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Texas SIP: 30 TAC 117.101-117.121: Utility Electric Generation in Ozone Nonattainment Areas; SIP effective 2004.04.26

Regulatory Text: 
TNRCC Chapter 117 –  Control of Air Pollution from Nitrogen Compounds

Subchapter B : Combustion at Existing Major Sources

DIVISION 1 : UTILITY ELECTRIC GENERATION IN OZONE NONATTAINMENT AREAS

Outline Division 1:
§117.101.  Applicability.
§117.103.  Exemptions.
§117.104.  Gas-Fired Steam Generation.
§117.105.  Emission Specifications for Reasonably Available Control Technology (RACT).
§117.106.  Emission Specifications for Attainment Demonstrations.
§117.107.  Alternative System-Wide Emission Specifications.
§117.108.  System Cap.
§117.110.  Change of Ownership - System Cap.
§117.111.  Initial Demonstration of Compliance.
§117.113.  Continuous Demonstration of Compliance.
§117.114.  Emission Testing and Monitoring for the Houston/Galveston Attainment Demonstration.
§117.115.  Final Control Plan Procedures for Reasonably Available Control Technology.
§117.116.  Final Control Plan Procedures for Attainment Demonstration Emission Specifications.
§117.117.  Revision of Final Control Plan.
§117.119.  Notification, Recordkeeping, and Reporting Requirements.
§117.121.  Alternative Case Specific Specifications.


§117.101.  Applicability.
As adopted by TNRCC September 26, 2001, effective October 18, 2001.
Approved by EPA November 14, 2001 (66 FR 57244) effective December 14, 2001.

     (a)  The provisions of this division (relating to Utility Electric Generation in Ozone Nonattainment Areas) shall apply to the following units used in an electric power generating system, as defined in §117.10(13)(A) of this title (relating to Definitions), owned or operated by a municipality or a Public Utility Commission of Texas (PUC) regulated utility, or any of their successors, regardless of whether the successor is a municipality or is regulated by the PUC, located within the Beaumont/Port Arthur, Houston/Galveston, or Dallas/Fort Worth ozone nonattainment areas:

          (1)  utility boilers;

          (2)  auxiliary steam boilers;

          (3)  stationary gas turbines; and

          (4)  duct burners used in turbine exhaust ducts.

     (b)  The provisions of this division are applicable for the life of each affected unit within an electric power generating system or until this division or sections of this title which are applicable to an affected unit are rescinded.

Adopted September 26, 2001, Effective October 18, 2001
**** end tx 117.101 adopted by TNRCC 09/26/2001 (7-21)**d29*ebze***c1e**

§117.103.  Exemptions.
As adopted by TNRCC September 26, 2001, effective October 18, 2001.
Approved by EPA November 14, 2001 (66 FR 57244) effective December 14, 2001.

     (a)  Reasonably available control technology.  Units exempted from the provisions of §§117.105, 117.107, and 117.113 of this title (relating to Emission Specifications for Reasonably Available Control Technology (RACT); Alternative System-wide Emission Specifications; and Continuous Demonstration of Compliance), except as may be specified in §117.113(h), (i), and (j) of this title, include the following:

          (1)  any new units placed into service after November 15, 1992;

          (2)  any utility boiler or auxiliary steam boiler with an annual heat input less than or equal to 2.2(1011) Btu per year; or

          (3)  stationary gas turbines and engines, which are:

               (A)  used solely to power other engines or gas turbines during start-ups; or

               (B)  demonstrated to operate less than 850 hours per year, based on a rolling 12-month average.

     (b)  Emission specifications for attainment demonstrations.  Stationary gas turbines and engines which are used solely to power other engines or gas turbines during start-ups are exempt from the provisions of §§117.106, 117.108, and 117.113 of this title (relating to Emission Specifications for Attainment Demonstrations; System Cap; and Continuous Demonstration of Compliance), except as may be specified in §117.113(i) of this title.

     (c)  Emergency fuel oil firing.

          (1)  The fuel oil firing emission limitations of §§117.105(c), 117.106(a), (b), and (c)(1)(B), 117.107(b), and 117.108 of this title shall not apply during an emergency operating condition declared by the Electric Reliability Council of Texas or the Southwest Power Pool, or any other emergency operating condition which necessitates oil firing.  All findings that emergency operating conditions exist are subject to the approval of the executive director.

          (2)  The owner or operator of an affected unit shall give the executive director and any local air pollution control agency having jurisdiction verbal notification as soon as possible but no later than 48 hours after declaration of the emergency.  Verbal notification shall identify the anticipated date and time oil firing will begin, duration of the emergency period, affected oil-fired equipment, and quantity of oil to be fired in each unit, and shall be followed by written notification containing this information no later than five days after declaration of the emergency.

          (3)  The owner or operator of an affected unit shall give the executive director and any local air pollution control agency having jurisdiction final written notification as soon as possible but no later than two weeks after the termination of emergency fuel oil firing.  Final written notification shall identify the actual dates and times that oil firing began and ended, duration of the emergency period, affected oil-fired equipment, and quantity of oil fired in each unit.

Adopted September 26, 2001, Effective October 18, 2001
**** end tx 117.103 adopted by TNRCC 09/26/2001 (7-21)**d29*ebze***c1e**


§117.104.  Gas-Fired Steam Generation.
Adopted by TNRCC April 19, 2000, effective May 11, 2000.
Approved by EPA March 16, 2001 (66 FR 15195) effective April 16, 2001.

