O FFICE OF THE V ICE P RESIDENT FOR R ESEARCH

E NVIRONMENTAL H EALTH & S AFETY

P.O. Box 400322• Charlottesville, VA 22904

- 4322

Phone : 434

- 982

- 4911•Fax: 434

- 982

- 4915 http://ehs.virginia.edu/ July 15, 2011

Mr. Brian Shrager Energy Strategies Group

Sector Policies and Programs Division

Office of Air Quality Planning and Standards U.S. Environmental Protection Agency Mail Drop D243

– 01 4030 Old Page Road Research Triangle Park, NC 27711

Attn: Docket ID No. EPA

- HQ

- OAR

- 2002

- 0058

Via: shrager.brian@epa.gov and combustionsurvey@erg.com

RE: University of Virginia comments on the final National Emission Standards for Hazardous Air Pollutants for Majo r Sources: Industrial, Commercial, and Institutional Boilers and Process

Heaters

Dear Mr. Shrager :

Please find attached our comments and supporting data related to the final National Emission Standards for Hazardous Air Pollutants for Major Sources: Industrial, Commercial, and Institutional Boilers and Process Heaters (Major Source Boiler MACT)

. . UVA is submitting these comments in response to the May 19, 2011 Federal Register Notice that stated EPA would accept additional data and information related to the rule until July 15, 2011.

The University of Virginia ( UVA ) is a public institute of higher education serving over 20,000

students. UVA op erates a variety of boilers from small boilers serving individual buildings to the five boilers at our Main Heat Plant providing district heating and process loads for our medical center and throughout the grounds of the university. For flexibility, we ha ve capability to fire a variety of fuels

– coal, distillate oil and natural gas. Our boilers serve over 15 million square feet of clinical, academic research, student, and support service space in more than 540 buildings.

We appreciate the opportunity to offer comments and seek clarification on implementation of the promulgated rule.UVA Comments on the Final Boiler MACT Regulations

July 15, 2011 Transmittal Letter Page 2

515 Edgemont Road

– P.O. Box 400322

– Charlottesville, VA

– 22904

- 4322 Phone (434) 982

- 4911

– Fax (434) 982

- 4915 Sincerely,

Jeffrey A. Sitler, CPG Environmental Compliance Manager

cc: Dr. Teresa A. Sullivan, President
Dr. Michael Strine, Executive Vice President and Chief Operating Officer
Dr. J. Milton Adams, Interim Executive Vice President and Provost

Col ette Sheehy, Vice President for Management and Budget Don Sundgren, Chief Facilities Officer Cheryl Gomez, PE, Director of Energy and Utilities
Kristin Carter, PE, Environmental Engineer Ralph Allen, Director En vironmental Health and Safety

Attachment

- Comments and Supporting DataUVA Comments on the Final Boiler MACT Regulations

July 15, 2011 Comment Page 1



### UVA Comments on the Major Source Final Boiler MACT Regulation

(Note: All page numbers refer to the 3/21/11 Federal Register Final Rule)

NATURAL GAS OPERATIONS IN SOLID AND LIQUID FUEL UNITS

At §63.7500 (a), (p 15565c3) the rule states:

“ You must meet the requirements in paragraphs (a)(1) through (3) of this section, except as provided in paragraphs (b) and (c) of this section. You must meet these requirements at all times. ”

Sub

- paragraphs (a) (1) through (a) (3) explain emission limits and refer to Tables 1 through 3 of

the sub

- part. The tables and other portions of the rule establish emission limits for regulated boilers based on the subcategory into which they fall based on the fuels used.

EPA has recognize d that many boilers can and do operate with different fuels, as indicated by the unit descriptions in §63.75 75

. For example, on page 15686 column 2 the rule states:

“ Unit designed to burn solid fuel subcategory means any boiler or process heater that bur ns any solid fuel alone or at least 10 percent solid fuel on an annual heat input basis in combination with liquid fuels or gaseous fuels. ”

However, the rule does not explain which emission limits and operating limits apply to a multiple fuel boiler when operating on different fuels.

