William Lawson 

 Director, Environmental Department 

1407 West North Temple, Suite 330 

Salt Lake City, Utah 84116 

 801.220.4581 (Office) 

801.220.2094 (Fax) 

 units. 

January 29, 2009 

Mr. David Finley 

Wyoming Division of Air Quality 

Herschler Building 

122 W. 25th Street 

Cheyenne, Wyoming 82002 

Re: PacifiCorp -- Wyoming BART Determinations and Regional Haze SIP 

Dear Mr. Finley, 

You have requested that PacifiCorp provide additional support regarding its proposed 

BART determinations for NOx emissions at Jim Bridger units 1 – 4 and Naughton unit 

3.1 The information contained in this letter is intended to elaborate on PacifiCorp’s 

BART analyses, which already have been filed with WDAQ for these

I. Executive Summary

This letter focuses solely on the proper BART emission limit for NOx at Naughton unit 3 

and the Jim Bridger units. PacifiCorp’s individual BART applications for each of these 

units contain a proposed BART emission limit which can be achieved through the 

installation of combustion controls such as low-NOx burners (LNB) and overfire air 

(OFA). This is appropriate and consistent with the guidance and requirements set forth in 

“Appendix Y” of EPA’s Regional Haze Regulations and Guidelines for Best Available 

Retrofit Technology; Final Rule (“Regional Haze Rules”), as those are incorporated into 

Wyoming’s state regulations. This is also consistent with the preamble which 

accompanies Appendix Y and the Regional Haze Rules (the “Preamble”). See 70 FR 

39104. 

Appendix Y references “presumptive BART” emission rates which vary based on boiler 

design and coal type. To the extent the presumptive BART NOx emission rates are 

relevant to Naughton unit 3 and the Jim Bridger units, it is important to note that the coal 

burned at these units is more comparable to bituminous than subbituminous (as the coal 

classification relates to NOx emissions). Correctly assuming that these units burn coal 

 

1

 This letter does not address any of the other PacifiCorp BART-eligible units in Wyoming nor is it 

intended as a comprehensive list of comments PacifiCorp may choose to make in regard to WDAQ’s 

upcoming BART determinations for the PacifiCorp units. 
Wyoming Division of Air Quality 

January 29, 2009 

Page 2 

2

with bituminous-like NOx emissions leads to a presumptive BART emission limit for 

NOx of 0.28 lb/MMBtu. This presumptive BART emission limit, however, is not the end 

of the analysis for any of the units, but only serves as a guide against which the calculated 

BART emission limit can be compared. 

Based on a variety of other factors as described herein and in the underlying BART 

applications, PacifiCorp continues to recommend that assigning a calculated 30-day 

rolling average BART emission limit for NOx of 0.26 lb/MMBtu for the Jim Bridger units 

is appropriate, including the installation of LNB and OFA as the proper BART control 

technology. Also, assigning a calculated 30-day rolling average BART emission limit for 

NOx of 0.35 lb/MMBtu for Naughton unit 3 likewise is appropriate, including the 

installation of LNB and OFA as the proper BART control technology. 

II. Background

In its BART applications for each unit covered by this letter, PacifiCorp and its 

consultant worked closely with WDAQ staff before submitting detailed BART 

engineering analyses for Naughton unit 3 and the Jim Bridger units. These analyses 

resulted in the proposed BART NOx emission limits and control technologies listed 

below in Table 1: 

Table 1 

Unit Proposed Rate Proposed Control Technology

Naughton 3 0.35 lb/MMBtu tune existing LNB and over-fire air system 

Jim Bridger 1 0.26 lb/MMBtu add LNB with separated over-fire air 

Jim Bridger 2 0.26 lb/MMBtu already added LNB with separated over-fire air 

Jim Bridger 3 0.26 lb/MMBtu add LNB with separated over-fire air 

Jim Bridger 4 0.26 lb/MMBtu add LNB with separated over-fire air 

In lieu of the above proposed rates, some may argue that WDAQ should instead impose 

the presumptive BART rate (found in Appendix Y) for tangentially-fired boilers burning 

subbituminous coal. This rate is 0.15 lb/MMBtu. To the extent this presumptive BART 

rate is applied, some may argue further that WDAQ should require the installation of 

SCR as the appropriate BART control technology in order to achieve this NOx emissions 

rate. As explained below, however, neither the facts nor the applicable BART 

requirements support these arguments. 

To the contrary, as noted in PacifiCorp’s BART applications, and as further explained 

herein: (i) applying the presumptive BART rate of 0.15 lb/MMBtu for subbituminous 

coal at these units is not appropriate; and (ii) requiring the installation of SCR at these 

units likewise is not an appropriate BART control technology. 
Wyoming Division of Air Quality 

January 29, 2009 

Page 3 

3

III. Based on Proper Coal Classification, the “Presumptive” BART NOx 

Limit for Naughton Unit 3 and the Jim Bridger Units is 0.28 lb/MMBtu 

As explained herein and in the BART applications, to the extent a presumptive BART 

emission limit (as found in Appendix Y) is relevant, then the appropriate presumptive 

BART limit for NOx at Naughton unit 3 and the Jim Bridger units is 0.28 lb/MMBtu. 

Presumptive BART

The Preamble to the BART rules observes that “States, as a general matter, must require 

owners and operators of greater than 750 MW power plants to meet [presumptive] BART 

limits.”2 70 FR 39104, 39131. The Preamble goes on to say, however that “a State may 

establish different requirements if the State can demonstrate that an alternative 

determination is justified based on consideration of the five statutory factors.” Id.

Specific to NOx emission limits, the Preamble notes that, “the NOx limits set forth here 

today are presumptions only; in making a BART determination, States have the ability to 

consider the specific characteristics of the source at issue and to find that the presumptive 

limits would not be appropriate for that source.” Id at 39134. 

By rule, Wyoming follows Appendix Y in determining the proper BART NOx emission 

limits for electric generating units (EGUs). Wyo. Reg., Chap. 6, Sec. 9(c). The 

presumptive BART NOx emission limits listed in Appendix Y are “differentiated by 

boiler design and type of coal burned.” See 40 CFR Part 51, Appendix Y, IV.E.5. As 

noted above, the presumptive BART NOx emission limit (for EGUs with tangentially 

fired boilers) is 0.15 lb/MMBtu for coal ranked as subbituminous. For coal ranked as 

bituminous, the presumptive BART NOx emission limit (for EGUs with tangentially 

fired boilers) is 0.28 lb/MMBtu.3 Id. EPA readily acknowledges that these presumptive 

NOx emission limits are based on many assumptions and also that, if one of these 

assumptions does not apply to a particular unit, it may affect the cost-effectiveness of the 

presumptive limit.4

 

 

2

 The Jim Bridger power plant exceeds 750 MW in total capacity; the Naughton power plant does not. 

3

 Even though the Wyoming rules distinguish – based on the amount of generating capacity – between 

whether Appendix Y “shall” apply or be used merely as “guidance,” Appendix Y itself applies the same 

presumptive NOx emission limit regardless of facility generating size. “For coal-fired EGUs greater than 

200 MW located at greater than 750 MW power plants and operating without post combustion controls 

[i.e., Jim Bridger units]. . . , we have provided presumptive NOx limits differentiated by boiler design and 

type of coal burned . . . . For coal-fired EGUs greater than 200 MW located at power plants 750 MW or 

less in size and operating without post-combustion controls [i.e., Naughton unit 3], you should likewise 

assume that these same levels are cost effective. You should require such utility boilers to meet the 

following NOx limits, unless you determine that an alternative control limit is justified . . . .” 70 FR 39171. 

 

4 “The following NOx emission rates were determined based on a number of assumptions, including that 

the EGU boiler has enough volume to allow for installation and effective operation of separated overfire air 

ports. For boilers where these assumptions are incorrect, these emission limits may not be cost-effective.” 

70 FR 39171. 
Wyoming Division of Air Quality 

January 29, 2009 

Page 4 

4

 

Coal Classification

Given the large disparity between the presumptive NOx emission limits for 

subbituminous and bituminous coals, it is very important to assign the proper coal 

classification when considering an individual unit. This is particularly true where, as is 

the case with Naughton unit 3 and the Jim Bridger units, the use of one coal quality 

classification results in a significantly different presumptive BART rate as compared to 

another coal classification. 

In the Preamble, EPA recognized “that, unlike the methods for controlling SO2 (which 

fall within a fairly narrow range of cost effectiveness and control efficiencies), the 

removal efficiencies and costs associated with the control techniques for NOx vary 

considerably, depending on the design of the boiler and the type of coal used.” 70 FR 

39104, 39134. Also, in that same section of the preamble, EPA recognized that “both cost 

effectiveness and post-control rates for NOx do depend largely on boiler design and type 

of coal burned.” Id. Therefore, to the extent presumptive BART rates are relevant; the 

BART analysis for Naughton unit 3 and the Jim Bridger units should carefully consider 

“the type of coal burned.” 

Unfortunately, neither Appendix Y, the Preamble, nor the Regional Haze Rules provide a 

standard or guidance to determine the appropriate coal classification. Instead, Appendix 

Y simply presumes that coal types are easily classified with a clear distinction between 

the various coals. This presumption, however, is not correct and certainly should not be 

the sole basis for assuming that the presumptive NOx emission rate of 0.15 lb/MMBtu is 

applicable to Naughton unit 3 and the Jim Bridger units. Indeed, a review of the literature 

shows that coal types are only loosely defined along a sliding scale, meaning that no 

bright line distinction between types of coal exists. 

