### Comments on Proposed BART Permit s for Nebraska Public Power District (NPPD) Gerald Gentleman Station (GGS) Units #1 and #2

Revised, January 18 , 2011

Nebraska Public Power District ( NPPD ) operates the Gerald Gentleman Station ( GGS )

, which includes two El ectric Generating Unit s (EGU s ), near Sutherland

, NE

. GGS

includes two BART

- eligible boiler s which burn pulverized Powder River Basin (PRB)

sub

- bituminous coal ( 8

, 576 Btu/lb; 0.30 % sulfur; 4.69% a sh in 2001 )

. EPA’s Clean Air Markets (CAM) database shows th at, in 2009, GGS ranked #48 (of 1

, 230 facilities) in

SO 2 

### emissi ons at 31,931 tons, and ranked #20 in NO X 

### emissions at 14,987 tons. The useful remaining life of GGS Units 1 and 2 is greater than 20 years under the current NPPD energy resource plan. Therefor e the remaining useful life has no impact on the annualized estimated control technology cost at this time.

The plant is located within 400 km of three Class I areas ( Badlands

, Wind Cave , and Rocky Mountain National Parks ) which are administer ed by the Na tional Park Service

. Modeling analyses have shown that GGS causes visibility impairment in the Badlands National Park (NP) @ 2.9 deciviews (dV) three

- year average 98 th 

### percentile impact, Wind Cave NP (2.5 dV), Rocky Mountain NP (1.1 dV), and Wichita Mount ains Wilderness (1.2 dV). GGS also contributes to visibility impairment at the Hercules Glades (0.7 dV) and Mingo (0.5 dV) Class I Wilderness areas. The cumulative impact of GGS on visibility is 9.3 dV.

Unit 1 is a dry

- bottom, wall

- fired boiler rated at 665 MW (net ). Unit 1 is equipped with a fabric filter to control particulate matter (PM 10 

### )

. It appears that Low

- NO

x 

### Burners (LNB)

and Over

- Fire Air (OFA) were installed 2005

– 2006 to reduce nitrogen oxides (NO

x 

### ) from about 0.45 pounds per million Btu (lb /mmBtu) and 12,000

– 14,000 tons per year (tpy) to about 0.2 2 lb/mmBtu and about 5,000

- 6,000 tpy. 1 

### T here are no controls for sulfur dioxide (SO 2 

### ) , which typically is emitted at 0. 5

– 0.6 lb/mmBtu and 14,000

– 1 7 ,000 tpy

. CAM data show that, in 2009, GGS Unit 1 ranked #82 (of 3,563 units) in SO 2 

### emissions at 15,805 tons, and ranked #57 in NO X 

### emissions at 5,446 tons.

Unit 2 is a dry

- bottom, wall

- fired boiler rated at 700 MW (net). U nit 2 is equipped with a fabric filter to control particulate matter (PM 10 

### ) . T here are no controls for SO 2 

### , which typically is emitted at 0.5

– 0.6 lb/mmBtu and 14,000

– 1 7 ,000 tpy. There are no controls

for NO

x 

### , which typically is emitted at 0. 30

– 0. 35 lb/mmBtu and 8 ,000

– 1 0 ,000 tpy. CAM data show that, in 2009, GGS Unit 2 ranked #80 (of 3,563 units ) in SO 2 

### emissions at 16,125 tons, and ranked #11 in NO X 

### emissions at 9,540 tons.

1 According to NDEQ, ―On January 4, 2006, the Department received a PSD Construction Permit appli cation for the replacement of Unit 1’s burner equipment system including an overfire air port system. NPPD installed new Low NOx Burners (LNB) on Unit 1 because the existing burners were near the end of their useful life and to be pro

- active in installing expected Best Available Retrofit Technology (BART) controls. A PSD construction permit was issued to GGS for the installation of the LNB on Unit 1 on August 18, 2006. A PSD permit was required for the modification due to the expected increase in carbon

mon oxide emissions as a result of the LNB installation.‖

### 2

In August of 2008 we filed comments regarding NPPD’s BART analyses

. W e are updating our comments to reflect new information obtained since 2008.

B ART Analyses

As noted by NPPD, t he five basic steps of a case

- by

- case BART analysis are: 1. Identify All Available Retrofit Control Technologies. Control technologies should

include pollution prevention, use of add

- on controls and combinations of the two. 2. Eliminate Technically Infeasible Options. Technologies demonstrated to be infeasible

based on chemical, physical, and engineering principles are excluded from further

consideration. 3. Evaluate Control Effectiveness of Remaining Control Technologies. T echnically

feasible control technologies are ranked in the order of highest expected emission

reduction to lowest expected emission reduction and are evaluated following a ―top

down‖ approach similar to BACT analyses. 4. Evaluate Impacts and Document Resul ts. Impacts that should be considered for each

control technology include: cost of compliance, energy impacts, non

- air quality

environmental impacts, and the remaining useful life of the unit to be controlled.

5. Evaluate Visibility Impacts. Modeling shoul d be p er formed on the pre

- and post

control emissions to determine the actual impact on visibility and assess the visibility improvement achieved and at what cost. This step does not need to be performed if the most stringent control technology is chosen.

However, before we begin a step

- by

- step discussion of the BART proposed for GGS for each pollutant, we provide some general comments.



### Cost

- Effectiveness Metrics

BART is not necessarily the most cost

- effective solution. Instead, it represents a broad

con sideration of technical, economic, energy, and environmental (including visibility improvement) factors. For example

, Oregon DEQ has established a cost/ton threshold of $7,300 based upon the premise that improving visibility in multiple Class I areas warra nts a higher cost/ton than where only one Class I area is affected. In their BART proposal for the San Juan Generating Station, New Mexico used a range from $5,946/ton to $7,398/ton. Colorado uses $5,000/ton, New York uses $5,500/ton, and Wisconsin is

usin g $7,000

- $10,000/ton as its BART threshold. 2



### One of the options suggested by the BART Guidelines to evaluate cost

- effectiveness is cost/deciview. We believe that visibility improvement must be a critical factor in any program designed to improve visibil ity. Compared to the typical control cost analysis in which estimates fall into the range of $2,000

- $10,000 per ton of pollutant removed,

2 ―The Department used cost

- per

- ton reduced as the primary metric for determining the BART level of control. The upper limit for this metric was $7,000 to $10,000 per ton, which reflects historical low

- end costs for controls required under BACT.‖ BEST AVAILABLE RETROFIT TECHNOLOGY AT NON

EGU FACILITIES April 19, 2010, WISCONSIN DEPARTMENT OF NATURAL RESOURCES

### 3

spending mill ions of dollars per deciview (dv ) to improve visibility may appear extraordinarily expensive. However, our compilation 3 

### of BART analyses across the U.S.

reveals that the average cost per dv proposed by either a state or a BART source is $1 4

- $ 18 million

, 4 

### with a maximum of $5 1 million per dv proposed by South Dakota at
the Big Stone power plant. (For examp le, w e note that OR DEQ has explicitly chosen $10 million/dv as a cost criterion, which is somewhat below the national average. )

NPPD has presented extensive information to support its contention that costs of pollution controls are increasing, and that this should be taken into account in these cost analyses. NPPD appears to have used cost escalation as its rationale to present a mix of costing techniques that borrow from the OAQPS Control Cost Manual (Cost Manual), and NPPD’s consultant’s proprietary me thods. We agree with NPPD that inflation should be a factor in these cost analyses. In fact, we included just such a factor our own analyses

that we discuss later in this document.

Much of NPPD’s argument against installing pollution controls at GGS cent ers on the

then

- increasing worldwide costs of pollution controls in general ; that is no longer true. According to a report prepared for the Utility Air Regulatory Group: 5

The recent moderation in the world economy has removed many of the supply barriers an d eased cost escalation. The cost to retrofit FGD and SCR equipment is expected to moderate from peak levels observed in the last 24 months, but may not significantly decline. A key reason is the ever

increasing complexity of the host sites. As host units are older and of smaller generating capacity, there is less available space for control equipment. Frequently, convoluted and complex ductwork is required, increasing retrofit difficulty. 

### While the concern about complex retrofits may be true for eastern EG Us where the cap

and

- trade programs allowed utilities to control the easiest and most cost

- effective retrofits

first

, and leave the more complex retrofits for later (or never), no such ―natural selection‖ process exists in Nebraska . T here is no reason to believe that Gerald Gentleman would be an especially difficult retrofit.