For example, UVA operates five boilers at its Main Heat Plant (MHP), three which can operate on coal or natural gas and two which can operate on distillate oil or natural gas. These five boilers use natural gas for start

- up and may operate on natural gas or coal for extended periods. According to the above proposed definition, if one of the coal/natural gas boilers burns at least 10 percent coal on an annual heat input basis, that boiler is classified as a solid fuel boiler . The problem with the regulations as written is they do not provide direction on which subcategory

based emission and operating limits apply

– coal or natural gas

– when that boiler is operating exclusively on natural gas.

In the current rule, a gas 1 fuel subcategory boiler (i.e., one burning natural gas) is not subject to numerical emission limits and is therefore not required to operate an air pollution control device. UVA therefore questions why a boiler, when it is operating on natural gas, needs t o comply with emission and operating limits established for a different fuel, regardless of the annual subcategory designation of the boiler. Compliance with operating limits established during coal

or oil

- fire operations while a boiler is exclusively fi ring natural gas will be problematic as described in the examples below.

SCRUBBER LIMIT: Specific to the UVA MHP coal/natural gas boilers, current regulations and the state air permit require operation of the baghouse and lime slurry

- fed spray dryer when firing coal, but do not require these controls when burning natural gas as SO 2 and particulate removal is not applicable. To comply with the sorbent injection rate limit that will be set while burning coal during the performance test, will we be required to feed lime slurry during 100% gas

- fire

conditions? To address the current lack of direction in the rule language, we suggest modify ingUVA Comments on the Final Boiler MACT Regulations

July 15, 2011 Comment Page 2

the load fraction definition in §63.75 75 (p15684c2) and Table 7 (p15696) to be based on heat inputs from only solid an d liquid fuels or

, alternatively worded, be based on the heat inputs of

non

- gas 1 fuels

.

O 2 LIMIT: The minimum O 2 limit will be set while burning distillate oil or coal during the performance test. Below are O 2 trim curves for our distillate oil

- natural gas fired boilers 3R and 4R at the Main Heat Plant below. According to the attached curve for Boiler 4R, the minimum

excess O 2 when firing oil is about 1% higher than while firing natural gas. Restricting O 2 to at least 3.4% while firing natural gas may result in a conflict between meeting CO and NO

x emission limits.UVA Comments on the Final Boiler MACT Regulations

July 15, 2011 Comment Page 3

Similar problems are expected for our coal

- and natural gas

- fired boilers (1R, 2R and 5). The O 2 trim curves for natural gas

- fire for these boilers are provided in the graph be lo w. Coal fire does

not have an automated curve ; excess O 2 is manually balanced by the operators. The graph shows the typical coal fire O 2 level of 6% O 2 , with a range of 4 to 10%. If a minimum O 2 limit is set during a coal

- fire performance test, complian ce with that value during natural gas operations at high load will be restricted.

UVA suggests that EPA reconsider the applicability of subcategory

- based emission limits for boilers that burn different fuels at different times and clarify the requirements to comply with the emission and operating limits based on the fuel(s) used at any poi nt in time. UVA understands and accepts the need for owners/operators to document and maintain operating records regarding fuel usage such that EPA can review the operating history to check that a unit was complying with applicable emission and operating limits, based on the fuel usage, at all times.

UNIT DESIGNED TO BURN GAS 1 SUBCATEGORY DEFINITION

The definition of uni t design ed to burn gas 1 subcategory changed between proposal and promulgation. The proposed rule definition included “any boiler or process heater that burns at least 90% natural gas and/or refinery gas on a heat input basis on an annual average ” . The promulgated rule definition only includes boilers or process heaters that can burn liquid fuel for periodic testing (≤ 48 hours) or periods of gas curtailment and gas supply emergencies. This change in the subcategory threshold deviates from the formula used for bio mass/bio

- based

solids

, coal/solid fossil fuel

, gas 2 (other) , and liquid subcategories which all use a 10% threshold

in the definition. This discrepancy provides a gap in applicability b etween gas 1 and liquid fire subcategories and raises the question of which subcategory applies when a unit burns less than 10 percent liquid fuel and natural gas for the remainder of the heat input on an annual basis.

