February 8 , 2010 Ms. Lisa Clarke Air Pollution Control Division- Policy and Planning Program Colorado Department of Public Health and Environment 4300 Cherry Creek Dr. S. Denver, CO 80246-1530 

# Energy Generation NA

Subject: Questions/Review for Co lorado Energy Nations (January 26, 2010 letter from CDPHE)

Dear Ms. Clarke: Colorado Energy Nations is pleased to provide this response to your January 26, 2010 letter regarding NOx emission controls. Each question is briefly summarized below followed by our response . Question 1 : CEN will be required to install LNB w/OFS for BART. Can you provide support that ULNBs will not result in further reductions for documentation purposes? Response: The term "ULNB" is associated w ith natural gas burners, not coal burners. Boilers Nos. 4 and 5 are Combustion Engineering (now ALSTOM Powe r) pulverized coal, tangentially f i red boilers w ith heat input capacities of 360 MMBtu/hr and 650 MMBtu/hr, respective ly. Based on information from ALSTOM Power, CEN plans to install low NOx burners wiith Separated Ove rf i re Air (SOFA) as descri bed i n our Ju ly 2006 BART analysis. The specific technology is ALSTOM Power's Low NOx Concentric Firing System (LNFCSTM) Level II as described in

### Appe~dix C of our July 2006 BART Analysis

. Burners, whether described as low NOx of U LNB, are only part of the best in-furnace NOx co nt rol system
. 1
To address the wide variety of boiler designs of varying vintage , along w ith a broad range of coals being fired, ALSTOM has developed a family of coal -fi red tangential low NOx systems
. The Low NOx Concentric Firing System (LNCFSTM) has four basic configurations
- from the LNCFSTM P2, and LNCFSTM Level I through**l** Ill, each w ith i ncreasing levels of reduction efficiency, system comp lexity and cost
. The TFS 2000R'M technology, with multiple levels of Separated Overfire Air (SOFA) and improved coal pulverization fineness control, prov ides the lowest in-furnace NOx emissions for certain low volatile

1 For coal fi red boil e rs there is no consi s tent definit io n of t he term or use of t he te rm ult ra low NOx burn e r (U LNB). ALSOTM's TFS 2000 R"' technology, w ith multiple leve l s of Sepa rated O verfire Air (SO FA) and im p roved coal pulverization fi neness control ca n, in th e r ight situation, achieve th e lowest possi b le NOx emission rate w ithout th e u se of post com bus t ion add-on emission co ntrol s. Page 11 Feb ruary 8, 1010 

### Colorado-Golden Energy Corp
. 25 101

### hStreet, P.O. Box 4088, Golden, Co. 8040 1 (303)277-5455 Fax (303)277-5629pulverized coal-fired units. These five different systems all utilize, in increasing levels of complexity, the basic Low NOx firing principles of staged combustion, rapid fuel devolatilization, and secondary air control. "For the subject units, the choice of low NOx f i ring systems is re latively l imited due to their small size and the fact that they are equipped for multiple fuel firing. The p ractical options for these units are limited to two basic choices; optimization of the existing firing system, and addition of a Separated Overfire Air System in combination with firing system modifications. These two options are essentially ALSTOM's LNCFSTM
- P2, and LNCFSTM Level II systems." 2 CEN plans to install the best performing, technically feasible, in-f urnace NOx em ission con t rol system which is ALSTO M's LNCFSTM L evel l I system. The LNCFSTM_P2 techn ology was rejected because it provides less NOx emission contro l. Based on ALSTOM Power's analysis, which included a site visit, potentially better performing systems cannot be applied to the relatively small No.4 and No.5 boilers. It is CEN's opinion, that ULNBs capab le of achieving lower NOx emissions are not available for Boilers Nos. 4 and 5 for coal firing. Question 

### 2 : CEN explained thoroughly the basis ofthe current coal supply. For a complete review of fuel switching, CE N needs to also examine fuels besides coal. These types of fuels include natural gas, biomas s

, etc. Please provide a qualitative discussion ofusing these fuels and whether these types of fuels will result in NOx benefits. A qualitative explanation regarding the feasibility ofusing natural gas, fuel oil, ethanol, sludge and/or wood as the primaryfuelfor Boilers 

### 4 and

### 5 will aid in the Division's documentation in the four-factor analysis for Colorado Energy Notion's Golden Facility. Response : The replacement ofcoal with natu ral gas wou ld reduce NOx emissions because natura l gas does not contain fuel bound nitrogen. Boiler 4 cu rrently has the capabil ity to burn all natural gas with a NOx emission limit of 0.20 lb/MMBtu. Boi ler 5 has limited capability, as the gas configuration is for ignitor levels only