Furthermore , i f the NPPD cost argument were carried to its logical conclusion, then no EGU should be required to install any pollution control equipment that involves a large capital expenditure. Instead, we believe that pollution control is an inherent cost of doing business, and that NPPD must show why GGS would experience uniquely higher costs for pollution controls than would normally be considered reasonable.

Cost Estimation M ethods

The cost estimates submitted by NPPD are severely lacking in the types of specific information needed to give them credibility. Although there are several methods for estimating costs, our experience leads us to believe that no one method is perfec t and that the costing methods need to be tempered by real

- world data. And, while NDEQ states

3 http://www.wrapair.org/forums/ssjf/bart.html

4 For example, PacifiCorp has stated in its BART analysis for its Bridger Unit #2 that ―The incremental cost effectiveness for Scenario 1 compared with the baseline for the Bridger WA, for example, is reasonable at $580,000 per day and $18.5 million per deciview.‖

5 J.E. Chichanowicz Report ―Current Cap ital Cost and Cost Effectiveness‖

- January 2010

### 4

that ― NPPD used vendor quotes for the majority of the analysis,‖ we found no documented actual vendor quotes in the materials made available for our review. 6 In t hat case, t 

### he BART Guidelines recommend use of the OAQPS Control Cost Manual:
The basis for equipment cost estimates also should be documented, either with data supplied by an equipment vendor (i.e., budget estimates or bids) or by a referenced source (su ch as the OAQPS

Control Cost Manual

, Fifth Edition, February 1996, 453/B

- 96

- 001). In order to maintain and improve consistency, cost estimates should be based on the OAQPS Control Cost Manual, where possible. The Control Cost Manual addresses most control technologies in sufficient detail for a BART analysis. The cost analysis should also take into account any site

- specific design or other conditions identified above that affect the cost of a particular BART technology option.



### Cost Escalation

NPPD includ ed an escalation component in its cost estimates. Larry Sorrels, an economist at EPA’s Office of Air Quality Planning and Standards (OAQPS) commented 7



### upon use escalation factors to calculate the levelized cost of each technology.

Estimating real annual co sts means no use of escalation factors

...



### I t is not appropriate to escalate costs into the future and compare them against current

cost thresholds.

Inflation and the Allowance for Funds During Construction:

Mr. Sorrels also provided 8 

### insight on matters pe rtaining to inflation and the Allowance for Funds During Construction (AFUDC):
On cost indexes, I prefer the CEPCI (Chemical Engineering Plant Cost Index) for escalating/deescalating costs for chemical plant and utility processes since this index specifica lly covers cost items that's pertinent to pollution control equipment (materials, construction labor, structural support, engineering & supervision, etc.). The Marshall & Swift cost index is useful for industry

- level cost estimation, but is not as accurate at a disaggregated level when compared to the CEPCI. Thus, I recommend use of the CEPCI as a cost index where possible.

I agree with including AFUDC in a capital cost estimate if this is already included in the base case as per a utility commission dec ision. Otherwise, I do not agree with its inclusion.



### T he CEPCI has decli ned since the NPPD analysis (see chart below)

6 The NPPD BART analysis contained such general statements as ―Equipment costs were developed based on vendor budgetary quotes‖ and ―Major equipment costs were based on vendor budgetary quotes.‖ NDEQ

refers to the ―2008 S&L NPPD Study‖ but we were no t provided a copy.

7 E

- mail dated September 7, 2010 to Don Shepherd of NPS.

8 7/21/10 e

- mail to Don Shepherd

### 5

and, as we will show later, NPPD included AFUDC costs that amount to scores of

millions of dollars.

Annual Costs

The Direct Annual Cost (DAC) component of the process is also important because it represents a significant portion of the Total Annual Cost. The methods presented by the Cost Manual for estimating DAC appear to be straight

- forward and should accurately represent annual co sts with no need for adjustment. However, we note in our review of the BART analyses p resented by NPPD that there appears to be a consistent significant

overestimation of DAC.

Visibility Improvement Metrics

NDEQ considered visibility improvements at Badl ands NP, but effectively ignored potential improvements to visibility in the other Class I areas where GGS is also causing or contributing to visibility impairment. We continue to believe that it is appropriate to consider both the degree of visibility imp rovement in a given Class I area as well as the cumulative effects of improving visibility across all of the Class I areas affected. It simply does not make sense to use the same metric to evaluate the effects of reducing

emissions from a BART source that impacts only one Class I area as for a BART source that impacts multiple Class I areas. And, it does not make sense to evaluate impacts at one Class I area, while ignoring others that are similarly significantly impaired. It follows

### 6

that, if emission from the BART source are reduced, the benefits will be spread well beyond only the most impacted Class I area, and this must be accounted for. 9 

### While NDEQ presented data describing improvements to visibility at Badlands NP that would

result from the various con trol scenarios it investigated, NDEQ still has not explained how it incorporated this information on impacts upon all Class I areas into its BART

decision.

The BART Guidelines represent an attempt to create a workable approach to estimating visibility im pairment. As such, they require several assumptions, simplifications, and shortcuts about when visibility is impaired in a Class I area, and how much impairment is occurring. The Guidelines do not attempt to address the geographic extent of the impairment, but assume that all Class I areas are created equal, and that there is no difference between widespread impacts in a large Class I area and isolated impacts in a small Class I area. To address the problem of geographic extent, we have been looking at

the cumulative impacts of a source on all Class I areas affected, as well as the cumulative benefits from reducing emissions. While there are certainly more sophisticated approaches to this problem, we believe that this is the most practical, especially when

c onsidering the modeling techniques and information available. For example, we understand that the Oregon Department of Environmental Quality used a similar approach in its analyses when it evaluated the benefits of various control strategies on all

14 of t he Class I areas within 300 km of the Boardman power plant.

Average versus Incremental Cost

- Effectiveness

Contrary to EPA g uidance to consider both average and incremental cost

- effectiveness

, NDEQ appears to have relied excessively upon incremental cost s and benefits when moving from a lower level of emission control to a higher level. Although NDEQ

calcula ted the average costs of scrubbin g SO 2 

### and concluded they were ―reasonable ,‖ it reported only the incremental costs and benefits in the body of its S IP analysis. NDEQ’s treatment of Selective catalytic reduction (SCR) is more troubling. While NDEQ correctly asserts that:
Although SCR is a feasible control technology, it would be most practical to install SCR in

combin ation with combustion controls... Ther efore, the cost associated with installing LNB/OFA is linked to this control technology throughout the analysis. 

### NDEQ goes on to reject addition of SCR to LNB/OFA on the basis of excessive

incremental costs and without estimating average cost

- effectiveness of ― SCR in

combination with combustion controls ‖ : The NDEQ determined that the incremental cost for the addition of SCR is excessive and that LNB/OFA would be required for BART. We believe that NDEQ must evaluate the cost

- effectiveness of 

### ― SCR in combinat ion with

combustion controls ‖ as it had recommended.

9 For example, the cumulative benefits have been a factor in the BART determinations by NM, OR, and
WY, as well as EPA in its proposals for the Navajo Generating Station and the Four Corners Power Plant.

### 7

BART for Sulfur Dioxide (SO 2 

### )

Step 1: Identify All Available Retrofit Control Technologies and Step 2: Eliminate Technically Infeasible Options.