UVA has eleven boilers rated at ≥10 MMBtu/hr that are designed to burn natural gas and

distillate oil. Currently, these natural gas/oil boilers are not limited to operating on oil only during natural gas curtailment periods. For the purpose of demonstrating compliance with 40 CFR 63, Subpart DDDDD, language needs to be provided that clarifies if a regulate d unit needsUVA Comments on the Final Boiler MACT Regulations

July 15, 2011 Comment Page 4

to have specific permit conditions that designate its possible fuel subcategories or if the operating reports and records required under §63 .7550 and §63 .7555 , respectively, suffice to demonstrate compliance.

NATURAL GAS CURTAILMENT REPORTING

At §63.75 45(f) (p15679c1) the rule states:

“ If you operate a unit designed to burn natural gas, refinery gas, or other gas 1 fuels that is subject to this subpart, and you intend to use a fuel other than natural gas, refinery gas, or other gas 1 fuel to fire the affected unit during a period of natural gas curtailment or supply interruption, as defined in § 63.7575, you

must submit a notification of alternative fuel use within 48 hours of the declaration of each period of natural gas curtailment or suppl y interruption, as defined in §63.7575.”

UVA questions the need for this requirement and its timing. Natural gas curtailment periods are often associated with extreme weather events. These events, by their nature, create extraordinary difficulties for ope rating plants and typically require additional activities to prepare for the event to eliminate or minimize operating disruptions. Including a requirement to submit a written notification of natural gas curtailment adds to the operating burden of available staff during this extremely busy period.

In addition, UVA does not understand the benefit or need of a 48

- hour notification. What does EPA intend to do with the information submitted by these notifications? What reduction or

minimization of emissions ca n be attributed to this notification? Boiler owner s /operator s must continue to comply with applicable emission and operating limits during any period of

curtailment and must document the actual fuel use in accordance §63 .7555(d). These and other operating records will adequately demonstrate compliance for regulated units, or non

compliance, if that occurs.

UVA suggests that EPA delete the requirement for the notification of fuel switching during periods of natural gas curtailment and instead add a line it em to reporting requirements listed in
§63 .7550(b).

FUEL SWITCHES AND SUBCATEGORY CHANGES

In §63.7545(h) (p15679c2), the rule describes notification requirements if a boiler intends to

switch fuels which result in the unit being subject to a different subcategory. This notification must include the date upon which the boiler will commence the fuel switch. Does a performance test need to be conducted to demonstrate compliance and establish new operating limits? Under

what time frame relative to the da te of the fuel switch does this testing need to occur?

O 2 CEMS MONITORING FOR CO EMISSIONS COMPLIANCE

At §63.75 25(a) (p15671c3) the final rule requires the installation of a continuous oxygen

emissions monitor ing system (O 2 CEMS) for boilers subject to a carbon monoxide (CO) limit. This requirement is different than the requirements of the proposed rule (75 Federal Register

32682

- 32073, 6/9/10) which required annual CO stack tests for units with heat input ratings of

10

– 100 MMBtu/hr and CO CEMS for units with heat input ratings over 100 MMBtu/hr.UVA Comments on the Final Boiler MACT Regulations

July 15, 2011 Comment Page 5

We have 14 boilers ≥10 MMBtu/hr subject to emission limits and the O 2 monitoring requirement; five of these boilers already monitor O 2 in the flue gas. According to the final rule,

we would need to install nine additional O 2 analyzers at three different locations (not regularly staffed) at an estimated capital cost over $600,000 (2011 dollars). This cost estimate is provided

i n Table 3 and is based on both the EPA Model Cost for CEMS and actual historical costs for CEMS equipment

.

Annual operation and maintenance costs including labor, calibration gases, and quarterly audits

would be an additional burden. Under the proposed rule , these nine boilers would have been required to conduct an annual CO stack test which would be about the same cost as an annual RATA required for the O 2 CEMS

- significantly less than the overall cost for installing O 2 CEMS. The final rule requirements f or demonstrating compliance with the CO standard are far more costly than the proposed rule and have logistical problems, as discussed in our first comment, for multiple fuel units.

UVA suggests that owners and operators be given more options for demonstr ating compliance with the CO emission limits, specifically allowing 10

– 100 MMBtu/hr units to use annual CO stack testing or CO CEMS in lieu of O 2 monitoring.

OUTPUT VERSUS INPUT

- BASED EMISSION LIMITS

In Table 1 (p15688) and Table 2(p15689) the final rule provides alternate emission limits based on energy output rather than energy input. These limits are a new addition and were not provided in the proposed rule. Based on preamble discussions at pages 15611, 15617, and 15630, EPA developed the output ba sed limits in response to comments on the proposed rule.

