November 30, 1998 Air and Radiation Docket and  [ nfonnationCenter ( 6102) Attention: Docket No. A 97 43 for the section 126proposal and Docket No. A 98 12 for the FIP proposal U. S. Environmental Protection Agency 401 Nl Street SW, room M 1580 Washington, DC 20460 Dear Sir/ Madame:

Attached for your consideration are the comments of the Interstate Natural Gas Association of America ( INGAA) on EPA s Federal implementation Plan to Reduce the Regional Transport of Ozone ( Docket No. A 98 12). INGAA is pleased to provide comments and is confident that EPA will carefully consider the many important elements we have raised.

We understand that EPA is preparing technical amendments to the OTAG SIP final rule and believe that many of the points raised in our comnnents here are directly related to some of those amendments. As such, INGAA is looking forward to meeting with EPA staff to discuss issues related to both the OTAG SIP CallInventory and the FIP proposal in detail, preferably prior to issuance of the technical amendments.

If you have any questions, please feel free to cantact me at 202 2165935

Sincerely,

Lisa S. Beal Director, Environmental Affairs Enclosure/

CC: D. Doniger, EPA J. Seitz, EPA INGAA EH& S Committee INTERSTATENATURAL GAS ASSOCIATION OFAMERICA 10 G STREET, N. E., SUITE: 700 WASHINGTON, D. C. 20002 202/ 216 5900FAX 202/ 216 0877 1 November 30,1998 Air and Radiation Docket and Information Center ( 6102) Attention: Docket No. A 97 43for the section 126proposal and Docket No. A 98 12for the FIP proposal U. S. E; nvironmental Protection Agency 401M Street SW, room M 1500 Washington, DC 20460 To whom it may concern:

The Interstate Natural Gas Association of America ( INGAA) is a non profit trade association representing virtually all interstate natural gas transmission pipeline companies operating in the United States and interprovincial pipelines operating in Canada, as well as natural gas companies in Mexico and Europe. INGMs U. S. members operate over 200,000 miles of pipeline and related facilities and account for over ' 90 percent of all natural gas transported and sold in interstate commerce.

INGM appreciates the opportunity to comment on the proposed Federal Implementation Plans ( FIPS) which may be needed if any State fails to revise its State Implementation Plan ( SIP) to comply with the nitrogen oxides ( NO) SIP call recently promulgated by E; PA ( 63FR57356). In general, INGAA's comments are related to the inconsistent nature of the proposed FIP Call compared with that of the finalized SIP call, the proposal of a control efficiency that is unachievable, and monitoring requirements. Specifically, INGAA has the following concerns:

0 EPA should clearly establish a distinction between small and large units that is dependent on the cutoff level specified in the fmal SIP rule of first,

2 INTERSTATE NATURAL GAS ASSOCIATION OF AMERICA 10 G STREET, N. E., SUITE 700 WASHINGTON, D. C. 20002 202/ 216 5900 FAX 2OW216 0877 250 MMBtu per hour, and second, in the absence of heat input data, greater than 1 ton per day.

EPA has failed to use ia consistent methodology to designate   large  units in the non EGU inventory.

EPA ignored information in the ACT document that indicates SCRis not a reliable control technique to achieve 90 percent reduction of NOx fi om lean burn engines in variable load applications.

EPA s control cost effectiveness and economic impact analysis are incorrect The proposed defmitiom of rich burn engineis inconsistent with existing state regulations in the 22 eastern states Grams Per Horsepower are a more appropriate expression of emissions limitations than Parts Per Million The use of CEMS or PEMS is unnecessary Specific Comments EPA should clearly establish a distinction between small and large units lhat is dependent on the cutoff level specified in the finalSIPrulemaking of first, 250 MMBtu per hour, and in the absence of heat input data, greater than 1 ton per clay second.

INGAA is very disturbed bywhat appears to be EPA s inconsistent interpretation of the Non EGU source category size cutoff determination methodology.

  When considering size cutoffs for non EGU units, the finalOTAG recommendations were at result of careful consideration of a number of factors that finally led to a designation criterion based upon horsepower.

In the finalSIP rulemaking, EPA recognized a need to continue to make a distinction between large and medium EGU units when considering inclusion of these units for emissions control and promulgated a 250 MMBtu per hour 3 and as an appropriate cutoff level for large non EGU point sources. In the fmal SIP rulemaking, EPA stated that it relied upon a capacity approach first and where capacity data was not available, a tons per day approach second. Under this methodology, if specific heat input capacity data were not available in the updated inventory, emissions reductions should have been assumed only if the units average summer day emissions were greater than one ton per day. EPA clearly intended to give sources an opportunity to provided the necessary capacity data because in the SIP call finalrule, the agency asked for additional comment that would speclfically address the emissions inventory.

hi response to the SIP prciposal, INGAA has already submitted a summary of the draft results of cumulative information from the natural gas industry that included detailed information about reciprocating engines and combustion turbines in the OTAG region. In response to EPA's most recent request, many of INGAA's individual members are gathering even more detailed and unit specific information to update the emissions inventory with specifically, the capacity data needed to niake the 250MMBtu determination.

I'NGAA is very concerned that EPA's language in the FIP call omits all reference to what should be the primary indication of size cutoff and corresponding emissions control consideration  250 MMBtu per hour. In fact, the only place were one can find any reference to the 250MMBtu cutoff is for boilers included in the trading program, not stationary combustion engines that have been excluded from the trading program.

EPA has clearly deviated from what was presented in the finalSIP call and in the FIP proposal, is attempting to establish a significantly more stringent and restrictive FIP. INGAA strongly protest to this action and urges EPA to maintain the regulatory structure it established in the final SIP rule.

4 EPA has failed to use a consistent methodology to designate " large" units in the non EGU inventory In the FIP proposal, EPA claims to have used the same methodology as that used in the SIP call to designate " large" non EGU units. The SIP call, 63 FR 57356 ( Tuesday, October 27, 19981, at 57416, explicitly set forth the five step process to be followed to designate Large sources from Small sources. Under the EtPA'salgorithm, heat capacity is first detennined either by inventory data ( step 1) or a default procedure ( step 2). Sources, withheat inputs of greater than 250 MMBtu/ hr are desibwated as Large sources and have assumed emission reductions ( step 3). Emission reductions based upon tonnage per day are assumed onlv if heat capacitv data are unavailable bv inventorv or default  data ( step 4). All other sources are considered Small ( step 5). Under this algorithm, all sources with kniown heat inputs of 250 MMBtu/ hr or less ( either by inventory or default data) are to be considered small. EPA now indicates that lhis explicit algorithm is not be followed. Now in the FIP EPA says that dividing line between Large and Small non EGU sources is to be 2400 horsepower. But the published inventory is not consistent with this interpretation nor the 250 MMBtu/ hour or even the one tonlday. In the final inventory, 1,887units in the inon EGU inventory with no capacity information are designated as " large" even. though the unit's average summer day emissions are less than one ton per day.

The proposed 2400 horsepower cutoff for reciprocating internal combustion engines is inconsistent with OTAG recommended horsepower cutoffs and inconsistent with the size cutoffs used by EPA in calculation of the SIP Call budgets. For non utility point sources, OTAG recommended that " Large" sources include reciprocating internal combustion engines equal to or larger than 8,000horsepower. In the final SIP Call inventory, EPA indicated that the Agency chose to use capacity indicators primarily to set cutoff levels. If the source was greater than 250 IMMBtu, additional emission reductions were included to calculate the state NOx budgets. Also, the proposed 2400 horsepower cutoff far reciprocating internal combustion engines is inconsistent with the OTAG recommended emissions cutoff for " Large" sources. For non5 1 utility point sources, OTAG recommended that " Large" sources include sources with 2 tons NOx emissions per average summer day or more. The 2400 horsepower cutoff is based on E; PA's assumption that sources . with NOx emissions of greater than or equal to one ton per day should be controlled.

While ECPA indicated that an applicability threshold of 2400 hp was selected because engines of that size have the potential to emit at least 1 tone per day of NOx, the applicability criterion ( doesnot recognize the fact that not all engines 2 2400 hp emit at least 1 ton per day of NOx. Many 2400 hp engines emit less than 1 ton per day of NOx. The applicability threshold of 2400 hp was selected based on EPA's use of emission factors for lean bum and rich bum engines found in the ACT document, 16.8 and 15.8g/ hp hr respectively. If EPA intends to regulate only " Large" reciprocating internal combustion engines, EPA should revise the applicability criterion to be consistent with the state budgets and EPA actions in the SIP Call rulemaloing.

The applicabilitycriterion does not recognize units that have already been controlled forNOx The proposed 2400 horsepower cutoffwould cause additional NOx controls for many more reciprocating engines than those designated " Large" in the SIP Call budgets. As proposed, the FIP would impose emission limitations and emissions monitoring requirements on allengines equal to or greater than 2400 hp within the FIP area, regardless of the unit's emissions. This would result in the imposiition of emission limitations and emissions monitoring requirements on engines that were designated " Small" in the state budgets and designated " Small" using the methodology described by EPA in the SIP Call rulemaking.

The purpose of the FIP should be to implement a program of control that would meet the promulgated NOx budgets, not to expand the program of control to other sources.

EPA must apply a consistent methodology for determining the size of a unit.

INGAA recommends that EPA consistently apply the size designation methodology used in the SIP cadl final rule.

