# Cost of NO x 

# BART

Controls on Controls on Controls on Utah EGUs

to:


## EC/R Incorporated 501 Eastowne Drive, Suite 250 Chapel Hill, NC 27514

October 22, 2015



## Andover Technology Partners Andover Technology Partners 112 Tucker Farm Road, North Andover, MA 01845 phone: (978) 683-9599; e-mail: staudt@AndoverTechnolo gy.com

## Andover Technology Partners Andover Technology Partners
112 Tucker Farm Road, North Andover, MA 01845

## Contents

**Sections Page**

**1. Background 1**

**2. NO x**  **Control Cost Methodology 2**

**PacifiCorp Hunter Units 1 & 2 22 PacifiCorp Huntington Units 1 & 2 24** www.AndoverTechnology.com 1



## Background

Andover Technology Partners (ATP) under contract to EC/R, Incorporated provided cost
estimates for Best Available Retrofit Technology (B ART) for NO x controls at the following Utah
Electricity Generating Units.

• PacifiCorp Hunter 1 & 2

• PacifiCorp Huntington 1 & 2www.AndoverTechnology.com 2



## NO x 

## Control Cost Methodology Control Cost Methodology

ATP has developed cost estimates for the following Utah coal-fired units.

• PacifiCorp Hunter Units 1 & 2

• PacifiCorp Huntington Units 1 & 2

For each unit, estimates of cost and cost effective ness were made for the following technologies, where applicable:

• New, advanced combustion controls that have been in stalled since 2007

• Selective Noncatalytic Reduction (SNCR) alone, but after installation of combustion controls

• Selective Catalytic Reduction (SCR) alone, but afte r installation of combustion controls

• Combustion controls in combination with SNCR

• Combustion controls in combination with SCR

Estimates were based upon an initial average annual NO x level equal to 2001-2003 historical rates (average of annual average for each of the th ree years) when new combustion controls were not
in use at these units. Emission rates with new com bustion controls were estimated from more recent
data for those units with combustion controls. 20 01-2003 historical data were also used to estimate annual heat input and the associated capacity facto r for each unit. For each unit, SNCR and SCR costs
were estimated in combination with new combustion c ontrols. The units are equipped as follows:

PacifiCorp Hunter Unit 1: Low NOx Burner Technology w/ Separated Overfire Air (OFA);
installed 2014 1 PacifiCorp Hunter Unit 2: Low NOx Burner Technology w/ Separated OFA; installed 2011 2 PacifiCorp Huntington Unit 1: Low NOx Burner Techno logy w/ Separated OFA; installed 2011 3 PacifiCorp Huntington Unit 2: Low NOx Burner Techno logy w/ Separated OFA; installed 2007 4

In estimating the cost of controls, the following w ere considered:

• Integrated Planning Model (IPM) Cost models (versio n 5.13) 5

• US EPA Air Pollution Control Cost Manual 6

• Data provided by PacifiCorp in their BART assessmen ts 7

1 PacifiCorp BART Analysis of Hunter Unit 1, July 2, 2012; pdf page 54; however, 2015 AMPD data indicate s close-coupled OFA

2 PacifiCorp BART Analysis of Hunter Unit 2, June 7, 2012; pdf page 55

3 PacifiCorp BART Analysis of Huntington Unit 1, Jun e 26, 2012; pdf page 12; however, AMPD data still sh ows close-coupled

OFA

4 PacifiCorp BART Analysis of Huntington Unit 2, Jun e 26, 2012; pdf page 54

5 Sargent & Lundy, IPM Model – Updates to Cost and Pe rformance for APC Technologies SNCR Cost Developmen t

Methodology Final March 2013 Project 12847-002 Sargent & Lundy, IPM Model – Updates to Cost and Pe rformance for APC Technologies SCR Cost Development Methodology

Final March 2013 Project 12847-002

6 EPA. 2002. EPA Air Pollution Control Cost Manual (S ixth Edition). EPA/452/B-02-001 (“the 2002 CCM”) Chapter 1, Selective Noncatalytic Reduction, —6/5 /2015 – Draft for Public Comment (“the 2015 SNCR CC M”) Chapter 2 Selective Catalytic Reduction, —6/5/201 5 – Draft for Public Comment (“the 2015 SCR CCM”)

7 PacifiCorp’s BART Analysis Update for Hunter Units 1 and 2 and Huntington Units 1 and 2, August 5, 201 4 PacifiCorp BART Analysis of Hunter Unit 1, July 2, 2012www.AndoverTechnology.com 3

• Data provided in comments to the State of Utah 8

• Other data that have been published and are describ ed in more detail in this report

The BART guidelines recommend use of the EPA Air Po llution Control Cost Manual, and the methodology used here for estimating costs is consi stent with the recommendations in the manual, such as use of overnight cost 9 for capital cost. The overnight cost methodology does not allow for inclusion of financing costs during construction (a lso called AFUDC). Capital costs were adjusted to 2014 costs using the Chemical Engineering Plant Cost Index (CEPCI) for capital costs and current reagent cost estimates were collected. The cost of power used for auxiliary loads equals e xpenses per net kWh as reported in 2014 FERC Form 1 data for PacifiCorp. 10 Capacity factors used in cost estimates were est imated from historical US EPA Air Markets Program Data 11 for the four units. Reagent costs are from a recent estimate. 12

Detailed cost estimates are provided in the Microso ft Excel Workbook that is provided with this

report:

• Microsoft Excel Workbook UT EGU BART_ Costs.xlsx

PacifiCorp BART Analysis of Hunter Unit 2, June 7, 2012 PacifiCorp BART Analysis of Huntington Unit 1, Ju ne 26, 2012 PacifiCorp BART Analysis of Huntington Unit 2, Ju ne 26, 2012

8 National Park Service Comments and attachments; May 1, 2015 HEAL UTAH * NATIONAL PARKS CONSERVATION ASSOCIATI ON * SIERRA CLUB; Comments on Proposed Amendments t o

Utah’s Regional Haze Rule; December 22, 2014 and De cember 18, 2014 Technical Support Document

9 “Overnight” costs means capital costs are expresse d in constant dollars for the base year, excluding Allowance for Funds

Used During Construction (AFUDC)

10 PacifiCorp FERC Form 1, Quarter 4, 2014, pages 402 .1, 403.1, 402.2 , line 35

11 http://ampd.epa.gov/ampd/

12 9/23/15 email from Fuel Tech, cost of $1.60 per ga llon 25% to 30% less for prill.www.AndoverTechnology.com 4

Combustion Controls
For combustion controls, capital and operating and maintenance cost estimates provided in PacifiCorp’s August 2014 estimate were used. Perce nt reduction and tons of NO x removed were based upon actual emission rates reported to EPA’s Air Ma rkets Program Data from 1) 2001-2003, and 2) after installation of new combustion controls using data from 2014 and 2015.

