted in writing and received by the Department before the end of the 

public comment period. If a public hearing is requested, it will be held on July 16, 2010 at 9:00 

a.m. CDT in the Gold Seal Center's fourth floor conference room at 918 E Divide Avenue, 

Bismarck, ND. If a public hearing is requested, the public comment period will remain open 

through July 26, 1020. 

The National Park Service, Federal Land Manager for TRNP, has provided comments on the 

proposed supplement. The comments and the Department's response to those comments may be 

accessed at the website listed above or by contacting the Department. 
If you plan to attend a requested hearing and will need special facilities or assistance relating to a 

disability, please contact the Department of Health at the above address at least three days prior 

to the hearing. 

26th Dated this day of May 2010 


Terry L. O'Clair, P .E. 


Director, Division ofAir Quality 

Affidavit of Publication 

Colleen Park, being duly sworn, states as follows: 

1. ram the designated agent, under the provisions and for the purposes of, 

Section 31-04-06, NDCC, for the newspapers listed on the attached 

exhibits. 

2. The newspapers listed on the exhibits published the advertisement of: 

ND Health Dept - Notice of Intent Air Pollution; 1 time(s) as required by 

law or ordinance. 

3. All of the listed newspapers are legal newspapers in the State of North 

Dakota and, under the provisions of Section 46-05-01, NDCC, are qualified 

to publish any public notice or any matter required by law or ordinance to 

be printed or published in a newspaper in North Dakota. 

Signed: _.I...t::.~~::!o:::!::Z=......!fL.L==-_,_ 

State of /110 

Couhtyof BlI1</&4H nAil . \}.' 11, 11,c. J/) 

Subscribed and'sWorn· to before me thi~day of ___ ..t.tI_....::W~...;;...;;;;;; u:::...­__"20.!JL. 

/ndti udd 

LINDA J. JUDD 

• Notary Public ~ state of North Dakota ~ 

j My Commission Expires July 9, 2014 ~ 
""1•••- Nl .IJ"W.!NIM..... . '""",,Wt V~ "'It .....1 Utc t""'t"'='''I. ., SlIndra K.1Ci.Iltz.~ #05186 '. d4!scribeIt III dlrJud&lnent to die IIWIIIIt ' 

THIS IS AN A1TEf1PT ro COlLECT bidder fer ash at public IIICdoII lit die . NotIceoflnClent THE REFERENCED DEBT AND ANY . frontdooroftheCounhouseirllheOqof 

toAmend the INFOkMATION OBTAINED WILL BE Bismarck in the County of Burleigh and 

StaCIa Implell'lelltaCiol1 Plan USED FOR THAT PURPOSE. THIS SI3te of North Dakota, on june 30,2010, at 

. for Nt PollutIon ConI:roI COMMUNICATION IS FROM A DEBT the hour of 10:00 AM. (Cl). to sadlly the 

RelatIng to the RedudIon COt.LECTOR. amount due. with inIIlnst Ihereo!!. and the 

of RezIonaI Haze SI22. 29 1615 - 6OS4S4 COSIS and expenses of such Ali. or 101IIICh ' , The North DaIcota Department of Health thereof u the proceeds of such sale wi . 

flu prepared a sUpplement to the State saIi* The property to be sold 5 siwated 

ImpIementaIion Plan (SIP) for the Control STATE OF NORTH DAl<'Ol'A in the County of BurleIgh and SI3te of ., of Air PoIIuIion for the State of North IN 0ISTRlCT COURT . North DakDta. and described u follows: . Dakota which addresses Regional Hue (vis- COUNTY OF BURLEIGH SOUTHWEST The North 23 Feet ofLot I9.AM of Lot 20 

ibIIity Impairment) in the federal Class I JUDICIAlDISTRlCT and the South 10 Feet of Lot 21,BIock38. 

areas. The supplement addresses require- BlI1l Jo M.Jadcson, ! fisher AddIIion to the Oq of Bbmarck menu for the'ltM. Heskett Stidon UIlIt 1 Plaintiff. for Street. HIpiIy arid UIlIic.y Purposer 

The wiM reduce regional haze w. by Imtrument Reterded in Book ll9;.' 

in Theodore Roosevelt Nadonal Park MorrIs E.Jackson, Paa 480 aka 1207 N. 14th St Bismardc:., 

1\ CPl and Lostwood WiIdemess Area Derendant . ND 58501. 

,I ~.The supplement Includes a IiIrmIt to tim No. IN TESTIMONY WHEREOF. I'-hereun­ " a foi 1lM. Heskett Station Unit 2. SUMMONS to set rrrt hand and seal this Ilth day rJ' 

whid1 establishes sulfur dk»dde emission THE STATE OF NORTH DAKoTA ~20IO. 

fnnlls which are intended to Irnprow vIslbil- TO' THE ABOVE-NAMED Is/Pat 0 HeInert 

Ity impairment in TRNP and lWA." .' DEfENDANT. Pit 0 Heinelt 

Acopy of the proposed supplement may be 'YOU A1lE HEREBY SUMMONED and' Sheriff of Burtei&b Cou~ North Dakota 

reviewed lit the Oepartmem's websIca at required to appear and defend IfIInst the BrJs/Dan v.nu 

www.ndhealth.govlAQIRegIonaIHaze1. A ComptaInt in the KIion, which Is IIiIrMth Deputy 

copy of the pn:!pOSed supplement may be senIid upon rou. or wII be ftIed with the STATE OF NoRTH DAl<'Ol'A L: . obaJned by.writing to the North Dakota Cleric of this Court, by serving upon the IS. , 

Department of Health. Division of Air undersigned an. answer or other proper, , County of BurleIgh . ..' 

QualIty. 9.18 E DIvIde A\'!Inue. 2nd Floor. response within. twenty (20) iI:qs after On this Ilth day of I1a); 2010. ,me. a: 

Bismarck. ND 58501-1947 or alII", the SI!nke,:of this Summons IlPQlq'OlI. Notary Public in and for said County and . 

:) 	 (701)328-51 saWr1tter! COIIIIllIIIti.may be, eKdusiwl of the d:Iti.of sertIce. If:~ r.II tl) Sta~ personally appeared Dan Wentz. , submitted to the aboYeaddrestfromJune . do judgment by default wi bi\.tal!.en known. to me to be the penon Who IS:. l' Ii II. 20 I 0 through July II~ 20 I~• .,. publie 3pinst you for tile relief ,iJemanded in described In, and whose name Is subscribed'. 


hearing will be held only ifthere iu request the ' . ,. ' to this insIrument . '. 


from die public for a hearing. Arrt request :. IsINorma j. Braddock .'' i
 ·n for a public hearing must be submitted In . Notary I'ubIIc .': 


II 


, writing and reCeM!d by the " under. Rule p.~ pfthe oaJcOi:a ~ Budel&h County. North ~ . ,.. i 


befOre the end of the Wblie cOmment riert-,of.CO\.II1, lIPOII servlCl! of this summons. " My COmmIssion 1Ilqiires: 2120113 (Seil~ '; I 


ocI.ffa publJc hearln, Isrequested..!t wl!I be ,,ou; ar)d the plaintiff,. ~ b!)!JIid :by, the ' MACKDfF K8.1OGG. LAW BRM .. , . 
 held on JuIr 16.2010 at 9:00 a.m. CDT In .'foIlo'oYI", restr'aInts: " .' .... .' P'Q Box 1097 .<.' 


the Gold Sf:aI Center's fourth floor confer.' (I) Neither spouse !1lIlid~l?fisell" OkkInson. NO 58602-1091" ,', 
 'elite room at 918 E Divide AVenue, '.ei)(I!mbeI;« otherWise diSsiP.;ite" 'A~ for PlalIItIIf :''. ", . 
 .Bismarck. NOh public heatin, Is request- , any oft/le parties' aSsets. except! \"(Publlshed:06IOS;06/I2;~,*lDr' 

. ; 	 eel, the public comment period wil remain' 1A) For. ~iIies of life or for . 615. 12 1 19· ~~!~ .. , open through July 26, 1020. , the ,necessary generation of 

The Nalional Park· ServIce. federal Land income or presenalion of . Manager forTRNP, has provided comments assets; or . on the proposed sUpplement The com- . (8) , For retalnlngctluniel·. to ments and the Depal:trnent's response to . cmyonor to contest the . those. comments- mar. be accessed at the . . pro(eedln,c. . ' '.. 

websIca Hsted above "r by contacdng the ·If a spouse disposes of, sells,;~' Department'. . ..or dissipate!! ~,durIng,_the 

If )"011 plan tp attend a requested hearin, Interim periQiI..t!lai Sj)O\ISe. shall • 
 .and will need C! facilities or assistance· to. the other spouse'an aCtOuntiRz within . 


! 

~aofH.:r·ar::~o::':t=thi(f)~~Pouse!III!T~ the ~er 'n..-.TI_, 

at least three dIrs prtor to the hearing. spouse,·,,· . 

Dated this ~6th day of May 20 IO. (3) All curl'l\llltly avallabhj Insonnce 

Ten-y L O'Qalr. P.E. c:amaae must be malri!alned and 

Director, Division ofAir QualIty ,continued WIthout change.· In . , 615 - 6OS4~ or beneficiary ~on. 

If either spouse vIoIaIes any of ttIese . . provisions. that spouse may be In : l I

I 

, , STATE OF NORTH DAKOTA CCII1tempt of court.. 


IN DISTRICT COURT Dated this 17th day of February, 2010. 


COUNTY OF BURlEIGH , 1s1Thcrisa L Cole 
 ,SOUTH CENTRAl. JUDICIAl DISTRICT TheresaL Cole 


American Legal Senlces. P.e. . 


I 	

Che¥y Chue Plaintiff. ~k. FSa. l'' 	 521 East MaIn A\'!Inue. Suite 400 

Bismardc. ND 5850 I ~=tIon, joIe and any penon In poss8ssion. (101) 258-1074 

Defendants. ' Fax (101) 530-1943 ~;:::;~~ Civl1 No. 10.c1 8 NO Bar1lO5l85 ,·DM.~ \Nfl) (Bid Schedule I) and the instal. . SUMMONS · ration and usoclated piping. Owner .' At:tomtq fer PlaIntiff THE STATE OF NORTH DAl<'Ol'A10THE 6/5,12 & 19 - 605516 fumlshed pre-treatJ11ellt equipment. Owner 

ABCN£ NAMED DEFENDANTS: l'umlshed MFIUF membrane equlpment".