     (a)  Subsections (b), (c), and (d) of this section (emission specifications adopted by the Texas Air Control Board in 1972) apply in the Dallas/Fort Worth ozone nonattainment area.  This section shall no longer apply after the applicable final compliance date for reasonably available control technology specified in §117.510(b)(1) of this title (relating to Compliance Schedule for Utility Electric Generation in Ozone Nonattainment Areas).

     (b)  No person shall allow emissions of nitrogen oxides (NOx), calculated as nitrogen dioxide (NO2), from any "opposed-fired" steam generating unit of more than 600,000 pounds per hour (lbs/hr) maximum continuous steam capacity to exceed 0.7 pound per million Btu (lb/MMBtu) heat input, maximum two-hour average, at maximum steam capacity.  An "opposed-fired" steam generating unit is defined as a unit having burners installed on two opposite vertical firebox surfaces.

     (c)  No person shall allow emissions of NOx, calculated as NO2, from any "front-fired" steam generating unit of more than 600,000 lbs/hr maximum continuous steam capacity to exceed 0.5 lb/MMBtu heat input, maximum two-hour average, at maximum steam capacity.  A "front-fired" steam generating unit is defined as a unit having all burners installed in a geometric array on one vertical firebox surface.

     (d)  No person shall allow emissions of NOx, calculated as NO2, from any "tangential-fired" steam generating unit of more than 600,000 lbs/hr maximum continuous steam capacity to exceed 0.25 lb/MMBtu heat input, maximum two-hour average, at maximum steam capacity.  A "tangential-fired" steam generating unit is defined as a unit having burners installed on all corners of the unit at various elevations.

     (e)  Existing gas-fired steam generating units of more than 600,000 lbs/hour, but less than 1,100,000 lbs/hr, maximum continuous steam capacity are exempt from the provisions of this section, provided the total steam generated from the unit during any one calendar year does not exceed 30% of the product of the maximum continuous steam capacity of the unit times the number of hours in a year. Written records of the amount of steam generated for each day's operation shall be made on a daily basis and maintained for at least three years from the date of each entry.  Such records shall be made available upon request to representatives of the executive director, Environmental Protection Agency (EPA), or any local air pollution control agency having jurisdiction.

********************** end tx 117.104 *********eazs********b1c** 


§117.105.  Emission Specifications for Reasonably Available Control Technology (RACT).
As adopted by TNRCC December 6, 2000, effective January 18, 2001.
Approved by EPA November 14, 2001 (66 FR 57244) effective December 14, 2001.

     (a)  No person shall allow the discharge into the atmosphere from any utility boiler or auxiliary steam boiler, emissions of nitrogen oxides (NOx) in excess of 0.26 pound per million (MM) Btu heat input on a rolling 24-hour average and 0.20 pound per MMBtu heat input on a 30-day rolling average while firing natural gas or a combination of natural gas and waste oil.

     (b)  No person shall allow the discharge into the atmosphere from any utility boiler, NOx emissions in excess of 0.38 pound per MMBtu heat input for tangentially-fired units on a rolling 24-hour averaging period or 0.43 pound per MMBtu heat input for wall-fired units on a rolling 24-hour averaging period while firing coal.

     (c)  No person shall allow the discharge into the atmosphere from any utility boiler or auxiliary steam boiler, NOx emissions in excess of 0.30 pound per MMBtu heat input on a rolling 24-hour averaging period while firing fuel oil only.

     (d)  No person shall allow the discharge into the atmosphere from any utility boiler or auxiliary steam boiler, NOx emissions in excess of the heat input weighted average of the applicable emission limits specified in subsections (a) - (c) of this section on a rolling 24-hour averaging period while firing a mixture of natural gas and fuel oil, as follows:


Emission Limit = [a(0.26) + b(0.30)]/(a + b)

          Where:

               a =     the percentage of total heat input from natural gas.
               b =     the percentage of total heat input from fuel oil.

     (e)  Each auxiliary steam boiler which is an affected facility as defined by New Source Performance Standards (NSPS) 40 Code of Federal Regulations (CFR), Part 60, Subparts D, Db, or Dc shall be limited to the applicable NSPS NOx emission limit, unless the boiler is also subject to a more stringent permit emission limit, in which case the more stringent emission limit applies.  Each auxiliary boiler subject to an emission specification under this subsection is not subject to the emission specifications of subsection (a) or (c) of this section.

     (f)  No person shall allow the discharge into the atmosphere from any stationary gas turbine with a megawatt (MW) rating greater than or equal to 30 MW and an annual electric output in MW-hours (MW-hr) of greater than or equal to the product of 2,500 hours and the MW rating of the unit, NOx emissions in excess of a block one-hour average of:

               (1)  42 parts per million by volume (ppmv) at 15% oxygen (O2), dry basis, while firing natural gas; and

               (2)  65 ppmv at 15% O2, dry basis, while firing fuel oil.

     (g)  No person shall allow the discharge into the atmosphere from any stationary gas turbine used for peaking service with an annual electric output in MW-hr of less than the product of 2,500 hours and the MW rating of the unit NOx emissions in excess of a block one-hour average of:

          (1)  0.20 pound per MMBtu heat input while firing natural gas; and

          (2)  0.30 pound per MMBtu heat input while firing fuel oil.