NPPD presented the following options and feasibility determinations:

Coal Desulfurization Infeasible

- not demonstrated for low

- sulfur PRB coal

Pahlman Process Infeasible

- not demonstrated on large coal

- fired boilers Other Regenerative Processes Infeasible

– none have been demonstrated on large coal

- f ired

boilers Wet Scrubbing Feasible based on demonstrated performance on many similar

units Dry Scrubbing Feasible based on demonstrated performance on many similar

units



### NPPD and NDEQ erred by not considering Dry Sorbent Injection (DSI) , which uses no

water

. ―Dry sorbent duct injection is a means for utility and large boiler operators to reduce emissions of sulfur oxides. The effectiveness of dry sorbent injection is dependent on the type of sorbent, injection location, and system operating parameters...F or higher removal requirements (greater than 50%), either trona or sodium bicarbonate is recommended. For systems equipped with baghouses (like GGS), trona is the more cost

effective sorbent since the residence time provided by the baghouse allows for this lower

cost sorbent to be used.‖ 10



### EPA states 11 

### that DSI can achieve up to 80% control efficiency. (While EPA also notes that DSI is an emerging technology for medi um

- to

- small industrial boilers, that is because larger boilers typically are required to inst all the more

- e fficien t wet or dry scrubbing systems.) For example, Nalco

- Mobotec advertises that its DSI systems can

achieve 50%

- 80% SO 2 

### control.

Oregon Department of Environmental Quality (ODEQ) is requiring DSI as BART for the

Boardman Power Plant. Ac cording to ODEQ

, “Dry sorbent injection is considered to meet the BART requirements because it is cost effective and will provide significant visibility improvement (>0.5 dV) in at least the Mt. Hood wilderness 12 

### area. Based on installations on

smaller boil ers, DSI can achieve emission reductions of 30 to 70%. Considering the size of the Boardman unit (duct geometry and exhaust gas flow), a DSI system may perform in the lower range of the control effectiveness, but the effectiveness could be improved with

ad ditional operating experience. Therefore, DEQ proposes a limit of 0.40 lb/MMBtu (35% emission reduction) in 2014 to satisfy the BART requirements. The limit is lowered to 0.30 lb/MMBtu (51% emission reduction) in 2018. The limit in 2018 could be met by fur ther refinements to the DSI system or in combination with ultra

- low sulfur coal or supplemental fuels, such as biomass.‖ (Please note that the Boardman EGU uses an electrostatic

10 Jon Norman, P.E., James R. Paye, Keith Day, O’BRIEN & GERE ENGINEERS, INC. ―DECISION

MATRIX FOR DRY SORBENT DUCT INJECTION FOR CONTROL OF SULFUR OXIDE

EMI SSIONS FROM COMBUSTION PROCESSES‖ Paper # 6

11 Air Pollution Control Technology Fact Sheet EPA

- 452/F

- 03

- 034

12 Addendum to the DEQ BART Report for the Boardman Power Plant (November 30, 2010)

### 8

precipitator to control particulate (PM) emissions, which decreases the effect iveness of DSI versus a baghouse like GGS.)



### Step 3: Evaluate Control Effectiveness of Remaining Control Technologies

N DEQ has underestimated the ability of modern SO 2 

### control systems. NDEQ effectively assumed that wet and dry scrubbing could achieve only 80%

- 87% SO 2 

### control down to

0.1

- 0.15 lb/mmBtu. It appears that NDEQ evaluated scrubbing at both 0.15 lb/mmBtu and 0.1 lb/mmBtu, but provides no information on how those analyses were conducted.

Unlike the retrofitting of NO

x 

### controls that is highly de pendent upon the existing boiler configuration, the SO 2 

### controls that could be added at GGS would be completely new, and should therefore be capable of performing as well as at a greenfield facility.

It is easier to achieve a higher SO 2 

### control efficienc y on coals with higher inherent, uncontrolled emissions. And, as uncontrolled emissions increase, controlled emissions will also tend to increase despite the increasing SO 2 

### control efficiency. It follows that it is harder to achieve a higher control effici ency on a gas stream with a lower inlet SO 2 

### concentration, but easier to achieve a lower outlet concentration. So, if one can achieve

lower emission rate on a ― dirtier ‖ gas stream, it would indicate a higher degree of scrubbing success. All of this must b e considered when determining the level of SO 2 

### control that is feasible for a given coal. 13



### Inspection of Table 1.a. (below) reveals that wet FGD systems are achieving (e.g., Navajo Generating Station, Intermountain Power) or being proposed/permitted at 0 .04

– 0.09 lb/mmBtu on coals with much higher uncontrolled emissions than currently seen at GGS. Based upon this data and a consideration of GGS’ cleaner coal quality, we believe

that a new wet FGD at GGS should be able to achieve 0.04 lb/mmBtu 14 

### (or lower) on a 30

- day rolling average.

13 For the sake of consistency, it is assumed that the SO 2 emissio n factor is dependent upon the coal type, but independent of the boiler type. The natural process of retention of sulfur in the ash is just as

fundamental a characteristic of the coal burned as its sulfur content and its heating value. So, bituminous

coals would emit 95% of their sulfur content as SO 2 , while sub

- bituminous coals wo u ld emit 87.5%, and

li gnites 75%.

14 For example, EPA proposed to permit the Desert Rock power plant at 0.06 lb/mmBtu (24

- hour average) despite coal with almost three times the unc ontrolled emissions as at GGS.

### 9 Table 1 .a. Wet Scrubber SO 2 Rankings (30

- day rolling averaging period)

SO 2 Coal Quality Capacity Emissions

or Limits Control

Facility Name Unit Status Permit

# %S (Btu/lb) (lb/mmBtu) MW (lb/mmBtu) (%)

NPPD

- GGS ( Proposed) 1&2 NE 0.30 8576 0.555 1365 0.040 92.8%

Colstrip 4 operating MT 0.75 8487 1.546 778 0.093 94.4%

Colstrip 4 operating MT 0.75 8487 1.546 778 0.091 94.5%

Intermountain

Pwr 3 issued UT

0065 0.75 11193 1.273 950 0.090 92.9%

Navajo 1 operating AZ 0.53 10919 0.922 803 0.072 92.9%

Navajo 3 operating AZ 0.53 10919 0.922 803 0.064 93.2%

Sithe

- Desert

Rock pending EPA 0.82 8910 1.611 1500 0.060 96.3%

Sithe

- Toquop application NV 1.4 8215 2.982 750 0.060 98.0%

Mustang application NM 1.56 864 7 3.157 300 0.060 98.1%

Intermountain

Pwr 2 operating UT 0.48 11817 0.772 820 0.059 92.4%

Navajo 2 operating AZ 0.53 10919 0.922 803 0.044 95.5%

FPL

- Glades application FL 1.98 12324 3.053 2x980 0.040 98.7%

Taylor application FL 3.46 7475 8.100 800 0.040 99.5%



### Inspection of Table 1

. b. (below) reveals that semi

- dry FGD systems are being proposed/permitted at 0.06

– 0.09 lb/mmBtu on coals with much higher uncontrolled emissions than currently used at GGS. Based upon this data and a consideration of G GS’ even cleaner coal quality, we believe that a new semi

- dry FGD at GGS should be able to achieve 0.06 lb/mmBtu (or lower) on a 30

- day rolling average.

Table 1 .b. Dry Scrubber SO2 Rankings (30

- day rolling averaging period)

SO2 Coal Quality Ca pacity Emissions

or Limits Control

Facility Name Unit Status Permit

# %S (Btu/lb) (lb/mmBtu) MW (lb/mmBtu) (%)

NPPD

- Gerald

Gentleman (Proposed) 1&2 NE 0.30 8576 0.555 1365 0.060 89.2%

LS Pwr

-- High

Plains 1 application CO 0.66 8200 1.409 600 0.090 93.6 %

Black Hills

Pwr

- WYGEN 3 issued WY 1.20 7950 2.642 100 0.090 96.6%

LS Power

White Pine draft permit NV 0.66 8200 1.409 3x530 0.089 93.7%

Basin Electric

-- Dry Fork permit WY 0.47 7800 1.054 385 0.075 92.9%

Newmont

Nevada issued NV

0036 0.45 8400 0.938 200 0.065 93.1%

LS Power

White Pine draft permit NV 0.3 8200 0.640 3x530 0.065 89.8%

LS Pwr

-- High

Plains 1 application CO 0.46 8200 0.982 600 0.065 93.4%

Sierra Pacific

Ely application NV 0.8 8100 1.728 2x750 0.060 96.5%

### 10

We call attention t o the permit issued by Nevada to Newmont Nevada requiring its dry

scrubber to meet the following limits on very low

- sulfur coal :

Section V. Specific Operating Conditions (continued)

A. Emission Unit #S2.001

- Pulverized Coal Fired Boiler (continued)

2. NA C 445B.3405 a. Emission Limits (continued) (7) Article 8.2.1.2 Federally Enforceable SIP

- The discharge of sulfur to the atmosphere

will not exceed 1,218.0 pounds per hour. (8) NAC 445B.305 BACT Emission Limit

– The discharge of SO 2 

### to the atmosphere will

not exceed: (i) While combusting coal with a Sulfur content equal to or greater than 0.45 percent (30

- day rolling period), based on daily ASTM sampling: (a) 0.09 pound per million Btu, based on a 24

- hour rolling average period. (b) 95% minimum SO 2 

### removal efficiency will be maintained across the system, based on

a 30

- day rolling period. (ii) While combusting coal with a Sulfur content less than 0.45 percent (30

- day rolling period), based on daily ASTM sampling: (a) 0.065 pound per million Btu, based on a 24

- hour rolling average period. (b) 91% minimum SO 2 

### removal efficiency will be maintained across the system, based on

a 30

- day rolling period.