Because coal classification is of such fundamental importance in selecting the proper 

presumptive BART rate, PacifiCorp included in its BART applications an explanation of 

why the coal burned at Naughton unit 3 and the Jim Bridger units should be considered to 

be bituminous for the purpose of considering presumptive BART limits for NOx. In 

addition, PacifiCorp has attached to this letter a technical memorandum prepared by 

CH2M Hill entitled “Coal Quality and Nitrogen Oxide Formation” (the “Coal Quality 

Technical Memo”), which discusses this coal classification issue in more detail. The 

attached memorandum is intended to amplify similar information provided in the BART 

applications for these units. 

Jim Bridger Units/Naughton Unit 3 Coal Classification

As the Coal Quality Technical Memo explains, a detailed analysis of the key coal 

characteristics that relate to the formation of NOx emissions supports the conclusion that 

 
Wyoming Division of Air Quality 

January 29, 2009 

Page 5 

5

the Jim Bridger units and Naughton unit 3 coals should be considered as bituminous for 

the purpose of applying a presumptive BART NOx emission limit. This conclusion alone 

supports presumptive BART limits based on bituminous coal. 

As an additional reason, and as explained in the Coal Quality Technical Memo, most 

coals from the Powder River Basin (“PRB”) are classified as subbituminous C and 

demonstrate high-reactivity and low-NOx production characteristics. It is against this 

backdrop of already low NOx emissions typically associated with PRB subbituminous 

coal that EPA selected the very low presumptive NOx emission rate of 0.15 lb/MMBtu 

for tangentially fired boilers (like those at Naughton unit 3 and the Jim Bridger units) and 

assumed that this rate could be achieved by combustion controls like LNB and OFA. In 

reaching this conclusion, however, EPA assumed that PRB subbituminous C coals to 

represent the entire class of subbituminous coals in use across the country since the PRB 

coals make up the largest share of such coals. However, there are other types of 

subbituminous coals that occur outside of the PRB that are not as reactive and low NOx 

forming as the PRB coals. EPA’s general assumptions regarding NOx emissions and 

subbituminous coals, therefore, fail to recognize that non-PRB subbituminous coals could 

have higher NOx emissions than PRB subbituminous C coals. This, in turn, affects the 

feasibility and cost effectiveness of the presumptive BART NOx emission limits (as 

stated in Appendix Y) for boilers using non-PRB subbituminous coal like Naughton unit 

3 and the Jim Bridger units. 

In other words, with NOx emissions from PRB subbituminous coal already low compared 

to other types of coal, EPA apparently believes it is a technologically easy and costeffective step to impose an even lower presumptive BART emission rate of 0.15 

lb/MMBtu (for tangentially fired boilers), which can be achieved by adding combustion 

controls like LNB and OFA. However, for non-PRB subbituminous coals, it is not such 

an easy and cost-effective step because combustion controls typically will not be enough 

to control NOx emissions to this rate. In this light, EPA’s presumed feasibility and costeffectiveness falls apart because very expensive and impractical post-combustion controls 

become part of the BART equation for certain subbituminous (non-PRB) coals. 

The Coal Quality Technical Memo concludes as follows: 

“For all these reasons, the [Naughton unit 3 and Jim Bridger units] coals . . . are 

more similar in their NOx formation potential to bituminous coals than to 

subbituminous coals such as PRB. Therefore, the presumptive BART limit that 

should be considered for the Jim Bridger [units] and Naughton [unit 3] . . . should 

be closer to 0.28 lb/MMBtu presumptive BART limit rather than the 

subbituminous 0.15 lb/MMBtu limit.” 

Considering the presumptive BART NOx emission limit for bituminous coal for 

Naughton unit 3 and the Jim Bridger units not only complies with the requirements of 
Wyoming Division of Air Quality 

January 29, 2009 

Page 6 

6

Wyoming law (including Appendix Y), but is more stringent than BART limits imposed 

on other Wyoming sources.5

 

Coal Classification In Other States

The coal classification issue discussed above in regard to presumptive BART limits is not 

unique to PacifiCorp’s units or the state of Wyoming. The State of New Mexico is 

addressing a similar issue concerning the San Juan Generating Station (SJGS). 

In New Mexico, the SJGS argues that it cannot meet the presumptive BART NOx

emissions limit of 0.23 lb/MMBtu (for a dry bottom, wall-fired boiler) for subbituminous 

coal. Using this presumptive BART limit was problematic because the local New Mexico 

coal used by SJGS fit into a “gray area” between bituminous and sub-bituminous coal. 

See “Discussion of SJGS Coal Ranking for BART NOx Presumptive Limit 

Determination.” The SJGS coal was less volatile, and has less oxygen and moisture, than 

the characteristics of PRB subbituminous coals used in developing the presumptive 

BART NOx emission limits under Appendix Y. Id. As the SJGS explains, “with respect 

to NOx combustion control performance, SJGS coal behaves more like a bituminous 

coal.” 6

 Id. 

The same can be said of the Jim Bridger units and Naughton unit 3 coals. Therefore, if a 

presumptive NOx emissions limit is considered for any of these units, PacifiCorp urges 

WDAQ to take account of the applicable coal characteristics and properly assume that the 

Jim Bridger units and Naughton unit 3 coals are closer to bituminous in composition than 

subbituminous. This proper assumption, in turn, leads to the conclusion that if a 

presumptive BART NOx emission limit is considered for any of these units, it should be 

at the 0.28 lb/MMBtu rate presumed for bituminous coal. As explained in the following 

section, however, the calculated BART emission rates noted in Table I above should 

control over the presumptive BART rates in any event. 

IV. The Five Factor Analysis Also Indicates SCR Is Not Appropriate 

 

5

 For example, Wyoming has proposed higher NOx emissions rates for other coal fired boilers in Wyoming. 

When making the BART determination for FMC’s Westvaco facility, Wyoming determined that a NOx

emissions rate of 0.35 lb/MBTU was BART. See August 4, 2008 BART Application Analysis, AP 6045, 

pg. 30. Additionally, Wyoming approved a BART NOx emissions rate of 0.49 lb/MBTU for General 

Chemical’s two coal fired boilers at its Green River Works facility. See August 4, 2008 BART Application 

Analysis, AP 6046, pg. 26. PacifiCorp’s proposed “presumptive” BART limit of 0.28 lb/MBTU for the 

Naughton and Jim Bridger power plants is much lower than these sources. 

6

 The BART NOx emission limit proposed by the New Mexico Environment Department for the SJGS is 

0.293 lb/MMBtu. This is consistent with the limit established in a consent decree concerning the plant 

which is unrelated to the BART determination. For information concerning SJGS BART issues, see 

http://www.nmenv.state.nm.us/aqb/reghaz/documents/COMPLETEFinalDiscussionofSJGSCoalClassificati

onRevisi.pdf
Wyoming Division of Air Quality 

January 29, 2009 

Page 7 

7

Establishing the appropriate presumptive BART NOx emission limit as described above 

is only one consideration in making a proper BART determination. Indeed, if an analysis 

of the five statutory factors supports a different emissions limit, then the presumptive 

BART rates take on a role only as a non-binding guide or marker for units like Naughton 

unit 3 and the Jim Bridger units. 

Five Factor Analysis and Proposed BART Limits

As noted, the presumptive BART limits are exactly what they purport to be – 

presumptions that can be rebutted and modified based on additional case by case 

information. In the Preamble, EPA states that its “presumption accordingly may not be 

appropriate for all sources. As noted, the NOx limits set forth here today are presumptions 

only; in making a BART determination, States have the ability to consider the specific 

characteristics of the source at issue and to find that the presumptive limits would not be 

appropriate for that source.” 70 FR 39134. Appendix Y further explains that a state “may 

determine that an alternative control level is appropriate based on a careful consideration 

of the [five] statutory factors,” particularly for boilers where EPA’s assumptions related 

to NOx emissions rates are incorrect. See Appendix Y, IV.E.5. 

PacifiCorp already has submitted a detailed five factor analysis for Naughton unit 3 and 

the Jim Bridger units in their individual BART applications. The final result of this 

analysis is a proposed BART emission limit for NOx at Naughton unit 3 of 0.35 

lb/MMBtu – higher than the presumptive BART limit of 0.28 lb/MMBtu. As for the Jim 

Bridger units, the result of the analysis is a NOx limit of 0.26 lb/MMBtu – lower than the 

presumptive BART limit. In each case; however, the proposed BART limits can be met 

by the installation of combustion controls. Imposing lower NOx limits than PacifiCorp 

has proposed would require the installation of post-combustion controls such as SCR, 

which is contrary to applicable BART requirements because the “cost of compliance” 

would be too high. 