You are hereby summoned to appear and chemial feed eqUipment, headng and , Deadlines defend IfIInst the Complaint in this aaIon, · ventilation, eIectriaI,. and additional '10. which hu. been filed with the Cleric of miscellaneous items at Mandaree WTP (Bid .• PUBLISH BY RECEIYEBY Schedule 2). Bid Schedule 31s for combined' . servin& upon the undersigned a copy of an Court and .is herewith ser'II!d upon rou. by 

BId Schedules I and 2 with Bid AdjusCment. ' answer 0/' other proper response within dedua for. conna award of both I 

(20) dIrs after the service of this $chedules to a single Bidder. The .Four 1 1bes. •• ; ............. FrL 12,Nooft
 SuinmoM UJlOfI rou. IIKClusiwl of the day of ,t!ears and Mandaree projects are located in, .,i 

service. If you fall to do so. judgment by · McKenzie County of North Dakota.

default will be taken against lOu for the Wed. .• .or. ............'. t4on. N~ &dl BID must be a«ompanled by a. 'f 

relief demanded in the <:ompIaInt. 'The rate enwIfope containing acopy ofa current ., original Complaint is flied with the Cleric of and valid Nerd! Dakota Contractor's 

the District Court in the County in which ·LIcense (must have been'lssued at least '.. this acdon is commenced, , FrIday ................... '*RIeI. 5P14
 10 calendar dIrs befOre the date of BId 

This acdon relates to the foreclosure of a openlng.) and a BIDDER's Band equal to 

IIIOI1pIe upon the f'oIlowIlII described real lat..••••••••••• Wed. 12 Noon 1M! percent of the full amount of the BID.

I property In the County of Burleigh, State of executed by the BIDDER as Prlnc'P!' and by 

i 
North Dakota Newspaper Association 


1435 Interstate Loop 


Bismarck, ND 58503-0567 


Ph (701) 223-6397· Fax (701) 223-8185 


INVOICE 

Order 27875·1006lNAO Invoice # 131966 

Attn: TOM BACHMAN 

ND REALm DEPARTMENT 

600 E BOVLEVARD AVE. 

DEPT. 301 

BISMARCK, ND 58505-0200 

Voice: 701.328.5188 Fax: 101.328.5200 

June 25,2010 

Advertiser: Administrative Serv: Accounting 

P.O.#: 

Amount Due $257.61 

AmoU;llt Paid 

PIet1Se detaell and retum thll portion wiJII yourpayment 

Administrative Serv: Accounting Invoice # 27875-10061NAO-I31966 

AdSize Rate Type Rate Total Discount (%) Caption Page Run Date 

Brsmarck Tribune (Bismarck ND) 

60.00 SPR2 0.72 .43.20 0.00 Notice of Intent Air P 06105110 

Dickinson Pre..(DIckinson NO) 

63.00 SPR2 0.63 . 39.69 0.00 Notice of Intent AIr P 06l06I10. 

Fargo, The Forum (Fargo NO) 

63.00 SPR2 0.69 43.47 0.00 Notice ~f Intent AIr P 06107/10 

Grand Forks Herald (Grand Forks NO) 

63.00 SPR2 0.71 44.73 0.00 . Notice of Intent AIr P 06105110 

Minot Dally News (MInot NO) 

87.00 SPR2 0.49 42.63 0.00 Notice Of Intent AIr P 06l06I10. 

WIlliston Herald (WIlliston NO) 

57.00 SPR2 0.77 43.89 0.00 Notice of Intent AIr P 06l06I10 

Gross Advertising 257.61 TotalMisc 0.00 Amount Paid O~OO 

Ar,alcy Discount Tax 0.00 Adjustments 0.00 

Other Discount 0.00 Total Billed 257.61 Payment Date 

Service Charge 0.00 Unbilled .0.00 Balance Due 257.61 

Your payment Is due upon nK:e1pt. Thank)'Ou In advance for)'OUt prompt paymenU 
Response 


to 


Public Comments 


Commenter: Dakota Resource Council and National Parks Conservation Association (hereafter 

referred to as DRC) 

Comment 1: DRC questions whether Heskett Unit 2 was properly evaluated under Reasonable 

Progress instead of under BART. 

Response: The Department determined that Heskett Unit 2 was not subject to BART based on 

refined modeling submitted by MDU on June 9,2006. This modeling showed that the impact of 

emissions from Heskett Unit 2 was less than 0.5 deciviews (98th percentile) at the three units of 

Theodore Roosevelt National Park (TRNP) and Lostwood Wilderness Area (L WA). The 

Department, in a letter dated May 8, 2007, agreed that Heskett Unit 2 was not subject to BART. 

EPA and the FLMs questioned the modeling protocol that was used. A new protocol based on 

EPA and FLM criteria, which the Department does not necessarily agree with, was developed. 

MDU submitted modeling ~ased on the EPA and FLM protocol which showed the maximum 

impact of emissions from Heskett Unit 2 was even less than the previous modeling at 0.28 

deciviews (98th percentile). Both EPA and the FLMs have reviewed the 2009 modeling and did 

not object to the determination that Heskett Unit 2 was not subject to BART. 

Comment 2: DRC claims that the modeling that shows Heskett Unit 2 was not subject to BART 

was not subject to public review. 

Response: Both the 2006 and 2009 modeling analyses were posted on the Department's website 

for review during the public comment period for the Regional Haze SIP (December 2009 ­

January 2010). The Department made its decision that Heskett Unit 2 was not subject to BART 

based on the 2006 modeling. The Department agreed to review that decision if the 2009 results 

showed Heskett Unit 2 was subject to BART. The Department found no reason to revise its 

May 8, 2007 decision that Heskett Unit 2 was not subject to BART. Both the 2006 and 2009 
modeling analysis were included in the final Regional Haze SIP submitted to EPA in March 

2010. 

The commenter indicates the impact to TRNP is 0.3 deciviews with the cumulative effects of 0.5 

deciviews including LWA. These results are from the 2009 modeling analysis. Apparently, the 

commenter has reviewed the 2009 analysis and extracted data from it. 

Comment 3: DRC claims MDU's own modeling results shows Heskett Unit 2 to be subject-toBART when cumulative impacts to multiple class I areas are "appropriately" considered. 

Response: DRC's position that a cumulative assessment of the impacts on multiple Class I areas 

is required to determine BART applicability is inconsistent with 40 CFR 51, Appendix Y ­

Guidelines for BART Determinations under Regional Haze. Section 111.3 of 40 CFR 51, 

Appendix Y, under Option 1, states "You can use dispersion modeling to determine that an 

individual source cannot reasonably be anticipated to cause or contribute to visibility impairment 

in !! [emphasis added] Class I area and thus is not subject to BART." There is no discussion 

regarding adding results for multiple Class I area. The modeling protocol the Department 

developed for determining whether sources are subject to BART (see Appendix A.l of SIP) does 

not require a cumulative assessment of impacts on multiple Class I areas. The determination of 

whether a source is subject to BART is based on the maximum impact (98th percentile) at any 

single Class I area. The Department's modeling protocol is consistent with 40 CFR 51, 

Appendix Y. 

Comment 4: The DRC provided several general concerns, with no supporting data for those 

concerns, regarding the Reasonable Progress Assessment. 

4a. DRC states that overestimated costs tend to reduce the apparent cost effectiveness of viable 

control technologies like Selective Non-Catalytic Reduction (SNCR). 

Response: The Department compared the cost of SNCR estimated by MDU to cost estimates for 

SNCR at four other small « 200 MWe) facilities. The results show that the MDU cost estimate 
(annualized cost) was near the average with two estimates being higher. It appears MDU's 

estimate is reasonable compared to similar size facilities. 

4b. DRC has concerns that comparing costs and cost effectiveness primarily or solely based on 

North Dakota facilities may be flawed. 

Response: The Department did not rely solely on cost estimates from other North Dakota 

facilities. MDU's cost estimate for SNCR was compared to two facilities in Minnesota, one in 

Montana and one in North Dakota. MDU's cost estimates for the wet scrubber and spray 

dryerlbaghouse were compared against results from EPA's CUECOST model. This model is 

used allover the U.S. The cost of low dust SCR was compared to results generated for the PGE 

Boardman Plant in Oregon (this was a compilation of results by ERG, Inc. from allover the 

nation) and cost estimates from two North Dakota facilities. MDU's estimate fell within the 

midrange of ERG's estimated range for high dust SCR at the PGE Boardman plant. Low dust 

SCR is expected to cost more than high dust SCR because of the flue gas reheat costs. This 

makes MDU's estimate even more conservative. The Department believes MOU's estimates are 

within the ± 30% range required for BART control estimates even though this source is not 

subject to BART. 

4c. DRC has concerns about not using the 98th percentile visibility results for determining 

reasonable progress. 

Response: As pointed out in the Response to Comments to EPA's comments on the FLM 

Consultation version of this supplement, the Regional Haze rule and EPA guidance does not 

require use of the 98th percentile results. In 40 CFR 51.308( d) it states "The reasonable progress 

goals must provide for an improvement in visibility for the most impaired days over the period of 

the implementation plan and ensure no degradation in visibility for the least impaired days over 

the same period." 40 CFR 51.301 states "most impaired days means the average visibility 

impairment (measured in deciviews) for the twenty percent of monitored days in a calendar year 

with the highest amount of visibility impairment," Least impaired days means the average 
visibility impairment (measured in deceiviews) for the twenty percent of monitored days in a 

calendar year with the lowest amount of visibility impairment. 

The Department is not aware of any EPA guidance that indicates the 98th percentile visibility 

results should be used. To the contrary, in EPA's document "Additional Regional Haze 

Questions" August 3, 2006, this issue is addressed. In the response to Question 1 under the 

Reasonable Progress section EPA states "Unlike the technical demonstration for CAIR or 

BART, the reasonable progress demonstration involves a test of a strategy. The strategy includes 

a suite of controls that has been identified through the identification of pollutants and source 

categories of pollutants for visibility impainnent - the application of four statutory factors 

and how much progress is made with a potential strategy with respect to the glide path. 