     (h)  No person shall allow the discharge into the atmosphere from any utility boiler or auxiliary steam boiler subject to the NOx emission limits specified in subsections (a) - (e) of this section, carbon monoxide (CO) emissions in excess of 400 ppmv at 3.0% O2, dry (or alternatively, 0.30 pound per MMBtu heat input for gas-fired units, 0.31 lb/MMBtu heat input for oil-fired units, and 0.33 lb/MMBtu for coal-fired units), based on:

          (1)  a one-hour average for units not equipped with a continuous emissions monitoring system (CEMS) or predictive emissions monitoring system (PEMS) for CO; or

          (2)  a rolling 24-hour averaging period for units equipped with CEMS or PEMS for CO.

     (i)  No person shall allow the discharge into the atmosphere from any stationary gas turbine with a MW rating greater than or equal to ten MW, CO emissions in excess of a block one-hour average of 132 ppmv at 15% O2, dry basis.

     (j)  No person shall allow the discharge into the atmosphere from any unit subject to this section, ammonia emissions in excess of 20 ppmv based on a block one-hour averaging period.

     (k)  For purposes of this subchapter, the following shall apply:

          (1)  The lower of any permit NOx emission limit in effect on June 9, 1993 under a permit issued pursuant to Chapter 116 of this title (relating to Control of Air Pollution by Permits for New Construction or Modification) and the NOx emission limits of subsections (a) - (g) of this section shall apply, except that gas-fired boilers operating under a permit issued after March 3, 1982, with an emission limit of 0.12 pound NOx per MMBtu heat input, shall be limited to that rate for the purposes of this subchapter.

          (2)  For any unit placed into service after June 9, 1993 and prior to the final compliance date as specified in §117.510 of this title (relating to Compliance Schedule for Utility Electric Generation in Ozone Nonattainment Areas) or approved under the provisions of §117.540 of this title (relating to Phased Reasonably Available Control Technology (RACT)), as functionally identical replacement for an existing unit or group of units subject to the provisions of this chapter, the higher of any permit NOx emission limit under a permit issued after June 9, 1993 pursuant to Chapter 116 of this title and the emission limits of subsections (a) - (g) of this section shall apply.  Any emission credits resulting from the operation of such replacement units shall be limited to the cumulative maximum rated capacity of the units replaced.  The inclusion of such new units is an optional method for complying with the emission limitations of §117.107 of this title.  Compliance with this paragraph does not eliminate the requirement for new units to comply with Chapter 116 of this title.

     (l)  This section shall no longer apply:

          (1)  to any utility boiler in the Beaumont/Port Arthur ozone nonattainment area after the appropriate compliance date(s) for emission specifications for attainment demonstrations given in §117.510(a)(2) of this title;

          (2)  to any utility boiler in the Dallas/Fort Worth ozone nonattainment area after the appropriate compliance date(s) for emission specifications for attainment demonstrations given in §117.510(b)(2) of this title; and

          (3)  in the Houston/Galveston ozone nonattainment area after the appropriate compliance date(s) for emission specifications for attainment demonstrations given in §117.510(c)(2) of this title.  For purposes of this paragraph, this means that the RACT emission specifications of this
section remain in effect until the emissions allocation for a unit under the Houston/Galveston mass emissions cap are equal or less than the allocation that would be calculated using the RACT emission specifications of this section.

Adopted December 6, 2000, Effective January 18, 2001
**** end tx 117.105 adopted by TNRCC 12/06/2000 (7-19)**d29*ebze***c1e**

§117.106.  Emission Specifications for Attainment Demonstrations.
As adopted by TNRCC September 26, 2001, effective October 18, 2001.
Approved by EPA November 14, 2001 (66 FR 57244) effective December 14, 2001.

     (a)  Beaumont/Port Arthur.  The owner or operator of each utility boiler located in the Beaumont/Port Arthur ozone nonattainment area shall ensure that emissions of nitrogen oxides (NOx) do not exceed 0.10 pound per million Btu (lb/MMBtu) heat input, on a daily average, except as provided in §117.108 of this title (relating to System Cap), or §117.570 of this title (relating to Use of Emissions Credits for Compliance).

     (b)  Dallas/Fort Worth.  The owner or operator of each utility boiler located in the Dallas/Fort Worth (DFW) ozone nonattainment area shall ensure that emissions of NOx do not exceed:  0.033 lb/MMBtu heat input from boilers which are part of a large DFW system, and 0.06 lb/MMBtu heat input from boilers which are part of a small DFW system, on a daily average, except as provided in §117.108 of this title or §117.570 of this title.  The annual heat input exemption of §117.103(2) of this title (relating to Exemptions) is not applicable to a small DFW system.