We have the following questions on how to demonstrate compliance with the output based

limits:

1. Can any unit demonstrate compliance with the output based limits rather than input based

limits or is it restricted to those units using the emission credit approach?

2. What equation is used to calculate output

- based emission rates? Preamble (page 15618 c1) refers to equations provided in the final rule, but we only found equations that apply

to the adjustment of emissions if the emission credit approach was used. We believe the calculation is straight forward and can be inferred from pertinent discussion in the preamble (page 15631c1):

“In the case of a boiler that produces steam for process or heating only (no power generation), the lb/MMBtu output

- based emission limit is based on the mass rate of emissions from the boiler and the energy content in terms of MMBtu of the boiler steam output.”

The preamble, at page 15631c2 and c3, discuss that th e output

- based limits were developed from the input based limits, and an average boiler efficiency for the best performing sources that made up the MACT Floor. Boiler efficiency is defined as steam Btu output divided by fuel Btu input

, which for real worl d systems is less than 100%

. A comparison of the input and output based limits in Tables 1 and 2 using the equation below, it appears that efficiencies of greater thanUVA Comments on the Final Boiler MACT Regulations

July 15, 2011 Comment Page 6

100% were used to convert input based limits to output based limits, with the exception of the

HCl emission limits.

Table 1. Calculated Average Boiler Efficiency

HAP/Fuel Input Based

Limits Output

Based Limits Calculated

Boiler Efficiency Input Based

Limits Output

Based Limits Calculated

Boiler Efficiency Existing Units (lb/MMBtu) New Units (lb/MMBtu)

PM / Solid Fuel 0.039 0.038 103% 0.0011 0.0011 100%

HCl / Solid Fuel 0.035 0.04 88% 0.0022 0.0021 105%
Hg /Solid Fuel 4.6E

- 06 4.5E

- 06 102% 3.5E

- 06 3.4E

- 06 103%

PM / Oil (U.S. & non continental) 0.0075 0.0073 103% 0.0013 0.001 130%

HCl / Oil (U.S. & non continental) 0.00033 0.0003 110% 0.00033 0.0003 110%
Hg / Oil (U.S.) 3.5E

- 06 3.3E

- 06 106% 2.1E

- 07 2.0E

- 07 105%
Hg / Oil (non

- continental) 7.8E

- 07 8.0E

- 07 98% 7.8E

- 07 8.0E

- 07 98%

PM / Gas 2 0.043 0.026 165% 0.0067 0.004 168%

HCl / Gas 2 0.0017 0.001 170% 0.0017 0.003 57%
Hg / Gas 2 1.3E

- 05 7.8E

- 06 167% 7.9E

- 06 2.0E

- 07 3950%

Boiler efficiencies were not calculated from CO and dioxin/furan input and output based emissions since they are not both expressed in units of lb/MMBtu.

12

- HOUR BLOCK AVERAGE CALCULATIONS

Table 4 (p15692) and Table 8 (p15697) use the term “12

- hour block average” as the calculated value for various operating parameters to compare against operating limits that are established from performance test data. In a few instances, the term “block” is not used (Table 8, #3c and #4c). In addition, the rule does not define how a “12

- hour block average” should be calculated

and how start

- up and shutdow n periods and periods of non

- operation should be considered in the

calculation of the “12

- hour block average.”

UVA suggests that EPA add a definition of “12

- hour block average” to §63 .7575 for

clarification. We propose the following definition: “ Twelve

- hour block average or 12

- hour block average means the average of all hourly average values when the affected facility is operating and combusting fuel measured over 12

- hour periods of time from 12:00 midnight to

1 1 : 59 am and 12:00 noon to 1 1 : 59 pm

. Data recorded during start

- up and shut

- down and periods

of non

- operation will not be excluded from t he calculated 12

- hours block average.”

