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 Colorado 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 with natural gas burners, not coal burners. Boilers Nos. 4 and 5 are 

Combustion Engineering (now ALSTOM Power) pulverized coal, tangentially fired boilers with heat input 

capacities of 360 MMBtu/hr and 650 MMBtu/hr, respectively. Based on information from ALSTOM 

Power, CEN plans to install low NOx burners wiith Separated Overfire Air (SOFA) as described in our July 

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 ULNB, are only part of the best in-furnace NOx control system.

1 

To address the wide variety of boiler designs of varying vintage, along with a broad range of coals being 

fired, ALSTOM has developed a family of coal-fired 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 with increasing levels of reduction efficiency, system complexity and cost. 

The TFS 2000R'M technology, with multiple levels of Separated Overfire Air (SOFA) and improved coal 

pulverization fineness control, provides the lowest in-furnace NOx emissions for certain low volatile 

1 For coal fired boilers there is no consistent definition of t he term or use of the term ultra low NOx burner (ULNB). ALSOTM's 

TFS 2000R"' technology, with multiple levels of Separated Overfire Air (SOFA) and improved coal pulverization fineness control 

can, in the right situation, achieve the lowest possible NOx emission rate without the use of post combust ion add-on emission 

controls. 

Page 11 

February 8, 1010 

Colorado-Golden Energy Corp. 25 101h Street, P.O. Box 4088, Golden, Co. 80401 (303)277-5455 Fax (303)277-5629 
pulverized 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 firing systems is relatively limited due to their small size 

and the fact that they are equipped for multiple fuel firing. The practical 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-furnace NOx emission control system 

which is ALSTOM's LNCFSTM Level l I system. The LNCFSTM_P2 technology was rejected because it 

provides less NOx emission control. 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 capable of achieving lower NOx emissions are not available for Boilers 

Nos. 4 and 5 for coal firing. 

Question 2: 

CEN explained thoroughly the basis of the current coal supply. For a complete review of fuel switching, 

CEN needs to also examine fuels besides coal. These types of fuels include natural gas, biomass, etc. 

Please provide a qualitative discussion of using these fuels and whether these types of fuels will result in 

NOx benefits. A qualitative explanation regarding the feasibility of using natural gas, fuel oil, ethanol, 

sludge and/or wood as the primary fuel for 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 of coal with natural gas would reduce NOx emissions because natural gas does not 

contain fuel bound nitrogen. Boiler 4 currently has the capability to burn all natural gas with a NOx 

emission limit of 0.20 lb/MMBtu. Boiler 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 would 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 prices 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 of utility 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, 1010 
while 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 volatility issues. However, fuel prices 

and steam production costs are subject to continued evaluations. 

Conversion to residual oil would offer very little 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 coal was $2.1/MMBtu. Conversion to residual oil is not 

reasonable 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, or 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 required. 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. In addition, the achievable 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 Clean Air Technology Center I Technology 

Transfer Network I US EPA 

Page I 3 

February 8, 1010 
Question 3: 

CEN needs to provide a brief review of the other three factors: non-air quality and energy impacts, time 

necessary for completion, and useful life. 

Response: 

Non-air and Energy Impacts 

There are no non-air 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-air quality impacts. The reagent materials, which may be urea 

or ammonia, require a significant amount of energy to produce and are made from natural gas, a limited 

resource. In addition, the prices for these materials fluctuate in response to natural gas and various 

economic factors. Both technologies result 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 for 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 regional 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 energy 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: 

• preliminary engineering, preparation of detailed construction cost estimates, and preparation 

of a detailed schedule and sequencing plan; 

• final contracting and internal funding approval; 

• final design and construction; and 

• performance, acceptance testing, and project closeout. 

For the proposed low NOx burner/SOFA system, the estimated time for 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 reasonable. 

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, 1010 
Boilers 4 and 5 are subject to regular maintenance. Colorado Energy Nations has no plans to shutdown 

the boilers. In accordance with the EPA Cost Control Manual, annualized costs have been based on 20 

years. 

Additional Information 

As briefly discussed during our phone conversation on 1/26/10, our November 2009 cost effectiveness 

analysis for SCR and SNCR was conservat ively based on 100% capacity factors for both Boilers 4 and 5. 

However, this conservative analysis over estimates the actual emission reductions that would be 

achieved by these technologies. Information recently submitted to CDPHE shows that the actual highest 

365-day rolling average capacity factor for Boiler 4, during the 2006 to 2008 period, was 286.6 

MMBtu/hr or 80% for the period ending July 8, 2008.

6 For Boiler 5, the highest 365-day rolling capacity 

factor of 522.2 MMBtu/hr or 80% occurred during the period ending January 16, 2007. Based on actual 

costs and emission reductions, more realistic cost effectiveness values would be significantly higher than 

the values submitted in November 2009. For SCR, the cost effectiveness increases from approximately 

$9,000/ton of NOx controlled to approximately $12,000/ton of NOx controlled. For SNCR, the estimated 

cost effectiveness increases from $3,158/ton to $3,465/ton. Details are provided in Tables 1 and 2. 

Sincerely, 

General Manager 

Copies: File Mr. Bob Hall 

AE~OM 

2 Technology Park Drive 

Westford, MA 01886-3140 

6 On 2/5/10, CEN submitted daily capacity and emission information for the years 2006 thru 2008 to Curt Taipale 

(response to 2/3/10 email information request from CDPHE). 

Page I 5 

February 8, 1010 
Table 1 SCR Annual Cost Effectiveness Based on Highest 12-month 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 

Annual 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 1 00% of maintenance labor 

Ammonia CEMS labor $ 20,000 $ 20,000 AECOM experience 

Electricity $ 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> 

Capital Recovery $ 2,187,084 $ 2,927,125 7.0%, 20 years, 0.1098 x (TCIcatalyst) <al 

Total Annual Cost $ 3,777,579 $ 5,504,218 

Cost Effectiveness, $/ton of NOx $ 11,576 $ 11,702 controlled 

(a) EPA Air Pollution Control Cost Manual, Sixth Ediition, Section 4, Page 2-44. EPA/452/B-002-001 . January 

2002. 

Page I 6 

February 8, 1010 
Table 2 SNCR Annual Cost Effectiveness Based on Highest 12-month Operation for the 

2006 to 2008 Period 

Process Heater 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 gal 

Operating Labor $ 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 maintenance 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. 

Page I 7 

February 8, 1010