6 EPA states that the FIP proposal is intended to achieve the NOp emissions reductiions required by the NOx SIP call rulemaking and that rulemaking docket cOnt0. s information and analyses that are relied upon in the NOx FIP proposal. gaough EPA has included by reference the entire NOx SIP call docket, the proposed rule States that the Ody portions that form the basis for the FIP mlemalking are those that address feasibility and cost effectiveness of control measures and the projection of emissions reductions that various control measures would achieve. Nevertheless, EPA s proposed FIP rule goes beyond these meas because it does not apply the same methodology described in the SIP rulemaking to designating   large  non EGU Units in the final inventory.

EPAignored information in the ACT document that indicates SCR is not a reliable: control technique to achieve 90 percent reduction of NOx from  lean burn engines in variable load applications.

AccoFding to the Technical Suppiort Document ( TSD) for Stationary Internal Combustion Engines ( VI B13 IEPA adopted SCR and 90 percent reduction as the control technique for lean bum engines based on information provided in Table 2 5of the Alternative Conlxol Techniques Document  NOx Emissions from Stationan Reciprocating Internal Combustion Engines ( EPA 453/ R

93032 ( ACTdocument):

The control level for spark ignited lean bum engines that meets the $ 2,00O/ ton criteria above, is a limit of 125 ppmv NOx at 15% 02. This represents selective catalytic reduction ( SCR) control. SCR provides the greatest NOx reduction of all technologies considered in the ACT document for lean bum engines and is capable of providing a 90 percent reduction in NOx emissions. This emission limitation corresponds to the   Expected controlled NOx emission levels  ( SCR) from Table 2 5 of the ACT document.

Table 2 5 does indicate a 90 percent reduction in NOx emissions for SCR and a footnote indicates this percent reduction is the   guaranteed NOx reduction available from most catalyst vendors.  Section <IP_ADDRESS> of the ACT states that  I emlssion reductions of 80 to 90+ percent are possible using SCR on lean bum engines that are used in baseload applications:

Based on the available information and the emission test data presented in ' Tables 5 8 and A 5, it is estimated that the achievable NOx emission reduction for SCR in gas fired applications is 80 to 90+ percent for baseload applications, with an NH, slip level of 10 ppmv or less.

However, Section <IP_ADDRESS> of , theACT states that inadequate information was available to determine achievable continuous NOx reductions and ammonia slip levels for SCR in variable load applications:

The available data are not sufficient to assess the achievable continuous NOx reductions and ammonia slip levels for SCR used invariable load applications.

Section <IP_ADDRESS> of the ACT notes that " there is also little experience with SCR in variable load applications due to ammonia injection control limitations." In addition, Section <IP_ADDRESS> states that variable load applications may pose problems for the SCR system:

The duty cycle of the engine should also be considered in determining the applicability of SCR. Exhaust temperature and NO, emission levels depend lipon engine power output, and variable load applications may cause exhaust temperature and NO, concentration swings that pose problems for the SCR system. The lower exhaust temperature at reduced power output may result in a reduced NO, reduction efficiency fkom the catalyst.

When the additional informattion presented in the ACT document is considered, along with'infomation presented in the comments provided below, it is clear that. EPA should not rely on SCR as the NOx control technique for lean burn engines in variable load appllications. SCR is not feasible for variable load 8 applications and a 90 percent reduction of NOx is not achievable using SCR on engines in variable load applications.

SCRis not feasible for variable load applications, such as natural gas compression.

The natural gas transmission industry has evaluated NOx emissions controls for hundreds of engines under NOx RACT and found that SCR is not a reliable control technique for engines in natural gas compression service ( avariable load application). State regulators have agreed  in no case is SCR required as NOlx MCT for engines in trimsmission service. Instead, NQx emissions reductions have been achieved using low emissions combustion ( LEC),

cornbustion modifications or parametric controls ( PC). These technologies are proven for natural gas fired lean burn engines, while SCR is not.

Reciprocating internal combustion engines in natural gas compression service are used to compress and move natural gas along the pipeline. An engine must respond to pipeline conditions, supply, and demand for natural gas. As a result, engines are frequently required to change load and speed conditions. This variable load operation complicates the successful operation of an SCR system given: 1) variations in NOx emissions, 2) variations in exhaust gas flow andl temperature, and 3) thermal cycling.

.1. Variations in NQx Emissions. In order for SCRto work properly, with the appropriate control of NOx emissions and without excessive ammonia emissions, it is necessary that the proportions of NOx and ammonia be correct. Changes in load and speed produce changes in the NOx emissions from the engines. For example, a load change of only five percent can significantly change the NOx emitted fi om an engine. When these changes occur, the ammonia feed system must be adjusted to maintain the proper ratio of ammonia to NOx. In Section <IP_ADDRESS>, the ACT notes that variable load can cause NOx concentration swings that pose problems for the SCR system. SCR systems traditionally use a feedback system that relies on a NOx or ammonia analyzer to adjust the 9 ammonia feed system. It takes approximately five minutes time to extract a sample and report NOx emission levels using a NOx CEMs. A recent installation of SCR at the Buckeye Pipeline station relies on a predictive emissions model ( PEMs) as the feed forward control for ammonia feed. The engines are not equipped with CEMs. INGAA understands that EPA and the South Coast Air Management District are reviewing this installation to determine if it is cost effective. At the Buckeye station, the engines were purchased new and the manufacturer designed the PEMs to control the ammonia feed system. In addition, the engines are used to drive liquid pumps and the variations in load and speed for the engines are limited by the range of operation of the pumps. In contrast, engines on a natural gas pipeline must respond to the conditions of the natural gas within the pipeline  a much wider range of operation than is required for liquid pumps like those at the Buckeye station. There are no known applications where PEMs have been successfully used as feed forward controls for existing reciprocating internal combustion engines.

 Variations in Exhaust Gas Flow and Temperature 2. Variable load conditions also result in variations in exhaust gas flow and temperature conditions. The ammonia control system would need to be adjusted to respond to ' the changes in the exhaust mass flow rate. Variable exhaust gas flow rates would also affect mixing in the catalyst. The wider the range in exhaust gas flow rates, the more difficult it is to design a catalyst that can reliably achieve high emission reductions ( e. g.,

90 percent). Reduced engine load can also decrease the exhaust gas temperature below the range for optimal NOx conversion, which would not allow the catalyst to1 reliably achieve high emission reductions.

Section <IP_ADDRESS> of the ACT states that " lower exhaust temperature at reduced power output may result in a reduced NOx reduction efficiency from the catalyst."

10  Thermal Cvcling 3.

' Variable load conditions also result in thermal cycling of the catalyst

i2S the engine exhaust temperature changes. This thermal cycling leads to reduced catalyst life.

The complications introduced Qy variable load operation have not been sufficiently resolved to ensure reliable operation of SCR on engines in variable load applications, such as natural gas compression. EPA concluded that SCR was a feasible control technology ( thatachieves 90 percent reduction of NOx)

based am a limited review of infarmation presented in the ACT document.

SCRwill not reliably achieve 90 percent reduction of NOx for variable load applications.

The TSI) indicates that EPA adopted SCR and 90 percent reduction based on vendor quotes presented in Table 2 5 of the ACT document. However, as presented in the comments above, EPA ignored other information in the ACT document that indicates SCR is not a reliable control technology to achieve 90 percent reduction of NOx for variable load applications.

The available data are not sufficient to assess the achievable continuous NOx reductions anid ammonia slip levels for SCR used in variable: load applications.

Variable load applications present unique difficulties for SCR that have not yet been adequately addressed to allow widespread application of SCR for engines in load following applications, such as natural gas compression..

In the ACT document, emission test data for six engines with SCR are presented. Results for over 30 emission tests for the six small engines are provided in the ACT document. All the engines tested are smaller than the proposed size cutoff of 2400 horsepower ( hp) proposed by EPA in the FIP. The 11 emissions data suggest that the percent NOx reduction achieved with SCR varies. Although the variability is not discussed in the ACT document, it is likelly that the variability is dlue to changes in the engine's operation. The range of effectiveness for the six engines is presented in the table below.

Engin Manufacturer Model Horsepower Number of Range of NOx Control e No. Tests Reported ( YO) 45 Clark HRA 6 660 5 84 91 47 Clark HRA 6 660 5 82 88 139 Cooper GMV 660 1* 50 Bessemer 248 Cooper GMV 8 800 9* 87 93 Bessemer 309 Clark HRA 32 350 12 65 84 357 Tecogen CM 200 29 1 2 95 97 The only engine that achieved levels greater than 90 percent for alltests conducted was a small engine designed for cogeneration ( the Tecogen). The Tecogen would be installed in a baseload application  not a load following application. Two other engines reported levels at or above 90 percent for at least one test, but levels less than 90 percent for other tests. The other engines did riot include any test results at or above 90 percent NOx reduction.

EPA adopted SCR and 90 percent reduction based on limited information presented in Table 2 5 of the ACT. However, information priesented in Section <IP_ADDRESS> of the ACT indicates that EPA was not able to determine an achievable NOx reduction level for the use of SCR in load following applications. Therefore, EPA should not use SCR and 90 percent reduction for lean burn engines in the FIP or in the state budgets for the SIP Call.

12 SCRis not a demonstrated NOx control technology for reciprocating internal combustion engines in variable load applications.

The ACT document states that " there is also little experience with SCRin variable load applications due to ammonia injection control limitations." As indicated above, the natural g, astransmission industry has evaluated NOx emissions controls for hundrelds of engines under NOx RACTand found that SCR is not a reliable control technique for engines in natural gas compression service ( avariable load applicattion).