Modeling occurs with a strategy and is not a source-specific demonstration like the BART 

assessment." [Emphasis added) 

In response to Question 2, it is stated "Reasonable progress is not required to be demonstrated 

based on a source-by-source basis. It is demonstrated based on a control strategy developed 

from a suite ofcontrols that has been assessed with the four statutory factors and the uniform 

rate of progress." [Emphasis added] 

It is clear to the Department that a BART type assessment (Le. 98th percentile) is not required. In 

fact, an assessment of individual sources is not required. The Response to both Question 1 and 2 

indicates any modeling should be assessed against the uniform rate of progress (glidepath). In 

Section 2.2 of "Guidance for Setting Reasonable Progress Goals Under the Regional Haze 

Program", the uniform rate of progress, or glidepath, is determined for the average of the 20% 

worst days or 20% best days. 

The Department has provided both the individual modeling results for sources and the 

cumulative modeling results for a control strategy for the group of sources that remained after 

the initial evaluation process was completed (see Section 9.1.5 of the RH SIP). We interpret the 

EPA guidance on Reasonable Progress to indicate that results for individual sources are not 
required. Therefore, any results presented would not have to include the 98th percentile values 

and should be compared to the average of the 20% worst days. 

4d. DRC has a concern with a 12-month rolling average instead of a 30-day rolling average and 

indicates the limit should be written as a nwneric limit and a percent reduction. 

Response: Heskett Unit 2 is subject to review under the Reasonable Progress requirements of the 

Regional Haze rule, not the BART requirements. The Department has found that it is not 

reasonable to require any reductions of S02 or NOx emissions from Unit 2. The reductions at 

Heskett Unit 2 are somewhat voluntary. Therefore, the Department believes that MDU should 

be afforded some flexibility in achieving the S02 reductions. A twelve month rolling average 

and allowing MDU to meet either a Ib/1 06 Btu limit or a percent reduction requirement allows 

this flexibility while still achieving the reduction of 553 tons per year of S02. The Department's 

modeling shows the proposed reduction in emissions will have virtually no effect on visibility in 

the Class I areas. Therefore, the averaging period of the emission limit will not affect visibility 

impacts. The Department has included adequate monitoring, recordkeeping and reporting in 

Conditions II.A.3-6 of the Permit to Construct. The commenter provided no specifics to dispute 

this finding. 

Comment 5: DRC states that they attach and incorporate by reference the comments submitted 

on January 8, 2010 for the Regional Haze SIP. 

Response: The Department incorporates by reference its response to the January 8, 20 I 0 DRC 

comments (see Appendix F.8 - Environmental Groups of the North Dakota State Implementation 

Plan for Regional Haze; Adopted February 24, 2010). 

Commenter: Montana Dakota Utilities (MDU) 

Comment 1: MOU has concerns that the requirement for a PSD Permit to Construct for changes 

associated with the S02 removal project could delay the installation of the sulfur dioxide removal 

project. MDU requested that language be included in the supplement for the S02 removal 
project which would allow the compliance date to be changed based on when the PSD Permit to 

Construct is issued. 

Response: The compliance date in the proposed Pennit to Construct for the S02 removal project 

states "as expeditiously as possible" but in no event later than five years after the U.S. EPA 

approval of the pennit as part of Regional Haze SIP. The Department interprets the language 

"expeditiously as possible" of this condition, to allow consideration of the timing of other 

pennits. Therefore, MDU will have up to five years to obtain any other required pennits. The 

supplement will be revised to indicate that the issuance of a PSD pennit for the removal project 

will affect the compliance date for the project. 
DAKOTA RESOURCE COUNCIL 

P. O. Box 1095, Dickinson NO 58602-1095 

(701) 483-2851; www.drcinfo.com 

July 11,2010 

Terry O'Clair, Director 

Division of Air Quality 

North Dakota Department of Health 

918 East Divide Avenue, 2nd Floor 

Bismarck, NO 58501-1947 

RE: Comments on the May 2010 Supplement No.1 to the North Dakota State 

Implementation Plan for Regional Haze 

Dear Mr. O'Clair: 

On behalf ofthe Dakota Resource Council and the National Parks Conservation Association, we 

respectfully submit the following comments on the May 2010 Supplement No. I to the North 

Dakota State Implementation Plan (SIP) for Regional Haze (the Supplement), which addresses 

the Montana Dakota Utilities' (MDU) Heskett Unit 2 (Heskett) under the Reasonable Progress 

section of the Regional Haze Rule. We additionally attach and incorporate by reference the 

comments our organizations submitted on the State's Regional Haze Rule. l 

We submit these comments on behalf of our more than 320,000 members and out of concern for 

the millions of people who visit America's national parks and public lands each year. North 

Dakota's recently submitted Regional Haze SIP identified Class I areas affected by emissions 

from North Dakota facilities, including Heskett. Impacted lands include Theodore Roosevelt 

National Park and Lostwood National Wildlife Refuge Wilderness Area in North Dakota, as well 

as public lands in South Dakota, Montana, Minnesota, and Michigan. 

We question whether Heskett is properly evaluated under the Reasonable Progress, rather than 

the Best Available Retrofit Technology (BART), portion of the SIP. Additionally, we echo the 

concerns raised by the Department of the Interior (001) and the Environmental Protection 

Agency (EPA), which were largely unaddressed by the North Dakota Department of Health 

(NDDH). 

I Comments ofNational Parks Conservation Association et. al. on North Dakota's Regional Haze State 

Implementation Plan, January 8, 2010. 
Review ofHeskett under the Reasonable Progress requirements is questionable for two reasons. 

First, the public has not had opportunity to review the modeling, submitted to NDDH by MDU in 

December 2009. As described by EPA in its January 8, 2010 comments on the Regional Haze 

SIP, 

" ... this updated modeling was completed after the start ofthe current public comment 

period on the Regional Haze SIP ...NDDH will need to revise the SIP to include the 

updated modeling and your related conclusions. The revision will need to follow North 

Dakota's public participation process for SIP revisions." (p. 3) 

However, the modeling this purports to establish Heskett as not subject-to-BART has not, to our 

knowledge, been subject to public review. Its conclusions are instead here presented as fact. 

Second, MDU's own modeling shows Heskett to be subject-to-BART when cumulative impacts 

to mUltiple Class I areas are appropriately considered. The impact to Theodore Roosevelt 

National Park (TRNP) is 0.3 deciviews, with cumulative effects of 0.5 deciviews including 

Lostwoods National Wildlife Refuge. Based on this cumulative impact, we believe that Heskett 

is more appropriately evaluated as subject-to-BART. 

In general, we concur wit~ the comments submitted by DOl and EPA, and find NDDH's 

response to these comments inadequate and unpersuasive. In particular we have continued 

concerns about: 

Overestimated costs, which tend to reduce the apparent cost effectiveness of viable 

control technologies like Selective Non-Catalytic Reduction (SNCR). 

Comparing costs and cost effectiveness primarily or solely with other North Dakota 

facilities, which may be similarly flawed, rather than a broader pool. When compared to 

determinations around the country, most if not all ofthe options available are cost 

effective on a $/ton basis. . 

The dismissal of98th percentile day results (and direct EPA comments on this matter) in 

examining visibility benefits, as required in a BART analysis. This tends to minimize the 

visibility benefits of emissions reductions. 

The lack of stringency in the limit established, with regard to the numeric limit, averaging 

time, and other parameters. There is no reason to establish a less stringent 12-month 

rolling average rather than a 30-day rolling average. Although the optimization described 

in the permit may result in a lower limit, this process is not subject to review by anyone 

other than NDDH. The permit limit should require compliance with both a percent 

emission reduction and a numeric limit, not a choice ofone or the other. 
We ask that the analysis ofthe Heskett facility be considered in the context of the far-reaching 

impacts ofthe facility's emissions on air quality, visibility, public lands and public health. The 

Heskett facility is likely more appropriately considered under the BART rubric rather than 

Reasonable Progress. This analysis, like many in the Regional Haze Plan, seems to have 

overinflated costs, underestimated benefits, and a severely limited the pool of comparison for 

what is deemed "cost effective," thereby making reasonable technologies appear less so. There is 

no reason for NDDH to allow the Heskett facility to reduce its emissions a minimal amount 

when better, cost effective options exist. 

Thank you for the opportunity to comment on the Reasonable Progress analysis of the Heskett 

facility. 

Sincerely, 

Mark Trechock, StaffDirector 

Dakota Resource Council 

P.O. Box 1095 

Dickinson, ND 58602-1095 

701-483-2851 

Stephanie Kodish 

National Parks Conservation Association 

706 Walnut Street, Suite 200 

Knoxville, TN 37902 

865-329-2424 

CC: 	 U.S. EPA Region 8 

NPS, Air Resources Division 
V.MONTANA-DAKOTA 


• UTILITIES CO 

ADiviSlOll of MDU Resources Group. Inc. 

400 N;Jrr;~ Faul!h Strear 

Bismarck ND 5850 I 

i7!)l) 22N9O(i 

July 9, 2010 

Mr. Terry O'Clair 

Director 

Division of Air Quality 2nd Floor 

North Dakota Department of Health 

918 E. Divide Avenue 

Bismarck, ND 58501-1947 

Re: Comments on the North Dakota Department of Health May 2010 Supplement No.1 to the 


State Implementation Plan for Reducing Regional Haze 


1-~Y71 Dear M~....O'Clair.' 

Montana Dakota Utilities Co. (Montana-Dakota) is submitting this letter to provide comment on 

Supplement No. 1 to the North Dakota State Implementation for Regional Haze (RH SfP 

Supplement) dated May 2010. Montana-Dakota generates, transmits and distributes electricity 

and distributes natural gas in North Dakota, South Dakota, Montana and Wyoming. The 

company owns and operates electric steam generating facilities which are subject to extensive 

regulation W1der the Federal Clean Air Act. The following comments pertain to R.M. Heskett 

Station Unit 2 (Heskett Unit 2) in the RH SIP Supplement. 

The RH SIP Supplement incorporates a permit to construct (PTC) specific to Heskett Unit 2. 

Section II of the PTC acknowledges that certain physical changes that will be necessary to meet 

the sulfur dioxide conditions in this PTe may require a separate permit: 

"While this Permit to Construct authorizes the construction and initial operation ofnew 

or modified air pollution control equipment and process changes to reduce sulfur dioxide 

emissions, the permittee may be required to apply for a Prevention ofSignificant 

Deterioration (PSD) permit to authorize any significant net emissions increase of 

particulate matter, PM10 and/or PM2.5 that will result/rom the installation ofthe flew 

or modified pollution control equipment and process changes. 