SNCR For SNCR the capital cost provided in PacifiCorp’s August 2014 estimate was used, excluding
AFUDC.
SNCR reagent consumption and the level of NO x reduction are very dependent upon a number
of factors – such as initial NO x level and furnace temperatures. Figure 1 is an ex ample of test data from an SNCR optimization program on a pulverized coal-f ired boiler that shows NO x reduction and chemical
utilization versus Normalized Stoichiometric Ratio (NSR – a measure of chemical treatment rate). Chemical utilization equals per cent reduction divi ded by NSR and is a measure of the efficiency of reagent use. The figure includes data from optimiz ed as well as unoptimized configurations, which is why some of the data points fall below the curves. The curves that would be developed for any given unit will vary from one unit to another and, while having similar shapes as those in Figure 1, may hav e somewhat different values based upon temperature an d baseline NO x . **Figure 1.** NO x Reduction and Reagent Utilization versus reagent t reatment rate in NSR for a Pulverized Coal-Fired Boiler during an SNCR optimization progr am 13 (data points plotted below the curves are at unopti mized conditions)

13 Staudt, J.E., Kehrer, K., Poczynek, J., Cote, R., P ierce, R., Afonso, R., Miles, D., and Sload, A., "Op timizing Selective NonCatalytic Reduction Systems for Cost-Effective Oper ation on Coal-Fired Electric Utility Boilers", pres ented at ICAC Forum '98, Durham, NC, March 19-20, 1998.www.AndoverTechnology.com 5 Percent reduction is related to the uncontrolled NO x level. Figure 2 shows the level of NO x reduction for various NO x levels for coal-fired electric generating units (E GUs). The best fit equation on the figure is used to estimate the level of reducti on possible for the four BART EGUs.

**Figure 2.** NOx reduction versus baseline NO x for coal-fired EGUs 14

Equation 1 and Figure 3 are taken from the CCM and are recommended for estimating SNCR reagent usage. Equation 1 characterizes the lines on Figure 3. Equation 1 is used to estimate treatment rate for SNCR systems.

**Equation 1.** Formula for estimating SNCR treatment rate 15

14 Chapter 1, Selective Noncatalytic Reduction, —6/5/ 2015 – Draft for Public Comment

15 US EPA, Air Pollution Control Cost Manual, EPA/452/ B-02-001, 2002, Section 4.2, Page 1-25www.AndoverTechnology.com 6 **Figure 3.** Estimates of SNCR treatment rate as a function of inlet NO x 15

Other elements of SNCR variable operating cost and fixed operating cost are estimated using IPM algorithms 16 (which happen to be consistent with the 2015 draft SNCR chapter of the CCM). PacifiCorp indicated fixed operating costs ranging from $277,500 to $280,000 per unit per year (or about $0.62/kW-yr), which is well above what is est imated using the cost manual or IPM algorithms (about $0.30/kW-yr). Without better explanation of these costs, the fixed operating cost of about $0.30/kW-yr determined using IPM and CCM algorithms are used.

16 Sargent & Lundy, IPM Model – Updates to Cost and Pe rformance for APC Technologies SNCR Cost Developmen t

Methodology Final March 2013 Project 12847-002www.AndoverTechnology.com 7

**SCR** SCR capital cost is estimated using data provided b y PacifiCorp. 17 PacifiCorp applied some of the factors and format of the 2002 CCM. However, t he costs provided by PacifiCorp were adjusted
here to account for items that are double-counted o r should not be allowed under the CCM, such as AFUDC. PacifiCorp provided multiple capital cost e stimates in PacifiCorp’s BART Analysis Update for Hunter Units 1 and 2 and Huntington Units 1 and 2, dated August 5, 2014, that included some duplication of costs that are identified in the spr eadsheet attached with this report. In addition, historical industry cost data were con sidered to determine if the costs were reasonable in the context of what has been reported at other facilities. 18, 19 For example, as shown in the worksheet TVA_SCR_Cost in the attached workbook UT_EGU BART Costs, over twenty SCRs installed at TVA plants cost from about $104/kW to $318/kW, using the CEPCI to adjust capital costs to 2014 dollars. Cichanowicz (2013) also found SCR co sts to cover a very wide range, but at a higher lev el, with some units as high as over $500/kW. Other ex amples of SCR systems in 2014 dollars (adjusted using the CEPCI) include Montour Station at a cost of $209/kW, Ashville at $216/kW, Belews Creek at $289/kW and DTE Monroe at $420/kW. 20 In all cases some costs were accepted and others we re not. The following are specific costs that were not accepted for any of these cost estima tes.

1. Process Contingency

PacifiCorp provided cost estimates that follow the general format of the 2002 CCM. Although the 2002 CCM shows a process contingency of 5% in T able 2.5 in Section 4.2 (page 2-44), this is not necessary today for SCR on coal-fired boilers firin g the coals used in Utah. According to the Department of Energy’s National Energy Technology L aboratory, 21

“Process contingency is intended to compensate for uncertainty in cost estimates caused by performance uncertainties associated with the devel opment status of a technology. Process contingencies are applied to each plant section bas ed on its current technology status.”

According to that document, for commercially availa ble technologies process contingency could range from 0-10%.

When the CCM was issued in January 2002, SCR had be en deployed in Europe and was commercially available but was only emerging in app lication on coal-fired utility boilers in the Unite d

17 PacifiCorp’s BART Analysis Update for Hunter Units 1 and 2 and Huntington Units 1 and 2, August 5, 20 14

18 Cichanowicz, J. E., “CURRENT CAPITAL COST AND COST -EFFECTIVENESS OF POWER PLANT EMISSIONS CONTROL TECHNOLOGIES”, Prepared for Utility Air Regulatory Group, January 2013

19 SCR Cost from Defendant's Response to Plaintiff's Interrogatory #8, North Carolina v. TVA, Filed with US District Court, Asheville, NC, September 1, 2006.

20 Costs shown in TVA_SCR Cost worksheet of UT_EGU BA RT Costs workbook http://pplweb.mediaroom.com/index.php?s=12270&item= 16522 Annual NC Clean Smokestacks Act Compliance Report , Progress Energy Carolinas, March 30, 2006 http://www.asheville.com/news/dukepoweremission.htm l PR Newswire , “DTE Energy Environmental Project W ill Create 900 Jobs”

21 US Department of Energy, National Energy Technolog y Laboratory, “Cost Estimating Methodology for NETL Assessments of

Power Plant Performance”, DOE/NETL-2011/1455, April 2011, pg 4.www.AndoverTechnology.com 8

States. According to a study by Cichanowicz, 22 at the end of 2001, there were only about 13,000 M W of coal SCR capacity in the United States, with nearly all installed in the prior two years, meaning that there was very limited long-term experience with SC R on US coals. SCR usage on coal-fired boilers has since increased over ten times to about 143,000 MW of coal capacity (over 50% of the 280,000 MW of current coal capacity) with most in operation for m ore than ten years. SCR is therefore a very well proven and well understood technology on a wide ran ge of US coals. As a result, the process contingency for SCR on coal-fired utility boilers s hould be much lower today than what it was when the CCM was issued in January 2002 – 5%. For SCR appli cations on utility boilers burning US western bituminous coals there should not be a need for pro cess contingency.