The Newmont Nevada permit indicates that a modern dry scrubber can achieve greater

than the 80% maximum assumed by NPPD and NDEQ, even on low

- sulfur coals.

In its ―response to Comments,‖ NDEQ appears to contend that, because some EGUs are not achieving the low SO 2 

### limits we suggest here, that GGS should not be expected to do so, either. We remind NDEQ that BART re quires ― Best Available Retrofit Technology,‖

not ― Average or Wors t Available Retrofit Technology.‖

Step 4 : Evaluate Impacts and Document Results.

NPPD’s FGD costs are overestimated

.

Dry Scrubber: NPPD has estimated that it would cost over $2,700/ton to control SO 2 

### using a dry scrubber at GGS (Table 2.a) . While much of this cost is due to extensive baghouse modifications to accommodate the additional particulate generated in the dry scrubber, the over

- $700 capital cost per kilowatt hour (kWh) appears unu sually high, especially when compared to the $423/kWh that Great River Energy proposes to spend to add a dry scrubber to its Stanton Unit #1 in North Dakota.

### 11

Table 2 .a. Gerald Gentleman

— NPPD estimates Dry FGD addition burning PRB sub

- bituminous

Unit #1 Source #2
Rating (MW Gross) each 665 company report 700
Rating (mmBtu/hr) 7,538 company report 7,538
Future Uncontrolled Emissions (tpy) 24,893 company report 24,893
Controlled Emissions (lb/mm Btu) 0.15 company report 0.15
Overall Control Efficiency (FGD) 74% calculated 73%
Emission Reductions (tpy) 19,908 company report 19,908
Capital Cost $ 490,796,000 company report $ 490,796, 000 Capital Cost ($/kW) $ 738 calculated $ 701

Annualized Cost $ 54,258,500 company report $ 54,258,500

Cost

- Effectiveness ($/ton) $ 2,726 company report $ 2,726



### Although we were unable t o estimate operating costs, and thus total annual costs and

cost

- per

- ton, due to a lack of information from NPPD, we were able to estimate capital costs based upon industry data 15 

### which lead to an estimated Capital Cost of $280

- $420/kW. ( For a 700 MW EGU like GGS 1 & 2, Capital Cost should be $200

- $300 million.) Even when we include NPPD’s high costs for ductwork, stack, and baghouse
modifications, our previous estimates of $374

- $393/kW appear much more reasonable

than those of NPPD. It is likely that the $700+/kW capital cost estimates from NPPD were the highly influenced by the improper inclusion of over $120 million in ―Escalation‖ costs and over $83 million in AFUDC costs. We also question a ―Contingency‖ cost of over $149 million (15%) of a $987 mi llion total; this is five times higher than the 3% contingency expense estimated by the Cost Manual.

Because the NPPD capital costs estimates were higher than we expected, we applied the Cost Manual methods to the NPPD cost analyses and our ―adjusted‖ re sults are presented

Table 2.b. below:

15 J.E. Cichanowicz ― Overview of Information on Project Control Technology Costs ‖ Oc tober 2010

### 12

Table 2.b. Spray

- Dry FGD at 0.15 lb/mmBtu

Dry FGD Cost Components NPPD* NPS**

Direct Capital Cost $ 575,827,000 $ 575,827,000

Indirect $ 47,452,000 $ 16,608,200

Escalation $ 120,449,000 $

-
Sales/Use Tax $ 11,077,000 $ 11,077,000

Contingency $ 148,745,000 $ 17,274,810

AFUDC $ 83,302,000 $

- Total Capital Cost $ 986,852,000 $ 620,787,010

Total Capital Cost/kW $ 723 $ 455

Capital Recovery Factor 0.0944

Levelized Capital Cost (w/ fan sized for FGD only) $ 80,013,000 $ 58,597,902

Levelized O&M Cost $ 27,806,000 $ 27,806,000

Levelized Outage Cost $ 698,000 $ 698,000

Total Levelized Capital, Outage and O&M Cost $ 108,517,000 $ 87,101,902

Tons SOx removed 40,426 40,426

Dry FGD cost

- effectiveness ($/ton) $ 2,684 $ 2,155

*DRY FGD AND ID FAN & AUXILIARY POWER CONCEPTUAL DESIGN COSTS
**Based upon OAQPS Control Cost Manual



### If the Escalation and AFUDC costs were eliminated, and the Contingency cost were adjusted to the recommended 3%, the resulting $3 66 mi llion reduction in dry scrubber costs would bring the Total Capital Cost down to a more realistic $45 5/kW

. Using the

NPPD O&M costs and SO 2 

### removal estimates in conjunction with our lower annual capital cost results in a cost

- effectiveness of less than $2, 200/ton.

Wet Scrubber: As shown in Table 3.a . (below), NPPD has estimated that it would cost over $2,700/ton to control SO 2 

### using a wet scrubber at GGS. Once again, NPPD estimates a capital cost/kWh of over $700. And, again, this appears unusually high,

e specially when compared to the $335

- $496/kWh that Basin Electric Power proposes to spend to add wet scrubbers to its Leland Olds Units 1 & 2 in North Dakota. Also in North Dakota, Minnkota Power is proposing to add a wet scrubber to its M.R. Young Unit 1 at a capital cost of $435/kWh.

Table 3.a . GGS

— NPPD estimates Wet FGD addition burning PRB sub

- bituminous

Unit #1 Source #2
Rating (MW Gross) each 665 company report 700
Rating (mmBtu/hr) 7,538 company report 7,538

Fu ture Uncontrolled Emissions (tpy) 24,893 company report 24,893
Controlled Emissions (lb/mmBtu) 0.15 company report 0.15
Overall Control Efficiency (FGD) 74% calculated 73%
Emission Reductions ( tpy) 19,908 company report 19,908
Capital Cost $ 514,909,500 company report $ 514,909,500
Capital Cost ($/kW) $ 774 calculated $ 736

Annualized Cost $ 54,225,000 company report $ 54,225 ,000

Cost

- Effectiveness ($/ton) $ 2,724 company report $ 2,724

### 13

Although we were unable to estimate operating costs, and thus total annual costs and

cost

- per

- ton, due to a lack of information from NPPD, we were able to estimate capital costs based upon industry data 16 

### which lead to an estimated Capital Cost of $370

- $460/kW. (For a 700 MW EGU like GGS 1 & 2, Capital Cost should be $250

- $330 million.) Our previous capital cost estimates of $368

- $388/kWh appear much more

reason able than those of NPPD.

It is likely that the $700+/kW capital cost estimates from NPPD were the highly influenced by the improper inclusion of over $12 6 million in ―Escalation‖ costs and over $8 8 million in AFUDC costs. We also question a ―Contingency‖ cost of over $ 155 million (15%) of a $ 1,035 million total; this is five times higher than the 3% contingency expense estimated by the Cost Manual.

Because the NPPD capital costs estimates were higher than we expected, we applied the

Cost Manual methods t o the NPPD cost analyses and our ―adjuste d‖ results are presented

Table 3 .b. below:

Table 3.b. Wet FGD at 0.15 lb/mmBtu

Wet FGD Cost Components NPPD* NPS**

Direct Capital Cost $ 597,727,000 $ 597,727,000

Indirect $ 51,963,000 $ 18,187,050

Escalation $ 126,848,000 $

-
Sales/Use Tax $ 14,634,000 $ 14,634,000

Contingency $ 155,308,000 $ 17,931,810

AFUDC $ 88,599,000 $

- Total Capital Cost $ 1,035,079,000 $ 648,479,860

Total Capital Cost/kW $ 758 $ 475

Capital Recovery Factor 0.0944

Levelized Capital Cost (w/ fan sized for FGD only) $ 83,965,000 $ 61,211,911

Levelized O&M Cost $ 24,485,000 $ 24,485,000

Levelized Outage Co st $

- $

- Total Levelized Capital, Outage and O&M Cost $ 108,450,000 $ 85,696,911

Tons SOx removed 41,338 41,338

Wet FGD cost

- effectiveness ($/ton) $ 2,623 $ 2,073

*WET FGD AND ID FAN & AUXILIARY POWER CONCEPTUAL DESIGN COSTS
**Based upon OAQPS Control Cost Manual



### If the Escalation and AFUDC costs were eliminated, and the Contingency cost s were adjus ted to the recommended 3%, the resulting $387 million reduction in wet scrubber costs would bring the Total Capital Cost down to a more realistic $475/kW. Using the

NPPD O&M costs and SO 2 

### removal estimates in conjunction with our lower annual capital cost results in a cost

- effectiveness of less than $2,100/ton.