According to a review of SCR conducted by the Gas Research Institute ( GRI) ( attadhed to these comments ais Appendix A), SCRhas been kstalled on reciprocating engines in very few instances. No natural gas fced lean bum engines were identifled by GRI in the EPA RACT/ BACT/ LAERclearinghouse with SCR controls ( based on a query of post 1991 determinations for natural gas fu ed internal combustion  15.004). RACT/ BACT/ LAER. deterrninations for lean burn engines relied on low emissions combustion ( LEC) technology, other combustion modification.( such as high energy ignition systems), or parametric controls ( such as retarded timing and airto fuel ratio adjustment).

A total of 18 diesel engines with SCR controls ( PA 0096 and PA 0097) were identitied in the clearinghouse. The SCR controls for the diesel engines reduce NOx emissions by 80 percent.

The GRI study also cites the fact that results from a 1996 survey of North American interstate natural gas transmission companies indicate that of the 599 lean burn engines with NOx controls, only two engines inthe United States have SCRinstalled. Those twa engines since have been mothballed due to difficulties operating the SCRunits in a load following application. NOx emissions from lean bum engines in pipeline service have been controlled using combustion modifications or ptmametriccontrols because of the problems associated with using SCRin the variable load application.

The information presented above indicates that SCRis not demonstrated in practice for load following applications. The information presented in the ACT 13 document is not a suMcient basis for EPA to conclude that SCR is feasible ( with 90 percent reduction) for all existing engines that would be subject to control requirements under the FIP proposal or the SIP Call. EPA should not base its FIP proposal or state budgets for the FIP and SIP Call on the use of SCR for lea& burn engines.

EPA's cost effectivenessanalysis for the use of SCR relies on 90 percent reduction of NOx, which is not feasible for load following applications.

The TSDindicates that EPA relied on Figure 2 6 of the ACT to evaluate the cost effectiveness of SCR:

As illustrated in Figure 2 6 of the ACT . .. . The cost effectiveness is about $ 800/ ton for a 2200 hp engine operated 8,000 hours per year. Therefore,

SCR meets the criteria of' less than $ 2,00O/ ton of NOx rteduction.

The cost effectivenessresults presented in the ACT document rely on 90 percent reduction of NOx. As indicated in the comments above, SCR has not been shown to reliably reduce NOx emissions by 90 percent in load following appllications. The ACT document states that although 90 percent is used for the cost effectiveness calculations in that document, EPA had insufficient infoinnation to determine " achievable continuous NOx reductions and ammonia slip levels for SCR used in variable load applications." Variable load operation pres, entsunique difficulties, including variations in NOx emissions, variations in exhaust gas flow and temperature, and thermal cycling, that have not been adequately addressed in the EPA cost analysis.

Therefore, EPA should not conclude that SCR is cost effective for all engines that would be subject to the FIP or SIP Call, since clearly EPA has not established the effectiveness or feasibility of SCR for load following applications. EPA should work with industry stakeholders to assess the cost effectiveness of NOx control techniques for reciprocating internal combustion engines.

14 Projection of Emission Reductions that Various Control Measures Would Achieve.

EP. A calculated the state budgets for the proposed FIP and the SIP Call based on the Agency's assessment that SCR can achieve 90 percent NOx reduction from lean burn reciprocating internal combustion engines. As indicated in the comments above, EPA concluded in the ACT document that, while SCR could achieve 80 to 90 percent NOx reductions for engines in baseload applications, there was insufficient information to assess achievable NOx reductions for SCR on engines in variable load applications. 90 percent reduction of NOx using SCR is not proven in practice for lean burn reciprocating engines in load

following applications.

EPA should reevaluate the emission reductions for lean burn engines based on NOx controls that are proven and are shown to be cost effective for lean burn reciprocating internal combustion engines.

The emission levels for lean bum engines cannot be achieved at a cost of $ 2,000 per ton of NOx. Based on the ACT document, EPA incorrectly concluded that SCR for lean burn engines could be implemented on a 2200 hp lean bum engine for about $ 800per ton of NOx. Industry data suggests that these costs are not correct.

While INGAA supports the 30 day rolling average, EPA should specify that emission limits are at 100% speed and 100940torque.

The attached GRI ( Appendix: A) report on the effectiveness of SCR applied to pipeline compressor engines also concludes that SCR is infeasible for pipeline compressor engines. The report documents that research data collected on internal combustion engines utilizing SCR is biased towards small engines in baseload applicationsrather than the type of units. The industry has only identified two compressor unitsthat have been tested with SCR These compressor units have been subsequently been removed & om service due to poor pelrformance. The report further concludes, as did the original ACT document 15 that SCR is not designed for load following applications. Finally the test data from the ACT document shows that the average performance of the tested engines was sigrniscantly below 90% emission reduction.

Control Cost Effectiveness and Economic Impact Analysis INGAA has examined the Regulatory Impact Analysis for the NOx SIP Call, FIP, and Section 126 Petitions, tlie Non Electricity Generating Unit Economic Impact Analysis for the NOx SIP Call and Ozone Transport Rulemaking  Non Electricity Generating Unit Cost Analysis. These documents contain cost analysis for control options jor Large Stationary IC engines. INGAA strongly believes that errors in the basic underling assumptions that support these analysis has severely distorted the conclusions reach regarding the control cost effectiveness of Large Stationary IC engine and the resultant economic impact on the natural gas transmission industry.

First, the emission inventory for IC engines category is significantly flawed regarding the number sources and their corresponding level of emissions. This directlv affects all subsequent economic analvsis using this inventory.

Second, EPA cost analysis far all control options depend on tons of NOx removed as a percentage of uncontrolled emissions. If uncontrolled emissions are significantly overstated,  whichwe believe they are in the EPA analysis, then cost effectivenessis likewise equally overstated. As stated above the ACT uses 16.8 g/ hp hr while AP 42 is 1lg/ hp hr. This difference alone could lead to und. er estimating cost by 50 percent.

Third, cost effectiveness is also affected by percentage of source utilization during the ozone season. INGAA members operate a number of IC engines at natural gas storage fields. Allthough source utilization varies widely average summer time values for IC engines with potential to exceed one ton a day are typically in the range 50 Yo or less. Thus cost effectiveness calculations for this sector could be underestimated by a factor of two from those used in EPA's cost analysis which was 91%. This fact point is confirmed by EPA's contractor 16 Pechan Avanti Group on page 57 in the September 17, 1998report entitled Ozone Transport Rulemaking Non Electricity Generating Unit Cost Analysis: There are uncertainties in the cost per ton values for IC engines because we do not know which engines are lean bum versus rich bum ( lean bum is assumed),

nor operating practices ( hours of operation and load). AJl of these factors affect control cost. Following on page 61:" For the non trading source analysis, the cost effectivenessof controls applied to IC engines are a key factor in the cost analysis.

Finally the cost for annual emissions monitoring are also significantly underestimated. In a study recently completed for the natural gas industry, the annual cost for CEM on a single IC engines is estimated as $ 107,000per year.

Thisis about two and one half times the $ 43,353 per year reported in the Regulatory Impact Analysis Report.

In summary, after the corrections noted above are made, EPA's conclusion that SCR and LEC NOx emission controls for IC engines are highly cost effective, i. e. iunder $ 2000 per ton, is in error.

The proposed definition ofrich burn engine is inconsistent with existing state regulations in the 22 eastern states.

Theproposed FIP defines rich bum engine as any engine with a lambda of 1.1 or less, based on the manufacturer's original air to fuel ratio compared to the stoichiometric air to fuel ratio. This definition has been implemented only in a few air pollution control districts in California. The Technical Support Document ( VI B 13) indicates that the California FIP rule was reviewed by EPA to develop the definitions arid control requirements for reciprocating internal combustion engines. However, the California FIP has no regulatory standing because the rule was withdrawn by EPA ( 60 FR 43468 43469), including the regulations issued on Febniary 14, 1995, but not published in the Federal Register. For the 22 eastem states, a more appropriate definition of rich burn engine is ' I a four stroke, spark ignited engine where the oxygen content in the ediaust stream before any dilution is 1% or less measured on a dry basis." Definitions based on 1% oxygen are currently used in a number of the 22 17 eastern states. None of the 22 eastern states use the California defintion of rich burn engine.

The proposed defmition of rich burn engine does not recognize that many engines that were originally considered " rich burn" have been modified so that the design and operating characteristics of the unit are akinto " lean burn"

engines.

These changes were made largely to comply with NOx emission reduction requirements. Under the proposed FIP, these engines would wrongly be considered " rich burn" since the original manufacturer's airto fuel ratio would be used.

NSCR would not be achievalde for all engines in the rich burn subcategory if this definition were adopted.

The proposed definition of rich burn engine includes engines with exhaust oxygen concentrations greater than 1 percent. Although some engines with exhaust oxygen content greater than 1 percent may be adjusted to run at levels compatible with NSCR, there are some engines that cannot be adjusted to run at such fuel rich conditions. Therefore, the proposed definition incorporates some engines for which the control technology will be infeasible for NOx control.

A lambda of 1.1 corresponds to approximately 2 percent oxygen in the exhaust.

An exhaust concentration of 2 percent would not be compatible with the use of NSCR to control NOx. In order to use NSCR as intended for NOx control, it would be necessary to adjust; the engine to run at 1 percent oxygen or less.

In order to use NSCR as intended for NOx control, it would be necessary to adjust the engine to run at 1percent oxygen or less. However, for some older models of engines, commercjially available air to fuel ratio controllers cannot ensure that the engines will operate with exhaust concentrations of 1 percent oxygen or less, at all load conditions, including low loads.

18 The definition of rich bum engine should not rely on the manufacturer's recommended air to fuel ratio.

This approach does not reflect the fact that existing engines have been rem mufactured or re constructed to convert an engine from a rich bum to a lean bum. These changes result in different air to fuel ratios khan those specified by the design of the engine manufacturer.