Cost of Compliance

Focusing on the cost of compliance factor, EPA assumes in the Preamble that 

approximately 75% of the EGUs would have BART NOx removal costs between $100 

and $1,000 per ton, and that almost all of the remaining EGUs could install sufficient 

combustion control technology for less than $1,500 per ton: 

“The limits provided were chosen at levels that approximately 75 percent of the 

units could achieve with current combustion control technology. The costs of such 

controls in most cases range from just over $100 to $1000 per ton. Based on our 

analysis, however, we concluded that approximately 25 percent of the units could 

not meet these limits with current combustion control technology. However, our 

analysis indicates that all but a very few of these units could meet the presumptive 

limits using advanced combustion controls such as rotating opposed fire air 
Wyoming Division of Air Quality 

January 29, 2009 

Page 8 

8

 

(“ROFA”), which has already been demonstrated on a variety of coal-fired units.7

Based on the data before us, the costs of such controls in most cases are less than 

$1500 per ton.” 70 FR 39135. 

EPA’s assumptions regarding the cost of controls place Naughton unit 3 or the Jim 

Bridger units outside the scope of expected removal costs when considering the lower 

presumptive limit of 0.15 lb/MMBtu. As indicated in the BART applications, these units 

can only meet this rate by installing SCR. Under this scenario, the incremental control 

costs per ton would approach $4,000 per ton, well above the presumed control cost range 

included in the Preamble. 

It is for this reason that EPA stated further in the Preamble that SCR generally is not cost 

effective for EGUs (except for cyclone boilers): 

“We also analyzed the installation of SCRs at BART-eligible EGUs, applying 

SCR to each unit and fuel type. The cost-effectiveness was generally higher than 

for current combustion control technology except for one unit type, cyclone units. 

Because of the relatively high NOx emission rates of cyclone units, SCR is more 

cost-effective. Our analysis indicated that the cost-effectiveness of applying SCR 

on coal-fired cyclone units is typically less than $1500 a ton, and that the average 

cost-effectiveness is $900 per ton. As a result, we are establishing a presumptive 

NOx limit for cyclone units based on the use of SCR. For other units, we are not 

establishing presumptive limits based on the installation of SCR. Although States 

may in specific cases find that the use of SCR is appropriate, we have not 

determined that SCR is generally cost-effective for BART across unit types.” 70 

FR 39135-36. (Emphasis supplied) 

V. LNB /OFA Are the Proper BART Control Technology; SCR is Not 

Unlike SCR, LNB/OFA is the proper BART control technology for Naughton unit 3 and 

the Jim Bridger units. 

A “BART” determination involves not only the setting of an emissions limit, but also the 

selection of a particular emissions control technology, or group of technologies, to 

achieve that limit. Wyoming’s BART rules refer to this as “control equipment”, “control 

technology”, and “BART technology.” Wyo. Reg., Chp. 6, Sec. 9(e)(i)(E), Sec. 9(e)(iii) 

and (e)(viii). Regardless of the term used, and as explained above, the Preamble and other 

guidance are clear that LNBs and OFA are intended to be the “BART technology” for the 

tangentially fired boilers such as Naughton unit 3, the Jim Bridger units, and other 

similarly situated units. 

7

 The BART applications for Naughton unit 3 and the Jim Bridger units explain why ROFA is not a 

workable alternative for those units. 
Wyoming Division of Air Quality 

January 29, 2009 

Page 9 

9

In the Preamble, EPA stated that, except for cyclone boilers, the “types of current 

combustion control technology options assumed include low NOx burners, over-fire air, 

and coal reburning.” 70 FR 39134; see also 39144 (“For all other coal-fired units, our 

analysis assumed these units will install current combustion control technology.”). In 

fact, in the Technical Support Document used to develop the presumptive BART NOx

emissions limits, EPA explained that the “methodology EPA used in applying current 

combustion control technology to BART-eligible EGUs” included applying “a complete 

set of combustion controls. A complete set of combustion controls for most units includes 

a low NOx burner and over-fire air.” See, “Technical Support Document, Methodology 

for Developing NOx Presumptive Limits,” EPA Clean Air Markets Division, pg. 1 (dated 

June 15, 2005). 

The Preamble identifies post-combustion controls for NOx, such as SCR and SNCR, as 

“BART technology” for only “cyclone” units. EPA made it clear that for “other units, we 

are not establishing presumptive limits based on the installation of SCR.” 70 FR 39136. 

Therefore, EPA’s presumptive “BART technology” is LNBs and some type of OFA. 

EPA further elaborated in the preamble on the SCR costs, stating that although “States 

may in specific cases find that the use of SCR is appropriate, we have not determined that 

SCR is generally cost-effective for BART across unit types.” Id. 

Other BART eligible sources in Wyoming have determined that LNBs and/or OFA are 

“BART technology,” and that SCR would not be appropriate. For example, after 

additional analysis and study, Basin Electric recently submitted its analysis that OFA was 

the appropriate BART technology for the Laramie River Station and that SCRs were not 

“BART” due to several factors, including the high cost and relatively low visibility 

improvement. See Basin Electric/Laramie River Station Refined BART Visibility 

Modeling, pages 13 and 14 (submitted July 24, 2008). 

Similarly, the State of Wyoming also determined that LNBs and OFA were BART for the 

coal-fueled boilers at FMC’s Westvaco facility and at General Chemical’s Green River 

Works facility. See August 4, 2008 BART Application Analysis, AP 6045, pg. 30, and 

August 4, 2008 BART Application Analysis, AP 6046, pg. 26. All of these BART 

analyses reviewed SCR and SNCR, but none of them found that SNCR or SCR are 

BART for any of these facilities. Likewise, LNBs and OFA should be determined to be 

BART technology for PacifiCorp’s Jim Bridger and Naughton EGUs. 

 

A recent survey of the western states indicates that no states have mandated SCR or 

SNCR as “BART technology” for any EGUs. For example, in Colorado’s recent BART 

determinations, Colorado recognized LNBs and OFA (or some modification of the same) 

as BART for 14 different EGUs. See Colorado’s Air Quality Regulations, Part F, IV.D. 

In fact, consistent with PacifiCorp’s position explained above, Colorado believes that 

Appendix Y and the preamble do not allow post-combustion control, such as SCRs, to be 

considered at all as “BART technology.” In a letter addressing BART issues, Colorado’s 

Air Quality Division explained that “Colorado’s BART rule does not allow for post 

combustion NOx controls. This provision is based upon the preamble to the final EPA 
Wyoming Division of Air Quality 

January 29, 2009 

Page 10 

10

BART rule and Appendix Y.” See January 11, 2008 letter to Vickie Patton from 

Colorado Division of Air Quality, pg. 3. 

Additionally, the Oregon Department of Environmental Quality, in the August 20, 2008, 

BART determination for the Boardman power plant, found that SCR was not BART 

technology and stated that the “capital cost of [SCR] is 7 times that of new low NOx 

burners with modified overfire air system.” PacifiCorp’s BART applications confirm that 

SCR is not cost-effective or otherwise appropriate for Naughton unit 3 or the Jim Bridger 

units. Therefore, Wyoming, like other western states that have considered the issue, 

should determine that BART technology for PacifiCorp’s Jim Bridger and Naughton 

power plants is LNBs and OFA, and not SCR or SNCR. 

VI. Conclusion 

Based on a close examination of the characteristics of coal burned Naughton unit 3 and 

the Bridger units, it is clear that the appropriate presumptive BART NOx emission rate 

for consideration at these units is 0.28 lb/MMBtu. The appropriate calculated NOx

emission rate, however, is 0.35 lb/MMBtu for Naughton unit 3 (30 day rolling average) 

and 0.26 lb/MMBtu for the Bridger units (30 day rolling average). The appropriate 

control technology to achieve these rates is LNB and OFA. 

Please feel free to contact us with any questions. 

Sincerely, 

William K. Lawson 

Director, Environmental Services 

cc: Idaho Power 
JMS ES012009037SLC\BART COAL QUALITY AND NITROGEN OXIDE FORMATION MEMO - FINAL.DOC 1 

T E C H N I C A L M E M O R A N D U M 

Coal Quality and Nitrogen Oxide Formation 

PREPARED FOR: Bill Lawson/PacifiCorp 

PREPARED BY: CH2M HILL 

COPIES: Mike Jenkins/PacifiCorp 

DATE: January 28, 2009 

Nitrogen oxide (NOx) formation in coal-fired boilers is a complex process that is dependant 

on a number of variables, including operating conditions, equipment design, and coal 

characteristics. 

Coal Combustion 

During coal combustion, NOx is formed in three ways: fuel NOx, thermal NOx, and prompt 

NOx. The dominant source of NOx formation (approximately 60 to 80 percent) is the 

oxidation of fuel-bound nitrogen (fuel NOx). The amount of nitrogen contained in the coal 

directly impacts the amount of fuel NOx formed. During combustion, part of the fuel NOx is 

released from the coal with the volatile matter, and part is retained in the solid portion (char). 

The nitrogen chemically bound in the coal is partially oxidized to nitrogen oxides (NO and 

NO2) and partially reduced to molecular nitrogen (N2). The release rate of nitrogen from the 

volatile fractions of the coal in the early stages of combustion and the release of nitrogen in 

the char portion later in the combustion process also impact NOx formation. In addition, the 

availability of oxygen in the combustion air to combine with nitrogen affects fuel NOx

formation. 

A smaller part of NOx formation (20 to 40 percent) is due to high-temperature fixation of 

atmospheric nitrogen in the combustion air (thermal NOx). Thermal NOx can be affected 

exponentially by local temperatures and can be proportional to the square root of oxygen 

availability. 