This condition is unique to Heskett Unit 2 as compared to the other PTCs that wi\] be issued to 

North Dakota power plants subject to BART and Reasonable Progress Goals; therefore, it is 

important to address possible timing concerns that arise from a situation where pemlitting delays 

to authorize a project could prevent meeting the compliance date specified in PTC condition 

I1.A.2. Specifically, if a PSD permit is required in order to meet the conditions in the PTC, then 

lhe time necessary to complete PSD review can take several months and could potentially 

jeopardize the timing of project completion. 
Montana·Dakota Comments on May 2010 Supplement No.1 for the NDDH RH SIP 

July 9,2010 

Page 2 

The purpose ofthis comment letter is to request that the RH SIP acknowledge the inherent risk in 

issuing a PTC for an emissions reduction when the PTC itself does not authorize changes to the 

facility that are necessary to meet the emissions reduction. We request that the following 

Janguage be inserted on page 5 ofthe RH SIP Supplement at the end ofthe section titled "Time 

Necessary for Compliance" as evidence of this acknowledgement: 

"The Department recognizes that limestone injection in the Unit 2 AFBC may potentially 

cause an increase in other pollutants for which a separate permit to construct, including 

a PSD permit, may be necessitated. Ifa related permit to construct is required, then that 

permitting schedule may impact the timing ofthe contemplated S02 emissions reductions 

pennit attached to this supplement. The Department recognizes that the S02 reduction 

pennit may need to be modified to address the schedule for processing any related permit 

action. " 

Thank you for the opportunity to provide comments on the proposed RH SIP Supplement. Please 

contact me at (701) 222-7844 if you would like to discuss this further. 

Sincerely, 

~:~;k~_ 

Abbie Krebsbach 

Environmental Manager 

cc: 	 Andrea Stomberg, Vice President Electric Supply 

Alan Welte, Generation Manager 

Tony Stroh, R.M. Heskett Station Manager 
Appendix J.1.5 


National Park Service 


Consultation Comments on Supplement No. 1 


And 


Department's Response 

NPS Prelim.inary Comments on Reasonable Progress Requirements for 


Montana Dakota Utilities CMDID R.M. Heskett Station Unit #2 


May 14, 2010 


Montana Dakota Utilities (MOU) operates the R. M. Heskett Station Unit #2 near 

Mandan, North Dakota, about 160 kIn east of Theodore Roosevelt National Park (NP), a 

Class I area administered by the National Park Service.. Heskett #2 includes an 

.atmospheric bubbling fluidized bed boiler fired with lignite from an adjacent mine and is 

rated at 78 MW output. Current emission control equipment consists of an electrostatic 

precipitat9r. 

Out of 3;558 Electric Generating Units. (EGUs) in EPA's· Clean Air Markets (CAM) 

database in 2008, Heskett #2 ranked #713 for S~ at 2,403 toris and #988 for NOx at 432 

tons. According to modeling results provided by MDU, emissions from ijeskett #2 cause 

0,3 dv .of impairment in visibility at Theodore Roosevelt NP and 0.5 dv cumulatively 

when Lostwood National Wildlife·Refuge is included. Consistent with EPA guidance, the 

..North Dakota Department of Health (NDDH) has sehicted O.S dv at each Class i area 

individually as its signifiCance level for triggering review under the Best Available 

Retrofit Technology (BART) program. Therefore, NDDH has detennined that Heskett 

#2 is not subject to BART. However, NDDH did review Heskett #2 with. respect to 

reasonable progress control requirements. . 

.­

Reasonable Progress. Control Technology Analysis 

While the "standardu . five-step BART analysis is itot specified for analyses under the 

Reasonable Progress program, -it provides' a _useful approach that is consistent and 

comparable to actual BART analyses. . 

SulfurDioxide ­

Step 1: Identify All A vallable Technolofiies 

-We a~that-NDDH has chosen a reasonable sui'te ofoptions. 

Step 1: Ellminate Technically Infeasible 9ptions 

We agree With NDDH's selection ofteelmically feasible options~ 

Step 3: Evaluate Control Effectiveness of Each Remaining Control Technology 

We disagree with NDDH's estimates of 94% control effectiveness of limestone injection 

and a spray-dry~ with a baghouse to achieve 0.09 Ib/mmBtu.For example, NDDH has 

. issued two pennits for fluidized bed boilers burning ND lignite in the past decade. 

According to EPA's RACTIBACTILAER Clearinghouse (RBLC), NDDH issued a 

pennit on 9114/07 to Oreat River Energy for the' I 12 MW Spiritwood Station. That permit 

limited S02 emissions to 0.06 Ib/mmBtu saying "SULFUR DIOXIDE CONTROL 

SYSTEM (LIMESTONE INJECTION AND SPRAY DRYER) WILL ACHIEVE 98.7% 

REMOVAL OF POTENTIAL EMISSIONS BASED ON THE WORST CASE, 30 DAY 
I 

LIGNITE. THE REMOVAL RATE WILL BE 98.8% BASED ON THE WORST CASE 


24 HOUR LIGNITE." . 


The RBLC also contains an entry for a pennit issued by NDDH on 6/03/05 to MDU for 


the 220 MW Gascoyne GCQerating Station which states, "THE [98.9%] EFFICIENCY IS 


THE OVERALL REMOVAL EFFICIENCY OF POTENTIAL S02 EMIS~IONS 

(COAL-TO-STACK) USING BOTH LIMESTONE INJECTION AND A SPRAY 


DRYER IT IS BASED ON BURNING LIGNITE THAT CONTAINS 1.0 % SULFUR 


(AS-RECEIVED) AND TIm 30 DAY .ROLL~G AVERAGE EMISSION RATE OF 


0.038, LBIMMBTU." 


NDDH has presented no justification for the much lower 94% efficiency it used in its 

analysis. 

We also disagree with NDDH's assumption that limestone injection into the fluidized bed 


can achieve only 60% control andt:educe ;S~ no lower than 0.364 Ib/mmBtu. It is 
 I 

generally accepted that a limestone fluidized bed boiler can inherently remove 90% ofthe 

uncontrolled . SOa. 1 Applying that 90% . reduction to the 2.15 Ib/mmBtu average 

uncontrolled emission rate provided by MOU yields a 0.215 Ib/mmBtu eIl)ission rate 

I . from the boiler. 

Step 4: Evaluate Impacts and Document Results 

Despite repeated advice from EP A ag~inst using the CUECost model instead of the I 'OAQP~ Control Cost ManuaI (Cost Manual), MDU' and NDDH have used the CUECost I 

mexlc:ll to estimate the costs of the wet scrubber andspray.-dryer options. We believe this I 

has resulted in an. overestimation of cOsts. For example, MOD' has estimated the Total 

Capital Investment (TCI) for a spray-dryer 'at $37,564,351 or $4821kW. By compariSQD, I 

the Colorado Department of Public Health and Environment has determined that BART 

for the 85 MW Martin Drake Unit #6 is a spray dryer with a TCI of$447IkW. ' 

It is impossible froin the data provided to evaluate MDU's .estimates for operating costs. i 

We request that MDU ·and/or NDDH provide an evaluation of operating costs in a ! 

manner that is transparent and similar to that .presented in the Cost ManuaI. For example, 


in the evaluation of the· spray-dryer option, we requ~t estimates of use rates for solvent ! 

I and reagent, waste generation. rate, and the,cost of electrici.ty . associated with the I 

scrubber. NDDH and MOD h~ve improperly increased the operation and maintenance I 

costs by 36,%--:this is not supported and not allowed by the Cost Manual. I 

NODI:I.should.support and explain'its $9,815,000 estimate for· the Total Annual COst for 

the spray~erlbaghouse combination.', ' I 

I 

I For example, NDDH estimated that limestone injection would achieve 88% S~ control in its May 2007 

analysis ofWestmoreland Power's Gascoyne 500 MW circulating fluidized bed boiler. 

2 

Step 5: Evaluate Visibility Results 


It is impossible from the data provided to evaluate MOU's estimates 'of the visibility 


improvements resulting from the control options evaluated. As noted by EPA in its May 


12, 2010, letter, "...visibility improvements are likely underestimated by your hybrid 


modeling system ..." NDDH should at least use the method described in the 12109 BART 


modeling report. 


Nitrogen Oxides 

Step 1: Identify All AvaHable Technologies 


We agree that NDDH has chosen a reasonable suite ofoptions. 


Step 2: Eliminate Technically Infeasible Options 


We agree with NDDH's selection of technically feasible options. 


Step 3: Evaluate Control Effectiveness of Each Remaining Control Technology 


NDDH has assumed that SNCR can reduce NOx emissions by 33%.2 We believe that 


. MDU's assumption of40% NOx reduction is more appropriate. 


Step 4: Evaluate Impacts and Document Results 


. We believ~ that NDDH haS overestimated the capital cost of SNCR by comparing the 


$521kW cOst at HeSkett to an average3 of costs from other BART analyses conducted by 


sources trying to avoid addition of SNCR. According to the Institute of Clean Air 


Companies,4 "Typical SNCR capital costs (including installation) for utility applications 


are $5-15IkW, vendor scope, which corresponds to a maximum of$201kW ifbalance-of­


plant capital requirements are included." 


It is impossible from the data provided to evaluate MOU's estimates for SNCR operating 


costs. We request that MDU and/or NDDH provide an evaluation ofoperating costs in a 


i . manner that is transparent and similar to that presented in the Cost Manual.' . t 

! 

We note that, while NDDH presented much lower Total Annual Costs based upon 

applying the Cost Manual approach, it provided neither its Cost Manual-based analysis 

nor a reason for rejecting the Cost Manual result in favor of the MOU cost which was r 

,

• 

more than two times higher. 1 

1 

.Step S: Evaluate Visibility Results i 

It is impossible from the data provided to evaluate MOU's estimates of the visibility ~ 

improvements resulting from the control options evaluated. As noted by EPA in its May 

I 

f 12, 2010, letter, "...visibility improvements are likely underestimated by your hybrid 


modeling system ..." NDDH should at least use the method described in the 12109 BART 


modeling report. 


r 

. 2 NDDH estimated that SNCR would achieve 40% NOx control in its May 2007 analysis of Westmoreland 

Power's Gascoyne 500 MW circulating fluidized bed boiler. 