Step 5: Evaluate Visibility Impacts.

16 J.E. Cichanowicz ― Overview of Information on Project Control Technology Costs ‖ Oc tober 2010

### 14

NDEQ estimates that reducing SO 2 

### emissions to 0.15 lb/mmBtu would improve visibility at Badlands NP (the only Class I area for which improvements was provided) by 0.785 dV, and by 0.845 dV at 0.10 lb/mmBtu

, but we did not have sufficient data to evaluate the cumulative benefits of improving visibility at the other Class I areas. If the scrubbers achieved the lower emission rates that we believe are reasonable, th en the visibility

benefits would increase.

BART Determination for SO 2



### NDEQ: Scrubber technology is a technically feasible SO 2 

### retrofit technology that could be implemented on GGS Units 1 and 2. Not taking the other environmental effects,

except energy, into account, the average cost effectiveness of using scrubbing control technology is approximately $2,500

– $2,700 per ton SO 2 

### removed. The cost per ton removed seems reasonable. When evaluating the cost effectiveness in terms of the visibility benefit de rived from scrubbing, the NDEQ assessed the average incremental visibility impairment improvement. The NDEQ also calculated the incremental cost per day of visibility improvement.

Over the three years of meteorology modeled, at 0.10 lb SO 2 

### /MMBtu, the aver age incremental visibility impairment improvement cost is $132,816,547 per year per change in deciview impact. The average number of days the Badlands would expect to experience a contribution from GGS of greater than 0.5 dV would be 22 per year. This is

a 39% reduction in the 56 days per year that the units contribute more than 0.5 dV. The average incremental cost per day of visibility improvement calculates to be $4,870,860 per day ($2,435,430 per unit).

Again, these values do not account for the added c osts that would be incurred from other environmental impacts, except energy. These values are of the same magnitude as the OPPD Nebraska City Unit 1 BART evaluation. There, NDEQ determined that additional

SO 2 

### controls were not reasonable, in part due to th e excessive cost per benefit in terms of visibility improvement (i.e., $/yr/dV).

Here in the case of NPPD GGS Units 1 and 2, NDEQ has serious concerns over the current availability of water to supply the scrubber and the potential e ffects of the depletion of water on threatened and endangered species in the Platte River Valley area. Since the incremental visibility impairment improvement cost is so large compared to similar improvements in visibility using LNB/OFA technology and most importantly, 17


### the pote ntial for other serious environmental impacts, the NDEQ has determined that it is inappropriate to require the installation of SO 2 

### scrubbing technology as BART at this time. NPPD shall instead continue to utilize low sulfur coal. However, additional SO 2



### co ntrols may be required in the future for purposes of ―reasonable further progress.‖ At that time, available control technologies would be evaluated, as well as water availability, whether water availability can reasonably be resolved, and the ability to mi tigate potential threats to endangered species in the Platte River Valley area.

17 How is LNB/OFA relevant to SO 2 scru bbers and water ?

### 15

The costs to transport water increased the total annualized cost associated with the installation of Wet FGD at GGS to $2,108,450,000. The average cost effectiveness of this

c ontrol technology is $52,956 per ton SO2 removed ($2,108,450,000 / 39,815 tons SO2 removed) based on an emissions rate of 0.15 lb/MMBtu. The average cost effectiveness of this control technology at an emissions rate of 0.1 lb/MMBtu is approximately $48,877 per ton SO 2 

### removed ($2,108,450,000/43,138 tons SO2 removed).

The NDEQ determined that the costs to transport water made scrubbing costs prohibitive

for NPPD as a BART SO 2 

### measure.

NPS SO 2 

### BART Conclusions:

NPPD and NDEQ erred by not considering Dry So rbent Injection (DSI), which uses no

water.

We have presented information showing that several EGUs are operating at, or have been proposed or permitted with much lower SO 2 

### limits than evaluated by NDEQ

. NDEQ

should evaluate a SO 2 

### limit that reflects the capabilities of modern scrubbers.

Use of EPA guidance and data results in capital cost estimates that are significantly lower than those presented by NPPD. NPPD should re

- do its scrubbing analyse s in the format presented by the OAQPS Control Cost Manual 18 

### and model the effects on all Class I areas of reducing SO 2 

### to 0.0 4

– 0.06 lb/mmBtu to provide the information to develop the ―fifth factor‖ in the BART process.

NO

x 

### BART 19



### NDEQ has combined these two boilers for its analysis, even though NO

x 

### emissions f rom these boilers differ substantially. 20 

### We continue to believe that s eparate analyses are

necessary. NDEQ has proposed only LNB and OFA as NO

x 

### controls (They have already been installed on Unit 1) to meet the presumptive BART limit

.

Step 1: Identify All Available Retrofit Control Technologies and Step 2: Eliminate Technically Infeasible Options.



### NDEQ has eliminated Selective Non

- Catalytic Reduction (SNCR) from consideration without sufficient justification on the basis that it is not technically feasible because of high temperatures measured in a similar boiler. However, it appears from the CAM data

that NO

x 

### emissions from the two boilers at GGS a re significantly different. T herefore

,

we question not only NDEQ’s assumption that it can eliminate SNCR on t he basis of temperature characteristics at a distant boiler, but also whether it can assume that the two

18 It would be very helpful if NPPD would provide vendor quotes and supporting documentation for major

cost items.

19 Presumptive BART for these wall

- fired boilers burning sub

- bituminous coal is 0.23 lb/mmBtu.

20 I n respon s e to our previous c omment on this issue, NDEQ replied that ― The temperature issue was

discussed with NPPD. The two units are different and could not be evaluated in combination.‖

### 16

boilers at GGS are so similar that they can be e valuated in combination, not individually. (This same concern applies to the rest of NPPD’s analyses of NO

x 

### controls.) Thu s
, NPPD

should show

, with data specific to each of the GG S boilers

, that this is the case at the

GG S facility also. However, in respon s e to our previous comment on this issue, NDEQ replied that ― The temperature issue was discussed with N PPD. The two units are different

and could not be evaluated in combination.‖ This indicates that NDEQ’s rejection of SNCR on the basis of similarity to another boiler is not valid.

Step 3: Evaluate Control Effectiveness of Remaining Control Technologies

NDEQ has underestimated the ability of modern NO

x 

### control systems: A significant

reason for the higher cost

- effectiveness of this option estimated by NDEQ is the low NO

x 

### control efficiency it assumed for a technology that should be able to achieve 90% cont rol. NDEQ estimates that addition of SCR can reduce NO

x 

### by 75%

- 83 % to 0.08 lb/mmBtu.

SCR is different from many other control technologies in that its efficiency is not highly dependent upon the concentration of the pollutant to be controlled. 21 

### Instead , SCR efficiency is primarily influenced by the design of the catalyst reactor, that is, the volume

of the catalyst, its cross

- sectional area, number of layers, and measures to prevent blinding and deactivation, as well as replacement schedule. If it is ne cessary to achieve a high degree of removal efficiency on an inlet stream with a low concentration, more catalyst can be included in the design. It is generally understood that NO X 

### reductions of approximately 90% or more may be achieved with SCR systems. 22 

### And, according to the June 13, 2009 ―Power‖ magazine article ―Air Quality Compliance: Latest Costs for SO 2 

### and NO X 

### Removal (effective coal clean

- up has a higher

– but known

–

price tag)‖ by Robert Peltier, ―An excellent example of the significant investment ma ny utilities have made over the past decade is American Electric Power (AEP), one of the largest public utilities in the U.S. with 39,000 MW of installed capacity with 69% of that capacity coal

- fired. AEP is under a New Source Review (NSR) consent decree s igned in 2007 that requires the utility install air quality control systems to reduce NO X 

### by 90%...‖

We are aware of vendor guarantees of 0.05 lb/mmBtu, 23 

### and understand that major vendors are designing SCR systems to achieve 0.02 lb/mmBtu 24 

### on coal

- fired b oilers.