A very small amount of NOx (less than 5 percent) is called “prompt” NOx. Prompt NOx

results from an interaction of hydrocarbon radicals, nitrogen, and oxygen. 

In a conventional pulverized coal burner, air is introduced with turbulence to promote good 

mixing of fuel and air, which provides stable combustion. However, not all of the oxygen in 

the air is used for combustion. Some of the oxygen combines with the fuel nitrogen to form

NOx. Low-NOx burners (LNBs) in combination with overfire air (OFA) are designed to 

reduce the amount of air introduced during initial combustion when the volatiles are driven 

off and introduce air downstream to combust the remaining unburned char. Hence, LNBs 

result in less conversion of fuel-bound nitrogen to NOx and lower combustion temperatures 

limiting thermal NOx. In addition, lower temperatures and oxygen availability can reduce 

hydrocarbon reaction rates resulting in less prompt NOx formation. For retrofit of existing 

boilers, boiler size and configuration can limit the effectiveness of LNBs and OFA. 
COAL QUALITY AND NITROGEN OXIDE FORMATION 

JMS ES012009037SLC\BART COAL QUALITY AND NITROGEN OXIDE FORMATION MEMO - FINAL.DOC 2 

Coal Ranking 

Coal ranking is a means of classifying coals according to their degree of metamorphism in 

the natural series, from lignite to subbituminous to bituminous and on to anthracite. 

The American Society for Testing Materials (ASTM) has developed a system for generally 

classifying coals based on their heating value, volatile content, moisture, reactivity, and other 

properties. Eastern U.S. coals (high-volatile bituminous) tend to be high-rank fuels with high 

heating values and low moisture. At the other end of the spectrum, U.S. lignite coals tend to 

be low rank, as their heating values are low, and moisture content high. Western U.S. coals, 

like Powder River Basin (PRB), tend to be categorized in the lower rank Subbituminous “C” 

range, while other western fuels tend to be categorized as higher rank bituminous or 

subbituminous coals. Figure 1 shows the criteria for ASTM’s coal rankings. 

FIGURE 1 

Coal Classification 
COAL QUALITY AND NITROGEN OXIDE FORMATION 

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Most coals from the PRB are classified as Subbituminous “C” and demonstrate highreactivity and low-NOx production characteristics. Based on data from the Energy 

Information Administration (EIA), PRB coals currently represent 88 percent of total U.S. 

subbituminous production and 73 percent of western coal production. Most references to 

western coal and subbituminous coal infer PRB origin and characteristics. Emissions 

standards differentiating between bituminous and subbituminous coals are presumed to use 

PRB coal as the basis for the subbituminous standards, due to their dominant market 

presence and unique characteristics. 

Coal Characteristics 

Coal characteristics directly and significantly affect NOx emissions from coal combustion 

and play an important role in the ability to design and operate LNBs and OFA systems. As 

previously discussed, of paramount significance is the ability to control the introduction of 

air into the burner zone. Burner Zone Stoichiometry is the ratio of combustion air admitted to 

the furnace versus the theoretical amount of air required for complete combustion. Most units 

are designed to operate between 1.14 and 1.25 stoichiometry, where 1.0 is the theoretical

amount of air required for combustion. When operating for low NOx, the Burner Zone 

Stoichiometry is reduced by the air staged through the OFA system. Aggressive low-NOx

firing systems typically are typically designed to operate with Burner Zone Stoichiometries 

less than theoretical (1.0). 

Tests run by the boiler manufacturer ALSTOM showed the influence of both fuel type and 

stoichiometry on NOx emissions as illustrated in Figure 2. As expected, as the stoichiometry 

decreases, the percentage of the fuel NOx converted to NOx decreases. This testing also 

shows the trend that as the fuel rank decreases, the rate at which the fuel nitrogen converts to 

NOx also decreases.
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FIGURE 2 

Nitrogen Conversion to NOx

0

10

20

30

40

50

60

BURN ER ZONE STOICHIOM ETRY

FUEL BOUND NITROGEN CONVERSION

L OW VOL

H I VOL A

H I VOL A

H I VOL B

H I-VOL C

SU BB IT C

L ower Higher

Subsequent testing in ALSTOM’s laboratory identified some of the key characteristics of the 

coals and mechanisms for this nitrogen conversion efficiency. In general, the lower the fuel 

rank, the faster the coal is devolatilized and the faster the fuel NOx is released. Based on the 

chemical kinetics under staged conditions, nitrogen preferentially bonds together to form 

inert molecular nitrogen N2 instead of NO or NO2. Therefore, the more nitrogen that can be 

released earlier in the combustion process, the lower the NOx emissions can be. Low-rank 

coals show favorable behavior with regard to greater fuel nitrogen release during the 

devolatilization phases of the combustion process; this is conducive to greater NOx reduction. 

This is one of the reasons coals like PRB tend to react favorably to staged combustion, 

producing some of the lowest levels of NOx observed on U.S. coals. 

The coals used at Bridger and Naughton tend to be higher rank than typical PRB coals. As 

such, they will have less fuel nitrogen released during the devolatilization phase of 

combustion, and thus will producehave somewhat higher NOx than will true PRB coals when 

fired under low-NOx staged conditions. 

A second major factor in fuel NOx is related to how the fuel NOx evolves from the solid coal 

char that is produced once the volatile component of the coal is combusted. Generally 

speaking, approximately 20 to 40 percent of the fuel NOx can source from fuel-bound 

nitrogen associated with the solid char. Control of NO from this char nitrogen component

cannot be directly controlled by air staging since under staged low-NOx combustion 

(reducing or pyrolysis conditions), char nitrogen conversion to NO remains relatively 
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constant. Typically, lower rank (more reactive) fuels have more fuel NOx associated with the 

volatiles than the char, so low-rank coals overall have the lowest NOx potential. 

The performance of the Bridger and Naughton coals tends to fall between the PRB coals and 

eastern bituminous coals shown. This would support the conclusion that the Bridger and 

Naughton coals have a NOx reduction potential below eastern bituminous coals, but not as 

low as true PRB coals. 

This conclusion is supported by additional ALSTOM laboratory data shown in Figure 3. 

Testing in ALSTOM’s bench-scale Drop Tube Furnace can determine the relative percentage 

of fuel NOx converted to NOx in both the devolatilization and char phases of combustion. It 

is clear that PRB coals can have greater than 78 percent of fuel NOx converted to NOx during 

devolatilization, which is far greater than that measured for bituminous coals. As a result of 

these observations, the performance of the Bridger and Naughton coals, in terms of total fuel 

NOx emissions would tend to fall between the PRB coals and eastern bituminous coals 

shown. 

FIGURE 3 

Fuel Nitrogen Conversion during Coal Devolatilization and Coal Char Combustion versus Coal Type 

Drop Tube Test Furnace Nitrogen Conversion versus Coal Type

78%

87%

83% 84%

58%

55%

31%

22%

13%

17% 16%

42%

45%

69%

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

PRB PRB PRB PRB PRB & Bit.

Blend

Bituminous Bituminous

% Fuel N to NOx 

During Devolatilization

During Char Combustion

As previously mentioned, NOx formed by fixation of atmospheric nitrogen to oxygen 

(thermal NOx) is the other main component of total NOx emissions for a boiler. The other 
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two primary factors are unit design and operating procedures, and are therefore very 

unit-specific. Unit design affects both the residence time of the combustion process as well as 

the thermal aspects of combustion. Unit design determines how “hot” a furnace is, which 

influences the thermal NOx contribution for both the baseline and post-retrofit NOx

emissions. From its extensive retrofit experience, ALSTOM developed a series of thermal 

NOx prediction methodologies based on the physical unit dimensions and the thermal 

conditions firing eastern and midwestern fuels. These site-specific predictive methodologies 

are used in combination with the fuel NOx prediction methodologies described above to 

make overall stack NOx emission predictions and commercial guarantees. 

Figure 4 shows ALSTOM’s experience on coals from the west that rank either as highvolatile bituminous B or C or as subbituminous B coals. The coals from Bridger and 

Naughton generally fall in these categories. Considering the data presented in Figure 4, 

ALSTOM expects that the NOx emission levels of the Bridger and Naughton coals will be 

higher than those of PRB coals. 

FIGURE 4 

ALSTOM Experience on Western High Volatile Bituminous B and C, and Subbituminous B 

Average NOx Emissions 

as Reported by the EPA for the First Quarter of 2004

0.00

0.05

0.10

0.15

0.20

0.25

0.30

0.35

0.40

Level 1, 

Hi-vol B

bit.

Level 1, 

Hi-vol C

bit.

Level 3, 

Hi-vol C

bit.

Level 3, 

Hi-vol C

bit.

Level 3, 

Hi-vol C

bit.

Level 3, 

Subbit.

B

TFS

2000R, 

Subbit.

C

, , 

ALSTOM Low NOx System / Coal Rank

NOx, lb/mmBtu

W estern Bituminous Sub-Bit B Sub-Bit C
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As discussed previously, a number of western coals are classified as subbituminous; 

however, they border on being ranked as bituminous and do not display many of the qualities 

of PRB coals, including most of the low-NOx-forming characteristics. The coals from the 

Bridger, Black Butte, Leucite Hills, and Naughton mines fall into this category. 