3 which should not have included Heskett I 

4 May 2000 White Paper on "Selective Non-Catalytic Reduction (SNCR) for Controlling NOli Emissions" 

t 

3 I 

f 

I 
.Time Necessary for Compliance .. 


"The Department [NDDH] believes up to 6.5 years would be necessary for some control 


options (i.e., scrubbers and selective catalytic reduction)." We believe that such controls 


could be added much more expeditiously_ For example, Minnesota Power has advised the 


MN Public Utilities commission of the following schedule fQr installation of a spray­


dryer, carbon injection, SCR and a baghouse at its 330 MW Boswell Unit #3. 


Minnesota Power's Boswell 3 Environmental Improvement Plan 


submitted 


October 27, 2006 


to the 


Minnesota Public Utilities Commission 


Docket No. EOIS/M-06-1501 


Pursuant to Minn. Stat. §§ 216B.68SI, subd, 5, 216B.1692, the following table 

presen ts thoepJann 1 ed sc h d e u e 1ft' or tmpJ I t emen a tion ac ti V1 'ftes: 

Activity Timeline 

Phase 1 - Conceptual Engineering 

Target Procurem~t Activities - Environm.entaI Equipment' Apr:i006-~ 

'Target .Procurement Activities- Turbine/Generator Oct 2006 - May 2007 

.Phase 2 .. Final Design & Procurem~:qt 

FabricatelDeliver .. SCR (incl. major steel and truss work) Jun 2007 .. May 2008 

FabricatelDeliver .. Fabric Filter: Apr .2008 .. May 2008 

FabricatelDeliver .. FGD System Dec 2007 - Jun 2008 

FabricatelDeliver .. Turbine/Generator Jun 2007 - Dec 2008 

Phase 3 .. Construction 

Site Preparation Apr 2007 .. Jun 2007 

Construction .. SCR Jun 2007 .. Jun 2009 

Construction .. Fabric Filter Jun'2007 -May 2009 

Construction .. FGD Jun 2007 - Jun 2009 

Construction .. ChimneylMonitoring Equipment Apr 2009- Jun 2009 

Construction - Turbine/Generator Jan 2009 .. Nov 2009 

Phase 4- Start-Up 

Checkout & Commission for Tuning Dec 2008 - Jun 2009 

Final Plant Start-Up and Tuning Apr 2009 ~Sep 2009 

Results, Conclusions & Recommendations 

• 	 MDU is proposing to voluntarily replace the s.and in the fluidized bed with 

limestone to improve 802 capture· to 0.60 Ib/mmBtu. We. believe that this 

approach is capable ofmuch lower (e.g,~ 0.20 Ib/mmBtu) 802 emissfons. 

4 

• 	 NDDH has improperly relied upon the CUECost model to estimate costs instead 

ofthe OAQPS Control Cost Manual approach recommended by EPA. 

• 	 NDDH should show the parameters used to estimate operating costs so that these 

critical evaluations are transparent and can be evaluated by outside parties. 

• 	 NDDH has overestimated the costs of the spray-dryerlbaghouse option, and 

underestimated its benefits. 

• 	 NDDH should base its estimates of SNCR Total Capital Investment costs upon 

industry data for actual installations instead of inflated cost estimates provided by 

MDU and other sources seeking to avoid additional controls. 

• 	 NDDH presented much lower Total Annual Costs based upon an application of 

the Cost Manual approach and should provide that analysis as well as a reason for 

rejecting the Cost Manual result in favor of the MDU cost which was more than 

two times higher. 

• 	. NDDH is proposing no additional NO" reductions. We believe that a proper 

anal'ysis that reflects the higher control efficiency and lower costs of SNCR may 

result ,in significantly better cost-effecti:veness, and lead to a different conclusion. 

• 	 NDDH should at least use the method described in the 12/09 BART modeling 

report. 

j 

! 

j 

I 

I 

5 

Response to 


National Park Service 


Comments 


May 14,2010 


Sulfur Dioxide: 

1. 	 The NPS does not agree with 94% reduction of S02 from limestone injection and a spray 

dryer . 

. Response 

Heskett Unit 2 is an atmospheric bubbling fluidized bed boiler, not a circulating fluidized 

bed boiler like the Gascoyne 175 and Gascoyne 500 plants. In addition, this unit was not 

originally designed as a bubbling fluidized bed combustor. It was converted from a 

spreader stoker design to a bubbling bed combustor in 1986. Thus, this unit may not be 

able to achieve 90% reduction by limestone injection that was proposed for the Gascoyne 

plants. North Dakota has one other bubbling bed combustor operating at Red Trail 

Energy, LLC. This boiler has not been able to achieve 90% S02 reduction with 

limestone injection. This boiler has both limestone injection and sodium bicarbonate 

injection into the flue gas (estimated at 70·90% efficiency). The two systems at this 

bubbling fluidized bed combustor have achieved a maximum combined S02 removal 

efficiency of 92.1 %. In the BACT review for Red Trail Energy, it was estimated that 

limestone injection and a spray dryer would reduce S02 emissions by 93% at this 

bubbling fluidized bed combustor. This is primarily due to a lower removal efficiency 

for limestone injection. The amount of S02 removal by limestone injection plus a spray 

dryer at Heskett Unit 2 is not known at this time due to its retrofit status. However, the 

Department believes 94% is reasonable based on the uncertainties (retrofit) and the 

experience with Red Trail's bubbling fluidized bed combustor. The evaluated emission 

rate of 0.055 Ib/l06 Btu is very similar to the Gascoyne 500 value of 0.06 Ib/l06 Btu for a 

spray dryer plus limestone injection. 

Regarding limestone injection, the additional 60% S02 reduction by limestone injected 

into the combustor equates to 82% overall reduction within the combustor. Based on our 

experience with Red Trail and the fact that Heskett Unit 2 was not originally designed as 

a bubbling fluidized bed unit, we believe 82% is reasonable. 

2. 	 NOOH has used the CUE Cost Model to generate costs for wet scrubber and spray dryer 

instead on the Control Cost Manual. 

Response 

The commenter is incorrect in this statement. The costs that were used in this evaluation 

for a spray and wet scrubber were provided by MOU. The NDDH only used the CUE 

Cost model to verify MOU's cost estimates. MOU provided a site specific cost estimate 

for the wet scrubber and spray dryer using the Control Cost Manual procedures. 

Additional information has been provided to show the specifics of each cost estimate. 
The NPS points out that the Colorado Department of Public Health estimated the cost of 

a spray dryer at Martin Drake Unit #6 at $4471kw compared to $4821kw at Heskett Unit 

2. This is a 7.8% difference in the cost of the spray dryer. Site specific factors can easily 

account for this amount of difference. In addition, the estimate for controls for 

Reasonable Progress, as well as BART., only have to have a ±30% accuracy. The 

estimate provided by MDU is well within this range when compared to the estimate for 

Martin Drake Unit #6. 

3. 	 The NDDH should support and explain its $9,815,000 estimate for the Total Annual Cost 

for the spray dryerlbaghouse combination. 

Response 

The cost for the spray dryerlbaghouse was provided by MDU and adjusted to 2009 

dollars. MDU Used the Control Cost Manual procedures for estimating the cost. Details 

of the analysis have been included in the supplement. 

4. 	 As noted by EPA in its May 12, 2010, letter " ...visibility improvements are likely 

underestimated by your hybrid modeling system; NDDH should use the modeling 

method described in the 12/09 BART Modeling report." 

Response 

States in the west are relying on WRAP's modeling to establish Regional Haze visibility 

improvement progress much like we suspect EPA will for their own purposes in 

preparing the Montana Regional Haze SIP. As shown in Table 8.11 of our Regional 

Haze SIP, the Department's hybrid modeling approach predicts significantly greater 

improvement in visibility for the BART controls compared to WRAP's modeling. This 

was expected, given the more, realistic treatment of point source plumes by Calpuff 

compared to WRAP's grid modeling. Therefore, it appears inconsistent for EPA, or the 

NPS, to argue that the Department's hybrid modeling system is underestimating visibility 

improvement, while accepting WRAP's modeling of visibility improvement for other 

states. The Department has included in Section 8.6 of our Regional Haze SIP submittal a 

Performance Evaluation of the hybrid modeling system. The results show very good 

agreement between modeled concentrations and observed concentrations at the 98th 

percentile, 90th percentile, average of the 20% worst days and annual average. 

The comment also suggests that the modeling results should include the 98th percentile 

results. We believe including the 98th percentile results is contrary to rule and EPA 

guidance on this issue. In 40 CFR 51.308( d) it states "The reasonable progress goals 

must provide for an improvement in visibility for the most impaired days over the period 

of the implementation plan and ensure no degradation in visibility for the least impaired 

days over the same period." 40 CFR 51.301 states ''most impaired days means the 

average visibility impairment (measured in deciviews) for the twenty percent of 

monitored days' in a calendar year with the highest amount of visibility impairment." 

Least impaired days means the average visibility impairment (measured in deciviews ) 

for the twenty percent of monitored days in a calendar year with the lowest amount of 

visibility impairment. 

2 

The Department is not aware of any EPA guidance that indicates the 98th percentile 

visibility results should be used. To the contrary, in EPA's document "Additional 

Regional Haze Questions" August 3, 2006, this issue is addressed. In the response to 

Question I under the Reasonable Progress section it states· "Unlike the technical 

demonstration for CAIR or BART, the reasonable progress demonstration involves a test 

of a strategy. The strategy includes a suite of controls that has been identified through 

the identification of pollutants and source categories of pollutants for visibility 

impairment - the possible controls for these pollutants (and their precursors) and source 

categories - the application of four statutory factors and how much progress is made 

with a potential strategy with respect to the glide path. Modeling occurs with a 

strategy and is not a source-specific demonstration like the BART assessment. 