The definition of rich bum engine should rely on exhaust oxygen content.

Lambda is more difficult to, measure/ calculate than exhaust oxygen levels. Two air to fuel ratios are necessary to determine lambda: the stoichiometric air tofuel ratio and the manufacturer's recommended air to fuel ratio.

A definition. of rich bum engine that relies on 1 percent exhaust oxygen concentration would be appropriate for the FIP.

The oxygen content of the exhaust is easy to measure on site and determine whether an engine meets the criteria of 1 percent or less. The definition is colnsistent with the use of NSCR for NOx control, which requires that oxygen be 1 percent or less. With this definition, the use of NSCR for NOx control would be achievable for all " rich burn" engines. The definition reflects the operating conditions of the engine, not simply the conditions specitied by the manufacturer. Therefore, the definition accommodates diverse operating conditions of existing engines, which may result in an exhaust gas oxygen content different than that specified by the manufacturer. The definition also takes into account the possible re manufacture or re construction of existing engines, which may result in an exhaust gas oxygen content different than that specified by the manufacturer.

Parts Per Million versus Grams Per Horsepower Hour IIVGAA believes that the expression of the emission limitations in terms of parts per million ( ppm) is unnecessary to assure compliance with seasonal tons of emissions and is inconsistent with the seasonal tonnage budgets. Tonnage limits would be more appropriate, especially for engines and turbines. If tonnage is not 19 acceptable, then grams per horsepower hour is more meaningful in the case of internal combustion engines.

Emissions Trading Program The: Use of CEMS or PEMS is Unnecessary While, INGAA supports the use of Parametric Emissions Monitoring Systems ( PEIMS) for sources to opt into an emissions trading program, the proposed use of CFR Part 60 requirements of continuous emissions monitoring ( CEMs) or PEMs under seasonal tonnage limits is overly burdensome to assure compliance for IC engines. Part 60 requires relative accuracy ( RA) of 20 percent.

At the proposed control levell of 125 ppm, this would mean a RA of 25 ppm. Tesiting of IC engines has established that this 20 percent FWactually represents 7 percent error in actual accuracy or 9 ppm. Contrast this to utility boilers where NOx concentrations are in the thousands of ppm. For these sources the actual errors allowed would be greater than 100 ppm.

Also, the use of CEMs or PEMs is inappropriate for compliance with a seasonal tonnage limit. The IC source category accounts for only a small ii actionof the total SIP Call region emissions. Requiring Part 60 level of accuracy is not justified to meet the overall budget goals.

EPA should allow the use of the same monitoring on IC engines as it uses in its Title V operating permit program In the proposed FIP, EPA indicated that the emission limitations will be considered applicable requirements and must be incorporated into Title V operating permits. If only " Large" sources are regulated by the FIP, then those sources would be considered major sources under Title V and required to obtain a Title V permit. Therefore, appropriate monitoring may be determined as a part of the Title V permitting process. The requirement to use CEMs in the proposed FIP is inconsistent with the flexibility that EPA has incorporated in the Agency's guidance on periodic monitoring and compliance assurance monitoring ( CAM). The FIP should preserve the flexibility to allow sources and 20 I'

Title V permitting authorities tc, determine the most appropriate monitoring to ensure compliance.

The FIP should not dictate cont. inuous emissions monitoring for reciprocating internal combustion engines that do not participate in the emissions trading program. The FIP should require that sources and Title V permitting authorities determine the most appropriate monitoring to ensure compliance when the emission limitations are incorporated into the source's Title V permit.

In the final SIP Call rulemaking, EPA did not require continuous emissions monitoring for non EGU units ithat would not participate in the NOx trading program. Rather, 51.121( i) only required continuous emissions monitoring for units serving electric generators with a nameplate capacity greater than 25 MWe or boilers, combustion turbines, or combined cycle units with a maximum design heat input greater than 250 mmBtu/ hr. The FIP should include the same flexibility with regards to monitoring as the requirements for the SIP Call.

For noln trading sources, the piurpose of monitoring is to demonstrate compliance with a NOx emissicin limitation. EPA has issued guidance for CAM and periodic monitoring that alllow sources and permitting authorities discretion to determine the most appropriate monitoring requirements to ensure compliancewith applicable requirements. However, EPA's approach under the FIP is inconsistent with the Agency's policy that compliance can be determined through monitoring other than continuous emissions monitoring.

EPA n. eedsto clarifs the differences between 98.4 compliance determination and 98.5( b) reporting requirements.

In 98. a4 of the proposed FIP, EPA indicates that reciprocating internal combustion engines must dem. onstratecompliance through the use of continuous ehssions monitors, pursuant to 40 CFR 60. In 98.5( b), however, EPA includes monitoring requirements that indicate a source must operate a CEMs which meets the applicaible requirements of 40 CFR part 60, subpart A or alternate calculational and recordkeeping procedures based upon actual 21 emissions testing and correlations with operating parameters. It is unclear why the requirements of 98.4 and 98.5 are not the same. In the find rule, EPA should incorporate the flexibility included in 98.5 into the compliance determination requirements under 98.4. In addition, EPA should incorporate add. itional flexibility that would be consistent with the principles for periodic monitoring and CAM. EPA should not impose additional monitoring requirements under 98.5 beyond those requirements included in 98.4 to determine compliance.

Allocation ofAllowances INGAA has been a long and ardent supporter of an output based allocation of dl6wances in the NOx trading system for large stationary sources under the FIF. INGAA is encouraged by EPA's apparent recognition of the value an output based system may bring to the proposed trading program. INGAA is an active member of the Coalition for Gas Based Environmental Solutions which is submitting comments on reLgarding this subject. INGAA fiilly supports and concurs with the comments of the Coalition which have been attached at Appendix B INGAA appreciates the opportunity to comment on this proposal and looks forward to working with EPA in the future. If you have any questions or need clarification, please feel free to contact me at 202 216 5935.

Sincerely,

Lisa S. Bed Director, Environmental Afbirs 22 Appendix A Gats Research Institute Technical Issues Related to the Potential Use of Selective Catalytic Reduction ( SCR) to Reduce NOx Emissions from Natural Gas FiredLean Bum Engines 23 Technical IssuesRelated to the Potential Use of Selective Catalytic Reduction ( SCR) to Reduce NOx Emissions frolm Natural Gas Fired Lean Burn Engines Prepared by: Coerr Emironmental Corporation and Radian International, LLC Prepared for: Gas Research Institute November 9, 1998 24 Table ofContents I. Introduction .......................................................................... 1 I1. Overview of SCR Technologg.................................................. 2 III. Basis for EPA's Concllusion that SCR is Effective .................... 3 Iv. SCR Installations on Lean BurnEngines ................................ 7 Difficulties Operating SCR Systems on Load FollowhgApplications9 Negative Environmental Impacts from SCR ................................ 12 VII. Conclusions ......................................................................... 13 25 I. INTRODUCTION On October 27, 1998 ( 63FR 57356), EPA promulgated the Agency's rulemaking to call for 22 eastern states and the District of Columbia to revise their State Implementation Plans ( SIP) to address the regional transport of ozone ( the SIP Call). EPA also proposed a Federal Implementation Plan ( FIP) that would be implemented if any state failed to subm. it an adequate SIP revision in response to the EPA SIP Call ( 63FR 56394).

In a technical support document for both rulemakings ( A 96 56, VI B 13),

EPA stated that emissions of nitrogen oxides ( NOx) from large lean burn reciprocating internal combustion engines can be reduced by 90 percent,

cost effectively, using Selective Catalytic Reduction ( SCR):

The control level for spark ignited lean burn engines that meets the $ 2,00O/ ton criteria . . . is a limit of 125 ppmv NOx at 15% 0,. This represents selective: catalytic reduction ( SCR) control . . . providing a 90 percent reduction in NOx emissions.

The Agency stated in the SIP Call rulemaking that 90 percent control with SCR was adopted based on information presented in the Alternative Control Techiaues Document  NOx Emissions from Station Reciprocating Internal Combustion Engines ( EPA 453/ R 93 0321 ( ACTdocument):

For [ reciprocating internal combustion engines], EPA determined based on the relevant ACT document, that post combustion controls are available that would achieve a 90 percent reduction from uncontrolled levels . . . . ( 63FR 57418)

EPA. used 90 percent control for large reciprocating internal combustion engines to calculate the state NOx budgets for the SIP Call and the FIP. In the FIP, IEPA also proposed an emission limitation of 125 ppmv for natural gas fired lean burn engines based on 90 percent control of NOx using SCR.

The Gas Research Institute ( GFLI) presents in this white paper an assessment of the technical issues related to the potential use of SCR to reduce NOx emissions from natural gas fired lean burn engines and the reasonableness of the EPAs estimate of a 90 percent reduction of NOx emissions from lean

burn engines using SCR. GRI intends to continue investigating NOx control techniqu. es for natural gas lean bum engines and NOx emissions monitoring techniques. This white paper includes information on SCR that could be assembled prior to the November 30 deadline for comments on the proposed FIP.

Overview ofSCR Technology SCR was developed to reduce NOx emissions from fossil fuel fired boilers. In the early to mid 1980s, SCR was applied to cogeneration gas turbine engines and reciprocating internal com bustionengines.

NOx reduction with SCR is based on the reaction of ammonia and NOx to form nitrogen and water. SCR uses a catalyst to promote the ammonia and NOx reaction. In the absence of a catalyst, the reducing reactions occur in the range of 1000 ° C. As the temperature is increased above the 1000 ° C range, the ammonia oxidizes to NO, thereby increasing the NOx emissions and as the temperature is decreased below the optimum range, unreacted ammonia is emitted from the system. When a catalyst is added, the ammonia and NOx react at temperatures significantlylower than those obtained without the catalyst.