As defined by ASTM, the only distinguishing characteristic that classifies the coals used at 

Jim Bridger and Naughton as subbituminous rather than bituminous—that is, they are 

“nonagglomerating” as compared to “agglomerating.” While each of these coals is 

considered nonagglomerating, they either do not exhibit those properties of 

nonagglomerating coals or exhibit them to only a minor degree. Agglomerating as applied to 

coal is “the property of softening when it is heated to above about 400 degrees Celsuis (°C)

in a nonoxidizing atmosphere, and then appearing as a coherent mass after cooling to room 

temperature.” Since the agglomerating property of coals is the result of particles transforming 

into a plastic or semiliquid state when heated, it reflects a change in surface area of the 

particle. Thus, with the application of heat, agglomerating coals would tend to develop a

nonporous surface while the surface of nonagglomerating coals would become even more

porous with combustion. As shown by Figure 5, the increased porosity provides more 

particle surface area resulting in more favorable combustion conditions. This 

nonagglomerating property assists in making subbituminous coals more amenable to 

controlling NOx by allowing less air to be introduced during the initial ignition portion of the 

combustion process. 

FIGURE 5 

Illustration of the Effect of Agglomeration on the Speed of Coal Combustion
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Table 1 compares key NOx-forming characteristics of the Bridger Mine, Black Butte, Leucite 

Hills, Naughton, a typical PRB coal, and Twentymile, a representative western bituminous 

coal. 

TABLE1 

NOx Characteristics Comparison 

Parameter PRB 

Bridger 

Mine 

Black 

Butte 

Leucite 

Hills Naughton Twentymile 

Nitrogen (% dry) 1.10 1.26 1.47 1.48 1.24 1.85 

Oxygen (% dry) 16.2 13.2 13.4 13.2 15.4 7.19 

Moisture (%) 27.3 19.1 20.7 19.0 20.9 9.85 

Coal rank Sub C Sub A Sub A Sub A Sub A Bit high vol B 

As shown in Table 1, although Bridger, Black Butte, Leucite Hills, and Naughton are

classified as subbituminous, they all exhibit higher nitrogen content, lower moisture content, 

and lower oxygen content than the PRB coal. The higher nitrogen content is an indication 

that more nitrogen is available to the combustion process and higher NOx emissions are 

likely. Oxygen content can be correlated to the reactivity of the coal with more reactive 

coals—generally containing higher levels of oxygen. As previously stated, more reactive 

coals tend to produce lower NOx emissions and are also more conducive to reduction of NOx

emissions, through use of combustion control measures such as LNBs and OFA. These 

characteristics indicate that higher NOx formation is likely with Bridger, Black Butte, Leucite 

Hills, and Naughton rather than with PRB coal. The Bridger, Black Butte, Leucite Hills, and 

Naughton coals all contain quality characteristics that fall between a typical PRB coal and 

Twentymile, a clearly bituminous coal that produces higher NOx—as has been demonstrated 

at power plants burning Twentymile coal. 

Using Jim Bridger 2 for illustrative purposes, Figures 6 and 7 graphically illustrate the 

relationship of nitrogen and oxygen content to related BART presumptive NOx limits for the 

coals listed in Table 1. Twentymile is used to graphically illustrate achievement of the Best 

Available Retrofit Technoloaogy (BART) presumptive NOx limit for a bituminous coal and 

the PRB coal corresponds to the subbituminous BART presumptive NOx limit. The Bridger 

blend consists of a representative combination of coals from the Bridger Mine, Black Butte, 

and Leucite Hills that has been used at Jim Bridger 2, and indicates the average NOx

emission rate achieved during 2003 to 2005. Jim Bridger 2 represents the NOx emission rate 

achieved after installation of ALSTOM’s current state of the art TFS2000 LNB and OFA 

System. This NOx emission level of 0.28 pound per million British thermal Units (MMBtu) 

corresponds to the BART presumptive limit for bituminous coal and underscores the 

difference in ability to reduce NOx while burning non-PRB subbituminous coals such as 

those from the Bridger Mine. 

Figures 6 and 7 both demonstrate that with the TFS2000 low-NOx emission system installed 

and burning a combination of the Bridger, Black Butte, and Leucite Hill coals, the likely NOx

emission rate will be closer to the bituminous end (0.28) of the BART presumptive NOx limit 

range than to the BART presumptive NOx limit of 0.15 pound per MMBtu. 
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PRB Subbituminous

Twentymile Bituminous

Bridger Blend

Jim Bridger 2

0.1

0.15

0.2

0.25

0.3

0.35

0.4

0.45

6.00 8.00 10.00 12.00 14.00 16.00 18.00

Typical Oxygen Content (%-Dry Basis)

NOx Limit (lb/MMBtu)

Subbituminous Presumptive Limit - 0.15lb/MMBtu

Bituminous Presumptive Limit - 0.28 lb/MMBtu

FIGURE 6 

Plot of Typical Nitrogen Content of Various Coals and Applicable Presumptive BART NOx Limits 

Jim Bridger 2 

PRB Subbituminous

Bridger Blend

Jim Bridger 2

Twentymile Bituminous 

0.1

0.15

0.2

0.25

0.3

0.35

0.4

0.45

1.00 1.10 1.20 1.30 1.40 1.50 1.60 1.70 1.80 1.90 2.00

Typical Nitrogen Content (%-Dry Basis)

NOx Limit (lb/MMBtu)

Bituminous Presumptive Limit - 0.28 lb/MMBtu

Subbituminous Presumptive Limit - 0.15 lb/MMBtu

FIGURE 7 

Plot of Typical Oxygen Content of Various Coals and Applicable Presumptive BART NOx Limits 

Jim Bridger 2 
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Coal quality characteristics also impact the design and operation of the boiler and associated 

auxiliary equipment. Minor changes in quality can sometimes be accommodated through 

operational adjustments or changes to equipment. It is important to note, however, that 

consistent variations in quality or assumptions of “average” quality for performance 

projections can be problematic. This is particularly troublesome when dealing with 

performance issues that are very sensitive to both coal quality and combustion conditions, 

such as NOx formation. There is significant variability in the quality of coals burned at Jim 

Bridger and Naughton. For example, in addition to burning coal from Black Butte and 

Leucite Hills, Jim Bridger burns coal supplied from the Bridger Mine consisting of three 

sources—underground, surface, and highwall operations. Each of these coal sources has 

different quality characteristics as well as inherent variability.

Several of the coal quality characteristics and their effect on NOx formation have been 

previously discussed. There are some additional considerations that illustrate the complexity 

of achieving and maintaining low NOx emissions with pulverized coal on a consistent, 

shorter term, such as a 30-day rolling average basis. 

Good combustion is based on the “three Ts”: time, temperature, and turbulence. These 

parameters along with a “design” coal are taken into consideration when designing a boiler 

and associated firing equipment, such as fans, burners, and pulverizers. If a performance 

requirement such as NOx emission limits is subsequently changed, conflicts with other 

performance issues can result. 

Jim Bridger is located at an altitude of 6,669 feet above sea level, and Naughton is at an 

elevation of 6,396 feet above sea level. At these elevations, atmospheric pressure is lower 

(11.5 pounds per square inch) as compared with sea level pressure of 14.7 pounds per square 

inch. This lower pressure means that less oxygen is available for combustion for each volume 

of air. To provide adequate oxygen to meet the requirements for efficient combustion, larger 

volumes of air are required. When adjusting air flows and distribution to lower NOx using 

LNBs and OFA, original boiler design restrictions again limit the modifications that can be 

made and still achieve satisfactory combustion performance. 

Another significant factor in controlling NOx emissions is the fineness of the coal entering 

the burners. Fineness is influenced by the grindability index (Hardgrove) of the coal. Finer 

coal particles promote release of volatiles and assist char burnout due to more surface area 

exposed to air. Nitrogen oxide reduction with high-volatile coals is improved with greater 

fineness and with proper air staging. The lower rank subbituminous coals such as PRB coals 

are quite friable and easy to grind. Coals with lower Hardgrove Grindability Index values, 

such as those used at Jim Bridger and Naughton, are more difficult to grind and can 

contribute to higher NOx levels. In addition, coal fineness can deteriorate over time periods 

between pulverizer maintenance and service as pulverizer grinding surfaces wear. 

Conclusions 

Both laboratory data and field experience indicate that western low-rank fuels are conducive 

to low-NOx firing. The laboratory data from carefully controlled small-scale experiments has 

documented that the lower rank subbituminous C (PRB) and lignite coals typical of the west 

will generate low-NOx due to the high volatility and quick yield of fuel bound nitrogen. The 

field experiences from these fuels match the predictions from the laboratory data. Based on 
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ALSTOM’s experience to date, most other western subbituminous coals, such as those fired 

by PacifiCorp, will produce NOx levels somewhere between PRB coals and eastern 

bituminous coals. 

For all of these reasons, the coals from the Bridger Mine, Black Butte, Leucite Hills, and 

Naughton mines used at the Jim Bridger and Naughton plants are more similar in their NOx

formation potential to bituminous coals than to the subbituminous coals such as PRB. 