     (c)  Houston/Galveston.  The owner or operator of each utility boiler, auxiliary steam boiler, or stationary gas turbine located in the Houston/Galveston ozone nonattainment area shall ensure that emissions of NOx do not exceed the lower of any applicable permit limit in a permit issued before January 2, 2001; any permit issued on or after January 2, 2001 for which the owner or operator submitted an application determined to be administratively complete by the executive director before January 2, 2001; any limit in a permit by rule under which construction commenced by January 2, 2001; or the following rates, in lb/MMBtu heat input, on the basis of daily and 30-day averaging periods as specified in §117.108 of this title, and as specified in the mass emissions cap and trade program of Chapter 101, Subchapter H, Division 3 of this title (relating to Mass Emissions Cap and Trade Program):

          (1)  utility boilers:

               (A)  gas-fired, 0.020; and

               (B)  coal-fired or oil-fired, 0.040;

          (2)  auxiliary steam boilers:
               (A)  with a maximum rated capacity equal to or greater than 100 MMBtu/hr, 0.010;

               (B)  with a maximum rated capacity equal to or greater than 40 MMBtu/hr, but less than 100 MMBtu/hr, 0.015; and

               (C)  with a maximum rated capacity less 40 MMBtu/hr, 0.036 (or alternatively, 30 parts per million by volume (ppmv) NOx , at 3.0% oxygen (O2), dry basis);

          (3)  stationary gas turbines (including duct burners used in turbine exhaust ducts):

               (A)  rated at 1.0 megawatt (MW) or greater, 0.015; and

               (B)  rated at less than 1.0 MW:

                    (i)  with initial start of operation on or before December 31, 2000, 0.15; and

                    (ii)  with initial start of operation after December 31, 2000, 0.015; and

          (4)  as an alternative to the emission specifications in paragraphs (1) - (3) of this subsection for units with an annual capacity factor of 0.0383 or less, 0.060.

          (5)  if and to the extent supported by the commission's continuing scientific assessment of the causes of and possible solutions to the Houston/Galveston area's nonattainment status for ozone, the executive director determines that attainment can be reached with fewer NOx emission reductions from point sources concurrent with additional emission reduction strategies, then the executive director will develop proposed rulemaking and a proposed state implementation plan revision involving revisions to the emission specifications in paragraphs (1) - (4) of this subsection for consideration at a commission agenda no later than June 1, 2002.  In the event that the total NOx emission reductions from utility and non-utility point sources required for attainment is determined to be 80% from the 1997 emissions inventory baseline, the revised specifications shall be the lower of any applicable permit limit in a permit issued before January 2, 2001; any permit issued on or after January 2, 2001 for which the owner or operator submitted an application determined to be administratively complete by the executive director before January 2, 2001; any limit in a permit by rule under which construction commenced by January 2, 2001; or the emission specifications in the following subparagraphs.  The commission reserves all rights to assign any additional NOx reduction benefits supported by the science evaluation to the relief of other control measures, including further NOx point source relief.

               (A)  utility boilers:

                    (i)  gas-fired, 0.030;

                    (ii)  coal-fired or oil-fired;

                         (I)  wall-fired, 0.050; and

                         (II)  tangential-fired, 0.045;

               (B)  auxiliary steam boilers, 0.030; and

               (C)  stationary gas turbines (including duct burners used in turbine exhaust ducts), 0.032.

     (d)  Related emissions.  No person shall allow the discharge into the atmosphere from any unit subject to the NOx emission limits specified in subsections (a) - (c) of this section:

          (1) carbon monoxide (CO) emissions in excess of 400 ppmv at 3.0% O2, dry (or alternatively, 0.30 lb/MMBtu heat input for gas-fired units, 0.31 lb/MMBtu heat input for oil-fired units, and 0.33 lb/MMBtu for coal-fired units), based on:

               (A)  a one-hour average for units not equipped with a continuous emissions monitoring system (CEMS) or predictive emissions monitoring system (PEMS) for CO; or

               (B)  a rolling 24-hour averaging period for units equipped with CEMS or PEMS for CO; and

          (2)  ammonia emissions in excess of ten ppmv, based on a block one-hour averaging period.

     (e)  Compliance flexibility.

          (1)  In the Beaumont/Port Arthur and Dallas/Fort Worth ozone nonattainment areas, an owner or operator may use either of the following alternative methods of compliance with the NOx emission specifications of this section:

               (A)  §117.108 of this title; or

               (B)  §117.570 of this title.

          (2)  An owner or operator may petition the executive director for an alternative to the CO or ammonia limits of this section in accordance with §117.121 of this title (relating to Alternative Case Specific Specifications).

          (3)  Section 117.107 of this title (relating to Alternative System-wide Emission Specifications) and §117.121 of this title are not alternative methods of compliance with the NOx emission specifications of this section.

          (4)  In the Houston/Galveston ozone nonattainment area, the following requirements apply.

               (A)  For units which meet the definition of electric generating facility (EGF), the owner or operator must use both the methods specified in §117.108 of this title and the mass emissions cap and trade program in Chapter 101, Subchapter H, Division 3 of this title (relating to Mass Emissions Cap and Trade Program) to comply with the NOx emission specifications of this section.  An owner or operator may use the alternative methods specified in §117.570 of this title for purposes of complying with §117.108 of this title.

               (B)  For units which do not meet the definition of EGF, the owner or operator must use the mass emissions cap and trade program in Chapter 101, Subchapter H, Division 3 of this title to comply with the NOx emission specifications of this section.

Adopted September 26, 2001, Effective October 18, 2001
**** end tx 117.106 adopted by TNRCC 09/26/2001 (7-21)**d29*ebze***c1e**

§117.107.  Alternative System-Wide Emission Specifications.
As adopted by TNRCC September 26, 2001, effective October 18, 2001.
Approved by EPA November 14, 2001 (66 FR 57244) effective December 14, 2001.