2. Project Contingency of 15% is too high in light of the cost method used and very conservative underlying assumptions.

The cost estimates developed for PacifiCorp are alr eady fairly conservative, allowing for overtime due to longer shifts, per diem, small tool s charges and other factors, and the estimates are based upon detailed estimates of the labor and mate rials to build the SCR. As a result, a 15% project contingency is excessive.

According to the 2002 SCR CCM, Section 1.1 Chapter 1, page 1-4,

“The accuracy of the information in the Manual work s at two distinct levels. From a regulatory standpoint, the Manual estimating procedure rests on the notion of the “study” (or rough order of magnitude - ROM) estimat e, nominally accurate to within ± 30%. This type of estimate is well suited to estimating control system costs intended for use in regulatory development because they do not require detailed site-specific information necessary for industry level analyses.”

The methods and cost elements of the 2002 CCM were adapted from the American Association of Cost Engineers, or AACE (CCM Section 1, Chapter 2, p 2-5). AACE 16R-90 23 states that, “Project Contingency is included to cover the costs that wou ld result if a detailed-type costing was followed a s in a definitive-type study.” According to NETL, 24 “AACE 16R-90 states that project contingency for a “budget-type” estimate (AACE Class 4 or 5) should b e 15% to 30% of the sum of BEC, EPC fees and process contingency.” AACE 18R-97 25 defines different classes of estimates, from 5 (le ast detailed) to 1 (most detailed). The methodology used in the CCM f alls into a Class 4 or Class 5, while the methodology used by PacifiCorp in their comments, w ith hundreds of line items and input parameters, is clearly a far more detailed estimate that leaves out very little, if any, project scope. Therefore , the cost estimate provided by PacifiCorp would fall int o a Class 1 or 2 estimate rather than Class 4 or 5 estimate.

For this reason, the 15% project contingency factor in the CCM for SCR shown in Table 2.5 on page 2-44 of Section 4.2 Chapter 2 is based upon us e of the cost estimating method described in the CCM to develop the Total Direct Capital Costs. It is not intended to apply to a detailed estimate tha t:

22 From data in Cichanowicz, J., Muzio, L., Hein, M., “T he First 100 GW of SCR in the U.S., - What Have We Learned?”, 2006

Mega Symposium

23 AACE Recommended Practice, AACE 16R-90; www.aacei.org/non/rps/18R-90.pdf

24 US Department of Energy, National Energy Technolog y Laboratory, “Cost Estimating Methodology for NETL Assessments of

Power Plant Performance”, DOE/NETL-2011/1455, April 2011, pg 5.

25 AACE Recommended Practice, AACE 18R-87; www.aacei.org/non/rps/18R-97.pdfwww.AndoverTechnology.com 9 • Includes many cost line items that are not explicit ly included in the estimating method described in the CCM to develop the Total Direct Ca pital Costs and meant to be included in the 15% project contingency, and

• Already has substantial contingency built into it t hrough conservative assumptions.

In fact, the 2002 CCM discusses the importance of n ot double-counting contingency in multiple places such as retrofit factor and contingency at p age 2-30 of Chapter 2 - Cost Estimation: Concepts a nd Methodology.

“Due to the uncertain nature of many estimates, ana lysts may want to add an additional contingency (i.e., uncertainty) factor to their est imate. However, the retrofit factor is a kind of contingency factor and the cost analyst must be careful to not impose a double penalty on the system for the same unforeseen conditions. Retrofit factors should be reserved for those item s directly related to the demolition, fabrication, an d installation of the control system. A contingency factor should be reserved (and applied to) only those items that could incur a reasonable but unanticipated increase but are not d irectly related to the demolition, fabrication, and installation of the system. For ex ample, a hundred year flood may postpone delivery of materials, but their arrival at the job site is not a problem unique to a retrofit situation.” (Emphasis added.)

The 2002 CCM, therefore, explicitly anticipates tha t some analysts may, incorrectly, apply multiple contingencies for the same areas of cost e ven when using the methods described in the CCM for estimating Total Direct Capital Costs. The CCM is clear that such double-counting should be avoided.

Because the cost estimates developed for PacifiCorp are already very conservative and based upon detailed estimates of the labor and materials to build the SCR, rather than study-level (class 4 or 5) estimates, they have double-counted both the cos ts that are intended by the CCM to be included in the project contingency when using the CCM method, plus they have added additional contingency in the form of conservative assumptions to address unc ertainties in their estimate. For this reason a 15 % project contingency is excessive for their estimate s. In light of the very conservative estimates the y already developed and the comprehensive nature of t hose estimates, no additional project contingency is allowed.

3. General Facilities

General Facilities are costs that are not directly associated with the process equipment, and include such things as access roads, safety equipme nt (such as eye-wash stations), general access, etc

. On the other hand, ductwork, piping, structural ste el to support process equipment and process auxiliaries (such as air compressors or cooling wat er) do not fall into the category of General Facili ties.

The cost estimate for PacifiCorp on all four units included a number of items that would fall into the category of General Facilities, and in ord er to avoid double-counting, an additional line ite m for General Facilities will not be included. To be mor e specific, examining PacifiCorp’s BART Analysis Update for Hunter Units 1 and 2 and Huntington Unit s 1 and 2 from August 5, 2014, numerous items are included that would fall into the category of G eneral Facilities, such as roadways, road signs, eyewash stations, pre-fabricated buildings, fire pr otection, and other items, examples as shown In Figure 4.www.AndoverTechnology.com 10 **Figure 4.** General Facilities items in the detailed Conceptua l Cost estimate.

4. AFUDC

AFUDC is not included in the overnight cost methodo logy of the CCM and therefore was not allowed. PacifiCorp correctly excluded this from t heir estimate.

5. Sales Taxes

Sales taxes are excluded from the PacifiCorp cost e stimate, as these do not apply to environmental upgrades in Utah. 26

6. Property Tax

A line item for capitalized property tax is shown f or each of the SCR cost estimates in the 2014 cost estimate for PacifiCorp. An annualized proper ty tax factor is also applied. 27 A tax rate of 1.0%,

26 HEAL UTAH * NATIONAL PARKS CONSERVATION ASSOCIATIO N *SIERRA CLUB, Comments on Proposed Amendments to Utah’s Regional Haze Rule, December 2 2, 2014www.AndoverTechnology.com 11

consistent with PacifiCorp’s 2014 submittals (page 25) is assumed, along with a declining apportionment of value, per Utah’s Recommended Pers onal Property Valuation Schedules. 28 The payment equivalent of the net present value is used to determine the annual equivalent payment per Equation 2.7 of Section 1 of the 2002 CCM.