Therefore the presumptive BART limit that should be applied to the Bridger and Naughton 

plants should be closer to the 0.28 pound per MMBtu bituminous presumptive BART limit 

rather than the subbituminous 0.15 pound per MMBtu limit. This is also demonstrated by the 

actual performance of the LNB OFA TFS2000 low-NOx emission system installed on Jim 

Bridger Unit 2. 

Reference 

ALSTOM, 2005. NOx Variation with Western U.S. Sourced Coals Fired in PacifiCorp Utility 

Boilers. Prepared for PacifiCorp. February 4. 

The referenced text is included as Attachment 1. 
ATTACHMENT 1 

NOx Variation with Western U.S. Sourced Coals 

Fired in PacifiCorp Utility Boilers 
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NOx VARIATION WITH WESTERN 

U.S. SOURCED COALS FIRED IN 

PACIFICORP UTILITY BOILERS 

Prepared For 

PacifiCorp 

February 4, 2005 

Copyright 2005 ALSTOM 

All Rights Reserved

Confidential Attorney Client Communication and Attorney Work Product 
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This document has been carefully prepared by ALSTOM, Inc. It is based in part on 

observations and analysis, and any conclusions made in this document are based in part 

on experience and judgement. Another qualified consultant might reach different 

conclusions. 

This document is provided only for the benefit of PacifiCorp, and not for the benefit of 

any third party.
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NOx VARIATION WITH WESTERN U.S. SOURCED COALS 

FIRED IN PACIFICORP UTILITY BOILERS 

ALSTOM, Inc 

Windsor, CT 

February 4, 2005 

ABSTRACT 

ALSTOM is a world leader in low NOx firing system technology, with over 380 boilers 

converted globally to low NOx firing on a wide range of coals. In the US, ALSTOM has 

provided low NOx firing systems to over 50 utility boilers that fire Powder River Basin 

(PRB), lignite, and a variety of Western bituminous and subbituminous coals. These units 

firing Western US coals account for over 21,000 MW of electrical generation. From this 

extensive field experience, as well as fundamental laboratory study, it is clear that each 

western US coal has unique variations in chemistry and characteristics that directly affect 

combustion, NOx formation, and NOx reduction potential. As such, ALSTOM maintains that 

NOx emissions predictions for specific Western U.S. sourced coals must carefully consider 

the fundamental properties unique to each coal. This paper will focus on ALSTOM’s 

experience burning lignite, subbituminous and Western bituminous coals under low NOx 

conditions, and outline how NOx generated in Western US coal fired utility boilers can be 

expected to vary significantly based on each coal’s unique characteristics. 

NOx Formation Mechanisms 

NOx formation and reduction in a utility boiler sources from the following three basic 

chemical mechanisms: 

1) Thermal NOx 

Thermal NOx, also known as Zel’dovich mechanism NOx, is formed from high 

temperatures (> 2700 F) in the combustion zone and furnace. Simply stated, nitrogen 

in the atmospheric air used for combustion combines with oxygen at these high 

temperatures to form NOx. Thermal NOx can be affected exponentially by local 

temperatures and can be proportional to the square root of oxygen availability. The 

key to minimizing thermal NOx is to stage fuel/air mixing in a controlled way, using 

low NOx firing systems and overfire air, to minimize excessive combustion 

temperatures. Boiler design, in terms of heat transfer characteristics, also plays a 

major role in thermal NOx formation. For a retrofit application these design 

parameters are fixed by the boiler size and configuration, and cannot be easily 

changed. In a typical coal fired utility boiler, approximately 20% to 40% of the 

total NOx comes from thermal NOx. 
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2) Fuel NOx

Fuel NOx is formed during combustion of fuels (like coal) containing inherent fuel 

bound nitrogen. Fuel NOx is affected by the total percentage of nitrogen contained in 

the coal, but there are other equally important factors. The release rate (reactivity) of 

nitrogen from volatile fractions of the coal in the early stages of combustion, and the 

nitrogen release rate from the solid coal char (in the later stages of combustion) have 

a direct impact on NOx. Coal chemistry factors such as coal porosity and fuel 

oxygen to nitrogen ratio also influence NOx formation. In addition, Fuel NOx can be 

affected by local oxygen availability. Low NOx firing systems reduce, but cannot 

eliminate fuel NOx generated from coal types that have high fuel NOx 

characteristics. In summary, coal chemical composition and physical properties 

all directly affect Fuel NOx, which typically represents approximately 60% to 

80% of the total NOx from a coal fired utility boiler. 

3) Prompt NOx 

 

Prompt NOx, also known as Fenimore NOx, is formed by fractionation of 

hydrocarbons (CH) in the presence of atmospheric nitrogen (N2) when combusting 

fuels. Complex interactions between CH and N2 form HCN and N, which can 

combine with atmospheric oxygen and evolve into additional NOx generated beyond 

thermal and fuel NOx mechanisms. Prompt NOx is normally less than 5 % of total 

NOx in coal fired boilers and can be controlled by optimized low NOx firing system 

design, as temperature and oxygen availability can affect hydrocarbon reaction rates. 

This brief description of NOx formation fundamentals provides a simplistic overview of the 

NOx generation process. ALSTOM has a wide NOx experience base of over twenty years of 

R&D, including US Government-sponsored projects, as well as designing and providing 

commercial Low NOx firing systems. It is ALSTOM’s position that these mechanisms 

interact in complex ways that are specific to each individual coal and boiler. 

In the 1980’s ALSTOM began developing NOx prediction tools and design methods for 

firing eastern U.S. bituminous coals in order to provide commercial guarantees to utilities 

mandated to comply with the Clean Air Act of 1990. Some of these predictive tools are 

laboratory based, while others are based on compilation and analysis of extensive field 

emissions data. In the 1990’s, electric utility units east of the Mississippi installed low NOx 

systems in response to the Clean Air Act Amendments. Many of these units, particularly in 

the Midwest, have since converted to Powder River Basin (PRB) coals for economic or 

sulfur emissions reasons. In the late 1990’s Texas regulations resulted in many PRB and 

lignite units being converted to low NOx firing. In addition to these units, other plants in 

Western states have or are in the process of implementing NOx controls. Many of these units 

are mine mouth units that fire coals that are unique to each unit. ALSTOM’s predictive 

methodology has evolved over the years as the unit experience base and range of fuels tested 

has grown. These field experiences and further laboratory testing of Western fuels have 

proven to ALSTOM that NOx emissions can vary substantially between these differing 

Western coals. 
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Western Coal Analysis and ASTM Rank 

Coal is a complex fuel with wide variations in chemical analysis, physical characteristics, 

and combustion reactivity. The American Society for Testing Materials (ASTM) has 

developed a system for generally classifying coals based on their heating value, volatile 

content, moisture, reactivity and other properties. Eastern U.S. coals (high volatile 

bituminous) tend to be high rank fuels with high heating values and low moisture. At the 

other end of the spectrum, U.S. lignite coals tend to be low rank, as their heating values are 

low, and moisture content high. Western U.S. coals, like Powder River Basin, tend to be 

categorized in the lower rank Subbituminous “C” range, while other Western fuels tend to be 

categorized as higher rank bituminous or subbitbuminous coals. 

Coal from the Powder River Basin in Wyoming accounts for approximately 35% of the total 

coal production in the United States. Due to the significant amount of PRB fuel fired, 

ALSTOM has expended significant time and effort studying all aspects of the firing system 

and boiler effects from the combustion of these coals. It is important to note that there are 

different mines within the PRB region, each with its own unique properties. The main focus 

of ALSTOM’s work on PRB coals has been on the mines south of Gillette, Wyoming, as 

these produce the largest volume of coal. 

In the Western United States, the lignite fields in North Dakota and Texas combine to 

produce approximately 7% of the total coal mined in the US. Due to the high moisture and 

ash content, and subsequent low heating value, lignite is not economical to transport long 

distances. Therefore, all lignite is consumed relatively close to the mine source. 

E. bit. Hi-vol B 

bit. 

Hi-vol C 

bit. 

Sub bit. A Sub bit. B Sub bit. C TX 

Lignite 

H2O 5.00 6.28 13.12 14.09 25.00 27.30 33.06 

VM 33.10 37.49 34.91 33.75 32.43 31.90 26.75 

FC 53.50 46.35 45.78 37.58 38.23 36.40 27.47 

Ash 8.40 9.88 6.19 14.58 4.00 4.40 12.72 

Hydrogen 5.00 4.68 4.22 4.12 3.72 3.49 3.02 

Carbon 71.70 67.70 61.58 55.70 53.88 51.18 39.45 

Sulfur 1.30 0.48 0.36 0.48 0.34 0.21 1.99 

Nitrogen 1.60 1.38 1.23 0.98 0.72 0.73 0.67 

Oxygen 7.10 9.60 13.30 10.05 12.32 12.71 9.09 

HHV 12959 12000 10861 9674 9350 8800 6935 

FC/VM 1.62 1.24 1.31 1.11 1.18 1.14 1.03 

HHVdaf 14964 14313 13461 13562 13169 12884 12790 

lb S/mmBtu 1.00 0.40 0.33 0.50 0.36 0.24 2.87 

lb N/mmBtu 1.23 1.15 1.13 1.01 0.77 0.83 0.97 

Ash Load 6.5 8.2 5.7 15.1 4.3 5.0 18.3 

Table 1 - Typical Coal Analysis
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There are also locally significant coal fields in Utah, Colorado, Montana, Wyoming, New 

Mexico, and Arizona. These fuels are also not transported as far as the coal from the 

Southern PRB. These coals rank between subbituminous A, B, and C and high volatile 

bituminous B and C. Combined, these six states account for approximately 15% of the total 

coal production in the US. Typical fuel analyses of various domestic ASTM ranked coals are 

shown in Table 1. 