OPERATING LOAD DEFINITION

The final rule added requirements for measuring and establishing limits for “operating load.” For example, Table 7 (p 15697) requiresUVA Comments on the Final Boiler MACT Regulations

July 15, 2011 Comment Page 7

“ 5. Any pollutant for which compliance is demonstrated by a performance test. a. Boiler or process heater operating load. i. Establish a unit specific limit for maximum operating load according to § 63.7520(c). (1) Data from the operating load monitors or from steam generation monitors. ”

However, the final rule does not clearly define or establish the requirements for the operating

load. For example, operating load for an individual boiler may be bas ed on:

 Feed rate of each fuel ( in volumetric

- or mass

- based units of tons/hr, gal/hr, or scfh)

 Total heat input (MMBTU/hr)

 Steam generation rate (lbs/hr) or

 Steam generation rate (MMBTU/hr).

UVA suggests EPA consider adding a definition for operating lo ad to §63.7575 , and include the ability for the owner/operator to explicitly define the monitor and units used for each regulated

device.

PERFORMANCE TEST RESULT SUBMITTAL DATE

There appears to be a discrepancy regarding the time allowed to prepare and s ubmit performance test reports in accordance with the rule. At §63.7515 (g) (p15668c1) the rule states:

“You must report the results of performance tests and the associated initial fuel analyses within 90 days after the completion of the performance tests. ”

At §63.7550(h) (p15681c1) the rule states:

“ As of January 1, 2012 and within 60 days after the date of completing each performance test, as defined in § 63.2, conducted to demonstrate compliance with this subpart, you must submit relative accuracy test audit ( i.e. , reference method) data and performance test ( i.e. , compliance test) data, except opacity data, electronically to EPA’s Central Data Exchange (CDX) by using the Electronic Reporting Tool (ERT) (see http://www.epa.gov/ttn/chief/ert/ert tool .html/ ) or other compatible electronic spreadsheet. ”

T he testing and data reduction requirements for performance tests in the final rule are substantial.

UVA recommends that EPA allow owners and operators 90 days to prepare, review, certify , and

submit th ese reports.

TEXT CLARIFICATION

At §63.7521(i) (p 15669c2) the rule states:

“ You must determine the concentration in the fuel of mercury, in units of microgram per cubic meter, and of hydrogen sulfide, in units of parts per million, by volume, dry basis, of each sample for each gas 1 fuel type according to the procedures in Table 6 to this subpart.”

The preceding text, in sub

- paragraphs (f) through (h), discusses “other” gas 1 fuels. Sub

paragraph (i) continues that discussion and describes the req uirements for determining concentrations of constituents in the fuel. However, the word “other” in describing the fuelsUVA Comments on the Final Boiler MACT Regulations

July 15, 2011 Comment Page 8

seems to have been omitted in the description in sub

- paragraph (i). UVA suggests that EPA

review this text and add the word “other” befo re the words “gas 1 fuel type” to make the description consistent and logical with the remaining text.

SCOPE OF THE ENERGY ASSESSMENT

The final rule included a definition in §63.7575 of what the energy assessment should include for

various size fuel con suming facilities. Please confirm that the term “facility” in our case would

be consistent with the Title V definition that characterizes as the entire contiguous are a of the campus as one facility , thus, it is the collection of buildings and the affected boilers within them

.

For fa cilities with energy consumption ≤ 1 TBtu/yr, the energy assessment definition provides a time limit (one or three days depending on the consumption) for conducting the assessment. Does this time limit correspond to all of the assessment criteria noted in Table 3 including development of the report or does it apply to a portion of the overall assessment (e.g., the boiler system only or the energy use system only)? Does this time limit apply to each boiler separately (i.e., one or three days per boiler) or the total of all boilers and associated energy use systems at the entire facility (i.e., one or three days per facility).

No maximum time limitations are provided for facilities with energy consumption over 1 TBtu/yr as allowed for facilities consuming ≤ 1 TBtu/yr. We recommend the definition of energy assessment be revised to include a reasonable or not to exceed time frame for conducting

the assessment facilities consuming over 1 TBtu/yr as was done for the f acili ti es under 1TBtu/ yr. We would propose a cap of 10 business days for facil i ties consuming m ore that 1TBtu/ yr

.

