U.S. Environmental Protection Agency
Air and Radiation Docket and Information Center
MC-6102
401 M Street, S.W.
Washington, DC 20460

                                                    Air Docket Number: A-92-71
 

Proposed Revision of Standards of Performance for Nitrogen Oxide Emissions From New Fossil-Fuel Fired Steam Generating Units; Proposed Revisions to Reporting Requirements for Standards of Performance for New Fossil-Fuel Fired Steam Generating Units; 62 Federal Register 36,948-36,963, July 9, 1997
 
 

Dear Sir or Madam:

The Natural Gas Supply Association appreciates the opportunity to comment on the subject notice of the proposed revisions to the 40 CFR part 60 subpart Da and subpart Db standards. The Natural Gas Supply Association represents independent and integrated companies that produce and market domestic natural gas ­ a clean and efficient fuel used in power generation, co-generation, and industrial boilers. In addition, many members of the NGSA own and operate industrial boilers and co-generation facilities that may be affected by this rulemaking. Therefore, The Natural Gas Supply Association has a significant stake in the outcome of this rulemaking.

The Natural Gas Supply Association submits the following detailed comments and recommendations for the Agency's consideration.
 
 

The Natural Gas Supply Association strongly supports the principle of fuel neutral performance standards as an equitable and defensible approach to limiting NOx emissions from new boilers and co-generation facilities.

The Natural Gas Supply Association strongly supports the principle and the rationale of fuel neutral performance standards in this rulemaking. In its rationale, EPA states:

The single emission limitation approach would expand the control options available by allowing the use of clean fuels as a method for reducing NOx emissions. Since projected new utility steam generating units are predominantly coal-fired, the use of clean fuels (i.e., natural gas) as a method of reducing NOx emissions from these coal-fired steam generating units may give the regulated community a more cost-effective option than the application of SCR. Similarly, for industrial units, the use of clean fuels as a method of reducing emissions may be a cost-effective approach for coal-fired and residual oil-fired industrial steam generating units.⁽¹⁾

The Clean Air Act Amendments of 1990 encourage the use of clean fuels as long as compliance options are available for all fuels ­ as is the case here.

The Natural Gas Supply Association agrees that the fuel-neutral emission limitation approach, which is also a performance standard, would expand the control options available to boiler operators by valuing the use of clean fuels as an integral part of the initial purchase decision with respect to subsequent control requirements. Thus eliminating an existing regulatory bias against the use of clean fuels.
 
 

The Natural Gas Supply Association supports the principle of the output-based standard for subpart Da sources. Output-based standards correctly incorporate and encourage process efficiency in environmental regulation.

EPA states:

Traditionally, utility NOx emissions have been controlled on the basis of boiler input energy (lb of NOx / million Btu heat input). However, input-based limitations allow units with low operating efficiency to emit more NOx per megawatt (Mwe) of electricity produced than more efficient units. Considering two units of equal capacity, under current regulations, the less efficient unit will emit more NOx because it uses more fuel to produce the same amount of electricity. One way to regulate mass emissions of NOx and plant efficiency is to express the NOx emission standard in terms of output energy. Thus, an output-based emission standard would provide a regulatory incentive to enhance unit operating efficiency and reduce NOx emissions.(2)

The Natural Gas Supply Association agrees that input based standards have allowed electric utility steam generating units to ignore its emissions of NOx in terms of total mass rate. Further, the growth of the electric utility industry in the past, for the most part, has not been based on obtaining the highest efficiency for any given generating capacity but has rather been based primarily on capital investments in new generating capacity. By establishing an output-based standard, the Agency will provide the incentive for operators to improve the efficiency ­ and total system cost - of any subpart Da source which commenced construction, modification, or reconstruction after July 9, 1997.
 
 

The Natural Gas Supply Association supports EPA's interpretation that selective catalytic reduction (SCR) is not nearly as cost effective ($ per ton of NOx) for subpart Da and Db natural gas or distillate oil-fired boilers as it is for coal fired boilers. EPA correctly recognizes that the use of clean fuels without SCR is as effective or more effective in controlling NOx per unit of output than firing coal in boilers with SCR.

In Table 3 of the preamble, EPA presented cost effectiveness values for SCR and SNCR applications in gas and oil fired steam generating units. These values range up to $147,900 per ton of NOx removed. For gas, distillate oil and residual oil firing configurations shown in the table, SCR is clearly not cost-effective. Choosing a clean fuel to begin with enables the operator to meet the requirements without adding SCR, which is prohibitively expensive when added to the premium paid for the clean fuels over that paid for coal.

Further, EPA states that "the main differences between industrial steam generating units and utility steam generating units are that industrial steam generating units tend to be smaller and tend to operate at lower capacity factors." Hence, EPA states

the differences would be reflected in the cost impacts of the various NOx control technologies. Smaller sized and lower capacity factor units tend to have higher cost on a per unit output basis.(3)

With this cost-ineffective basis, EPA proposed no additional controls for new gas-fired and distillate oil-fired units and basically retained the 0.20 lb per MMBtu standard for these units. The Natural Gas Supply Association supports this EPA interpretation of the results.
 
 

Co-generation units should be allowed to take credit for 100% of the steam output as energy output for purposes of determining the effective emissions rate limit for such units.

EPA proposed that co-generation units subject to subpart Da can only take credit as energy output for 50% of the steam input. EPA proposed to define "net output" to mean:

the net useful work performed by the steam generated taking into account the energy requirements for auxiliaries and emission controls. For units generating only electricity, the net useful work performed is the net electrical output (i.e., net buss bar power leaving the plant) from the turbine/generator set. For co-generation units, the net useful work performed is the net electrical output plus one half the useful thermal output (i.e., steam delivered to an industrial process).(4)

Steam can have many uses other than purely using its thermal properties for a power generating cycle. Rather, steam can also be used to flood a reservoir for enhanced crude oil recovery or used as a reactant in a petrochemical manufacturing process. Restricting the credit to 50% is arbitrary. The Natural Gas Supply Association supports a presumptive 100% credit for steam production at co-generation facilities.
 