The essential components of the SCR system are: SCR catalyst Exhaust ducting and SCR housing Ammonia system 2 Control system and coiitinuous emissions monitors ( CEMs)

Traditional SCR catalysts are base metal catalysts composed of vanadium pentoxjde, titanium dioxide, or tungsten trioxide. The temperature range for the base metal SCR catalysts for NOx conversions greater than 80 percent is about 300 to 425 ° C. During the 1980szeolite SCR catalysts were developed.

These catalysts have a wider temperature operating range md offer more resistance to sulfur poisoning, which has been a problem with some of the other SCR catalysts. The SCRprocess requires about two to three times the catalyst size of that required for oxidation exhaust catalysts ( such as used for CO control), since SCR space velocities are low compared to those required for other post combustion catalybc controls. Typically, 2 to 3 catalyst stages are required in the SCR system.

SCR requires on site storage of ammonia and an ammonia delivery system.

The ammonia system includes the ammonia storage tank, the ammonia flow regulation system, and the ammonia injectors. Heaters are required to vaporize the ammonia. The type of vaporization system used depends on the type off ammonia used  anhydrous or aqueous  and on the ambient temperature range experienced at the site. In order for SCR to work, the ammonia must be fully vaporized and evenly dispersed across the face of the catalyst.

The arnmonia control system generally includes NOx CEMs upstream and downstream of the SCR catallyst. The ammonia flow rate required is based on a preset ammonia to NOx ratio and determined from a measurement of the inlet SCR NOx concentration and fi om determination of the exhaust flow rate of the engine. System performance is checked by measuring the outlet SCR NOx concentration.

The exhaust gas samples are conditioned ( e. g., dried and filtered) and are pumped to the NOx analyzer. Typically, the NOx analyzer is cycled between the inlet = andoutlet of the SCR unit. Generally this type of system requires a response time of approximately five minutes to obtain an accurate, stable reading of the NOx concentrations.

Basis for EPA's Conclusion that SCR is Effective EPA used information found in the ACT document as the basis for use of 90 percent NOx reduction in the SIP Call and FIP rulemakings. In the technical support document for stationaqr internal combustion engines ( A 96 56, VI

B 13), EPA stated that 90 perceint effectiveness for the use of SCR on natural gas fired ' lean bum engines was adopted based on the " achievableNOx reduction" presented in Table 2 5 of the ACT document. Table 2 5 is reproduced below.

4 TABLE 2 5. EXPECTED RANGE OF NO, EMISSION REDUCTIONS AND CONTROLLED EMISSION LEVELS FOR CONTROL TECHNIQUES APPLIED TO LEAN BURN SI ENGINES [ NATURAL GAS FUEL)

Control Average uncontrolled NO, emission level" Achievable Expected controlled NOx emission levels technique NO, reduction, YO  g/ hp hr Ppmv g/ hp hr ppmv AF 16.8 1,230 5  30 11.8  16.0 860  1,170 IR 16.8 1,230 0  20 13.4  16.8 980  1,260 AF + IR 16.8 1,230 20  40 10.1  13.4 740  980 SCR 16.8 1,230 90" 1.7 125  LE I 16.8 I 1,230 87 2.0' 150 _ I The uncontrolled emission rate shown is a representative average for lean bum SI engines. The actual uncontrolled emission rate will vary from engine to engine. bGuaranteedNO, reduction available from most catalyst vendors. ' Guaranteed controlled NO, emission level available from engine manufacturers.

Footnote " b" to Table 2 5 indicates that the basis for the 90 percent reduction for SCR is based om the " guaranteed NOx reduction available from most catalyst vendors." Section 2 the ACT does not include a detailed discussion of the information provided by the vendors to support the claims for 90 percent reduction or the long term performance for SCR Section <IP_ADDRESS> of the ACT provides further discussion of the achievable emission reduction using SCR. In that section, the ACT states that emission reductions of 80 to 90+ percent is possible using SCR on engines in baseload applications: Based on the available information and the emission test data presented in Tables 5 8 and A 5, it is estimated that the achievable NOx emission reduction for SCR in gas fired applications is 80 to 90+ percent for baseload applications, with an NH, slip level of 10 ppmv or less.

The: ACT states that 90 percent NOx reduction was used in Chapter 6 to calculate controlled NOx emission levels and cost effectiveness. However, the ACT also states that inadequate information was available to determine achdevable continuous NCbx reductions and ammonia slip levels for SCR in variable load applications:

The available data are not sufficient to assess the achievable continuous NOx reductions and ammonia slip levels for SCR used in variable load applications.

As : indicated in Section V of this paper, variable load applications present unique difficulties for SCR that have not yet been adequately addressed to allow widespread application of SCR for engines in load following applications, such as natural gas compression.

In the ACT there is emissions test information for 6 reciprocating internal combustion engines, 3 Clark engines, 2 Cooper Bessemer engines, and 1 . Tecogen engine. The engines range in size from 291 to 800 horsepower. All the engines are smaller thian the engine horsepower EPA adopted in the FIP ( 2400hp). A total of 34 eimission test results are provided in the ACT that report NOx emission reductions. Two emission test results report zero NOx emission reductions. The emission results presented were drawn from emission tests conducted in California from 1986  1992. Two Clark engines and the Tecogen engine were stillin service at the time the ACT document was published. The other three SCR units had been removed from service or the engines had been replaced with electric units. The ACT document stated tha. t emissions test data fior existing installations with SCR ranged from 65 to 95 percent reduction. According to the technical support document, EPA calculated the expected control1e: d NOx emission level ais 1.7 g/ hp hr ( 125ppmv) based on an average uncontrolled NOx emission level of 16.8 g/ hp hr ( 1230 ppmv) and 90 percent reduction of NOx using SCR. However, the emissions data in the ACT document suggests that the percent NOx reduction achieved by engines varies. No explanation is provided in the ACT document for the variability of the SCR effectiveness. No infoimation is provided on the operating conditioins of the engines when tested. Also, no information is provided on ammonia emissions ( i. e., ammonia slip) from the units. The range of effectiveness reported for the 6 engines is presented in the table below.

Engin Manufacturer Model I Horsepowe I Number of I Range of NOx  e No. r Tests ControlReported (%) 45 Clark HRA 6 660 5 84 91 __ __ 47 Clark HRA 6 660 5 82 88 139 Cooper GMV 660 1* 50 Bessemer ~ ~ ~~~

248 Cooper GMV 8 800 9* 87 93 Bessemer 309 Clark HRA 350 12 65 84 32 357 Tecogen CM 29 1 2 95 97 I I200 I I a ) ne additional test was conducted, where zero emission reduction was reported. No explanation is provided in the report for those results.

Only one engine, the Tecogen, ireported levels greater than 90 percent for all tests conducted. This small engine is designed to be used for cogeneration.

Two other engines ( Nos. 45 and 248) reported levels at or above 90 percent for at least one test, but levels less than 90 percent for other tests. The other engines did not include any test results at or above 90 percent NOx reduction.

The emissions data included ini the ACT document for natural gas fired lean bum engines demonstrate that the effectiveness of SCR systems are variable.

7 The ACT document does not discuss or explain the variable emissions results and does not identlfy the factors that would contribute to this variability. Only the small cogeneration engine consistently reported emission reductions greater than 90 percent. The other engines did not Consistently achieve emission reductions at or above 90 percent. As indicated in the ACT document, the 90 percent reduction presented by EPA in the SIP and FIP was based on information presented in Table 2 5. However, information presented1 in Section <IP_ADDRESS> indicates that EPA was not able to determine an achievable NOx reduction level for the use of SCR in load following applications.

SCR Installations on Lean Burn Engines There is limited operating experience to date with the use of SCR on reciproca. tinginternal combustion engines. At the time the ACT document was published, EPA identified a. total of 23 engines ( including 3 engines using digester gas) with lean burn engines in the United States based on information provided by catalyst vendors and approximately 40 installations of SCR overseas. The ACT document also noted that there is little experience with SCE in variable load applications due to ammonia injection control limitations.

At present, no natural gas fired lean burn engines were identified in the EPA RACT/ BACT/ LAER clearinghouse with SCR controls ( Queryof 15.004, post 1991). HACT/ BACT/ LAER determinations for lean burn engines have relied on low emissions combustion ( LEC) technology, other combustion modification ( such as high energy ignition systems), or parametric controls ( such as retarded timing and alir to fuel ratio adjustment). A total of 18 diesel engines with SCR controls ( PA 0096 and PA 0097) were identified in the clearinghouse. The SCR colntrols for the diesel engines reduce NOx emissions by 80 percent.

8 For the natural gas transmission industry, there are no hown SCR installations on lean burn engines in pipeline service. Two lean bum engines at a natural gas storage facility in California have SCR. These engines have been mothballed due to the operations and maintenance prob1e: msrelated to the use of SCR with the variable loads experienced in the naturatl gas storage operation. The engines are not used presently.

Therefore, there are no engines in pipeline service within the United States at this tirne that have SCR installed. The two engines in California where SCR was installed have been mothballed and are not currently in use.