7. Indirect Installation Costs

According to the 2002 CCM, page 2-43,

“Indirect installation costs are those associated with installing and erecting the control system equipment but do not contribute directly to the phy sical capital of the installation. This generally includes general facilities and engineering costs s uch as construction and contractor fees, preproduction costs such as startup and testing, in ventory capital and any process and project contingency costs.”

As a result, several costs cited in PacifiCorp’s co st estimate, such as Contractor Construction Management / Field Engineering and Contractor Train ing Classes, are not allowed because these are included in the 10% Engineering and Home office fee s that are already included in the cost.

8. Catalyst and Catalyst reactor

Sargent & Lundy arrives at a catalyst cost by escal ating a 1998 cost of catalyst using the CEPCI, whic h does not consider what catalyst actually costs toda y. As shown in Figure 5. Roughly $5,500 per cubic meter is a reasonable value for anticipated future catalyst prices. However, most replacement catalys t in the United States is regenerated catalyst, and i s substantially less expensive than new catalyst. 29, 30 PacifiCorp assumes different catalyst costs in diff erent locations of their August 2014 estimate. PacifCorp assumes new catalyst cost of $240/ft 3 ($8,600/m 3 ) and replacement cost of $290/ft 3 ($10,400/m 3 ) on pages 21, 27, 33, and 39 of their August 2014 BART submittal. On the other hand, in their Conceptual Cost estimate of the same submitta l (see pages 54, 65 89, and 100) they assume 1040 cubic meters at a cost of $6,750,000 (see item 31.5 3.15), or $6,500/m 3 with additional cost of labor for installation. These costs are at the upper level t o well above what catalyst actually costs. Furtherm ore, the escalation in catalyst prices assumed by Sargen t & Lundy appears excessive based upon Cichanowicz’s information shown in Figure 5. There fore, an assumed current and future catalyst price of $5500 per cubic meter is a reasonable price for catalyst – especially in light of the availability and lower cost of recycled catalyst – roughly half the price of new catalyst. 29, 30 The initial catalyst charge is included in the capital cost and future replacement cost is incorporated into the operating cost. Adjustments are therefore made to both the capital and operating costs for the SCR that were developed for PacifiCorp.

27 PacifiCorp’s BART Analysis Update for Hunter Units 1 and 2 and Huntington Units 1 and 2, August 5, 201 4, page 47

28 Class 8 , Machinery and Equipment schedule, from 20 15 Recommended Personal Property Valuation Schedule s and

Registered Vehicle Uniform Fees, Utah State Tax Com misssion, Property Tax Division

29 Hartenstein, H., Servatius, P., Schluttig, A. “Lif etime Extension of SCR-DeNOx Catalysts Using SCR-Te ch’s High Efficiency

Ultrasonic Regeneration Process”, Coal-Gen Chicago, Illinois, July 25-27, 2001

30 Hartenstein, H., “German Experience with Catalyst Regeneration”, 2007 NOx Round Table and Expo, Cinci nnati, Feb 5-6,

2007www.AndoverTechnology.com 12 **Figure 5.** SCR Catalyst Prices. 31

Sargent & Lundy has estimated 1040 cubic meters of catalyst. The estimate by Sargent & Lundy of catalyst volume appears to be too great – two reactors each with about 520 cubic meters of catalyst. See line 55 of the EPA cost effectivenes s comparison (Appendix A) for each of the units in the August 5, 2014 PacifiCorp document (pages 22, 28, 3 4, and 55). This is roughly double the amount of catalyst that would normally be expected for units of this size. For example, a 350 MMBtu/hr (roughly 35 MW) coal-fired boiler would require about 42 m 3 of catalyst. 32 Table 1 also shows examples of power plants with SCRs installed along with the cat alyst volume. Except for Comanche, which has very low NOx reduction, the catalyst volumes are general ly in the range of 0.89 to 1.38 cubic meters per MW of capacity while the estimate for PacifiCorp is well over 2 cubic meters per MW. PacifiCorp did not provide any discussion to explain why the catal yst volume was so large for the Hunter and Huntington units. Explanations might include extr emely high deactivation rates, but this is not discussed at any point in PacifiCorp’s documentatio n. For that matter, there is no reason to believe that the coals burned at these plants should have u nusually high deactivation rates. A review of USGS Coal Quality Data 33 for catalyst poisons showed that the Utah coals ha d arsenic contents typically below 1 ppm and rarely more than a few ppm, well be low most eastern bituminous coals, and sodium, potassium and phosphorus levels were consistent wit h or generally lower than Pennsylvania bituminous coals, which are currently used with SCR equipped facilities. Calcium oxide in the ash, wh ile higher than for Pennsylvania coals, was below that of Powder River Basin coals.

31 J. Edward Cichanowicz, CURRENT CAPITAL COST AND C OST-EFFECTIVENESS OF POWER PLANT EMISSIONS CONTROL TECHNOLOGIE, Prepared for, Utility Air Regulatory G roup, July 2013

32 US EPA, Air Pollution Control Technology Fact Shee t, http://www3.epa.gov/ttn/catc/dir1/fscr.pdf

33 Database is available at http://energy.er.usgs.gov /coalqual.htmwww.AndoverTechnology.com 13 Sargent & Lundy’s estimate appears to be based upon “Naughton 3 actual catalyst volumes”. 34 However, this is misleading since Naughton 3 has no t constructed an SCR. In fact, the owners plan to convert the unit to natural gas. 35

**Table 1.** High Dust Coal-Fired SCRs in the United States

Plant Unit MW % Red’n Catalyst Volume m 3 Lifetime,

hrs or yrs NH3 slip,

ppm Reference

Montour 1 745 90 671 (HC) 2 yrs 2 36
Montour 2 755 90 671 (HC) 2 yrs 2 36 Trimble Cty 547 90 674.6 (plate) NA 2 37 Spruce 2 800 64 1100 (HC) 26,280 2 38 Comanche 3 800 36 400 (Cor) 24,000 2 38
Iatan 1 670 77 800 (HC) 24,000 2 38
Iatan 2 900 68 800 (HC) 24,000 2 38 Cope 1 430 90 426 (HC) 16,000 2 38
St John River 2 units 670 each 85 770 each (HC) 18,000 39
AES Somerset 675 90 897 (plate) 24,000 3 40 Hawthorn 500 55.6 477 (plate) 24,000 2 40 Catalyst is indicated as honeycomb (HC), corrugated (Cor ), or plate (plate) NA means data was not available in paper

To determine a more reasonable catalyst volume, an independent calculation of catalyst volume was made using two methods: 1) using empiric al Equations 2.22-2.27 of the 2015 CCM, and 2) using the projected activity method using equation 2.21 of the 2015 CCM.