Operational evidence from SCR retrofits on eastern EGUs (see Appendix A for ―EGUs

21 However, as noted below in an excerpt from the EPA Control Cost manual, at very low inlet

conc entrations, removal efficiency may be lower: In general, higher uncontrolled NOx inlet concentrations result in higher NOx removal efficiencies due to reaction kinetics. However, NOx l evels higher than approximately 150 parts per million (ppm), generally d o not resul t in increased performance. Low NOx inlet levels result in decreased

NOx removal efficiencies because the reaction rates are slower, particularly in the last laye r of catalyst.

22 A ccording to the Institute of Clean Air Companies white paper titl ed ―Selective Catalytic Reduction (SCR) Control of NO

x Emissions from Fossil Fuel

- Fired Electric Power Plants‖ (published in May 2009),

― By proper catalyst selection and system design, NO X removal efficiencies exceeding 90 percent may be

achieved.‖

23 Minne sota Power Taconite Harbor BART analysis.

24 Babcock & Wilcox presentation to Minnesota Pollution Control Agency.

### 17

less than 0.06 lb/mmBtu in 2009‖) clearly indicates that SCR can achieve 0.05 lb/mmBtu or lower on an annual basis. For example, we found eight dry

- bottom, wall

- fire d boilers operating at or below 0.05 lb/mmBtu in 2009. W e also looked at monthly data for 28 EGUs with SCR’s operating at or below 0.05 lb/mmBtu on an annual average (see Appendix A for ―2009 monthly emissions‖) and found that, of the 228 mo n ths of data,

2 14 were at or below 0.06 lb/mmBtu. For dry

- bottom, wall

- fired EGUs, we found that 73

of 77 months were at or below 0.06 lb/mmBtu. We conclude that SCR can achieve 0.05

lb/mmBtu on an annual basis and 0.06 lb/mmBtu on a 30

- day rolling average basis.

It is generally assumed that SCR can achieve at least 90% NO X 

### reduction, 25 

### and we have presented evidence demonstrating that SCR can achieve 0.05 lb/mmBtu (or lower) on

similar wall

- fired boilers. For example, Tri

- State Generation has submitted analyses 26 

### of appli cation of SCR at its Craig Colorado station which is based upon an assumption that SCR can achieve 0.05 lb/mmBtu. We also note that Salt River Project (SRP) assumed that addition of SCR to the Navajo Generating Station 27 

### could achieve 0.05 lb/mmBtu on

an an nual basis. The combination of the real

- world examples we have previously presented plus the assumptions by Tri

- State and SRP should provide sufficient weight

- of

evidence for NDEQ to conclude that SCR can reasonably be expected to achieve 0.05 lb/mmBtu (or better) on an annual basis.

Step 4 : Evaluate Impacts and Document Results.

NPPD’s SCR costs are overestimated

. T able 4.a ( below ) uses company data and

estimates that the combination of LNB/OFA+SCR would cost about $2,300/ton t o reduce

NO X 

### emissions to 0 .08 lb/mmBtu on an annual average basis.

Table 4.a. NPPD estimates for LNB+SCR burning PRB sub

bituminous

Unit #1 Source #2
Rating (MW Net ) each 665 company report 700
Rating (mmBtu/hr) 7,538 company report 7,538
Future Uncontrolled Emissions (tpy) 15,122 company report 15,122

Controlled Emissions (lb/mmBtu) 0.08 company report 0.08
Overall Control Efficiency (FGD) 83% calculated 75%
Emission Reductions (tpy) 12,463 company rep ort 12,463
Capital Cost $ 257,540,500 company report $ 257,540,500
Capital Cost ($/kW) $ 387 calculated $ 368

Annualized Cost $ 28,625,500 company report $ 28,625,500

Cost

- Effectiveness ($/ton) $ 2,297 company report $ 2,297



### SCR Cost Estimation Methods

25 J.E. Chichanowicz Report Current Capital Cost and Cost Effectiveness

- January 20 10

26 Exhibit 16

- Craig Stations 1, 2, and 3 November 2010 B lack & Veatch Report, Tables 2

- 1, 2

- 1, 4

- 6,4

- 8,

7

- 7, 7

- 8, ―Selective Catalytic Reduction System‖

27 Slide 36 of ― Navajo Generating Station Preliminary Capital Cost Estimate ” prepared by Sargent & Lundy and presented by Salt River Project to the Environmenta l Protection Agency

– July 20, 2010

. (electronic file attached)

### 18

The SCR cost estimates submitted by NPPD are severely lacking in the types of specific information needed to give them credibility. Although there are several methods for

estim ating SCR costs, our experience leads us to believe that no one method is perfect and that the costing methods need to be tempered by real

- world data. An excellent example of a SCR retrofit cost analysis was prepared for the Navajo Generating Station (NGS) and is being provided separatel y (in Appendix B. ―SCR Costs‖ )

. The NGS analysis contains the type of vendor estimates and detailed engineering analyses recommended by the BART Guidelines and necessary to arrive at a reasonable and

informed estimate of sit e

- specific costs. In the absence of such a comprehensive analysis,

the BART Guidelines recommend use of the EPA Control Cost Manual.

“Real

- World” SCR Capital Costs

Real

- world, utility industry

- generated e vidence that NPPD has overestimated its SCR

costs can be found in a June 2009 article in ―Power‖ magazine: 28



### ―One more current data set is the historic capital costs reported by AEP averaged over several years and dozens of completed projects. For example, AEP reports that their historic average capital costs for SCR systems are $162/kW for 85% to 93% NO X 

### removal...‖

―...historical data finds the installed cost of an SCR system of the 700MW

- class as approximately $125/kW over 22 units with a maximum reported cost of $221/kW in

2004 dollars. This data was r eported prior to the dramatic increase in commodity prices of 14% per year average experienced from 2004 to 2006 (from the FGD survey results). Applying those annual increases to the 2004 estimates for three years (from the date of the survey to the end of 2007) produces an average SCR system installed cost of $185/kW...‖

―Overall, costs were reported to be in the $100 to $200/kW range for the majority of the systems, with only three reported installations exceeding $200/kW.‖

Five industry studies conducted between 2002 and 2007 have reported the installed unit capital cost of SCRs, or the costs actually incurred by owners, expressed in dollars per kilowatt. These actual costs are generally lower than estimated by NPPD

.

The first study evaluated the instal led costs of more than 20 SCR retrofits from 1999 to 2001. The installed capital cost ranged from $106 to $213/kW, converted to 2007

dollars. 29 

### Costs are escalated through using the CEPCI.

28 June 13, 2009 ―Power‖ magazine article ―Air Quality Compliance: Latest Costs for SO2 and NOx Removal (effective coal clean

- up has a higher

– but known

– price tag)‖ by Robert Peltier. http://www .masterresource.org/2009/06/air

- quality

- compliance

- latest

- costs

- for

- so2

- and

- nox

- removal

effective

- coal

- clean

- up

- has

- a

- higher

- but

- known

- price

- tag/

### 19

The second survey of 40 installations at 24 stations reported a co st range of $76 to $242/kW , converted to 2007 dollars. 30



### The third study, by the Electric Utility Cost Group, surveyed 72 units totaling 41 GW, or 39% of installed SCR systems in the U.S. This study reported a cost range of $118/kW to $261/kW , converted t o 2007 dollars. 31



### A fourth study, presented in a course at PowerGen 2005, reported an upper bound range

of $180/kW to $202/kW , converted to 2007 dollars. 32



### A fifth summary study, focused on recent applications that become operational in 2006 or

were sched uled to start up in 2007 or 2008, reported costs in excess of $200/kW on a routine basis, with the highest application slated for startup in 2009 at $300/kW. 33



### EPA’s Region 8 Office has compiled a graphic presentation of SCR capital costs adjusted

to 2009 dollars

—

please see Appendix B for ―SCR Capital Costs and References‖. The EPA data confirm that SCR capital costs typically range from $73

– $243/kW.