. Conversion of the boilers to natural gas would probably reduce NOx emissions by at least 50% from the proposed BART emission rates of 0.32 lb/MMBtu and 0.28 lb/MMBtu for Boilers 4 and 5, respectfully. However, the achievable emission reductions wou ld depend on the type of burners that would be used and would require further study. There is the added negative Colorado economic impact in that CEN coal is from purchased from Colorado mines. Fuel is the largest steam production cost incurred by Colorado Energy Nations. Natural gas p ri ces tend to be much higher than coal and very volatile. Over the last five years, average monthly utility natural gas prices have been 3.8 times the price ofutility coal on a $/MMBtu basis. In addition, in the one year period from July 2007 to June 2008, monthly natural gas prices rose from $7.6/MMBtu to $12.7/MMBtu

2 Letter from Fred Hess (ALSTOM Power) to Bob Hall ( ENSR). M ay 19, 2006. Page 

## I 2 February 8, 1010while average coal prices only rose from $1.8 to $2.1/MMBtu. In December 2009, the average utility natural gas cost was $5.02/MMBtu while the average coal cost was $2.14/MMBtu. 3 Although there are some issues with the cost of natural gas, this fuel does offer some operating and maintenance cost advantages. The use of natural gas would eliminate pulverizer and baghouse operating and maintenance costs as well as ash handling and disposal costs. Other boiler maintenance costs would also be reduced if coal was not burned. At the present time, Colorado Energy Nations cannot commit to convert to natural gas due to price and price volati lity issues. However, fuel prices and steam production costs are subject to continued evaluations. Conversion to residual oil would offer very litt le if any NOx emission reduction. In addition, U

.S. Energy Information Administration data indicates the monthly average utility residual fuel oil cost in December 2009 was approximately $12/MMBtu while coa l was $2.1/MMBtu. Conversion to residual oil is not reasonab le due to minimal, if any, NOx emission reduction, and very high costs. Distillate oil, ethanol, and biodiesel are premium, high price fuels used primarily in many types of mobile sources. However, in some parts of the country, distillate oil and biodiesel are used for residential and commercial heating. Because these fuels are used in the same markets, the prices are similar. Although these fuels offer some potential NOx emission reductions, the costs are prohibitive. In December 2009, the average utility cost of distillate fuel was reported to be approximately $14/MMBtu while natural gas was $5/MMBtu and coal was $2.1/MMBtu. 4 Projections of future prices by the U.S. Energy Information Administration indicate that prices for these premium fuels will remain much higher than natural gas and coal. Conversion to distillate oil, ethanol, o r biodiesel is not reasonable due to the very high costs. Boilers 4 and 5 are pulverized coal fired boilers that are not capable of burning wood or other types of biomass. In order to burn wood or biomass, major modifications to the furnaces to install some type of grate and stoker firing system would be requ ired. This type of conversion may not be technically feasible. In addition, wood fuels and biomass have much lower heating values on a Btu/ft3 basis than coal. Adequate space to handle and store these fuels at the Colorado Energy Nations site is not available. I n addition, the achievab le NOx emission reductions are uncertain. EPA's RACT/BACT/LAER Clearinghouse lists 8 BACT permits (RBLIC IDs LA-0188, MN-0074, ND -0022, OH-0307, VA-0298, WA0327, WA-0329, WA-0335) for wood , wood waste, and biomass combustion with a NOx emission range from 0.12 lb/MMBtu to 0.45 lb/MMBtu and an average emission rate of 0.24 lb/MMBtu. 5 However, the lower emission limits require the use of Selective Noncatalytic Reduction. The use of sludge as the primary fuel is not feasible due to handling and storage issues. In addition , there are no proven NOx reduction benefits.