The coals fired at Jim Bridger Station are generally classified (ranked) by ASTM Standards 

as Western Sub-Bituminous “B” and “C” coals as seen on the attached Coal Classification 

Chart. Coals fired at Huntington Canyon are generally ranked as high volatile “B” or “C” 

bituminous. Coals at Naughton are typically ranked as sub bituminous “B”. The coals fired 

at Hunter Station are classified as High Volatile Bituminous “B” and “C”. Typical coal 

analyses are attached in Table 2 below. 

Hunter Huntington Canyon Bridger Naughton 1&2 Naughton 3 

 

H2O 8.56 9.95 19.1 20.8 21.1 

VM 36.74 35.39 30.1 34.2 34.1 

FC 44 47.11 40.4 40.6 39.7 

Ash 10.71 7.55 10.1 4.5 5.2 

Hydrogen 4.58 4.48 3.5 4.04 3.95 

Carbon 64.12 65.3 54 56.87 55.78 

Sulfur 0.4 0.33 0.6 0.56 1.1 

Nitrogen 1.15 1.04 1.1 1.03 1.03 

Oxygen 10.44 11.35 11.4 12.2 11.84 

HHV 11489 11499 9428 10012 9900 

 

FC/VM 1.2 1.33 1.34 1.19 1.15 

HHV daf 14231 13938 13373 13403 13495 

Ash Load 9.3 6.6 10.7 4.49 5.28 

Table 2 - Coals Fired at PacifiCorp Stations 

Several of the Pacificorp stations, such as Jim Bridger, are mine mouth plants and fire coals 

that are unique to those units. These coals have very limited distribution outside of the 

specific plants, and as such, there are no operating low NOx systems firing these coals. 

Supporting data detailing the limited distribution of these coals is provided in the Appendix 

of this paper. 

Comparing the above PacifiCorp coal analysis to that of the well-studied Power River Basin 

coals, it can be generally stated that these coals tend to be somewhat higher rank than PRB 

coals. It is expected that these fuels have somewhat different combustion characteristics than 

PRB coals. 
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Influence of Coal Analysis and Rank on NOx 

Since over 60% of total stack NOx can be attributed to fuel NOx, ALSTOM’s Power Plant 

Laboratory has studied the conversion of fuel bound nitrogen to NOx, as a function of fuel 

type and Burner Zone Stoichiometry. Burner Zone Stoichiometry is the ratio of combustion 

air admitted to the furnace versus the theoretical amount of air required for complete 

combustion. Most units are designed to operate between 1.14 and 1.25 stoichiometry, where 

1.0 is the theoretical amount of air required for combustion. When operating for low NOx 

the Burner Zone Stoichiometry is reduced by the air staged through the Separated Overfire 

Air (SOFA) system. Aggressive low NOx firing systems typically are typically designed to 

operate with Burner Zone Stoichiometries less than theoretical (1.0). 

This testing clearly showed the influence of both fuel type and stoichiometry on NOx 

emissions as illustrated in Figure 1. As expected, as the stoichiometry decreases the 

percentage of the fuel bound nitrogen converted to NOx decreases. This testing also shows 

the trend that as the fuel rank decreases, the rate at which the fuel nitrogen converts to NOx 

also decreases.

Figure 1 - Nitrogen Conversion to NOx 

Subsequent testing in the laboratory identified some of the key characteristics of the coals 

and mechanisms for this nitrogen conversion efficiency. In general, the lower the fuel rank, , 

the faster the coal is devolatilized and the faster the fuel bound nitrogen is released. Based 

on the chemical kinetics under staged conditions, nitrogen preferentially bonds together to 

0

10

20

30

40

50

60

BURNER ZONE STOICHIOMETRY

FUEL BOUND NITROGEN CONVERSION

LOW VOL

HI VOL A

HI VOL A

HI VOL B

HI-VOL C

SUBBIT C

Lower Higher
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form inert molecular nitrogen N2 instead of NO or NO2. Therefore, the more nitrogen that 

can be released earlier in the combustion process, the lower the NOx emissions can be. Low 

rank coals show favorable behavior with regard to greater fuel nitrogen release during the 

devolatilization phases of the combustion process; this is conducive to greater NOx 

reduction. This is one of the reasons coals like PRB tend to react favorably to staged 

combustion, producing some of the lowest levels of NOx observed on U.S. coals. 

The PacifiCorp coals tend to be higher rank than typical PRB coals. As such, they will have 

less fuel nitrogen released during devolatilization, and thus will have somewhat higher NOx 

than true PRB coals when fired under low NOx staged conditions. 

A second major factor in fuel NOx is related to how the fuel bound nitrogen evolves from the 

solid coal char that is produced once the volatile component of the coal is combusted. 

Generally speaking, approximately 20-40% of the Fuel NOx can source from fuel bound 

nitrogen associated with the solid char. Control of NO from this char nitrogen component 

cannot be directly controlled by air staging since under staged low NOx combustion 

(reducing or pyrolysis conditions), char nitrogen conversion to NO remains relatively 

constant. Typically, lower rank (more reactive) fuels have more fuel bound nitrogen 

associated with the volatiles than the char, so low rank coals overall have the lowest NOx 

potential. 

Figure 2 - Air Burnoff of PRB Coals and Reference Coals 

Air Burnoff of 200x400 Mesh PRB Project Coals

0.0

0.1

0.2

0.3

0.4

0.5

0.6

0.7

0.8

0.9

1.0

200 250 300 350 400 450 500 550 600 650

Temperature (oC)

Burnoff Rate, -dW/dt (relative)

SPRB 3

NPRB

BSF Cordero Rojo

SPRB 2

PRB Blend

SPRB 5

SPRB 1

Sub Bit

BSF Viking, hvCb

North Cambria

East Bit 1

East Bit 2

SPRB 4 PRB Sub Bit. C 

Eastern Bit. 
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In order to better understand how fuel bound nitrogen in both the volatile and char 

components of different rank coals affects total NOx reduction potential, coals and their char 

components are tested in a laboratory instrument known as the Thermal Gravimetric 

Analyzer, or TGA. Under this analysis the burn-off rate (change in weight/unit time) for 

various coals or coal chars can be shown as a function of temperature. An example of a 

TGA analysis for a wide variety of coals in shown in Figure 2. As can be seen, all of the 

PRB coals tested have similar rapid burn-off rates as compared to bituminous coals. This 

indicates that low rank PRB coals potentially have high volatile fuel nitrogen conversion 

rates and therefore lower NOx potential as compared to high rank Eastern bituminous coals. 

The performance of the PacifiCorp coals tends to fall between the PRB coals and Eastern 

bituminous coals shown. This would support the conclusion that the PacifiCorp coals have a 

NOx reduction potential well below Eastern bituminous coals, but not as low as true Powder 

River Basin coals. 

Drop Tube Test Furnace Nitrogen Conversion versus Coal Type

78%

87%

83% 84%

58%

55%

31%

22%

13%

17% 16%

42%

45%

69%

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

PRB PRB PRB PRB PRB & Bit.

Blend

Bituminous Bituminous

% Fuel N to NOx 

During Devolatilization

During Char Combustion

Figure 3 - Fuel Nitrogen Conversion During Coal Devolatilization and Coal Char 

Combustion versus Coal Type. 
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This conclusion is supported by additional ALSTOM laboratory data shown in Figure 3. 

Testing in ALSTOM’s bench scale Drop Tube Furnace can determine the relative percentage 

of fuel bound nitrogen converted to NOx in both the devolatilization and char phases of. 

combustion. It is clear that PRB coals can have greater than 78% of fuel bound nitrogen 

converted to NOx during devolatilization, which is far greater than that measured for 

bituminous coals. As a result of these observations, the performance of the PacifiCorp coals, 

in terms of total fuel NOx emissions would tend to fall between the PRB coals and Eastern 

bituminous coals shown. 

As mentioned earlier, NOx formed by fixation of atmospheric nitrogen to oxygen (thermal 

NOx) is the other main component of total NOx emissions for a boiler. The other two 

primary factors are unit design and operating procedures, and are therefore very unit specific. 

Unit design affects both the residence time of the combustion process, as well as the thermal 

aspects of combustion. Unit design determines how “hot” a furnace is, which influences the 

thermal NOx contribution for both the baseline and post-retrofit NOx emissions. From its 

extensive retrofit experience, ALSTOM developed a series of thermal NOx prediction 

methodologies based on the physical unit dimensions and the thermal conditions firing 

Eastern and Midwestern fuels. These site-specific predictive methodologies are used in 

combination with the fuel NOx prediction methodologies described above to make overall 

stack NOx emission predictions and commercial guarantees. 

Field Experience with Western U.S. Coals 

To date, ALSTOM has retrofitted over 50 units firing Western U.S.coals since 1995. 