Catalyst Volume Using Empirical Approach

The empirical equation 2.22 is used in worksheet NO x-SCR_$ton lines 63-71 of the workbook UT_EGU BART Costs to estimate catalyst volume. It results in a total catalyst volume of roughly 50 0
cubic meters – which is more consistent with normal practice and the data in Table 1. In addition,

34 PacifiCorp’s BART Analysis Update for Hunter Units 1 and 2 and Huntington Units 1 and 2, August 5, 20 14, see pdf page 22

35 PUBLIC UTILITY COMMISSION OF OREGON STAFF REPORT PUB LIC MEETING DATE: March 17, 2014;

http://www.puc.state.or.us/meetings/pmemos/2014/031 714/reg1-LC%2057.pdf
BEFORE THE PUBLIC UTILITY COMMISSION OF OREGON LC 57; “In the Matter of PACIFICORP, dba PACIFIC POWE R ORDER;

2013 Integrated Resource Plan. DISPOSITION: 2013 IR P ACKNOWLEDGED WITH EXCEPTIONS AND REVISIONS JUL 0 8 2014 PacifiCorp, Exhibit RR of Reply Testimony, Summar y of Alternative Compliance Technology Solutions, 1 -3-2014

36 Glaser, R., Licata, A., Robinson, T., “THE SCR RET ROFIT AT THE MONTOUR STEAM ELECTRIC STATION”, Present ed at the

Electric Power Generation Association,, October 24- 25, 2000,, Hershey, Pennsylvania

37 Saudners, E., Straight, S., et. al., “SCR SYSTEM P ERFORMANCE AT LG&E’S TRIMBLE COUNTY GENERATING STATIO N”,

Presented at the EPRI Workshop on Selective Catalyt ic Reduction, October 22-23, 2002, Atlanta, Georgia

38 Buschmann, J., Cohen, M., “New Developments in NO x Reduction”, Coal Gen, August 17-19, 2011,Columbus, OH

39 Smith, et. al. “St. Johns River Power Park 2 x 670 MW SCR - Designed to Ensure Fuel Flexibility”, The Mega Symposium,

Paper #96, Baltimore, MD, August 25-28, Baltimore, MD

40 Calvello, J., “Recent Coal Fired SCR Operating Exp erience in the USA” 2001, EPRI NO x Workshop, Nov 12-17, 2001www.AndoverTechnology.com 14

32,000 hours between catalyst changes as assumed by Sargent & Lundy is quite unusual, and as shown in Table 1, lifetimes of 16,000 hours or 24,000 hou rs are more common.

Catalyst Volume Using Projected Catalyst Activity A pproach

As a second check, the projected catalyst activity method is also used in lines 73-85 of the NOxSCR_$ton worksheet. This uses equation 2.21 of the 2015 CCM, and this m ethod is more consistent with how a catalyst supplier would estimate catalys t volume in that catalyst lifetime, deactivation ra te and catalyst design characteristics are incorporate d into this method. 41 With this method it is necessary to estimate the activity level for the ne w catalyst. As shown in Figure 6, which demonstra tes the impact of test conditions on measured catalyst activity, the activity K was 45 m/hr for a 1 meter long sample in a test reactor with a velocity of 15 ft/sec (4.6 m/sec). This demonstrates that an assumed ko of 42.5 m/h as a starting point for the SCR catalyst sizing is reasonable and conservative. Other references show new catalyst activity in the range of 42.7 42 and about 42.5 m/h. 43 Based upon these sources, an assumption of 42.5 m/h is assumed

.

**Figure 6.** Calculated Effect of Velocity on Measured Catalys t Activity, K 44

Specific surface area of the catalyst must be deter mined. In selecting the catalyst, the dust loading should be considered. Table 2 shows the pl ate catalyst or honeycomb catalyst pitch for different dust loadings. Based upon EIA Schedule 923 data for 2014, the fuel burned at the Hunter an d

41 John Cochran, “Fuel Impacts on Design and Performa nce of Catalysts”, McIlvaine “Hot Topic Hour”, June 30, 2011 Ken Jeffers, “SCR Catalyst Management “, 2008 WP CA/Ameren ESP and SCR Seminar, Effingham, IL, Augus t 20, 2008

42 US Patent 7741239, Table 3

43 Hartenstein, “German Experience with Catalyst Rege neration”, 2007 NOx Round Table and Expo, February 5-6, 2007, see

slide 12. X and Y axis labels are apparently trans posed.

44 Electric Power Research Institute, Protocol for La boratory Testing SCR Catalyst Samples 1012666, Fina l Report, December

2006, see Fig 3-1; as described in this document, K calculated using normal rather than actual flowrat es and therefore normal flowrates are used in equation 2.2 1 to determine catalyst volume.www.AndoverTechnology.com 15

Huntington plants averages about 10% fly ash, which would roughly result in a little under 6 grain/dsc f. This would permit a honeycomb of perhaps 7.4 mm or 8.2 mm pitch. An 8.2 mm pitch catalyst will have a lower chance of plugging and is therefore se lected. Neglecting any plugged cells, honeycomb catalyst with a pitch of 8.2 mm and 1 mm wall thick ness has a specific surface area that can be estimated by multiplying the circumference of each cell (equal to four times the pitch minus the wall thickness, or 4*(p-t)) times the number of cells pe r square meter (equal to the square of one meter divided by the pitch, or (1/p)^2) and then multiply by an assumed catalyst depth of one meter. For a honeycomb catalyst with 8.2 mm pitch and 1 mm wall thickness, this results in 428 m 2 /m 3 , and this
calculation is shown in cell N83 of worksheet NOx-S CR_$ton.

**Table 2** . Catalyst pitch selection for different dust loadi ngs 45

Finally, a deactivation rate must be assumed to est imate future activity. Table 3 shows
deactivation rates for different coals. Since the units use bituminous coals, k/ko = 0.70 is assumed.

**Table 3**

. Deactivation rates for different coal types 45
Coal Time, hr k/ko Inferred highest deactivation rate per hour (1/τ, for lowest k/ko) 46
Low Dust 16,000 0.80

- 0.85 1.39E-05
Bituminous 16,000 0.70

- 0.75 2.23E-05
PRB 16,000 0.65

- 0.70 2.69E-05 Lignite 16,000 0.50

- 0.55 4.33E-05

In using Equation 2.21, it is important to be consi stent between the procedure used in determining catalyst activity and the use of that c atalyst activity value in estimating catalyst volum e. Industry convention (as described in Reference 47) is to calculate catalyst activity from laboratory t ests

45 Ken Jeffers, “SCR Catalyst Management “, 2008 WPCA/ Ameren ESP and SCR Seminar, Effingham, IL, August 2 0, 2008

46 Estimated using Equation 2.2 of the 2015 CCM

47 Electric Power Research Institute, Protocol for La boratory Testing SCR Catalyst Samples 1012666, Fina l Report, December

2006www.AndoverTechnology.com 16

under representative conditions; however, catalyst activity is then represented in terms of volume
flowrates at normal conditions. This has the benef it of providing consistent measures of catalyst activity across the industry. Therefore, when usin g catalyst activity values determined with this procedure for calculating catalyst volume with Equa tion 2.21, SCR system volume flowrate adjusted to normal conditions should be used in Equation 2.21 r ather than the actual volume flowrate, as
demonstrated in Reference 48. With a 15% additi onal allowance for plugging and a 16,000 hour time before the first catalyst replacement and using equ ation 2.21, these assumptions result in catalyst volumes estimated at 577 cubic meters (using the ma ximum catalyst size estimated for the four units).