     (a)  An owner or operator of any gaseous- or coal-fired utility boiler or stationary gas turbine may achieve compliance with the nitrogen oxides (NOx) emission  limits of §117.105 of this title (relating to Emission Specifications for Reasonably Available Control Technology (RACT)) by achieving compliance with a system-wide emission limitation.  Any owner or operator who elects to comply with system-wide emission limits shall reduce emissions of NOx from affected units so that, if all such units were operated at their maximum rated capacity, the system-wide emission rate from all units in the system as defined in §117.10(13)(A) of this title (relating to Definitions) would not exceed the system-wide emission limit as defined in §117.10 of this title.

          (1)  The following units shall comply with the individual emission specifications of §117.105 of this title and shall not be included in the system-wide emission specification:

               (A)  gas turbines used for peaking service subject to the emission limits of §117.105(g) of this title;

               (B)  auxiliary steam boilers subject to the emission limits of §117.105(a), (c), (d), or (e) of this title.

          (2)  Coal-fired utility boilers or steam generators shall have a separate system average under this section, limited to those units.

          (3)  Oil-fired utility boilers or steam generators shall have a separate system average under this section, limited to those units.  The emission limit assigned to each oil-fired unit in the system shall not exceed 0.5 pound (lb) NOx per million British thermal units (MMBtu) based on a rolling 24-hour average.

     (b)  The owner or operator shall establish enforceable emission limits for each affected unit in the system calculated in accordance with the maximum rated capacity averaging in this section as follows:

          (1)  for each gas-fired unit in the system, in lb/MMBtu:

               (A)  on a rolling 24-hour averaging period; and

               (B)  on a rolling 30-day averaging period;

          (2)  for each coal-fired unit in the system, in lb/MMBtu on a rolling 24-hour averaging period;

          (3)  for stationary gas turbines, in the units of the appropriate emission limitation of §117.105 of this title; and

          (4)  for each fuel oil-fired unit in the system, in lb/MMBtu on a rolling 24-hour averaging period.

     (c)  An owner or operator of any gaseous and liquid fuel-fired utility boiler, steam generator, or gas turbine shall:

          (1)  comply with the assigned maximum allowable emission rates for gas fuel while firing natural gas only;
          (2)  comply with the assigned maximum allowable emission rate for liquid fuel while firing liquid fuel only; and

          (3)  comply with a limit calculated as the actual heat input weighted sum of the assigned gas-firing, 24-hour average, allowable emission limit and the assigned liquid-firing allowable emission limit while operating on liquid and gaseous fuel concurrently.

     (d)  Solely for purposes of calculating the system-wide emission limit, the allowable mass emission rate for each affected unit shall be calculated from the emission specifications of §117.105 of this title, as follows.

          (1)  The NOx emissions rate (in pounds per hour) for each affected utility boiler, steam generator, or auxiliary steam boiler is the product of its average activity level for fuel oil firing or maximum rated capacity for gas firing and its NOx emission specification of §117.105 of this title.

          (2)  The NOx emissions rate (in pounds per hour) for each affected stationary gas turbine is the product of the in-stack NOx, the turbine manufacturer's rated exhaust flow rate (expressed in pounds per hour at megawatt (MW) rating and International Standards Organization (ISO) flow conditions), and (46/28)(10-6);

     Where:

     In-stack NOx     =     NOx (allowable) x (1 -%H2O/100) x [20.9 -%O2/(1 -%H2O/100)]/5.9

     NOx (allowable)     =     the applicable NOx emission specification of §117.105(f) or (g) of this title (expressed in parts per million by volume NOx at 15% oxygen (O2) dry basis)

     %H2O     =     the volume percent water in the stack gases, as calculated from the manufacturer's data, or other data as approved by the executive director, at MW rating and ISO flow conditions

     %O2     =     the volume percent O2 in the stack gases on a wet basis, as calculated from the manufacturer's data, or other data as approved by the executive director, at the MW rating and ISO flow conditions.

Adopted September 26, 2001, Effective October 18, 2001
**** end tx 117.107 adopted by TNRCC 09/26/2001 (7-21)**d29*ebze***c1e**

7.B.1 §117.108.  System Cap.
As adopted by TNRCC September 26, 2001, effective October 18, 2001.
Approved by EPA November 14, 2001 (66 FR 57244) effective December 14, 2001.

     (a)  An owner or operator of an electric generating facility (EGF) in the Beaumont/Port Arthur or Dallas/Fort Worth ozone nonattainment areas may achieve compliance with the nitrogen oxides (NOx) emission limits of §117.106 of this title (relating to Emission Specifications for Attainment Demonstrations) by achieving equivalent NOx emission reductions obtained by compliance with a daily and 30-day system cap emission limitation in accordance with the requirements of this section.  An owner or operator of an electric generating facility in the Houston/Galveston ozone nonattainment area must comply with a daily and 30-day system cap emission limitation in accordance with the requirements of this section.

     (b)  Each EGF within an electric power generating system, as defined in §117.10(13)(A) of this title (relating to Definitions), that would otherwise be subject to the NOx emission rates of §117.106 of this title must be included in the system cap.

     (c)  The system cap shall be calculated as follows.

          (1)  A rolling 30-day average emission cap shall be calculated using the following equation.