In 1996, the natural gas transmission industry conducted a survey to gather information on the reciprocating engines and turbines in natural gas transmission service. The transmission companies provided information on over 5,000 reciprocating inteirnal combustion engines. As a part of the survey, information was provided on over 800 reciprocating internal combustion engines with some form of NOx emission controls in place. The survey results indicate that tlhe natural gas transmission industry has installed technology that relies on combustion modification or parametric controls to reduce NOx emisstionsfrom lean bum engines, rather than post

combustion controls, such as SCR. Only 2 of the 599 lean bum engines with NOx controls have SCR listalled ( the California units). For natural gas transmission, SCR is the NOrr control technique that has been used least to reduce emissions from lean burn engines. Low emissions combustion ( LEC)

or other combustion or parametric control techniques have been used most often to reduce NOx emissions from lean bum engines. In contrast, for rich

burn engines, post combustion catalytic control ( non selectivecataly hc reduction  NSCR) is the NOx control technique that has been used most often to reduce NOx emissions. The transmission industry survey indicates that 100 of 201 rich bum engines with NOx controls have NSCR installed. The results of the industry survey are presented below. ban Burn Engines qpe of Control In SIP Call Not in SIP Call Total Units States States Low Emissions Combustion High Energy Ignition Other NOx Control Parametric Controls SCR Total 245 139 384 87 21 108 49 13 62 39 4 43 0 2* 2* 371 179 599 * Possible conversion to lean bum conversion. Data for these engines are under review.

The survey results include NOx controls that were installed by natural gas transmission companies to comply with NOx RACT and BACT requirements.

No natural gas transmission company was required to install SCR as NOx RACT or BACT. Although some companies did consider SCR as a potential control option, SCR was found to be unacceptable due to the limits of the ammonia delivery system and the need for load following horsepower to respond to pipeline conditions. ( More discussion of this issue is included in the following section of this white paper.)

Therefore, while NSCR is widely applied for natural gas fired rich burn engines, there are very few instances where SCR has been applied to natural gas fired lean burn engines. State air regulatory agencies did not require 10 SCR to implement NOx RACT or BACT requirements. At present, there are no engines in the natural gas transmission industry that are operating with SCR. Rather, combustion modification and parametric controls have been the techniques applied to reduce NOx emissions from existing lean burn engines.

Difficulties Operating SCR Systems The following issues must be considered in the context of NOx control with SCR Variable load operation Ammonia handling and storage Catalyst maintenance arid disposal Engine maintenance Continuous emissions monitoring Variable load operation complicates the successful operation of an SCR system given:

1) variations in NOx emissions, 2) variations in exhaust gas flow and temperature, and 3) thermal cycling.

In order for SCR to work properly, with the appropriate control of NOx emissions and without excessive ammonia emissions, it is necessary that the proportions of NOx and ammonia be correct. Reciprocating internal combustion engines in natural gas transmission service are used to compress and move natural gas along the pipeline. The load and speed of the engines must respond to pipeline conditions, supply, and demand for natural gas. As a result, engines are frequently required to change load and speed conditions. These changes produce changes in the NOx emissions from the engines. For examplie, a load change of only 5 percent can significantly change the NOx emitted from an engine  for some engines NOx can increase as much as 50 piercent. When these changes occur, the 11 ammonia feed system must be adjusted to maintain the proper ratio of ammonia to NOx. In Section <IP_ADDRESS>, the ACT notes that variable load can cause NOx concentration swings that pose problems for the SCR system.

SCR systems traditionally use a feedback system that relies on a NOx or ammonia analyzer to adjust the ammonia feed system. It takes approximately 5 minutes time to extract a sample and report NOx emission levels using a NOx CEMs. Therefore, for load  allowing applications, a feedback system is not sufficient alone to allow the ammonia feed system to be adequately responsive to maintain NOx reductions. Some load following engines may be able to use SCR if the systems incorporate feed forward controls. The feed forward controls incorporate sophisticated predictive emissions models ( PEMs), which estimate NOx and adjust the ammonia feed system accordingly. A recent installation of SCR at the Buckeye Pipeline station uses PEMs as the feed forward controls for an SCR with new Waukesha engines. For existing engines, no applications are known where PEMs have been successfully used as feed forward controls for SCR. One reason that the feed fomard system may not have been applied to existing engines is the need to develop a sophisticated predictive emissions model to estimate NOx. For new engines, engine manufacturers have information readily available to develop the: PEMs. However, for existing engines, the owner or operator would have to independently develop a PEMs that would be sophisticated enough to reliably control the ammonia feed system. The engines at the Buckeye Pipeline station also represent a load following application with a limited range of operating conditions since the engines are used to drive liquid pumps. For natural gas transmission, the engines are used to compress gas along the pipeline and the pipeline conditions create a wider ratnge of operating conditions for the load following engines. The Buckeye Pipeline station experienced difficulties with catalyst masking when lube oil residuals were deposited on the catalysts during frequent start up tests. For natural gas transrnlssion service, engines often experience 12 frequent start ups, which may lead to catalyst masking, as experienced at Buckeye.

Variable load conditions also result in variations in exhaust gas flow and temperature conditions. The imonia control system would need to be adjusted to respond to the changes in the exhaust mass flow rate ( especially dual shaft engines). Variable exhaust gas flow rates would also affect mixing in the catalyst. The wider the range in exhaust gas flow rates velocities, the more difficult it is to design a catalyst that can reliably achieve high emission reductions ( e. g., 90 percent). Reduced engine load can also decrease the exhaust gas temperature below the range for optimal NOx conversion, which would not allow the catalyst to reliably achieve high emission reductions.

Section <IP_ADDRESS> of the ACT states that   lower exhaust temperature at reduced power output may result in a reduced NOx reduction efficiency from the catalyst.  Variable load conditions also result in thermal cycling of the catalyst, which leads to reduced catalyst life. These variable load conditions are cornmon for engines in natural gas transmission service.

As indilcated in the EPA ACT document, there is little experience using SCR systems on engines in load following applications, such as natural gas transmission. Although catalyst vendors suggest that SCR can be designed to work in load following applications, installations of SCR systems on load

following applications have been limited. The results of the 1996 survey of natural gas transmission companies were queried to identify SCR installations. Based on that search, only two engines have SCR installed and those engines have been mothballed.

The continuous and reliable operation of an SCR system requires close monitoring of several subsystems. This includes ammonia storage, control, metering, injection, and leak detection systems. Problems can occur with the clogging of the ammonia inozzles and these have to be closely monitored and corrective action taken immediately to ensure proper injection rates and even distribution of ammonia in the flue gas for proper mixing. In addition,

most SCRsystems rely on CEMs as the feedback control for the ammonia feed system. In order to ensure reliable performance, NOx CEMs, including sample conditioning, need to be properly calibrated and maintained, which requires specially trained personnel. Finally, instrumentation for ammonia injection rate needs to be calibrated frequently to ensure proper control.

These activities become difficult if the station is unmanned, which is often the case in pipeline operation.

Maintenance of the SCR system requires periodic catalyst cleaning in order to restore its reactivity. Cleimbg is accomplished by washing of the catalyst with water and typically requires several days downtime for removal of the catalyst, the washing and the re installation of the catalyst. Disposal of the solution remaining from this procedure can be an issue. Contaminants from lube oil and engine wear, such as metals or silicon oxides, will affect the frequency of catalyst cleaning and can reduce catalyst effectiveness and catalyst life. To minimize contamination, specially formulated lubricating oils must be used. For four stroke engines, the use of low contaminant lube oil may result in increased valve wear. The vendor generally handles disposal of SCRcatalysts.

Most SCR systems rely on continuous emissions monitors ( CEMs) as the feedback contxol for the ammonia feed system. The installation, operation and : maintenance of a NOx CEMs are complicated and require specially trainled personnel.

14 Negative Environmental Impacts from SCR I SCR relies on the use of ammonia injected in the exhaust stream in the presence of a catalyst to control NOx emissions. Ammonia is a colorless gas wiith a pungent odor. Ammonia is poisonous if inhaled in great quantities and is irritating to the eyes, nose, and throat in lesser amounts. Ammonia is explosive when mixed with air in certain proportions ( approximately one volume of ammonia to two volumes of air).

Unlike technology like combustion modifications or parametric controls ( which is used on engines in natural gas transmission service), SCR is not a pollution prevention technique and uses additional resources,

which in turn create safety hazards and hazardous waste disposal prob1e: ms. For example, periodic cleaning of the catalyst is required to maintain catalyst effectiveness. After cleaning, the cleaning solution is considered a hazardous waste and creates disposal problems.

Additionally, catalyst disposall itself can create environmental problems because the catalyst may contain heavy metals and other toxic substances.

SCRsystems usually operate: with an ammonia/ NOx molar ratio of about 1.0. This is close to the theoretical limit required for complete NOx reduction. However, due to kinetic limitations and improper mixing between the ammonia and the flue gas, complete reduction is not achieved, leading to unreacted ammonia escaping into the atmosphere.

Increasing the ammonia injection rate to overcome deleterious kinetic and mixing effects increases the probability of NOx reduction, but also increases ammonia slip emissions. To achieve high NOx reduction efficiencies consistently, SCF: systems typically operate with a relative excess of ammonia, resulting in ammonia slip emissions. This issue creates a potential for an increase in ammonia emissions into the 15 atmosphere, which is further exacerbated by ammonia flow difficulties associated with variable load operation.

There are safety concerns associated with accidental spills of ammonia.

At low concentrations, ammonia can cause health effects and can be a nuisance due to its objectionable odor. At high concentrations, it is a toxic compound and a fire hazard. Safety hazards can occur if the ammonia is spilled or there are leaks from ammonia storage vessels.

Safety hazards can be reduced if aqueous ammonia or urea is used.