Therefore, the estimated catalyst volume of 1040 cu bic meters used by PacifiCorp is well in excess of what is expected from other facilities or from other methods for estimating catalyst volume. The two other methods result in catalyst volumes in roughly the same range and volumes that are consistent with what has been used in other high-du st coal-fired EGU applications.

Conservatively using the highest estimated catalyst volume of the two methods, a catalyst volume of 577 cubic meters and a catalyst lifetime until the first catalyst addition of 16,000 hours i s assumed in this analysis.

An increase in catalyst lifetime to 32,000 hours wo uld not explain the high catalyst volume estimated by Sargent & Lundy. For bituminous coals k/ko between 0.70 and 0.75 is expected after 16,000 hours, or a reduction in activity of between 25% and 30% every 16,000 hours. 49 Therefore, given that catalyst activity decays at an exponenti al rate given by Equation 2.2 of the 2015 CCM and volume is determined by Equation 2.21, an increase in volume to go from 16,000 hours to 32,000 hours should be equal to between about 1/0.75 to 1/0.70, or between 1.33 to 1.43, or no more than about 43% more catalyst – not a near doubling of catalyst size.

Impact on SCR Reactor and associated equipment

As a result of the much lower catalyst volume, it i s necessary to make several adjustments to the PacifiCorp estimate for both the catalyst and t he SCR reactor cost. Only one reactor is necessary as opposed to two. This is because only about half as much catalyst is actually necessary (577 m 3 ). Drawings prepared by Sargent & Lundy and submitted by PacifiCorp with their August 5, 2014 BART analysis show two reactors, each with a square cros s section with each side between 40 feet and 50
feet. 50 To calculate gas volume, the factors in Table 4 c an be used to aid in calculations of gas flow and were determined with calculations using EPA’s CUECO ST for different coals in the CUECOST coal
database. 51

48 John Cochran, “Fuel Impacts on Design and Performa nce of Catalysts”, McIlvaine “Hot Topic Hour”, June 30, 2011

49 Jeffers, K., “SCR Catalyst Management”, 2008 WPCA/A meren, ESP and SCR Seminar Effingham, IL August 20, 2008

50 PacifiCorp’s BART Analysis Update for Hunter Units 1 and 2 and Huntington Units 1 and 2, August 5, 20 14, see pdf pages 79

and 114

51 http://www3.epa.gov/ttncatc1/products.htmlwww.AndoverTechnology.com 17

**Table 4.** Flue gas estimates for different coals at differen t combustion air conditions estimated with
CUECOST

units % air Jefferson,
OH Logan,

WV No. 6 Illinois Wyoming

PRB Lignite,

ND Total Dry lbmole/MMBtu 120% 30.2 30.0 30.2 30.4 30.8 Total Wet lbmole/MMBtu 120% 33.0 32.8 33.5 35.1 35.7 Total Dry lbmole/MMBtu 115% 29.0 28.7 28.9 29.1 29.5 Total Wet lbmole/MMBtu 115% 31.7 31.5 32.2 33.8 34.4
The inlet gas velocity and catalyst channel velocit y for one reactor of 50 feet to a side was calculated and it is sufficiently low. 52 Since the reactor will likely remain roughly the same height, having three layers initially installed, the cross sectional area of the catalyst reactors will be red uced roughly in proportion to the catalyst volume, which will reduce the perimeter of the reactor vessel, thereby reducing the material needed for the SCR re actor vessel roughly in proportion to the reduced perimeter. Using this approach to estimate the redu ction in cost for a single reactor vessel, an approximation is to use the square root of the chan ge in cross sectional area so that if the cross
sectional area were cut in half as a result of cata lyst volume being cut in half, roughly 71% (square root of 0.5) of the materials would be used for the reac tor.

On the other hand, Sargent & Lundy assumed two SCR reactors. Assuming a common wall rather than two completely separate reactors, the r eduction can also be estimated as going from seven walls (three for each reactor plus the one common) to four walls, or 4/7 or 57% of the labor and materials (SCR vessel casing, hood, gallery insulat ion, etc.) to build one SCR vessel versus two. Go ing from two separate reactors to one would go from 8 w alls to 4, or a roughly 50% reduction. To be conservative, the ratio of the square root of the r atio of the volume of catalyst was used (roughly 0. 74). The reduced catalyst perimeter provides a rough est imate of the reduced surface area (as opposed to cross sectional area) of the catalyst reactor and a ssociated materials for the reactor. This is an approximation, but a conservative one since the rea ctor hood and inlet, as well as the reactor vessel are all scaled in this manner, and ductwork was not scaled down at all although some of the cost for ductwork would in fact be reduced by cutting the nu mber of ducts in half, while perhaps making them somewhat larger. Items identified in the estimate as Other Direct Costs are scaled down in accordance
with the reduction of direct costs.

Because only one reactor of roughly the same size a s one of the two reactors assumed by Sargent & Lundy is necessary, equipment such as soo tblowers, sonic horns, LPA screens and static mixers are all cut in half versus the estimate by S argent & Lundy. Also, SCR support steel is cut in half because only one reactor with roughly half the tota l volume of catalyst is needed versus Sargent & Lundy’s estimate.

52 See worksheet NOx-SCR_$ton in attached Excel workb ook. Lines 29-32. Per pg 2-51 of 2015 CCM a superficial velocity of 16 f/s or 5 m/s may be used to estimate cross section al area Also, per Hans Jensen-Holm, Nan-Yu, Jim Jianhua Cui , “Implementation of SCR DeNOx Technology on Coal- Fired Boilers in P.R.

China”, pg 11 shows channel velocities of 6-7.5 m/s

.www.AndoverTechnology.com 18 The resulting adjustments to the PacifiCorp estimat e are shown in lines 10-20 of worksheet SCR_PacifiCorp Annual_Adjusted in the workbook UT_E GU BART Costs.

Catalyst lifetime also plays a role in the economic s and affects the annual allocated cost for catalyst replacement. The assumed 32,000 hours bef ore the first layer replacement – or a replacement time of four years to the first catalyst addition i s unusually high. As Table 1 demonstrates, the mos t common catalyst replacement periods are between 16, 000 hours and 24,000 hours. A life of 16,000 hours, or two years between replacement, is assumed in this analysis. This is conservative in the sen se that it provides a higher catalyst annual replaceme nt cost and seems generally consistent with both practice and other bituminous units.