NOX 30-day rolling average emission cap (lb/day)

       = Sum from i = 1 to N of {Hi × Ri

Where:

     i     =      each EGF in the electric power generating system

     N     =      the total number of EGFs in the emission cap

     Hi     =     (A)  For the Beaumont/Port Arthur and Dallas/
Fort Worth ozone nonattainment areas, the average 
of the daily heat input for each EGF in the 
emission cap, in million Btu per day, as certified 
to the executive director, for the system highest 
30-day period in the nine months of July, August, 
and September 1996, 1997, and 1998.  For EGFs 
exempt from the 40 Code of Federal Regulations 
(CFR) Part 75 monitoring requirements, if the heat 
input data corresponding to the system highest 
30-day period (as determined for EGFs in the 
system subject to 40 CFR Part 75 monitoring) is not 
available, the daily average of the highest 
calendar month heat input in 1996-1998 may be used.

                  (B)  For the Houston/Galveston ozone nonattainment 
area:

                        (i)  The average of the daily heat input for 
each EGF in the emission cap, in million Btu 
per day, as certified to the executive 
director, for any system 30-day period in 
the nine months of July, August, and 
September 1997, 1998, and 1999;

                        (ii)  For EGFs exempt from the 40 CFR 
Part 75 monitoring requirements, if the heat 
input data corresponding to any system 30-day 
period (as determined for EGFs in the system 
subject to 40 CFR Part 75 monitoring) is not
available, the daily average of the highest 
calendar month heat input in 1997-1999 may 
be used; and

                        (iii)  The level of activity authorized by 
the executive director for the third quarter 
(July, August, and September), until such 
time two consecutive third quarters of actual 
level of activity data are available, shall 
be used for the following:

                              (I)  EGFs for which the owner or 
operator has submitted, under 
Chapter 116 of this title, an 
application determined to be 
administratively complete by the 
executive director before 
January 2, 2001;

                              (II)  EGFs which qualify for a permit 
by rule under Chapter 106 of this title 
and have commenced construction before 
January 2, 2001; and

                              (III)  EGFs which were not in operation 
before January 1, 1997;

                        (iv)  After two consecutive third quarters of 
actual level of activity data are available 
for an EGF described in subsection (c)(1) of 
this section, variable (B)(iii) of this 
figure, the owner or operator may calculate 
the baseline as the average of any two 
consecutive third quarters in the first five 
years of operation.  The five-year period 
begins at the end of the adjustment period as 
defined in §101.350 of this title (relating 
to Definitions); and

                        (v)  In extenuating circumstances, the owner 
or operator of an EGF may request, subject 
to approval of the executive director, up to 
two additional calendar years to establish 
the baseline period described in subsection 
(c)(1) of this section, variable (B)(i) - (iv) 
of this figure.  Applications seeking an 
alternate baseline period must be submitted 
by the owner or operator of the EGF to the 
executive director:

                              (I)  no later than December 31, 2001; or

                              (II)  for EGFs for which the baseline 
period as described in subsection (c)(1) 
of this section, variable (B)(i) - (iv) 
of this figure is not complete by 
December 31, 2001, no later than 90 days 
after completion of the baseline period.

     Ri     =     (A)  For EGFs in the Beaumont/Port Arthur ozone 
nonattainment area, the emission limit of §117.106(a) 
of this title;

                  (B)  For EGFs in the Dallas/Fort Worth ozone 
nonattainment area, the emission limit of §117.106(b) 
of this title; and

                  (C)  For EGFs in the Houston/Galveston ozone 
nonattainment area, the emission limit of §117.106(c) 
of this title.


          (2)  A maximum daily cap shall be calculated using the following equation.


NOX maximum daily cap (lb/day)

       = Sum from i = 1 to N of {Hmi × Ri

Where:

     iN, and Ri are defined as in paragraph (1) of this subsection.

     Hmi     =     The maximum heat input, as certified to the executive director, allowed or possible (whichever is lower) in a day.


          (3)  Each EGF in the system cap shall be subject to the emission limits of both paragraphs (1) and (2) of this subsection at all times.


     (d)  The NOx emissions monitoring required by §117.113 of this title (relating to Continuous Demonstration of Compliance) for each EGF in the system cap shall be used to demonstrate continuous compliance with the system cap.

     (e)  For each operating EGF, the owner or operator shall use one of the following methods to provide substitute emissions compliance data during periods when the NOx monitor is off-line:

          (1)  if the NOx monitor is a continuous emissions monitoring system (CEMS):

               (A)  subject to 40 Code of Federal Regulations (CFR) 75, use the missing data procedures specified in 40 CFR 75, Subpart D (Missing Data Substitution Procedures); or

               (B)  subject to 40 CFR 75, Appendix E, use the missing data procedures specified in 40 CFR 75, Appendix E, §2.5 (Missing Data Procedures);

          (2)  use Appendix E monitoring in accordance with §117.113(d) of this title;

          (3)  if the NOx monitor is a predictive emissions monitoring system (PEMS):

               (A)  use the methods specified in 40 CFR 75, Subpart D; or

               (B)  use calculations in accordance with §117.113(f) of this title; or

          (4)  if the methods specified in paragraphs (1) - (3) of this subsection are not used, the owner or operator must use the maximum block one-hour emission rate as measured by the 30-day testing.

     (f)  The owner or operator of any EGF subject to a system cap shall maintain daily records indicating the NOx emissions and fuel usage from each EGF and summations of total NOx emissions and fuel usage for all EGFs under the system cap on a daily basis.  Records shall also be retained in accordance with §117.119 of this title (relating to Notification, Recordkeeping, and Reporting Requirements).