I n calendar year 2009, UVA ’s five Main Heat Plant boilers consumed 1,262,053 MMBtu or 1.26 TBtu/yr of energy. This energy consumption does not include the amount used by the other 113

much smaller oil, gas, and combination fuel boilers also operat ed ac ross campus. According to our annual energy consumption, we are required to perform an energy assessment for each affected boiler system and any energy use system accounting for at least 20% of the energy

output. Almost every building on UVA’s Charlottes ville campus is either served by a boiler or through a district heating distribution network from a central heat plant. Based on our recent experience, including internal and external resources, the estimated cost for conducting an energy assessment of ou r buildings is $0.60 per square foot. Based on our approximately14.5 million square feet that are conditioned (some directly served by a boiler(s) and other by district heat) , we estimate the energy use system evaluation piece of the overall energy assessment will cost $ 3

. 8 million to meet this proposed work practice standard. This cost doesn’t include the evaluation of the individual boiler systems which will add substantial expense to the overall

assessment.

UVA proposes that the energy assessment only apply to existing boilers subject to emission

limits rather t han all existing boilers as the rule currently requires. Emission standards only apply to non

- gas 1 fired boilers and those with a heat input rating  10 MMBtu/hr. There are 118 existing boilers at UVA which can be sorted as follows by fuel and heat inpu t rating :UVA Comments on the Final Boiler MACT Regulations

July 15, 2011 Comment Page 9

Table 2

- Number of Boilers by Fuel and Input

Capacity

Coal

- Fired Boilers
>100MM BTU/hr 1

10MM

-- 100MM BTU/hr 2

1MM

-- 10MM BTU/hr 0
<1MM BTU/hr 0

Net Total 3

Liquid

- Fired Boilers
>100MM BTU/hr 2

10MM

-- 100MM BTU/hr 9

1MM

-- 10MM BTU/hr 6

< 1MM BTU/hr 8

Net Total 25

Gas Fired Boilers
>100MM BTU/hr 0

10MM

-- 100MM BTU/hr 2

1MM

-- 10MM BTU/hr 29
<1MM BTU/hr 5 9

Net Total 90

Net Total Boilers 118

If t he energy assessment only applied to boilers subject to emission limits, we would have 14

boilers to audit which include our three heat plants and one other athletic facility

.

Alternatively , t he p rocess could be mu ch simplified by conducting the energy audit on the energy use systems equivalent to 20% of the total faci l i ty energy consumption rather than 20 percent of every existing boilers energy use system.UVA Comments on the Final Boiler MACT Regulations

July 15, 2011 Comment Page 10



### T able 3

– O 2 

### CEMS Initial Costs

Assumptions

2 boilers located in Bldg 7533: N orth Grounds Heat Plant

, linked to one DAS.

4 boiler l ocated in Bldg 5575: Massie Rd Heat Plant , linked to one DAS.

3 boilers located in Bldg 5576: 2 serving U

- Hall and 1 serving McCue, linked to one DAS

Total b oilers requiring O 2 CEMS 9

Total DAS required: 3

Costs per CEMS: $ Source

Probe stinger $ 300 Realistic Equipment Costs

Probe box $ 4,500 Realistic Equipment Costs

Heated sample line $ 3,000 Realistic Equipment Costs

Gas conditioner $ 5,000 Realistic Equipment Costs

Instrument rack $ 1,000 Realistic Equipment Costs

O2 analyzer $ 7,500 Realistic Equipment Costs

Sub

- Total Equipment $ 21,300

Auxiliary equipment $ 1,065 5.0% of base equipment cost

Freight $ 1,065 5.0% of base equipment cost

Fabrication $ 2,130 10.0% of base equipment cost

Install and Check CEMS $ 10,546 EPA Model Cost System

Performance Specification Tests $ 8,047 EPA Model Cost System

Sub

- Total Other $ 22,853

Total per CEMS $ 44,153

Number of CEMS 9

Total Cost of CEMS $ 397,379

Costs per System: $ Source

Planning $ 2,694 EPA Model Cost System

Select Equipment $ 6,874 EPA Model Cost System

Support Facilities $ 18,700 EPA Model Cost System

DAS hardware $ 15,000 Realistic Equipment Costs

DAS software $ 25,000 Realistic Equipment Costs

Computer & Peripherals $ 4,000 Realistic Equipment Costs

QA/QC Plan $ 15,244 EPA Model Cost System

Sub

- Total $ 87,512

Number of Systems 3

Total Cost of Systems $ 262,535

Overall Cost $ 659,914