Tangentially fired units burning low rank fuels consistently produce the lowest NOx 

emissions levels in the country on a yearly basis. 

Figure 4 shows the experience on coals from the West that rank either as high volatile 

bituminous B or C or as subbituminous B coals. The coals that PacifiCorp is currently firing 

generally fall in these categories. Considering the data presented in Figure 4, the NOx 

emission levels of the PacifiCorp coals will be higher than those of PRB coals. 

A recently published ALSTOM technical paper on Western coal firing experience is attached 

in the Appendix section of this paper. This technical paper was presented at the EERC 

Western Fuels Symposium in 2004. 
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Figure 4 – ALSTOM Experience on Western high volatile bituminous B and C, and 

subbituminous B 

CONCLUSIONS 

Both laboratory data and field experience indicate that Western low rank fuels are conducive 

to low NOx firing. The laboratory data from carefully controlled small scale experiments 

has documented that the lower rank subbituminous C (PRB) and lignite coals typical of the 

West will generate low NOx due to the high volatility and quick yield of fuel bound nitrogen. 

The field experiences from these fuels match the predictions from the laboratory data. Based 

on ALSTOM’s experience to date, most other Western bituminous coals such as those fired 

by PacifiCorp will produce NOx levels somewhere between PRB coals and Eastern 

bituminous coals. 

Average NOx Emissions 

as Reported by the EPA for the First Quarter of 2004

0.00

0.05

0.10

0.15

0.20

0.25

0.30

0.35

0.40

Level 1, 

Hi-vol B bit.

Level 1, 

Hi-vol C bit.

Level 1, 

Hi-vol C bit.

Level 3, 

Hi-vol C bit.

Level 3, 

Hi-vol C bit.

Level 3, 

Hi-vol C bit.

Level 3, 

Subbit. B

Level 3, 

Subbit. B

TFS 2000R,

Subbit. C

ALSTOM Low NOx System / Coal Rank

NOx, lb/mmBtu

Western Bituminous Sub-Bit B Sub-Bit C
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APPENDIX

List of Contents

 

A. PacifiCorp Coal Supply Data 

B. “ALSTOM’s Low NOx Firing Experience on Western Fuels”, Jennings, Patrick and 

Hart, Doug. Presented at EERC Western Fuels Symposium, 2004 

A PacifiCorp Coal Supply 

The PacifiCorp units that are located in Wyoming and Utah include the following sites with 

ALSTOM “Tangential –fired” boilers: 

Wyoming Units

Dave Johnston Station 

Jim Bridger Station 

Naughton Station 

Utah Units

Carbon Station 

Hunter Station 

Huntington Canyon Station 

The coals fired at the Jim Bridger and Naughton Stations are classified as Sub-Bituminous 

“B” coals while the coals fired at Dave Johnston Station as Sub-Bituminous “C” form the 

Powder River Basin. The coals fired at Carbon, Hunter and Huntington Canyon Stations are 

classified as high Volatile “C” to high Volatile “B” Bituminous coals. 

The coal data below is from “RDI – Coal.dat” (U.S. Plants and Coal Sources). This data 

will show that Jim Bridger Station and Naughton Station are the prominent users of the coals 

that are fired at these stations, while the other units fire coals that are used at multiple 

locations. 

Jim Bridger Station 

The coal that has been fired at Jim Bridger Station since 2000 comes from the following 

mines in Sweetwater County, WY: 

Jim Bridger 

Black Butte & Leucite Hills 

The other plants that have received coal form these mines are: 

Naughton Station - 454,000 tons in 2000 

North Valmy Station – 68,000 tons in 2001 
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Naughton Station 

The coal that has been fired at Naughton Station since 2000 comes from the following mines 

in Lincoln County, WY and Sweetwater County, WY: 

Kemmerer (Elkol & Sorenson) 

Black Butte & Leucite Hills – 454 tons in 2000. 

No other plants are listed as receiving coal from the mines in Lincoln County, WY 

Carbon Station 

The coal that has been fired at Carbon Station since 2000 comes from the following mines in 

Emery County, Carbon and Sevier Counties in UT: 

Deer Creek (C) 

Crandall Canyon 

Bear Canyon No. 2 

Bear Canyon No. 1 

Sufco 

Skyline No. 3 

Dug Out 

Whiskey Creek (Synfuel) 

West Ridge 

The other plants that have received 50,000 or more tons of coal from these mines from 2000 

or later are: 

Hunter – PacifiCorp (UT)* 

Huntington Canyon – PacifiCorp (UT)* 

Grand River Terminals –TVA (IL) 

Asbury – Empire District Electric Co. (MO) 

Cora Transfer Terminal – TVA (IL) 

Genoa – Dairyland Power Coop (WI)*

Intermountain Generating – Los Angeles Dept. of Water and Power (UT) 

Sibley – Aquila (MO) 

Boardman – Portland General Electric – (OR) 

ACE Cogeneration – Ace Cogeneration Co. (CA) 

Argus – IMC Chemicals – (CA)*

Edgewater – Wisconsin Power & Light – (WI) 

Gardner – Nevada Power Co. – (NV) 

Michigan City – Northern Indiana Public Service Co. - (IN) 

North Valmy – Sierra Pacific Power Co. – (NV) 

Stockton CoGen Co. – Air Products & Chemicals, Inc. - (CA) 

Alma - Dairyland Power Coop - (WI) 

J.P. Madgett - Dairyland Power Coop – (WI) 

Manitowoc – Manitowoc Public Utilities – (WI) 

Mount Poso Cogeneration – Mount Poso Cogeneration (CA) 
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Hunter Station

The coal that has been fired at Hunter Station since 2000 comes from the following mines in 

Emery County, Carbon and Sevier Counties in UT: 

Deer Creek (C) 

Trail Mountain 

Dug Out 

Sufco 

West Ridge 

The other plants that have received 50,000 or more tons of coal from these mines from 2000 

or later are: 

Carbon Station – PacifiCorp (UT)* 

Huntington Canyon Station – PacifiCorp (UT)* 

Grand River Terminals –TVA (IL) 

Asbury Station – Empire District Electric Co. (MO) 

Cora Transfer Terminal – TVA (IL) 

Genoa Station – Dairyland Power Coop (WI)* 

Intermountain Generating – Los Angeles Dept. of Water and Power (UT) 

Sibley Station – Aquila (MO) 

Boardman Station – Portland General Electric – (OR) 

ACE Cogeneration – Ace Cogeneration Co. (CA) 

Argus – IMC Chemicals – (CA)* 

Edgewater Station – Wisconsin Power & Light – (WI) 

Gardner Station – Nevada Power Co. – (NV) 

Michigan City Station – Northern Indiana Public Service Co. – (IN) 

North Valmy Station – Sierra Pacific Power Co. – (NV) 

Stockton CoGen Co. – Air Products & Chemicals, Inc. – (CA) 

Alma Station – Dairyland Power Coop – (WI) 

J.P. Madgett - Dairyland Power Coop – (WI) 

Manitowoc – Manitowoc Public Utilities – (WI) 

Mount Poso Cogeneration – Mount Poso Cogeneration (CA) 

Huntington Canyon Station 

The coal that has been fired at Huntington Canyon Station since 2000 comes from the 

following mines in Emery County, Carbon and Sevier Counties in UT: 

Deer Creek (C) 

Emery 

Dug Out 

Sufco 

West Ridge 
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The other plants that have received 50,000 or more tons of coal from these mines from 2000 

or later are: 

Carbon Station – PacifiCorp (UT)* 

Hunter Station – PacifiCorp (UT)* 

Grand River Terminals –TVA (IL) 

Asbury Station – Empire District Electric Co. (MO) 

Cora Transfer Terminal – TVA (IL) 

Genoa Station – Dairyland Power Coop (WI)* 

Intermountain Generating – Los Angeles Dept. of Water and Power (UT) 

Sibley Station – Aquila (MO) 

Boardman Station – Portland General Electric – (OR) 

ACE Cogeneration – Ace Cogeneration Co. (CA) 

Argus – IMC Chemicals – (CA)* 

Edgewater Station – Wisconsin Power & Light – (WI) 

Gardner Station – Nevada Power Co. – (NV) 

Michigan City Station – Northern Indiana Public Service Co. – (IN) 

North Valmy Station – Sierra Pacific Power Co. – (NV) 

Stockton CoGen Co. – Air Products & Chemicals, Inc. – (CA) 

Alma Station – Dairyland Power Coop – (WI) 

J.P. Madgett - Dairyland Power Coop – (WI) 

Manitowoc – Manitowoc Public Utilities – (WI) 

Mount Poso Cogeneration – Mount Poso Cogeneration (CA) 

* ALSTOM, Inc. - “Tangential-fired” units 

Dave Johnston Station

The coal fired at Dave Johnston Station is a sub-bituminous coal from the Powder River 

Basin (PRB). This coal is fired at numerous units that fire the coals from the PRB region: 

Dave Johnston receives coal from the following mines since the year 2000: 

Black Thunder 

Coal Creek 

Cordero (Caballo Rojo) 

Dave Johnston 

Dry Fork 

Wyodak 

Jacobs Ranch 

Caballo 

Buckskin 

Rawhide 

There are many units that fire coals from the PRB region.