9. Cost of Induced Draft (ID) Fan and Auxiliary Load

Sargent & Lundy has estimated 2090 kW and 2182 kW f or load (page 47 of August 2014 PacifiCorp submittal). Because there are very few electric loads besides the fan, and they are small by comparison, the largest single load by far is the i ncreased fan load from the SCR system pressure drop

. Calculations were performed in the fan power worksh eet to estimate fan load based upon pressure drop and volume flowrate. The loads estimated by S argent & Lundy correspond to a combined fan and motor efficiency of over 80%. 53 Using a combined fan and motor efficiency of 65% and pressure loss values per the 2002 CCM, 54 results in a load of about 2.7-2.8 MW, or about 36 00-3800 hp. This is also consistent with the value estimated using the 2015 CCM of about 2.6-2.8 MW. 55 Therefore, although the load was underestimated, Sargent & Lundy over-e stimated the cost of the fans used in the PacifiCorp submittal. Two 6000 hp (4475 kW) fans a nd motors included in the capital cost estimate (see line 31.35.00 of Conceptual Cost Estimate on p ages 54, 65, 89 and 100 of the August 2014 submittal) are too large even allowing for 2x100% flow capability. They presume a fan efficiency of under 50%, which is too low (see calculations in fa n_power worksheet). These large fans would need to be throttled or run at less than full speed. Sm aller fans properly sized for the load would be a m ore economical choice. Therefore, the cost of the fans in PacifiCorp’s estimate should be reduced. To estimate the cost of lower power fans, it is possib le to use the algorithm for estimating fan cost in
CUECOST.

The CUECOST ID fan cost algorithm in the fabric fil ter worksheet is

(97.41*Volume Flow^0.619) 56

This can be used to estimate the cost for lower pow er fans, although, it is not possible to use it directly because the CUECOST algorithm does not acc ount for escalation of costs since that algorithm was originally developed. However, since the algor ithm demonstrates that cost of a fan is proportiona l
to the maximum volume flowrate raised to the 0.619 power, it can be used to scale the costs provided

53 See calculation in fan_power worksheet of UT_EGU_B ART_Costs workbook

54 2002 CCM, Section 1, page 2-32, Section 2 page 2-46 , calculation is in fan_power worksheet of UT_EGU_B ART_Costs workbook

55 2015 CCM; Equation 2.61

56 Coal Utility Environmental Cost (CUECost) Model Vers ion 1.0 -http://www3.epa.gov/ttncatc1/products.html , see line 59 of

FF ESP Cost & Tech. Results worksheetwww.AndoverTechnology.com 19

by Sargent & Lundy for PacifiCorp. Since power is e qual to the product of volume flow and pressure drop and the pressure drop across the SCR system at full load is unaffected by the choice of fan, we c an scale cost by horsepower raised to the 0.619 power to estimate the cost of a fan sized for lower power than 6000 hp. Using this approach, the cost of a 3 800 hp motor and fan would be estimated as:

Cost for 6000 hp fan * (3800/6000)^0.619

The resulting adjustments to the PacifiCorp estimat e are shown in line 21 of worksheet SCR_PacifiCorp Annual_Adjusted in the workbook UT_E GU BART Costs.

Therefore, the adjusted capital cost estimate adjus ts for the estimated auxiliary load assuming
that most of it is from the fan. This is also a co nservative estimate because in many cases existing fans can be modified to increase their output and overco me the increased pressure drop, and this would be a much less costly approach than installing two new fans.

10. Operating Cost - Cost of generating steam for hydro lyser

On page 47 of their August 2014 submittal PacifiCor p uses a cost of fuel of $5/MMBtu to generate steam. This is incorrect. The urea hydro lyser will utilize steam from the boiler, the cost of which is the additional fuel needed to generate the steam. According to FERC Form 1 data, the cost of fuel at the plants is as shown in Table 5. PacifiC orp’s cost of energy to heat the steam was therefor e changed to these values and adjusted for actual cap acity factor.

**Table 5.** Reported Fuel Cost in 2014 FERC Form 1

Plant unit Average Fuel Cost, $/MMBtu

Hunter 1 1.9590
Hunter 2 1.9080 Huntington 1 1.8300 Huntington 2 1.8300www.AndoverTechnology.com 20

**Assumptions**

In estimating cost of control, it is assumed that a full complement of combustion controls, including new Low NOx Burner Technology w/ Separate d OFA , are implemented prior to installation of post-combustion controls (SNCR and SCR). Actual an nual average emissions rates for the 2001-2003 period were used to estimate the emission rate prio r to installation of new combustion controls. Similarly, actual annual average emissions rates fo r 2014 and the first two quarters of 2015 were used to estimate the emission rate following with new co mbustion controls. For 2014, full year data was used, except for Hunter 1. In the case of Hunter 1 , only 2014 May to December data was used because combustion controls were installed in April. The a verage reported emission rates for 2001-2003, 2014 and 2015 (quarters 1 & 2) are shown in Table 6. Th ese demonstrate that all four units installed
combustion controls to reduce NOx emissions since 2 003.

**Table 6.** Reported emission rates for affected EGUs

**Facility Name Facility** 

**ID (ORISPL)**  **Unit**

**ID Annual**  **Heat Input, MMBtu**  **2001-03**
**avg. Avg. NO**  **x Rate (lb/MMBtu)** 

**2001- 2003**  **2014 2015 avg** 

**Q1, Q2 AVG after** 

**comb controls** 

Hunter 6165 1 31,372,895 0.4006 0.209 0.204 0.2067
Hunter 6165 2 31,537,898 0.3817 0.195 0.201 0.1977 Huntington 8069 1 31,365,923 0.3747 0.214 0.224 0.2191 Huntington 8069 2 29,899,997 0.3860 0.224 0.203 0.2136 All historical emissions and heat input data were d eveloped from the EPA Air Markets Program Data. Hunter 1 2014 data was May to December because of co mbustion control installation in April, other units were the complete yearwww.AndoverTechnology.com 21

**Cost Estimating**

The capital cost estimates are reflective of 2014 d ollars with capital costs all adjusted to 2014 using the CEPCI. The cost calculation results are summarized in the following sections of this report
and are detailed in the Microsoft Excel workbook at tached to this report:

• UT_EGU BART Costs

The details of the estimating methods are described in the workbook. Consistent with the EPA Control Cost Manual, 57 capital cost estimates do not include AFUDC or Own er’s Costs (beyond the 10% allowed for engineering and home office).

For combustion controls, capital and operating cost s are based upon what was provided by PacifiCorp. 7

For consumables, the following estimates are used:

• Urea - delivered price of urea prill about $489/ton 58

• Power and fuel – based upon 2014 FERC Form 1 data
Although anhydrous ammonia is generally a less expe nsive SCR reagent, urea has advantages especially with regard to safety. Since PacifiCorp has indicated urea as the SCR reagent in its cost estimate to include a urea to ammonia system with s olutionizing equipment, 59 it is assumed that urea prill will be the reagent of choice, with the under standing that if PacifiCorp were to later select anhydrous ammonia, the capital and operating costs would both be somewhat lower.