However, because water becomes saturated at about 25 percent ammonia by weight, aqueous ammonia tanks must be four times larger than anhydrous ammonia tanks for the same application. Consequently,

the cost of storage tanks and transportation costs for aqueous ammonia will be greater than if anhydrous ammonia were used. If a concentrated aqueous solution of urea is used, the urea tank must be heated to avoid re crystallization of the urea. The corrosive nature of ammonia leads to failure of piping and other components. Additionally suspended rust particlles often clog filters and ammonia injection nozzles requiring more fi equent cleaning or replacement of equipment.

Storing and using ammonia in quantities above the thresholds specified in the RMP rule may create situations where the facility has to comply with the provisions of 40 CFlR part 68 as well.

ConcXusions As presented in this paper, 90 percent reduction of NOx emissions from lean burn reciprocating internal combustion engines using SCR is not demoinstrated in practice. Although catalyst vendors indicated to EPA that 90 percent reduction typically would be achievable for gas fired applications, the emissions data presented in the ACT document suggests that NOx reduction varies for engines with SCR. Also, the ACT states that insufficient data were available to estimate achievable NOx 16 reduction levels for the use of SCR in variable load applications, such as natural gas transmission. Since engine operation can significantly affect partmeters that affect SCR performance ( such as NOx emission levels,

exhaust gas flow and exhaust gas temperature), SCR systems would rieeld to be evaluated over the full range of engine operations to determine achievable NOx control levels. Load following applications, such as natural gas compression, present unique difficulties for SCR systems,

which were not fully addressed by EPA in determining the applicability of SCIZ or the 90 percent effectiveness. Also, EPAs assessment of the cost

effectiveness of SCR did not include costs that would be incurred for variable load applications, including costs to develop a forward feed PEM and costs that result from vendors " over engineering" the SCR system to try to offset reduced NOx control efficiencies.

SCR has been installed on reciprocating internal combustion engines in very few instances. Of the 599 lean bum engines with NOx controls that.

were included in a survey of natural gas transmission companies, only two engines in the United States have SCR installed and those engines have been mothballed due: to difficulties operating the SCR units in a load following application., Instead, because of the problems associated witln using SCR in variable load applications, NOx emissions from lean

burn engines in pipeline service have been controlled using combustion modification or parametric controls.

17 Appendix B COMMENTS OF THE COALITION FOR GAS BASIED ENVIRONMENTAL SOLUTIONS ON THE FEDERAL IMPLEMENTATION PLAN TO REDUCE THE EtEGIOMAL TRANSPORT OF OZONE 18 Joel Bluestein Director 1655 North Fort Myer Drive Suite 600, Arlington, VA 22209 703 528 1900  FAX 703 528 5106 COALITIONFOR 6AS BASED COMMENTS OF THE. COALITION FOR GAS BASED ENVIRONMENTAL SOLUTIONS ON THE FEDERAL IMPLEMENTATION PLAN TO REDUCE THE : REGIONALTRANSPORT OF OZONE The Coalition for Gas Based Environmental Solutions is a group of natural gas producers, pipelines and distribution companies formed to prom. ote environmental regulation that recognizes and encourages the use of low emitting, high efificiency fuels and technologies. The Coalition is pleased to have this opportunity to comment on the   Federal Implementation Plan to Redluce the Regional Transport of Ozone.  The Coalition s comments focus on the allocation of allowances in the NO, trading system that EPA would implement for large stationary sources under the FIP. The Coalitioln strongly supports output based allocation as part of the trading program and urges the EPA to adopt options 2 or 3 presented in the FIP proposal. In addition, this letter presents some specific recommendations for improving the proposed output based allocation system, in particular more equitable and appropriate treatment of cogeneration facilities.

The allocation of allowances in the trading program represents the annutal distribution of a large amount of money. If NO, allowances are worUi $ 3000/ ton, the allocation will distribute over $ 1.5 billion worth of allowances to affected sources each year. In a competitive electric market, this value will affect the utilization of generating assets. If allowances are distributed lbased on historical emissions or heat input, they will subsidize and incentivize higher emissions and higher energy consumption. Only an output based allocation provides the correct signal by rewarding sources that produce the greatest output with the lowest energy consumption and emissions.

The IEPA has begun to suggest that it understands the value of output based allocation. In addition to providing the output based options 2 and 3in the FIP, EPA recently promulgated output based New Source Perfctrmance Standards for NO, emissions from large boilers. In the preamble to that rule as in the SIP call, EPA discussed the advantages of output based regulation. The Coalition applauds the EPA s support for output based allocation.

19 The greatest barrier to output based regulation in the FIP at this time seems to be a perceived lack of data to use in making the allocations. The EPA has committed to a process to develop monitoring programs thait will clearly provide the data to support output based allocations. These data are expected to be available within a few years, so the real issue at this time is how to do the allocations for 2003 and 2004 with the available data. After that time, detailed data should be available to do the allocations.

If we expect to be moving to output based allocation within a few years, it seems a waste of effort to develop an input based program for 2003 and 2004, only to immediately begin developing an output based program. This is even more true whien we consider that the data required and avatilable for the first years of an input based program are not very different from those for an output based program. The Coalition therefore urges the EPA to adopt an output based allocation methodology such as option 2 or 3 for the final FIP. Some specific recommendations on the methodology follovr.

These recommendations ffocus on the electric generating sector. Although the Coalition supports the use of output based allocation for all sources, the value of output based allocation for industrial boilers is too small given the type of data available at this time and the effort involved. We suggest that the EPA focus on electric generators initially and bring in the industrial boilers in a few years as the improved monitoring data become available.

._ Output based allocation to utility boilers The EPA approach to calculation of output for these units is to use heat input data from the acid rain CEMs and apply a heat rate to calculate output. This is not unreasonable as a short term solution. There will be some difficulty matching boilers to CEMs to generators, but that can be dealt with. The Coalition does recommend the use of ELA Form 767 as a source of heat rate data rather than Form 860 as proposed by EPA. Form 767 tracks heat input and power generation on a monthly basis and is a more accurate, complete and reliable source of heat rate than Form 860. For that matter, Fonn 767 would be a more reliable source of output data than the approach suggested by EPA since the measurement of output ( and for that matter input) as specified by Form 767 is more accurate than the estimation method used to calculate heat input for acid rain CEM purposes. However, the approach suggested by EPA is adequate and may be more attractive to EPA since involves less reliance on outside data sources. Finally, many states may require sources to provide heat iriput data which the EF A could use in making the allocations.

20 Output based allocation to non utilitv electric generators This is a more difficult case since EPA has no direct access to data on either input or output for NUGs at this time. The proposed approach is again to multiply heat input times a heat rate. Although the FIP states that heat input data from EIA Form 867 were used, this is apparently an error since lhese data are confidential at this time. Instead, it appears that EPA used heat input data frcbm the 2007 IPM forecast, backcast to 1995. For he: atrates, the EPA suggests using generic values for different equipment types since specific data are not available. The Coalition suggests several possible improvements: IPM has specific heat rate values for many non utility generators. These could be used instead of the generic values.

Better still, if EPA is going to use IPM data, simply use the IPM generation forecast and backcast to 1995. This is probably more accurate than the proposed approach.

Again, many states require non utility generators to provide data on heat input which the EPA could use instead of the IPM data. It could then use either specific heat rate data or the generic values to calculate generation.

Cogeneration Cogeneration, also known as combined heat and power,

has been recognized as a high efficiency generation technique that can make a significant contribution to national environmental and energy efficiencygoals. President Clinton is on record supporting expanded use of CHI? as an economically beneficial strategy to address energy, environmental, and global climate change challenges. In response, the U. S. Department of Energy has initiated a CHI? Challenge program that seeks to address barriers to expanded deployment of CHP in the marketplace. EPA s Atmosplheric Pollution Prevention Division ( APPD) has supported DOE SCHP Challenge program, particularly in the area of identifymg and addressing regulatory impacts on cogeneration.

A Cogeneration facility provides both electric and thermal energy at a combined efficiency higher dhan normal separate generation of them output. Because it is providing both thermal and electric output, however, it consumes more energy per kwh thana standard electric generator. The basic approatch to output based allocation for cogeneration facilities should be to allocate them allowances equivalent to those allocated for conventional separate generation of the same output. In the hlly developed output based allocation system, this is straightforward: The thermal and electric output are measured and the facility receives its proportional share of the allowance pool for electric and thermal generation respectively.

The proposed output based allocation in the FIP does not recognize cogeneration and in fact perializes cogeneration facilities because it gives 21 them the same credit as simple electric generators, even though they must consume more energy in order to provide useful thermal energy. The EPA should remedy this oversight by allocating allowances to cogeneration facilities for thermal and electric output. This should be done by using generic techniology specific factors similar to those proposed for heat rate. Specifically, the EPA should calculate the thermal output of cogeneration facilities by using the following generic power to heat ratios.

Recommended Power to HeatRatios for Cogeneration Facilities Power to Heat System mpe Steam Turbine Simple Cycle Combustion .

Turbine RUtio 0.2 0.5 1IO 1.75 Combined Cycle I. C. Engine The electric output should ' be divided by the power to heat ratio and converted from kwh to MMI3tu thermal output. This can be used in one of two ways depending on how industrial sources are being treated: If industrial sources are being treated on an output basis, the thermal output can be used directly to calculate the share of allowances to be allocated to the facility.

If industrial sources are being treated on an input basis, the thermal output should be divided by a typical boiler efficiency such as SO%, to calculate the equivalent heat input that would be required to provide that amount of thermal energy. The equivalent heat input would be multiplied by 0.17 lbMME3tu to calculate the allocation.

As noted above, some states may have more specific information which the EPA could use to calculate these allocations.

Finally, all of these approaches should be applied in the Section 126 language and should be provided to the states for use in making allocations for 2003..