A graphic illustration of a ―real

- world‖ retrofit was presented by Burns & McDonnell at

the 2010 Power Pl ant MegaSymposium and is provided in Appendix B in the ―Boswell

retrofit‖ files. Despite the limited space and other obstacles, the SCR installation cost $205/kW. 34 

### It should also be noted that the Boswell Unit 3 retrofit was designed to meet

0.0 5 lb/mmBtu

. Burns & Mc Donnell reported that performance tests showed that,

― Average NOx emissions at the outlet of the SCR reactor were 0.029 lb/mmBtu, which is below the design emission rate for the SCR system (0.05 lb/mmBtu).‖

Thus, the overall range for these ind ustry studies is $50/kW to $300/kW . The upper end of this range is for highly complex retrofits with severe space constraints, such as Belews

29 Bill Hoskins, Uniqueness of SCR Retrofits Translates into Broad Cost Variations, Power Engineering, May 2003 . Ex. 2. The reported range of $80 to $160/kW $123

- $246/kW was converted to 2008 dollars ($116

- $233/kW) using the ratio of CEPCI in 2008 to 2002: 575.4/395.6.

30 J. Edward Cichanowicz, Why are SCR Costs Still Rising?, Power, April 2004, Ex. 3; Jerry B urkett, Readers Talk Back, Power, August 2004, Ex. 4. The reported range of $56/kW

- $185/kW was converted to 2008 dollars ($83

- $265/kw) using the ratio of CEPCI for 2008 to 1999 (575.4/.390.6) for lower end of the range and 2008 to 2003 (575.4/401.7) fo r upper end of range, based on Figure 3.

31 M. Marano, Estimating SCR Installation Costs, Power, January/February 2006. Ex. 5. The reported range of $100

- $221/kW was converted to 2008 dollars ($130

- $286/kW) using the ratio of CEPCI for

2008 to 2004: 57 5.4/444, 2. http://findarticles.com/p/articles/mi_qa5392/is_200602/ai_n21409717/print?tag=artBody;col1

32 PowerGen 2005, Selective Catalytic Reduction: From Planning to Operation, Competitive Power College, by Babcock Power, Inc. and LG&E Energy, December 2005, Ex. 6. The reported range of $160

- $180/kW) was converted to 2008 dollars ($197

- $221/kW) using the ratio of CEPCI for 2008 to 2005 (575.4/468.2).

33 J. Edward Cichanowicz, Current Capital Cost and Cost

- Effectiveness of Power Plant Emissions Contro l Technologies, June 2007, pp. 28

- 29, Figure 7

- 1 (Ex. 1).

34 Minnesota Power’s Environmental Improvement Plan submitted to the MN PUC 10/27/06, Docket

#E015/M

- 06

- 1501. LNB+OFA+SCR TCI = $77 million in 2006 $ on 375 (gross) MW Unit #3.

### 20

Creek, reported to cost $265/kW

, 35 

### or Cinergy's Gibson Units 2

- 4. Gibson, a highly complex, space

- constrained retro fit in which the SCR was built 230 feet above the power station using the largest crane in the world, 36 

### only cost $251/kW in 2007 dollars. 37



### We reviewed NPPD’s Appendix C 38 

### to determine the costs it had specifically assigned to

SCR and derived part of T able 4b. below:

Table 4.b SCR at 0.08 lb/mmBtu

SCR Cost Components NPPD* NPS**

Direct Capital Cost $ 268,199,000 $ 268,199,000

Indirect $ 35,212,000 $ 53,639,800

Escalation $ 60,482,000

Sales/Use Tax $ 5,589,000 $ 5,589,000

Contingency $ 72,779,000 $ 61,685,770

AFUDC $ 41,150,000

Total Capital Cost (w/ fan sized for SCR only) $ 478,151,000 $ 389,113,570

Total Capital Cost/kW $ 350 $ 285

Capital Recovery Factor 0.0944

Levelized Capital Cost (w/ fan sized for SCR only) $ 38,75 5,000 $ 36,729,568

Levelized O&M Cost $ 14,515,000 $ 14,515,000

Levelized Outage Cost $ 1,021,000 $ 1,021,000

Total Levelized Capital, Outage and O&M Cost $ 54,291,000 $ 52,265,568

Tons NOx removed 9,970 9,970

SCR cost

- effectiveness ($/ton) $ 5,445 $ 5,242

*SCR AND ID FAN & AUXILIARY POWER CONCEPTUAL DESIGN COSTS **Based upon O AQPS Control Cost Manual



### NPPD's $350/kW capital cost is much higher than the $250

- $300/kW range estimated for SCR at this facility by applying recent industry cost data. 39 

### It is likely that the capital cost estimates from NPPD were the highly influenc ed by the improper inclusion of over $ 6 0 million in ―Escalation‖ costs and over $ 41 million in AFUDC costs. We also question a ―Contingency‖ cost of over $ 72 million ( 27 %) of a $ 268 million total; this is higher than the 2 3% contingency expense estimated b y the Cost Manual. If the $89 million in these excess costs is eliminated from the NPPD estimate, the resulting $285/kW becomes more consistent with industry data. Finally, by choosing the most costly alternative for supplying ammonia to the SCR, the use o f urea with a conversion plant, NPPD has further increased costs above the typical industry SCR installation.

35 Steve Blankinship, SCR = Supremely Complex Retrofit, Power Engineering, November 2002, Ex. 7. The unit cost: ($325,000,000/1,120,000 kW) (608.8/395.6) = $290/kW. http://pepei.pennnet.com/display_article/162367/6/ARTCL/none/none/1/SCR

- =

- Supremely

- Complex

Retrofit/

36 Standi ng on the Shoulder of Giants, Modern Power Systems, July 2002, Ex. 8.

37 McIlvaine, NOX Market Update, August 2004, Ex. 9. SCR was retrofit on Gibson Units 2

- 4 in 2002 and 2003 at $179/kW. Assuming 2002 dollars, this escalates to ($179/kW) (608.8/395.6) = $275.5/kW. http://www.mcilvainecompany.com/sampleupdates/NoxMarketUpdateSample.htm

38 SCR AND ID FAN & AUXILIARY POWER CONCEPTUAL DESIGN COSTS

39 J.E. Chichanowicz Report ― Current Capital Cost and Cost Effectiveness ,‖ January 2010

### 21

Because the NPPD capital costs estimates were higher than we expected, we applied the

Cost Manual me thods to the NPPD cost analyses.

EPA Control Cost Manual

We have been working with an Excel workbook we derived from the SCR cost estimation method presented by EPA’s Office of Air Quality Planning and Standards Control Cost Manual (Cost Manual). Based upon the industry data cited above, we now

bel ieve that the Cost Manual method tends to underestimate the Direct Capital Cost (DCC) component of the SCR cost estimate. Because the Total Capital Investment (TCI) component is directly proportional to the DCC in the Cost Manual method, a straightforward application of the Cost Manual method usually results in TCI costs lower than what we would expect from the real

- world industry data presented above. Therefore,

we have been developing a way to modify the Cost Manual method to provide TCI

estimates more co nsistent with industry data. First, we adjust the DCC from the Cost Manual’s 1998 baseline to current (2009) cost using the Chemical Engineering Plant Cost Index (CEPCI ratio = 1.34 ) to adjust costs for inflation. ( 

### Please see the individual source analyses in Appendix B. ―NPS SCR modified Cost manual approach for GGS #1‖ (and #2) for specific details of how we apply this method.) In this case, the Cost Manual method yields $ 79

- $ 83 /kW (Please see the ―ICC‖ tab cell L18.), which appears too low

for EGUs thi s size and thus prompted us to over

- ride the Cost manual’s TCI calculation.

The Cost Manual assumes that the TCI for SCR will be 141% (cell M 17) of the DCC (cell L4), and that the costs that comprise the TCI will also be ratios of the DCC. Our

next step assumed that the NPPD $134 million estimate for DCC for each EGU is reasonable, and applied the Cost Manual 141% ratio to estimate a new TCI (cells M20 and M21 on the ―ICC‖ tab). Because this new $270

- $284/kW TCI falls within the expected values for EGUs of this size, it will be used for further estimates and is fed back

to cell C7 of the ―Given/Assume‖ tab and to cell F5 on the ―Ann Cost‖ tab. Because the NPPD estimate of $342

- $360/kW (Please see the ―ICC‖ tab cell O18.) is more expensive than expected , and no reason has been provided to justify any exceptional costs, it will not be used in subsequent estimates.