[emphasis added] 

The response to Question 2 in the "Additional Regional haze Questions" document, it is 

stated "Reasonable progress is not required to be demonstrated on a source-by-source 

basis. It is demonstrated based on a control strategy developed from a suite of controls 

that has been assessed with the four statutory factors and the uniform rate of 

progress. [emphasis added] 

It is clear to the Department that a BART type assessment (Le. 98th percentile) is not 

required. In fact, an assessment of individual sources is not required. The Response to 

both Question 1 and 2 indicates any modeling should be assessed against the uniform rate 

of progress (glidepath). Section 2.2 of "Guidance for Setting Reasonable Progress Goals 

Under the Regional Haze Program", the uniform rate of progress, or glidepath, is 

determined for the average of the 20% worst days and 20% best days. 

The Department has provided both the individual modeling results for sources and the 

cumulative modeling results for a control strategy for the group of sources that were left 

after the initial evaluation process was completed (see Section 9.5.1 of the RH SIP). We 

interpret the EPA guidance on Reasonable Progress to indicate that results for individual 

sources are not required. Therefore, any results presented would not have to include the 

98th percentile values and should be compared to the average ofthe 20% worst days. 

Nitrogen Oxides 

1. We believe that NDDH has overestimated the capital cost ofSNCR. 

Response 

The cost for SNCR that was used in the analysis was provided by MDU (adjusted to 2009 

dollars). The Department verified the cost by comparing MDU's estimate to other 

similar sized facilities. MDU's estimate was near the middle of the range of costs 

evaluated. MDU's estimate is a site specific estimate for a combustion unit that was 

retrofitted to be a fluidized bubbling bed combustor. The details of the estimate have 

been included in the supplement. The NDDH believes the estimate is within the ±30% 

accuracy required for this analysis and more accurate since it is site specific. 

3 
The annual operating cost was $1,041,000 per year (2009 dollars) or $13.36Ikw. This is 

nearly identical to the SNCR annual operating cost at M.R. Young Station Unit 1 of 

$13.44Ikw (2006 dollars) and $ 14.061kw (2006 dollars) at Stanton Unit 1. The operators 

of M.R. Young Station have not tried to avoid putting on SNCR. In fact, it may be just 

the opposite. The Stanton Unit·l estimate was made using EPA's Control Cost Manual. 

The NDDH believes the MDU estimate is within the ±30% accuracy required for this 

analysis. 

2. Visibility modeling should use the method described in the 12/09 BART modeling report. 

Response 

See response to Comment 4 under the sulfur dioxide section. 

Time Necessary for Compliance 

The NPS believes controls can be added more expeditiously. 

Response 

The Department provided a time necessary for installing the top control technologies that 

were considered cost effective. The amount of time will be affected by an available work 

force and scheduled outages. Several sources have begun working on BART controls 

early because of concerns about product and work force availability. We believe the 

amount of time is reasonable for a source subject to the Reasonable Progress 

requirements. 

Results, Conclusions and Recommendations 

1. The voluntary control of limestone injection can achieve a lower S02 emission rate than 

0.60 Ib/106 Btu. 

Response 

The NDDH has determined that no additional controls are required under the Reasonable 

Progress portion of the Regional Haze rules. The addition of limestone is somewhat 

voluntary by MDU. The 0.60 Ib/l06 Btu emission rate is the rate that MDU is 

comfortable that the particulate matter emission limits can be met using an electrostatic 

precipitator. An optimization study will be conducted to determine if a greater sulfur 

dioxide removal efficiency can be achieved. If it can, the proposed permit requires the 

lower emission rate (greater removal efficiency). 

2. NDDH should not rely on the CUE Cost model. 

Response 

See response to Comments 2 and 3 in sulfur dioxide section and Comment 1 of the 

nitrogen oxides section. 

4 

3. 	 NDDH should show the parameters used to estimate costs. 

Response 

The beginning of the supplement discusses the source characteristics, capacity, baseline 

emission rates, estimated control efficiencies, etc. The inlet sulfur content is shown in 

the excerpts from MDU's draft BART analysis. All the infonnation needed to estimate 

the operating cost, and the capital cost, is available. 

4. 	 NDDH has overestimated the cost of spray dryerlbaghouse option. 

Response 


See response to Comments I and 2 in the sulfur dioxide section. 


5. 	 NDDH should base its estimates on SNCR Total Capital Investment Costs on industry 

data instead of inflated estimates by sources seeking to avoid controls. 

Response 


The Department has made a comparison of MDU's estimated capital and annualized 


costs to other estimates in BART analyses. This comparison showed very good 


agreement with the average of all units. The annualized cost agrees very well with 


estimates for the M.R. Young Station and Leland Olds Station on a dollar-per-kilowatt 


basis. The NPS has been using the out-of-date EPA Control Cost Manual to estimate 


costs. The NDDH believes the site specific estimate for Heskett Unit 2 is reasonable 


based on the estimates provided for other facilities. 


6. 	 NDDH should provide reasons for rejecting the Cost Control Manual results in favor of 

the MDU results. 

Response 


See response to Comment 6 of this section and page 3 of the Supplementary Cost 


Infonnation. 
 

,

~ 

7. 	 NPS believes a proper NOx cost analysis will lead to a different conclusion about costs. I 

Response 


The NDDH believes the site-specific cost estimate provided MDU is sufficiently accurate 
 

for the Reasonable Progress analysis (see Response to Comment I, Nitrogen Oxides I section and Comments 2, 5 and 6 of this section). The amount of visibility improvement 


in the most impaired days for the application of SNCR will be less than 0.009 deciviews 


(estimated at 0.001 deciviews). This amount of visibility improvement is negligible. As 


stated in EPA's Guidance for Settling Reasonable Progress Goals under the Regional 


Haze Program (June I, 2007), the NDDH has the right to include other relevant factors in 
 

its decision on reasonable progress. The cost of SNCR on a dollar-per-ton and dollar-per­


deciview basis is excessive. The negligible amount of visibility improvement and the 


cost clearly indicates SNCR is not reasonable. 


5 
8. NDDH should use the BART modeling methodology. 

Response 


See response to Comment 4 in the Sulfur Dioxide section. 


6 

Appendix 1.3.3 


U.S. Environmental Protection Agency 


Comments on Supplement No. 1 


And 


Department's Response 

ENCLOSUREl 

EPA Region 8 Preliminary Comments on 


March 8.2010 Draft Regional Haze SIP Supplement Number 1 


(ELM Consultation Version) 


General Comment 

• 	 As noted in our January 8, 2010 comment letter for Antelope Valley Station and Coyote 

Station, based on your analysis, there appear to be available controls for Heskett Station 

Unit 2 under Reasonable Progress that carry similar costs to those found reasonable under 

BART. Given that the potential visibility improvements are likely underestimated by 

your hybrid modeling system, the analysis does not support your conclusions that it is not 

reasonable to impose these controls at this tim~. For further guidance, please refer to the 

Regional Haze Rule (64 FR 35732, July I, 1999). 

Detailed Comments 

SIP Text:· 

.1. 	 Reasonable Progress Goals - Required Controls for Point Sources and Table 9.9, 

Visibility Improvement and Cost Effectiveness: 

North Dakota Department of Health (NDDH) has chosen to heavily rely on visibility 

. improvement to reject Reasonable Progress controls for Heskett Station Unit 2 and other 

facilities on a unit-by-unit basis. However, visibility improvement is not one ofthe four 

Reasonable Progress statutory factors (cost. of compliance, time necessary for compliance, 

energy/non-air quality environmental impacts ofcompliance, and remaining useful life of 

any potentially affected sources). While we think· the State has the flexibility to consider 

visibility improvement for individual unit controls in Its decision-making, we have 

concerns with the State's methodology. 

When considering visibility improvement associated with controls at individual units, we 

consider it importarlt to include the 98th percentile day results in addition to the 20% 

worst days' results. Looking only at the 20% worst days dilutes the beneficial impacts of 

individual unit controls. We recognize that part ofthe focus in setting the reasonable 

progress goals vis-a-vis the uniform rate ofprogress i$ on the 20% worst days, but the 

uniform rate ofprogress and the reasonable progress goalS represent cumulative impacts 

and reductions across a range of sources and source categories. In that context, a 

cumulative regional scale deciview improvement value may have a different meaning 

because it is compared to a value needed to reach the uniform rate ofprogress. For 

example, while a deciview improvement of 0.1 deciview might not seem significant in an 

absolute sense, it may be significant if total deciview improvement needed to reach the 

unifonn rate ofprogress is 1 or 2 deciviews. For evaluating individual unit visibility . 

impacts, the BART approach represents the more reasonable model because it is 

specifically geared to consideration of unit-by-unit impacts. In our view, since the 98th 

percentile day results are used in determining BART, they should also be used in 

- 1 ­
determining Reasonable Progress controls for individual units. Also, a relatively low 

visibility benefit for controlling an individual unit should not be a major factor when 

selecting Reasonable Progress measures; given the ultiritate purpose ofthe Regional Haze 

program, cumulative effects across sources need to be considered. Heskett Station and 

other.power plants are some ofthe larger emittersin.the State and controls are available 

at reasonable cost effectiveness levels. 

2. 	 Table 9.8, Control Options Cost: 

. Table 9.8 requires some clarification. The statement in the middle ofthe table with an 

asterisk is unclear and could perhaps be deleted. Regarding footnote b, as the State used 

the Montana-Dakota Utilities Company (MDU) estimate, the references to Leland Olds 

and M.R. Young should be removed to eliminate confusion. NDDH references 

information related to the PGE Boardman plant. EPA Region 10 has not determined that 

these analyses are reasonable. Furthermore, in general we do not recommend relying on 

the 'CUECost model. This·was the·'model that MDUpriinarily used to estimate the costs 

that you refer to in your analyses. According to the BART Guidelines, in order to 

maintain and improve consistency, cost estimates should be based on the OAQPS Control 

Cost Manual where po·ssible (70 FR 39166, July 6, 2005). 

3. 	 Section 10.6.1.3, R.M. Heskett Station Unit 2: 

It appears that MDU and NDDH believe at least this minimal level of control is 

reasonable now. As such, it should be included as a required Reasonable Progress control 

in the SIP. NDDH notes that MDU has committed to increase S02 removal efficiency to 

a minimum of70% in this planning period. We note that in a June 9, 2006 letter from 

MDU to Terry O'Clair, MDU commits to "control S02 emissions by installing and ' 

operating the necessary equipment to use limestone as the bed material in the boiler." Is 

this still the intended teohnical approach for limestone injection? We suggest language 

be included in the SIP text to clarify the intended technical approach for limestone 

injection. In addition, the proposed 0.60 IblMMBtu emission limit is problematic; as 

discussed in comment 5 below, a more stringent limit is appropriate and reflects optimal 

use ofthe control technology. 