     (g)  The owner or operator of any EGF subject to a system cap shall report any exceedance of the system cap emission limit within 48 hours to the appropriate regional office.  The owner or operator shall then follow up within 21 days of the exceedance with a written report to the regional office which includes an analysis of the cause for the exceedance with appropriate data to demonstrate the amount of emissions in excess of the applicable limit and the necessary corrective actions taken by the company to assure future compliance.  Additionally, the owner or operator shall submit semiannual reports for the monitoring systems in accordance with §117.119 of this title.

     (h)  The owner or operator of any EGF subject to a system cap shall demonstrate initial compliance with the system cap in accordance with the schedule specified in §117.510 of this title (relating to Compliance Schedule for Utility Electric Generation in Ozone Nonattainment Areas).

     (i)  For the Beaumont/Port Arthur and Dallas/Fort Worth ozone nonattainment areas, an EGF which is permanently retired or decommissioned and rendered inoperable may be included in the source cap emission limit, provided that the permanent shutdown occurred after January 1, 1999.  For the Houston/Galveston ozone nonattainment area, an EGF which is permanently retired or decommissioned and rendered inoperable may be included in the source cap emission limit, provided that the permanent shutdown occurred after January 1, 2000.  The source cap emission limit is calculated in accordance with subsection (b) of this section.

     (j)  Emission reductions from shutdowns or curtailments which have been used for netting or offset purposes under the requirements of Chapter 116 of this title may not be included in the baseline for establishing the cap.

     (k)  For the purposes of determining compliance with the source cap emission limit, the contribution of each affected EGF that is operating during a startup, shutdown, or upset period shall be calculated from the NOx emission rate measured by the NOx monitor, if operating properly.  If the NOx monitor is not operating properly, the substitute data procedures identified in subsection (e) of this section must be used.  If neither the NOx monitor nor the substitute data procedure are operating properly, the owner or operator must use the maximum daily rate measured during the initial demonstration of compliance, unless the owner or operator provides data demonstrating to the satisfaction of the executive director and the EPA that actual emissions were less than maximum emissions during such periods.

Adopted September 26, 2001, Effective October 18, 2001
**** end tx 117.108 adopted by TNRCC 09/26/2001 (7-21)**d29*ebze***c1e**

§117.110.  Change of Ownership - System Cap.
As adopted by TNRCC September 26, 2001, effective October 18, 2001.
Approved by EPA November 14, 2001 (66 FR 57244) effective December 14, 2001.

     In the event that a unit within an electric power generating system is sold or transferred, the unit shall become subject to the transferee’s system cap.  In the Dallas/Fort Worth ozone nonattainment area, the value Ri in §117.108(c) of this title (relating to System Cap) is based on the unit’s status as part of a large or small system as of January 1, 2000, and does not change as a result of sale or transfer of the unit, regardless of the size of the transferee’s system.

Adopted September 26, 2001, Effective October 18, 2001
**** end tx 117.110 adopted by TNRCC 09/26/2001 (7-21)**d29*ebze***c1e**

§117.111.  Initial Demonstration of Compliance.
As adopted by TNRCC December 6, 2000, effective January 18, 2001.
Approved by EPA November 14, 2001 (66 FR 57244) effective December 14, 2001.

     (a)  The owner or operator of all units which are subject to the emission limitations of this division (relating to Utility Electric Generation in Ozone Nonattainment Areas) must test the units as follows.

          (1)  Test for nitrogen oxides (NOx), carbon monoxide (CO), and oxygen (O2) emissions.

          (2)  Units which inject urea or ammonia into the exhaust stream for NOx control shall be tested for ammonia emissions.

          (3)  Testing shall be performed in accordance with the schedules specified in §117.510 of this title (relating to Compliance Schedule for Utility Electric Generation in Ozone Nonattainment Areas).

     (b)  The tests required by subsection (a) of this section shall be used for determination of initial compliance with the emission limits of this division.  Test results shall be reported in the units of the applicable emission limits and averaging periods.  If compliance testing is based on 40 Code of Federal Regulations, Part 60, Appendix A reference methods, the report must contain the information specified in §117.211(g) of this title (relating to Initial Demonstration of Compliance).

     (c)  Continuous emissions monitoring systems (CEMS) or predictive emissions monitoring systems (PEMS) required by §117.113 of this title (relating to Continuous Demonstration of Compliance) shall be installed and operational before testing under subsection (a) of this section. Verification of operational status shall, as a minimum, include completion of the initial monitor certification and the manufacturer's written requirements or recommendations for installation, operation, and calibration of the device.

     (d)  Initial compliance with the emission specifications of this division for units operating with CEMS or PEMS in accordance with §117.113 of this title shall be demonstrated after monitor certification testing using the NOx CEMS or PEMS as follows:

          (1)  To comply with the NOx emission limit in pound per million (MM) Btu on a rolling 30-day average, NOx emissions from a unit are monitored for 30 successive unit operating days and the 30-day average emission rate is used to determine compliance with the NOx emission limit.  The 30-day average emission rate is calculated as the average of all hourly emissions data recorded by the monitoring system during the 30-day test period.