3 EIA- Forecasts and Analysis of Energy Data 4 EIA - Forecasts and Analysis of Energy Data 5 

### I RACT /BACT /LAER Clearinghouse (RBLC) 

### I RACT /BACT /LAER Clearinghouse 

### I Cl ean Air Techno logy Center 

### I Technology Transfer Network I US EPA Page 

## I 3 February 8, 1010Question 3: 

### CEN needs to provide a briefreview of the other threefactors: non-air quality and energy impacts, time necessary for completion, and useful life. Response: Non-air and Energy Impacts There are no non-ai r quality impacts associated with the planned low NOx burners and separated overfire air system. Energy impacts are not significant. SNCR and SCR have similar potential non-a i r quality impacts. The reagent materials, which may be urea or ammon ia, require a significant amount of energy to produce and are made from natura l gas, a limited resource. In addition, the prices for th ese materials fluctuate in response to natural gas and various economic factors. Both technologies resu lt in ammonia emissions. Ammonia in the flue gas may be absorbed by fly ash which may have detrimental effects of flyash disposal and reuse. In some cases SCR has caused a blue plume fo r reasons that are not entirely understood. In addition, SCR converts some of the 502 in the flue gas to sulfuric acid mist which contributes to regiona l haze. SNCR requires energy for pumping and compressed air needed 

### to inject the urea solution. For Boilers 4 and 5, the estimated energy consumption is 

### 90 kW per hour total. SCR requires much more ene rgy due the pressure drop through the reconfigured duct work and the catalyst. For Boilers 4 and 5, the estimated pressure drop through the catalyst is 7 to 8 inches water column and the total energy consumption is approximately 

### 1,000 kW per hour. Time Necessary for Completion After SIP approval, time will be needed for:
• pre li m i na ry engineering , preparation of detai led construction cost estimates, and preparation of a detailed schedule and seq ue ncing plan; • f i nal contracting and i nternal funding approva l; • final design and constru ction; and • performance, acceptance testing, and project closeout. For the proposed low NOx burner/SO FA system, the estimated t ime fo r completion is 12 to 18 months. For SNCR, the 24 to 36 months for project completion is reasonable. For SCR, the 36 to 48 months for project completion is reasonabl e. These timetables assume that contractors and materials will be available. A backlog of projects may develop due to an increased number of control project installations from the final resolution of CAIR, CAMR, and NESHAP regulations impacting bot h electric generating units and industrial boilers. 

### Useful Remaining life Page 

## I 4 February 8, 

### 1010Boilers 4 and 5 are subject to regular maintenance

. Co lorado Energy Nations has no plans to shutdown the boilers

. In accordance with the EPA Cost Contro l Manua l , an n ualized costs have been based on 20 years . Additional I nformation As briefly discussed during our phone conversation on 1/26/10, our Novembe r 2009 cost effectiveness ana lysis for SCR and SNCR was conservat ively based on 100% capacity factors for both Boilers 4 and 5. However, this conservative analys is over estimates the actual emission reductions that wou ld be achieved by these technologies

. Information recently submitted t o CDPHE shows that the actual highest 365-day rolling ave rage capac ity facto r for Boil e r 4, du ri ng the 2006 to 2008 period, was 286.6 MMBtu/hr or 80% for the period end i ng Ju ly 8, 2008

. 6 For Boile r 5, t h e highest 365-day roll i ng capacity fact or of 522

.2 MMBtu/hr or 80% occurred during the period ending J anuary 16, 2007. Based on actual costs and emission reductions, more realistic cost effect iveness values would be significan t ly higher than the va l ues subm itted in November 2009. For SCR, the cost effectiveness i ncreases from approximately $9 , 000/ton of NOx controlled to approxi mately $12,000/ton of NOx controlled . F or SNCR, the estimated cost effectiveness increases from $3,158/ton to $3,465/ton. Details are provided in Tables 1 and 2

.
Sincerely,

General Manage r
Copies: Fi l e M r . Bob Hall**AE~OM** 2 Technology Park Drive Westford, MA 01886-3 1 40

6 On 2/5/10, CEN subm itted dai ly capacity and emis sion information for the years 2006 thru 2008 to Curt Taipa le (response to 2/3/10 ema i l information req uest from CDPHE)

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### Table 1 SCR Annual Cost Effectiveness Based on Highest 12-mo nth Operation for the 2006 to 2008 Period
Process Heater Boiler4 Boiler 5 Capital Cost Total Installed Cost $23 ,800 ,000 32 ,300,000 November 2009 report submitted to CDPHE Boiler Capacity, MMBtu/hr 360 650 NOx Emissions before Control, 0.32 0

.28 lb/MMBtu 2006 to 2008 maximum 12- month Annual Capacity Factor, % 80% 80% rolling average for each unit, data submitted to CDPHE on 2/5/2010 NOx Emissions before Control, lb/ton/yr 401.6 640 .4 NOx Emissions after Control, lb/MMBtu 0.0600 0.0600 Control Efficiency, % 81