NDDH Proposed Permit to Construct - Heskett Station: 

4. 	 Based on your discussions with MDU, it appears that this level ofminimal control is 

considered reasonable at this time. Therefore, even if you disagree with our other 

comments regarding Reasonable Progress, at least this level ofS02 control should be 

included in the SIP as a required Reasonable Progress control measure. As such, the 

permit should more closely mirror the BART penmt format, including the appropriate 

3O-day rolling average emission limit and compliance detennination, monitoring, 

recordkeeping, and reporting requirements. 

5. 	 Based on our review ofthe control efficiency and emission rate specified in the proposed 

permit, the emission limit should calculate out to 0.38 IblMMBtu, not 0.60 IblMMBtu. 

The permit control efficiency of 70% removal is on a basis of S(h equivalent to the boiler 

inlet, while the 60% control efficiency that appears in Supplement No. 1 is on the basis of 

-2­
uncontrolled S02 in the exhaust stream. Considering that your analysis and cost 

estimates are based on the latter, the permit limits should be revised to be consistent with 

the findings in the analysis. 

According to the Clean Air Markets Division database, the:highest uncontrolled emission 

rate (exhaust) at Heskett Station Unit 2 in the past ten years was 0.951blMMBtu. At 60% 

control this equates to a 0.381b1MMBtu limit. In comparison, we find the 0.60 

IblMMBtu specified in the proposed permit represents an excessive margin of 

compliance, at only about 37% control. We would expect that the proposed permit 

specify an initial limit in the vicinity ofO.38IblMMBtu. IfNDDHhas reason to believe a 

lower limit might not be achievable, the permit could include a provision to adjust the 

limit upward, pending review ofstack test results. In order to adjust the permit limit 

later, a SIP revision would be required. An optimization study that is not defined in the 

permit and is subject only to NDDH approval (not EPA approval) does not ensure, in 

terms of federal enforceability,-that the so1.irCe will ultimately be subject to an emission 

limit in IblMMBtu that corresponds to at leaSt 60% control. IfNDDH wants to require an 

optimization study to determine ifcontrols can do better than 0.38 IblMMBtu and 60% 

control, we would have no issue with that. 

- 3 ­
ENVIRONMENTAL HEALTH SECTION 

Gold Seal Center, 918 E. Divide Ave. NORTH DAKOTA Bismarck, NO 58501-1947 


DEPARTMENT of HEALTH 
 701.328.5200 (fax) 

www.ndhealth.gov 

May 27, 2010 

Ms. Callie Videtich 

Director, Air Program 

U.S. EPA, Region 8 


1595 Wynkoop Street 


Denver, CO 80202-1129 


Re: 	 Comments on RH SIP 


Supplement No. 1 


Dear Ms. Videtich: 

This letter is in response to comments that your staff provided on the Department's Supplement 


No. 1 to the North Dakota State Implementation Plan for Regional Haze. With respect to the 


comments, our responses are as follows: 


General Comment 

As noted in our January 8, 2010 comment letter for Antelope Valley Station and Coyote Station, 

based on your analysis, there appear to be available controls for Heskett Station Unit 2 under 

Reasonable Progress thai carry similar costs to those found reasonable under BART. Given that 

the potential visibility improvements are likely underestimated by your hybrid modeling system, 

the analysis does not support your conclusions that it is not reasonable to impose these controls 

at this time. For further guidance, please refer to the Regional Haze Rule (64 FR 35732, July I, 

1999). . 

Response: 

The only controls at Heskett Station Unit 2 that have costs on a dollar-per-ton basis that are 

similar to required BART controls are limestone injection for sulfur dioxide control and staged 

combustion for nitrogen oxides controls. Limestone injection has a cost of more than $116.7 

million per deciview and staged combustion has a cost greater than $40.7 million per deciview. I These costs are considered excessive. EPA Guidance (Guidance for Setting Reasonable Progress 

Goals Under the Regional Haze Program; June 1, 2007) states "therefore, in assessing additional i 

emissions reduction strategies for source categories or individual, large scale sources, simple cost 

effectiveness estimates based on a dollar-per-ton calculation may not be as meaningful as a I 

Environmental HeaM Division of Division of Division of Division of 

Section Chiefs Office AlrQuality Municipal Facilities Waste Management Water Quality 

701.328.5150 701.328.5188 701.328.5211 701.328.5166 701.328.5210 

Printed on recycled paper. 
Ms. Videtich 	 2 May 27, 2010 

dollar-per-deciview calcu.Iation". Clearly, cost on a dollar-per-deciview basis is one of the four 

statutory factors that must be evaluated. We have evaluated all four statutory factors. 

The EPA Guidelines, Section 5.0, states "Howeve~., you have flexibility in how to take into 

consideration these statutory factors and any other factors that you have determined to be 

relevant." Since the purpose of the Regional Haze rules is to improve visibility in the Federal 

Class I areas, the Department has determined that actual visibility improvement by a reduction 

strategy for a source category, or source, is a relevant factor. The maximum improvement for 

the most impaired days is 0.009 deciviews when sulfur dioxide emissions from Heskett Station 

Unit 2 are reduced by 95% and nitrogen oxides by 40%. Any control alternative that reduces 

emissions by a smaller amoUnt would have even less impact on visibility impairment. The 0.009 

deciview improvement represents 0.05% improvement at Theodore Roosevelt National Park and 

Lostwood WildemessArea. This amount of visibility improvement is negligible and does not 

warrant additional controls. 

The comment also states "Given that the potential visibility improvements are likely 

underestimated by your hybrid modeling system, the analysis does not support your conclusions 

that it is not reasonable to impose these controls at this time." States in the west are relying on 

WRAP's modeling to establish Regional Haze visibility improvement progress much like we 

suspect EPA will for their own purposes in preparing the Montana Regional Haze SIP. As 

shown in Table 8.11 of our Regional Haze SIP, the Department's hybrid modeling approach 

predicts significantly greater· improvement in visibility for the BART controls compared to 

WRAP's modeling. This was expected, given the more realistic treatment of point source 

plumes by Calpuff compared to WRAP's grid modeling. Therefore, it appears inconsistent for 

EPA to argue that the Department's hybrid modeling system is underestimating visibility 

improvement, while accepting WRAP.' s modeling of visibility improvement for other states. 

The Department has included in Section 8.6 of our Regional Haze SIP submittal a Performance 

Evaluation of the hybrid modeling system. The results show very good agreement between 

modeled concentrations and observed concentrations for the 98th percentile, 90th percentile, 

average of the 20% worst days and the annual average. EPA has provided no basis for your 

statement that our hybrid modeling system is likely underestimating the amount of visibility 

improvement! 

Based on the excessive cost and virtually no visibility improvement from additional air pollution 

controls, we have determined that no additional controls are reasonable at this time. 

SIP Test 

1. 	 Reasonable Progress Goals - Required Controls for Point Source and Table 9.9, Visibility 

Improvement and Cost Effoctiveness: 

North Dakota Department of Health (NDDH) has chosen to heavily rely on visibility 

improvement to reject Reasonable Progress controls for Heskett Station Unit 2 and other 

facilities on a unit-by-unit basis. However, Visibility improvement is not one of the four 

Reasonable Progress statutory factors (cost of compliance, time necessary for compliance, 
Ms. Videtich 3 May 27, 2010 

energy/non-air quality environmental impacts of compliance, and remaining useful life of 

any potentially affected sources). While we think the State has the flexibility to consider 

visibility improvement for individual unit controls in its decision-making, we have c(}ncerns 

.with the State's methodology. 

When considering visibility improvement associated with controls at individual units, we . 

consider it important to include the 9l1h percentile 4ay results in addition to the 20% worst 

days'results. Looking only ai the 20% worst daJ's dilutes the beneficial impacts ofindividual 

unit controls. We recognize that part ofthe focus in setting the reasonable progress goals 

vis-II-vis the uniform rate ofprogress is on the 20% worst days, but the uniform rate of 

progress and the reasonable progress goals represent cumulative impacts and reductions 

across a range ofsources and source categories. In that context, a cumulative regional scale 

deciview improvement value may have a different meaning because it is compared to a value 

needed to reach the uniform rate ofprogress. For example, while a deciview improvement of 

0.1 deciview might not seem significant in an absolute sense, it may be significant iftotal 

deciview improvement needed to reach the uniform rate ofprogress is 1 or 2 deciviews. For 

evaluating individual unit visibility impacts, the BART approach represents the more 

reasonable model because it is specifically geared to consideration ofunit-by-unit impacts. 

In our view, since the 98'h percentile day results are used in determining BART, they should 

also be used in determining Reasonable Progress controls for individual units. Also, a 

relatively low visibility benefit for controlling an individual unit should not be a major factor 

. when selecting Reasonable Progress measures; given the ultimate purpose of the Regional 

Haze program, cumulative effects across sources need to be considered Heskett Station and 

other power plants are some ofthe larger emitters in the State and controls are available at 

reasonable cost effectiveness levels. 

Response: 

As stated in the response to the General Comment, the Department evaluated the cost on a 

dollar-per-ton and dollar-per-deciview basis (statutory factor). The Department also used its 

allowed discretion in evaluating the amount of actual visibUity improvement (deciviews) . 

. After having considered all four statutory factors, and other relevant factors as allowed by 

EPA guidance, the Department has concluded that no additional controls are warranted. This 

decision was not based solely· on the amount of visibility improvement as you have 

. suggested. 