 

EPA should adopt a heat rate for extrapolating the output-based standard based on analysis of heat rates of new units.

The Natural Gas Supply Association strongly supports an output-based standard for subpart Da sources. EPA adopted a simple across-the-board extrapolation method to obtain the 1.35 lb / MWh performance standard. EPA proposed the 1.35 lb / MWh output based standard by converting all of the input based emission data with a single heat rate factor.(5) The Natural Gas Supply Association believes that EPA has performed ample due diligence to select the approach. However, EPA should conduct analysis on sustainable heat rates (over the averaging period) for new units after the first year of operation. The agency should consider aligning the time frames for the cost analysis and the heat rates to ensure that the baseline heat rate is achievable for good performers over time. EPA should not consider any and all boilers in the current EPA database or all those that are available for purchase today. The EPA database and the set of boilers currently available for purchase include some that are significantly below the operating efficiency parameters of what is considered good practice. EPA should make a judgement in this rule regarding the baseline efficiency based on a subset of new boilers that are at the higher end of the efficiency spectrum.

EPA chose 38% for new boilers, citing that new boilers generally operate around 38% efficiency, which corresponds to a heat rate of 9,000 Btu per kWh. NGSA does not challenge that finding. However, the NGSA believes that EPA should be consistent in its analytical approach and choose a representative, sustainable heat rate for new boilers after 5 years of operation. This would be consistent with its economic impact analysis of examining the impacts in the 5th year. EPA should present a database of heat rates for such new boilers on which it intends to choose the presumptive heat rate conversion factor.
 
 

EPA should recognize natural gas reburn, as well as selective catalytic reduction, as the demonstrated technology basis for subpart Da sources.

The EPA is basing the best demonstrated technology (BDT) on selective catalytic reduction technology in order to establish these proposed revisions. EPA states:

The technical basis selected for establishing revised NOx emission limits is the performance of SCR (in combination with combustion controls).(6)

However, The Natural Gas Supply Association believes that EPA should recognize gas reburn as a viable technology in this rulemaking as the agency correctly did in the recently promulgated Acid Rain Phase II NOx regulations. In those regulations, 40 CFR 76.6,(7) both selective catalytic reduction and natural gas reburn form an equivalent technical basis for cyclone boilers and wet bottom boilers. For these proposed revisions to the new source performance standards, there is no reason to believe that natural gas reburn would be in any way inferior in NOx emissions control performance than selective catalytic reduction.

The EPA cites several concerns in this rulemaking with respect to gas-based control techniques:

The fuel cost differential between gas and coal is one of the main concerns with the application of gas-based technologies for the reduction of NOx from coal-fired boilers. Access to gas supply (proximity to pipeline) and long term gas availability are additional concerns that may limit natural gas use solely for NOx control.

The Natural Gas Supply Association believes these issues have been adequately addressed by EPA in the final Acid Rain NOx rulemaking.(8) EPA found little cause for concern regarding fuel cost differential between gas and coal and little cause for concern for access to gas supply.(9) Further, in siting new boilers, the owner or operator would take such factors into consideration prior to the planning, costing, construction, and siting of any new boiler. If natural gas access or pricing is a concern at a specific location, the owner or operator may choose other options.

Furthermore, the use of gas reburn with advanced low-NOx burner technology in non-cyclone boilers is capable of reducing NOx emissions rates to easily meet the subpart Da proposed limits of .15 lb/mmbtu. Gas reburn in combination with other burner and combustion controls should be considered acceptable NSPS NOx control alternatives to SCR for most or all boiler types. In any event, the Agency should not preclude the use of alternatives to SCR for coal boilers required to meet the proposed NSPS limits.
 
 
 
 

NGSA recommends an averaging period sufficiently flexible to encourage further pollution prevention.

NGSA recommends an averaging period of 1 year, consistent with the NOx standards under the Acid Rain Program and the rationale supporting that annual averaging period. The Agency should amend the proposed standards with an annual averaging period rather than making the standards themselves less stringent for the following reasons.

First, the effect of an annual averaging period as compared to the rolling 30-day average will be environmentally neutral. In principle, the mass of emissions to the environment is equivalent. Second, a longer averaging period will allow further opportunities for pollution prevention, encouraging more affected facilities to pilot a combination of innovative and conventional control technologies, as well as co-firing or switching fuels seasonally. Third, by adopting an annual averaging period, sources subject to both the new source performance standards and the Acid Rain NOx standards can streamline the record keeping and reporting aspects of both programs. For these reasons, NGSA strongly supports the principle and rationale underlying the proposed performance standards but recommends a 1-year averaging period.
 
 

We trust these comments are helpful to the Agency as the Agency proceeds in this rulemaking. If the agency requires further explanation of the issues presented in this filing or requests further information, please contact our office. We welcome your call.

^{1. 62 FR 36,952 middle column}

^{2. 62 FR 36,954; left column.}

^{3. 62 FR 36951; middle and right columns.}

^{4. Proposed 40 CFR 60.41a}

^{5. 62 FR 36,954; right column.}

^{6. 62 FR 36,952; left column.}

^{7. 61 FR 67,163; left column.}

^{8. 61 FR 67,112 - 67,164}

^{9. See also "Final Acid Rain Phase II NOx Rule: Response to Comments Document."}

This page last updated October 8, 1997.