.3% 78.6% NOx Emissions after Control , lb/ton/yr 75
.3 170.0 NOx Emission Reduction, ton/yr 326.3 470 .4 Annu al Costs, $/yr Catalyst Annual Cost Catalyst Replacement Cost $ 630,000 $ 1,290 ,000 Catalyst Life 3

.0 3

.0 Annual Costs, $/yr $ 240 ,063 $ 491,557 7% interest < a> Urea $ 117,167 $ 168,878 1

.088 ton urea per ton NOx removed at a delivered cost of $330/ton Operating Labor $ 25,550 $ 25,550 2.0 hr/day at $35/hr Supervisor $ 3 ,833 $ 3,833 15% of operating labor Maintenance Labor $ 25 , 550 $ 2

.0 hr/day at $35/hr 25,550 Maintenance Materials $ 25,550 $ 25,550 100% of ma intenance labor Ammonia CEMS labor $ 20,000 $ 20 ,000 AECOM experience E lectricity $ 120,493 $ 463 ,886 LD&B

. 216 kW for Boiler No, 4 and 824 kW for Boiler No , 5. $0.08/kWh Overhead $ 60,290 $ 60 ,290 60% of oper, maint. & supv labor + maint. material costs < a > Taxes, Insurance, and Administration $ 952,000 $ 1,292,000 4% of total installed cost < a > Cap ital Recovery $ 2 , 187,084 $ 2,927 , 125 7.0% , 20 years, 0

. 1098 x (TCIcata lyst) <al Total Annual Cost $ 3 ,777 ,579 $ 5 ,504,2 1 8 Cost Effectiveness , $/ton of NOx $ 11,576 $ 11,702 controlled (a) EPA Air Pollution Control Cost Manual, Sixth Ed iition , Section 4 , Page 2-44. EPA/452/B-002-001

. January 2002.
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### Table 2 SNCR Annual Cost Effectiveness Based on Highest 12-month Operation for the 2006 to 2008 Period
Process Heate r Boiler 4 Boiler 5 Total Capital Cost Total Installed Cost $2 ,840,000 November 2009 report submitted to CDPHE Boiler Capacity, MMBtu/hr 360 650 1010 NOx Emissions before Control, 0.32 0

.28 0

.294 lb/MMBtu 2006 to 2008 maximum 12- month Annual Capacity Factor, % 80% 80% 80% rolling average for each unit, data submitted to CDPHE on 2/5/2010 NOx Emissions before Control , 401.6 640.4 1042.0 lb/ton/yr NOx Emissions after Control, 0

. 192 0

. 168 Performance estimate from Fuel lb/MMBtu 

### 0.177 Tech Control Efficiency, % 40.0% 40.0% NOx Emissions after Control, 241

. 0 384.2 625.2 ton/yr NOx Emission Reduction , ton/yr 160

.7 256.2 416.8 Annual Costs, $/yr Estimate from Fuel Tech, 23 and 38 Urea solution $ 280,662 $467 ,968 $ 748,629 gal/hr. $1.75/gal delivered cost based on quotation from CDI, Inc. <a> Water $ 4 ,377 Estimate from Fuel Tech, 26 gal/min

. $0

.4/1,000 ga l Operating Labo r $ 19,546 $ 19 , 163 $ 38 ,708 0.5 hr/shift at $35/hr (bJ Supervisor $ 2,932 $ 2,874 $ 5,806 15% of operating labor <bl Maintenance Labor $ 19,546 $ 19 , 163 $ 38,708 0.5 hr/shift at $35/hr<bl Maintenance Materials $ 19,546 $ 19 , 163 $ 38 ,708 100% of ma intenance labor ( bJ Ammonia CEMS Labor $ 20,000 $20 ,000 $ 40,000 AECOM experience Electricity $ 50,503 Estimate from Fuel Tech, 90 kW//hr. $0

.08/kWh. Overhead $ 48,941 $ 48 ,217 $ 97,159 60% of oper, maint. 

### & supv labor + maint. material costs (bJ Taxes, Insurance, and $ 113,600 4% of total installed cost (bJ Administration Capital Recovery $ 268,076 7.0%, 20 years, 0

. 1098 TCI (bl Total Annual Cost $1,444,274 Cost Effectiveness, $/ton of NOx $ 3,465 controlled (a) CDI, Inc, is a licensed supplier with a distribution center in Greeley, CO. Luis Cervantes 714-990-3940. (b) EPA Air Pollution Control Cost Manual , Sixth Edition, Section 4 , Page 2-44

. EPA/452/8-002-001. January 2002

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