The comment also suggests that the modeling results should include the 98th percentile 

results. We believe including the 98th percentile results is contrary to rule and EPA guidance 

on this issue. In 40 CFR 51.308( d) it states "The reasonable progress goals must provide for 

an improvement in visibility for the most impaired days over the period of the 

implementation plan and ensure no degradation in visibility for the least impaired days over 

the same period." 40 CFR 51.301 states "most impaired days means the average visibility 

impainnent (measured in deciviews) for the twenty percent of monitored days in a calendar 

year with the highest amount of visibility impainnent." Least impaired days means the 

average visibility impainnent (measured in deciviews) for the twenty percent of monitored 

days in a calendar year with the lowest amount of visibility impainnent. 
Ms. Videtich 4 May 27, 2010 

The Department is not aware of any EPA guidance that indicates the 98th percentile visibility 

results should be used. To the contrary, in EPA's document "Additional Regional Haze 

Questions" August 3, 2006, this issue is addressed. In the response to Question 1 under the 

Reasonable Progress section it states "Unlike the technical demonstration for CAIR or 

BART, the reasonable progress demonstration involves a test of a strategy. The strategy 

includes a suite of controls that has been identified through the identification of pollutants 

and source categories of pollutants for visibility impairment - the possible controls for these 

pollutants (and their precursors) and source categories - the application of four statutory 

lacton and how much progress is made with a potential strategy with respect to the 

glide path. Modeling occurs with a strategy and is not a source-specific demonstration 

. like the BART assessment. [Emphasis added] 

In response to Question 2, it is stated "Reasonable progress is not required to be 

demonstrated based on a source-by-source basis. It is demonstrated based on a control 

strategy developed from a suite of controls that has been assessed with the four statutory 

factors and the uniform rate of progress. [Emphasis added] 

It is clear to the Department that a BART type assessment (i.e 98th percentile) is not required. 

In fact, an assessment of individual sources is not required. The Response to both Question I 

and 2 indicates any modeling should be assessed against the uniform rate of progress 

(gJidepath). In Section 2.2 of "Guidance for Setting Reasonable Progress Goals Under the 

Regional Haze Program", the uniform rate of progress, or glidepath, is determined for the 

average of the 20% worst days or 20% best days. 

The Department has provided both the individual modeling results for sources and the 

cumulative modeling results for a control strategy for the group of sources that were left after 

the initial evaluation process was completed (see Section 9.5.1 of the RH SIP). We interpret 

the EPA guidance on Reasonable Progress to indicate that results for individual sources is not 

required. Therefore, any results presented would not have to include the 98th percentile 

values and should be compared to the average of the 20% worst days. 

With regard to cost, you claim that some of the controls are available at a reasonable cost. 

However, EPA has provided no guidance on cost effectiveness on either a dollar-per-ton, or 

more importantly, a dollar-per-deciview basis. As you have pointed out, other relevant 

factors may be considered in our decision regarding controls for Reasonable Progress. We 

believe the lack of visibility improvement by the addition of controls is extremely relevant. 

2. Table 9.8, Control Options Cost: 

Table 9.8 requires some clarification. The statement in the middle of the table with an 

asterisk is unclear and could perhaps be deleted. Regardingfootnote b, as the State used the 

Montana-Dakota Utilities Company (MDU) estimate, the references to Leland aids and MR. 

Young should be removed to eliminate confusion. NDDH references information related to 

the PGE Boardman plant. EPA Region 10 has not determined that these analyses are 

reasonable. Furthermore, in general we do not recommend relying on the CUE Cost model. 
Ms. Videtich 5 May 27, 2010 

This was the model that MDU primarily used to estimate the costs that you refer to in your 

analyses. According to the BART Guidelines, in order to maintain and improve consistency, 

cost estimates should be based on the OAQPS Control Cost Manual where possible (10 FR 

39J66, July 6, 2005). 

Response: 

The statement in the middle of the table and footnote b will be removed. 

Regarding the CUE Cost Model, the Department only. used it to determine the cost of 

controls for Heskett Unit 2 for the purpose of checking' MDU's estimate. Based on our 

testing of the CUE Cost Model for SNCR versus the Control Cost Manual, it appears they 

provide similar results. All costs were provided by MDU or extrapolated from other BART 

analyses. MOU used the Control Cost Manual Procedures to develop their cost estimate. 

Additional information has been included which provides the details of MDU's cost 

estimates. 

The Department has also reviewed the estimated cost of the baghouse and compared it to the 

cost at Stanton Unit 1 and the Gascoyne 175 plant. The annualized cost for Stanton Unit 1 

was $25.921kw (2007 dollars) and $15.34Ikw (2004 dollars) at Gascoyne 175. The 

annualized cost at Heskett Unit 2 is $16.661kw (2009 dollars). Both the Stanton Unit 1 and 

Gascoyne 175 estimates were prepared using the procedures of the Control Cost Manual. 

We beJieve the estimate is accurate. The CUE Cost Model is easier to use and is provided by 

EPA. It appears to provide reliable results. 

3. Section 10.6.1.3, R.M Heskett Station Unit 2: 

It appears that MDU and NDDH believe at least this minimal level of control is 

reasonable now. As such, it should be included as a required Reasonable Progress 

control in the SIP. NDDH notes that MDU has committed to increase S01 removal 

efficiency to a minimum of 70% in this planning period We note that in June 9, 2006 

letter from MDU to Terry a'Clair, MDU commits to "control S01 emissions by installing 

and operating the necessary equipment to use limestone as the bed material in the 

boiler." Is this still the intended technical approachfor limestone injection? We suggest 

language be included in the SIP text to clarify the intended technical approach for 

limestone injection. In addition, the proposed 0.60 IblMMBtu emission limit is 

problematic; as discussed in comment 5 below, a more stringent limit is appropriate and 

reflects optimal use ofthe control technology. 

Response: 

The Department has determined that additional controls at Heskett Unit 2 are not 

reasonable at this time. The S02 reductions that will be achieved are an agreement 

between the Department and MDU and are not required by the Regional Haze rules. 
Ms. Videtich 	 6 May 27, 2010 

The technical approach is still to use limestone in the bed of Heskett Unit 2 to achieve 

reductions fr-om their current sulfur dioxide emission rate. Section 10.6.1.3 already 

indicates that limestone will be injected into the boilers. Whether the limestone will 

replace all of the bed material is unknown at this time. We believe Section 10.6.1.4 

covers this issue. 

NDDH Proposed Permit to Construct - Heskett Station 

4. 	 Based on your discussions with MDu, it appears that this level of minimal control is 

considered reasonable at this time. Therefore, even if you disagree with our other 

comments regarding Reasonable Progress, at least the level of S02 control should be 

included in the SIP as required Reasonable Progress control measure. As such, the 

permit should more closely mirror the BART permit format, including the appropriate 

30-day rolling average emission limit and compliance determination, monitoring, 

recordkeeping, and reporting requirements. 

Response: 

Since we have detennined that no additional controls are required under Reasonable 

Progress, we believe it is inappropriate to include the reductions that will be achieved at 

Heskett Station Unit 2 under that portion of the SIP. We have included the reductions in 

10.6.1, Emission Reductions Due to Ongoing Air Pollution Control Programs. Because of 

our findings on the Reasonable Progress analyses and the somewhat voluntary nature of 

the reductions, we believe the discussion of the Heskett Unit 2 reductions is more 

appropriately included in this section. For the same reasons, we believe the Permit to 

Construct should afford MDU some flexibility in meeting the emission limits. 

5. 	 Based on our review ofthe control efficiency and emission rate specified in the proposed 

permit, the emission limit should calculate out to 0.38 IblMMBtu, not 0.60 IbIMMBtu. 

The permit control efficiency of70% removal is on a basis ofS02 equivalent.to the boiler 

inlet, while the 60% control efficienCy that appears in Supplement No. J is on the basis of 

uncontrolled SO} in the exhaust stream. Considering that your analysis and cost 

estimates are based on the latter, the permit limits should be revised to be consistent with 

the findings in the analysis. 

According to the Clean Air Markets Division database, the highest uncontrolled emission 

rate (exhaust) at Heskett Station Unit 2 in the past ten years was 0.95 IbIMMBtu. AT 

60% control this equates to a 0.381b1MMBtu limit. In comparison, we find the 0.50 

IblMMBtu specified in the proposed permit represents an excessive margin of 

compliance, at only about 37% control. We would expect that the proposed permit 

specify an initial limit in'the vicinity ofO.38IbIMMBtu. IfNDDH has reason to believe a 

lower limit might not be achievable, the permit could include a provision to adjust the 

limit upward, pending review ofstack test results. In order to adjust the permit limit 

later, a SIP revision would be required An optimization study that is not defined in the 

permit and is subject only to NDDH approval (not EPA approval) does not ensure, in 

terms offederal enforceability, that the source will ultimately be subject to an emission 
Ms. Videtich f 7 May 27, 2010 

limit in IblMMBtu that corresponds to at least 60% control. IfNDDH wants to require 

an optimization study to determine ifcontrols can do better than 0.38 JblMMBtu and 60% 

control, we would have no issue with that. 

Response: 

The 70% reduction of potential S02 emissions is the rate that MDU believes can be 

achieved while still maintaining compliance with their particulate matter emission limit.' 

Since Heskett Unit 2 is equipped with an electrostatic precipitator, not a baghouse, the 

Department believes an increase in particulate matter emissions is a concern. This is one 

of the reasons for the optimization , study. In addition, the amount of ~02 reduction from 

limestone injection at a retrofitted bubbling fluidized bed combustor is unknown. Our 

experience with Red Trail Energy's bubbling fluidized bed combustor indicates that the 

80-90% removal rate at circulating fluidized bed combustion units may not be achievable 

at some bubbling fluidized bed units. 

The Reasonable Progress analysis indicates a 60% reduction from the current actual 

emissions. This equates to an 82% reduction of the potential-to-emit. The agreement 

(included in the Permit to Construct) only requires an overall removal efficiency of 70% 

from the potential-to-emit. The agreement with MDU will reduce current emissions by 

about 34% (see Section 10.6.1.3). Using a baseline of 0.91 Ib/l06 Btu, this equates to 

0.60 Ib/l06 Btu. Based on an annual average sulfur content of 0.71 % and a heat content 

of 7100 Btu/lb, the potential-to-emit is 2.0 Ibll06 Btu. Thirty percent of the sulfur 

reaching the inlet of the boiler (70% reduction of the inlet sulfur content) equates to 0.60 

Ib/l06 Btu. 

The Department cannot guarantee that emissions will be any lower than 0.60 Ib/106 Btu 

after the optimization study is completed. If a lower rate can be achieved, the Permit to 

Construct requires the lower rate. 

If you have any questions, pJease contact Tom Bachman ofmy staff at (701 )328-5188. 

r?~~ Terry L. O'Clair, P.E. 

Director 

Division of Air Quality 

TLOITB:csc 

xc: Abby Krebsbach, MDU