Annual SCR Costs

The Direct Annual Cost (DAC) component of the process is also important because it represents a significant portion of the T otal Annual Cost. The methods presented by the Cost Manual for estimating DAC appear to be straight

- forward and should accurately represent annual costs with no need for adjustment. However, the BART analyses

p resented by NPPD show a consistent significant overestimation of DAC.

We applied the procedures described in Section 4, Chapter 2 of the Cost Manual to the

GGS boilers (Tables 5.a and 5.b)

. 40 

### Because modern SCR systems are typically designed

to achieve 90+% NO

x 

### reductions, we used 0.05 lb/mmBtu as our target . Except for the

40 Our calculations are co ntained in the attached Excel workbook in Appendix B.

### 22

Annual Maintenance Costs, all other O&M cost estimates produced by NPPD were significantly higher than estimated by a direct application of the Cost Manual, even though we estimated a greater amount of NO X 

### removal which should have led to higher operating costs in our estimates . Due to a lack of supporting information, we were unable to determine the reasons for NPPD’s higher cost estimates. W e estimated a Total Annual Cost of $2 4.5 million for GGS Unit 1 , and produced cost

- effective ness estimates of $2,000 /ton.

Table 5.a Annual Costs for SCR at

0.05 lb/mmBtu Gerald Gentleman Station Unit 1

NPPD/NPS NPS NPPD

Annual Maintenance Cost = $ 2,835,007 $ 733,000.00 26%
Annual Reagent Cost = $ 824,401 $ 1,751,000 212%
Annual Electricity Cost = $ 762,722 $ 2,412,000 316%
Annual Catalyst Cost = $ 732,419 $ 2,329,000 318%

DAC = $ 5,154,549 $ 7,225,000 140%

Indirect Ann ual Cost = $ 17,840,306 $ 19,128,000 107%

SCR Total Annual Cost = $ 22,994,855 $ 27,145,500 118%

CC+SCR Total Annual Cost = $ 24,474,855 $ 28,625,500 117%

NOx Removed by SCR = 5,3 03 4,626 87%

Total NOx Removed = 12,160 12,463 102%

SCR Cost effectiveness = $ 4,336 $ 5,445 126%

Total Cost effectiveness = $ 2,013 $ 2,297 114%

Table 5.b. A nnual Costs for SCR at

0.05 lb/mmBtu Gerald Gentleman Station Unit 2

NPPD/NPS NPS NPPD

Annual Maintenance Cost = $ 2,835,000 $ 733,000.00 26%
Annual Reagent Cost = $ 800,657 $ 1,776,000 222%

Annual Electr icity Cost = $ 740,755 $ 2,412,000 326%
Annual Catalyst Cost = $ 732,419 $ 2,367,000 323%

DAC = $ 5,108,831 $ 7,288,000 143%

Indirect Annual Cost = $ 17,840,263 $ 19, 627,000 110%

SCR Total Annual Cost = $ 22,949,094 $ 27,145,500 118%

CC+SCR Total Annual Cost = $ 24,429,094 $ 28,625,500 117%

NOx Removed by SCR = 5,150 4,692 91%

Total NOx Removed = 8,318 12,463 150%

SCR Cost effectiveness = $ 4,456 $ 5,445 122%

Total Cost effectiveness = $ 2,937 $ 2,297 78%



### We estimated a Total Annual Cost of $24.4 million for GGS Unit 2, and produced cost

effectiveness estimates of $2,900/ton. 41



### Step 5: Evaluate Visibility Impacts.

41 The higher Total Cost Effectiveness for LNB/OFA+SCR on GGS #2 is primarily due to its inherently

lower uncontrolled NO X emissions and the higher cost/ton of the LNB/OFA to reduce NO X emissions to

the presumptive BART level.

### 23

NDEQ estimates that reducing NO X 

### emissions to 0.08 lb/mmBtu would improve visibility at Badlands NP (the only Class I area for which improvements was p rovided) by 1.152 dV , but we did not have sufficient data to evaluate the cumulative benefits of improving visibility at the other Class I areas. If the SCR achieved the lower emission rate that we believe is reasonable, then the visibility benefits would increase.

BART Determination for NO X

Quoting NDEQ: LNB/OFA technology is a feasible NO x retrofit technology that could be implemented on GGS Units 1 and 2.

The average cost effectiveness of this control technology is $198 per ton NO

x removed. Over the three years of meteorology modeled, the average incremental visibility impairment improvement cost is $4,475,825 per year per change in deciview impact.

Utilizing SCR technology is also feasible only if LNB/OFA is utilized. The incremental cost

effectiven ess (incremental cost SCR) is $5,445 per ton NO

x removed, over 25 times the amount of LNB/OFA alone. Over the three years of meteorology modeled, the incremental visibility impairment improvement cost of adding SCR is $111,993,640 per year per change in de ciview impact. The average incremental improvement in visibility for the addition of SCR is less than 0.5 dV and improvement would be seen on an average of 7.3 days per year.

The NDEQ determined that the incremental cost for the addition of SCR is excessi ve and that LNB/OFA would be required for BART.

Therefore BART for GGS Units 1 and 2 shall be the installation of LNB/OFA with an emission

limitation of 0.23 lb NOx/MMBtu.



### NPS NO

x 

### BART Conclusions :

We have presented information showing that several EGUs are operating at much lower

NO X 

### rates than evaluated by NDEQ. NDEQ should evaluate NO X 

### rates that reflect the capabilities of SCR systems.

Use of EPA guidance and industry data results in capital and O&M cost estimates that are significantly lower than those presented by NPPD. NDEQ improperly rejected Selective Catalytic Reduction (SCR) as too expensive on an incremental cost

- per

- deciview

improvement ($/dv) basis. NDEQ began its cost

- effectiveness analysis by estimating the average costs of combustion co ntrols:
The total annualized cost associated with the installation of LNB/OFA is $2,960,000. The cost effectiveness of LNB/OFA is $198 per ton NOx removed ($2,960,000 / 14,956 tons NOx removed). 

### and then the combination of combustion control plus SCR:

The total annualized cost associated with the installation of LNB/OFA and SCR is $57,251,000. The cost effectiveness of LNB/OFA and SCR is $2,297 per ton NOx removed ($57,251,000 / 24,926 tons NOx removed). 

### in accordance with its proper understanding of the co st

- effectiveness of such a

combination:

### 24 Although SCR is a feasible control technology, it would be most practical to install SCR in

combination with combustion controls . This is because if NOx formation was not reduced upstream of the SCR system, the amoun t of catalyst required would be higher, subjecting more catalyst to degradation. The amount of ammonia required would also be higher, increasing the capital and O&M costs of SCR significantly. Also, reagent costs would be significantly higher if

LNB/OFA we re not used to minimize NOx emissions before treatment with the SCR system. Therefore, the cost associated with installing LNB/OFA is linked to this control technology throughout the analysis. 

### NDEQ should have stopped at that point. However, NDEQ then cont radicted its proper assessment of the combination of combustion controls plus SCR and created an incremental cost for a ―straw man‖ strategy that it had already deemed ―impractical‖:
The incremental cost effectiveness calculation compares the costs and per formance level of a control option to those of the next most stringent option. The incremental cost analysis of installing LNB/OFA and SCR as opposed to LNB/OFA alone is $5,445 ([$57,251,000

- $2,960,000] / [24,926

– 14,956]). 

### NDEQ should have relied upon its good judgment that ― it would be most practical to install SCR in combination with combustion controls‖ and based its decision upo n the outcome of that analysis. 42



### Use of EPA guidance and data result in cost

- effectiveness value s for combustion

modificat ions plus SCR of $2,000

- $ 3 ,000 /ton

. This cost

- effectiveness appears reasonable, given the magnitude and extent of GGS’ impacts upon visibility.

NDEQ should re

- do its SCR analysis in the format presented by the OAQPS Control Cost

Manual 43 

### and model the e ffects on all Class I areas of reducing NO

x 

### to not greater than

0.07 lb/mmBtu and provide the information to develop the ―fifth factor‖ in the BART

process.

42 It should be noted that the combustion controls currently present on GGS #1 did not exist at the time the BART Guidelines were finalized, and thus cannot be separated from the LNB/OFA+SCR combination endorsed by NDEQ.

43 It would b e very helpful if NPPD would provide vendor quotes and supporting documentation for major

cost items.