Pending the development of more accurate monitoring data, the EPA has very little data on which base an allocation  either input or output  which can truly be characterized as highly accurate, verifiable and quality assured. For electric generators affected by the acid rain program, the EPA may have better data than for the others. However, it has not been shown that the CEM heat input data are more reliable than generation data provided to EIA and there are engineeringreasons to believe that it might be less accurate. For the remainder of the sources, EPA has no reliable data for either input or output.

22 3 If the ultimate goal is an output based system  and it should be.

at If the EPA is planning to provide reliable output data within the next few years  and it is.

Then we should not quibble over which set of inaccurate data is less bad. We should proceed to set up the regulatory structures that we will need and use in the future using the best available data and apply better data in the next few years as they become available. We have the ability to do output based allocation for 2003 with as much accuracy as any other approach. Data and methodological shortcomings should not be used as an excuse to delay the development of regulatory systems that reduce costs and pollution and which have been identified is our goal.

For clarifications or hrther information on these comments, please contact Joel Bluestein at 7103 528 1900 or jbluesteint3eea inc. com.

23 FAX TKANSMITTA DATE June 5,2002 NUMBER OF PAGES ( incfudlngthis cwver Sh88t):

TO: Name Bill Neuffer I Pmtectlog Texas by pmlng end Pmentrng ~ allullan Organization US EPA OAQPS FAX Number ( 919) 641 0824 FROM: TEXAS NATURAL RESOURCE CONSERVATION COMNllSSlON Name Randy Hamilton

DivisiodRegion Air Permits Division Telephone Number ( 512) 2394512 FAX Number ( 512) 239 1300 NOTES:

The DukeRexas Eiastern test results for the SIXrich bum YVG103s converted to lean burn in 1999with Enginuity's precombustlonchamber engineering. We seem to have misplaced this test report, but the company sent acopy today.

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[Federal Register Volume 84, Number 168 (Thursday, August 29, 2019)]
[Notices]
[Page 45486]
[FR Doc No: 2019-18670]

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DEPARTMENT OF ENERGY

Federal Energy Regulatory Commission

[Docket No. EL19-94-000]

TerraForm Power, Inc.; Notice of Petition for Declaratory Order

August 23, 2019.
    Take notice that on August 22, 2019, pursuant to Rule 207 of the
Federal Energy Regulatory Commission's (Commission) Rules of Practice
and Procedure, 18 CFR 385.207 and sections 366.3(b)(1), 366.3(d), and
366.4(b)(3) of the Commission's regulations,\1\ TerraForm Power, Inc.
(Petitioner), on behalf of itself and its current and future
subsidiaries that are holding companies (collectively, the TerraForm
HoldCos), filed a petition requesting that the Commission, among other
things, issue a declaratory order granting the TerraForm HoldCos an
exemption from the requirements of sections 366.2, 366.21, 366.22, and
366.23 of the Commission's regulations under the Public Utility Holding
Company Act of 2005,\2\ all as more fully explained in the petition.
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    \1\ 18 CFR 366.3(b)(1), 366.3(d), and 366.4(b)(3) (2019).
    \2\ 18 CFR 366.2, 366.21, 366.22, & 366.23 (2019).
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    Any person desiring to intervene or to protest this filing must
file in accordance with Rules 211 and 214 of the Commission's Rules of
Practice and Procedure (18 CFR 385.211, 385.214). Protests will be
considered by the Commission in determining the appropriate action to
be taken, but will not serve to make protestants parties to the
proceeding. Any person wishing to become a party must file a notice of
intervention or motion to intervene, as appropriate. Such notices,
motions, or protests must be filed on or before the comment date.
Anyone filing a motion to intervene or protest must serve a copy of
that document on the Petitioner.
    The Commission encourages electronic submission of protests and
interventions in lieu of paper using the ``eFiling'' link at http://www.ferc.gov. Persons unable to file electronically should submit an
original and 5 copies of the protest or intervention to the Federal
Energy Regulatory Commission, 888 First Street NE, Washington, DC
20426.
    This filing is accessible on-line at http://www.ferc.gov, using the
``eLibrary'' link and is available for review in the Commission's
Public Reference Room in Washington, DC. There is an ``eSubscription''
link on the website that enables subscribers to receive email
notification when a document is added to a subscribed docket(s). For
assistance with any FERC Online service, please email
<EMAIL_ADDRESS>or call<PHONE_NUMBER> (toll free). For
TTY, call<PHONE_NUMBER>.
    Comment Date: 5:00 p.m. Eastern time on September 23, 2019.

Kimberly D. Bose,
Secretary.
[FR Doc. 2019-18670 Filed 8-28-19; 8:45 am]
 BILLING CODE P


[Federal Register Volume 82, Number 232 (Tuesday, December 5, 2017)]
[Notices]
[Pages 57440-57441]
[FR Doc No: 2017-26139]

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DEPARTMENT OF ENERGY

Federal Energy Regulatory Commission

[Docket Nos. CP15-550-000; CP15-551-001]

Venture Global Calcasieu Pass, LLC; TransCameron Pipeline, LLC;
Notice of Schedule for Environmental Review of the Calcasieu Pass
Project

    On September 4, 2015, Venture Global Calcasieu Pass, LLC filed an
application in Docket No. CP15-550-000 requesting authorization under
Section 3 of the Natural Gas Act to site, construct, and operate new
liquefaction facilities. On the same day, TransCameron Pipeline, LLC
filed an application in Docket No. CP15-551-000 requesting a
Certificate of Public Convenience and Necessity pursuant to Section
7(c) of the Natural Gas Act to construct, operate, and maintain certain
natural gas pipeline facilities. The combined proposed projects are
known as the Calcasieu Pass Project (Project) and would liquefy and
export 10.0 million tonnes per annum of liquefied natural gas (LNG).
    On September 18, 2015, the Federal Energy Regulatory Commission
(FERC or Commission) issued its Notice of Application for the Project.
Among other things, that notice alerted other agencies issuing federal
authorizations of the requirement to complete all necessary reviews and
to reach a final decision on the request for a federal authorization
within 90 days of the date of issuance of the Commission staff's final
Environmental Impact Statement (EIS) for the Project. This instant
notice identifies the FERC staff's planned schedule for completion of
the final EIS for the Project, which is based on an issuance of the
draft EIS in March 2018.

Schedule for Environmental Review

    Issuance of Notice of Availability of the final EIS: July 3, 2018.
    90-day Federal Authorization Decision Deadline: October 1, 2018.
    If a schedule change becomes necessary for the final EIS, an
additional notice will be provided so that the relevant agencies are
kept informed of the Project's progress.

Project Description

    Venture Global Calcasieu Pass, LLC's proposed facilities include
nine single mixed refrigerant liquefaction blocks, two LNG storage
tanks, a 720 megawatt electric generating plant, a marine terminal
consisting of a turning basin and LNG carrier berths, LNG piping,
transfer lines, and loading facilities. TransCameron Pipeline, LLC's
proposed facilities include approximately 23.4 miles of 42-inch-
diameter pipeline, one meter station, three mainline valves, one pig
launcher, and one pig receiver. All facilities would be in Cameron
Parish, Louisiana.

Background

    On October 10, 2014, the Commission staff granted Venture Global
Calcasieu Pass, LLC's and TransCameron Pipeline, LLC's joint request to
use the FERC's Pre-filing environmental review process and assigned the
Calcasieu Pass Project Docket No. PF15-2-000. On January 20, 2015, the
Commission issued a Notice of

Intent to Prepare an Environmental Impact Statement for the Proposed
Calcasieu Pass Project, Request for Comments on Environmental Issues,
and Notice of Public Scoping Meeting (NOI). On August 2, 2016, the
Commission issued a Supplemental NOI that discussed TransCameron
Pipeline, LLC's June 28, 2016 amendment, which included removal of the
West Lateral pipeline as well as minor workspace adjustments along the
East Lateral pipeline.
    The original and Supplemental NOIs were sent to federal, state, and
local government agencies; elected officials; affected landowners;
environmental and public interest groups; Native American tribes and
regional organizations; commentors and other interested parties; and
local libraries and newspapers. Major issues raised during scoping
include project design, alternatives, water resources, wildlife,
vegetation, land use, recreation, transportation, traffic,
socioeconomics, and cultural resources.
    The U.S. Army Corps of Engineers, U.S. Coast Guard, U.S. Department
of Transportation, U.S. Environmental Protection Agency, and U.S.
Department of Energy are cooperating agencies in the preparation of the
EIS.

Additional Information

    In order to receive notification of the issuance of the EIS and to
keep track of all formal issuances and submittals in specific dockets,
the Commission offers a free service called eSubscription. This can
reduce the amount of time you spend researching proceedings by
automatically providing you with notification of these filings,
document summaries, and direct links to the documents. Go to
www.ferc.gov/docs-filing/esubscription.asp.
    Additional information about the Project is available from the
Commission's Office of External Affairs at (866) 208-FERC or on the
FERC Web site (www.ferc.gov). Using the eLibrary link, select General
Search from the eLibrary menu, enter the selected date range and Docket
Number excluding the last three digits (i.e., CP15-550 or CP15-551),
and follow the instructions. For assistance with access to eLibrary,
the helpline can be reached at<PHONE_NUMBER>, TTY<PHONE_NUMBER>, or
at [email protected]. The eLibrary link on the FERC Web site
also provides access to the texts of formal documents issued by the
Commission, such as orders, notices, and rule makings.

    Dated: November 29, 2017.
Kimberly D. Bose,
 Secretary.
[FR Doc. 2017-26139 Filed 12-4-17; 8:45 am]
 BILLING CODE 6717-01-P