57 EPA. 2002. EPA Air Pollution Control Cost Manual (S ixth Edition). EPA/452/B-02-001, p 2-5 - 2-7

58 9/23/15 email Fuel Tech

59 PacifiCorp’s BART Analysis Update for Hunter Units 1 and 2 and Huntington Units 1 and 2, August 5, 20 14, pp 74, 108www.AndoverTechnology.com 22



### Hunter 1 & 2

An overhead view of Hunter plant is shown in Figure 6. Hunter units 1 and 2 are the two units to the left. Units 1 and 2 are tangentially fired units that have recently added more modern
combustion controls.

**Figure 6.** Hunter Power Plant

It was previously determined that post-combustion N Ox controls, including SNCR and SCR, are
feasible. 60 Detailed cost estimate calculations are provided in the Microsoft Excel workbook provided with this report. Table 7 shows the estimated cost s of control for each of the Hunter units. Although the units are similar, costs will vary somewhat for each unit due to: 1) different installed costs for equipment that are determined by unit specifics, an d; 2) somewhat different actual emission rates for
each unit.

60 PacifiCorp’s BART Analysis Update for Hunter Units 1 and 2 and Huntington Units 1 and 2, August 5, 20 14www.AndoverTechnology.com 23 **Table 7** 

**.** Hunter Estimated Control Costs

**Hunter 1 Cost**  **of controls**

**Combustion Control (CC)**  **SNCR SCR**  **CC and SNCR CC and SCR** 
Capital Cost, $/kW $26 $17 $221 $43 $247 Control Efficiency 48% 21% 76% 59% 88%
**Uncontrolled Rate**

NO x Rate (lb/hr) 1922 992 992 1922 1922

NO x Rate (lb/MMBtu) 0.40 0.21 0.21 0.40 0.40

NO x (TPY) 6284 3242 3242 6284 6284
**Controlled Rate**

NO x Rate (lb/hr) 992 780 240 779.81 239.95

NO x Rate (lb/MMBtu) 0.21 0.16 0.05 0.16 0.05

NO x (TPY) 3242 2549 784 2548.98 784.32

Tons/Year Removed 3042 693 2458 3735.01 5499.67

Total Cost/year $1,161,898 $2,632,634 $11,929,013 $3,794,531 $13,090,910 $/Ton $382 $3,796 $4,853 $1,016 $2,380 $/ton Incremental $3,796 $5,268 $3,796 $5,268

**Hunter 2 Cost**  **of controls**

**Combustion Control (CC)**  **SNCR SCR**  **CC and SNCR CC and SCR** 
Capital Cost, $/kW $20 $18 $231 $38 $251 Control Efficiency 48% 21% 75% 59% 87%
**Uncontrolled Rate**

NO x Rate (lb/hr) 1,765 914 914 1,765 1,765

NO x Rate (lb/MMBtu) 0.38 0.20 0.20 0.38 0.38

NO x (TPY) 6,018 3,117 3,117 6,018 6,018
**Controlled Rate**

NO x Rate (lb/hr) 914 720 231 720 231

NO x Rate (lb/MMBtu) 0.20 0.16 0.05 0.16 0.05

NO x (TPY) 3,117 2,457 788 2,457 788

Tons/Year Removed 2,902 660 2,328 3,562 5,230

Total Cost/year $864,040 $2,583,159 $11,854,673 $3,447,199 $12,718,714 $/Ton total $298 $3,913 $5,092 $968 $2,432 $/ton Incremental $3,913 $5,558 $3,913 $5,558

incremental
versus CC incremental

versus SNCR incremental

versus CC incremental

versus CC and
SNCRwww.AndoverTechnology.com 24



### Huntington 1 & 2

An overhead view of Huntington plant is shown in Fi gure 7. Units 1 and 2 are tangentially fired units and have recently added more modern combustio n controls. Units 1 and 2 are tangentially fired units that have recently added more modern combusti on controls.

**Figure 7.** Huntington Power Plant

It was previously determined that post-combustion N Ox controls, including SNCR and SCR, are
feasible. 761 Detailed cost estimate calculations are provided in the Microsoft Excel workbook provided with this report. Table 8 shows the estimated cost s of control for each of the Huntington units. Although the units are similar, costs will vary som ewhat for each unit due to: 1) different installed costs for equipment that are determined by unit specifics , and; 2) somewhat different actual emission rates
for each unit.

61 PacifiCorp’s BART Analysis Update for Hunter Units 1 and 2 and Huntington Units 1 and 2, August 5, 20 14www.AndoverTechnology.com 25 **Table 8** 

**.** Huntington Estimated Control Costs
**Huntington 1 Cost**  **of controls**

**Combustion Control (CC)**  **SNCR SCR**  **CC and SNCR CC and SCR** 
Capital Cost, $/kW $18 $17 $216 $34 $234 Control Efficiency 42% 22% 77% 54% 87%
**Uncontrolled Rate**

NO x Rate (lb/hr) 1741 1018 1018 1741 1741

NO x Rate (lb/MMBtu) 0.37 0.22 0.22 0.37 0.37

NO x (TPY) 5876 3436 3436 5876 5876
**Controlled Rate**

NO x Rate (lb/hr) 1018 797 232 797 232

NO x Rate (lb/MMBtu) 0.22 0.17 0.05 0.17 0.05

NO x (TPY) 3436 2692 784 2,692 784

Tons/Year Removed 2440 745 2652 3,185 5,092

Total Cost/year $810,754 $2,686,934 $11,994,475 $3,497,687 $12,805,229 $/Ton $332 $3,609 $4,522 $1,098 $2,515 $/ton Incremental $3,609 $4,879 $3,609 $4,879
**Huntington 2 Cost**  **of controls**

**Combustion Control (CC)**  **SNCR SCR**  **CC and SNCR CC and SCR** 
Capital Cost, $/kW $21 $17 $222 $38 $243 Control Efficiency 45% 22% 77% 57% 87%
**Uncontrolled Rate**

NO x Rate (lb/hr) 1,762 976 976 1,762 1,762

NO x Rate (lb/MMBtu) 0.39 0.21 0.21 0.39 0.39

NO x (TPY) 5,770 3,194 3,194 5,770 5,770
**Controlled Rate**

NO x Rate (lb/hr) 976 765 228 765 228

NO x Rate (lb/MMBtu) 0.21 0.17 0.05 0.17 0.05

NO x (TPY) 3,194 2,506 747 2,506 747

Tons/Year Removed 2,576 688 2,446 3,264 5,023

Total Cost/year $941,438 $2,566,724 $11,931,528 $3,508,162 $12,872,966 $/Ton $365 $3,730 $4,877 $1,075 $2,563 $/ton Incremental $3,730 $5,326 $3,730 $5,326

incremental
versus CC incremental

versus SNCR incremental

versus CC incremental

versus CC and
SNCR