          (2)  To comply with the NOx emission limit in pound per MMBtu on a rolling 24-hour average, NOx emissions from a unit are monitored for 24 consecutive operating hours and the 24-hour average emission rate is used to determine compliance with the NOx emission limit.  The 24-hour average emission rate is calculated as the average of all hourly emissions data recorded by the monitoring system during the 24-hour test period.  Compliance with the NOx emission limit for fuel oil firing shall be determined based on the first 24 consecutive operating hours a unit fires fuel oil.

          (3)  For EGFs complying with §117.108 of this title (relating to System Cap), a rolling 30-day average of total daily pounds of NOx emissions from the EGFs are monitored (or calculated in accordance with §117.108(e) of this title) for 30 successive system operating days and the 30-day average emission rate is used to determine compliance with the NOx emission limit.  The 30-day average emission rate is calculated as the average of all daily emissions data recorded by the monitoring and recording system during the 30-day test period.  There must be no exceedances of the maximum daily cap during the 30-day test period.

          (4)  To comply with the NOx emission limit in pounds per hour or parts per million by volume at 15% O2 dry basis, on a block one-hour average, any one-hour period while operating at the maximum rated capacity, or as near thereto as practicable, after CEMS or PEMS certification testing required in §117.113 of this title is used to determine compliance with the NOx emission limit.

          (5)  To comply with the CO emission limit in parts per million by volume on a rolling 24-hour average, CO emissions from a unit are monitored for 24 consecutive hours and the rolling 24-hour average emission rate is used to determine compliance with the CO emission limit.  The rolling 24-hour average emission rate is calculated as the average of all hourly emissions data recorded by the monitoring system during the 24-hour test period.

Adopted December 6, 2000, Effective January 18, 2001
**** end tx 117.111 adopted by TNRCC 12/06/2000 (7-19)**d29*ebze***c1e**

§117.113.  Continuous Demonstration of Compliance.
As adopted by TNRCC December 6, 2000, effective January 18, 2001.
Approved by EPA November 14, 2001 (66 FR 57244) effective December 14, 2001.

     (a)  NOx monitoring.  The owner or operator of each unit subject to the emission specifications of this division (relating to Utility Electric Generation in Ozone Nonattainment Areas), shall install, calibrate, maintain, and operate a continuous emissions monitoring system (CEMS), predictive emissions monitoring system (PEMS), or other system specified in this section to measure nitrogen oxides (NOx) on an individual basis.

     (b)  Carbon monoxide (CO) monitoring.  The owner or operator shall monitor CO exhaust emissions from each unit subject to the emission specifications of this division using one or more of the following methods:

          (1)  install, calibrate, maintain, and operate a:

               (A)  CEMS in accordance with subsection (c) of this section; or

               (B)  PEMS in accordance with subsection (f) of this section; or

          (2)  sample CO as follows:

               (A)  with a portable analyzer (or 40 CFR 60, Appendix A reference method test apparatus) after manual combustion tuning or manual burner adjustments conducted for the purpose of minimizing NOx emissions whenever, following such manual changes, either:

                    (i)  NOx emissions are sampled with a portable analyzer or 40 CFR 60, Appendix A reference method test apparatus; or

                    (ii)  the resulting NOx emissions measured by CEMS or predicted by PEMS are lower than levels for which CO emissions data was previously gathered; and

               (B)  sample CO emissions using the test methods and procedures of 40 CFR 60 in conjunction with the annual relative accuracy test audit of the NOx and diluent analyzer.

     (c)  CEMS requirements.

          (1)  Any CEMS required by this section shall be installed, calibrated, maintained, and operated in accordance with 40 CFR, Part 75 or 40 CFR, Part 60, as applicable.

          (2)  One CEMS may be shared among units, provided:

               (A)  the exhaust stream of each unit is analyzed separately; and

               (B)  the CEMS meets the applicable certification requirements of paragraph (1) of this subsection for each exhaust stream.

     (d)  Acid rain peaking units.  The owner or operator of each peaking unit as defined in 40 CFR Part §72.2, may:

          (1)  monitor operating parameters for each unit in accordance with 40 CFR Part 75, Appendix E, §1.1 or §1.2 and calculate NOx emission rates based on those procedures; or

          (2)  use CEMS or PEMS in accordance with this section to monitor NOx emission rates.

     (e)  Auxiliary boilers.  The owner or operator of each auxiliary boiler as defined in §117.10 of this title (relating to Definitions) shall:

          (1)  install, calibrate, maintain, and operate a CEMS in accordance with this section; or

          (2)  comply with the appropriate (considering boiler maximum rated capacity and annual heat input) industrial boiler monitoring requirements of §117.213 of this title (relating to Continuous Demonstration of Compliance).

     (f)  PEMS requirements.  The owner or operator of any PEMS used to meet a pollutant monitoring requirement of this section must comply with the following.  The required PEMS and fuel flow meters shall be used to demonstrate continuous compliance with the emission limitations of this division.

          (1)  The PEMS must predict the pollutant emissions in the units of the applicable emission limitations of this division.

          (2)  Monitor diluent, either oxygen or carbon dioxide:

               (A)  using a CEMS

                    (i)  in accordance with subsection (b) of this section; or

                    (ii)  with a similar alternative method approved by the executive director and EPA; or
               (B)  using a PEMS.

          (3)  Any PEMS for units subject to the requirements of 40 CFR 75 shall meet the requirements of 40 CFR 75, Subpart E, §§75.40 - 75.48.

          (4)  Any PEMS for units not subject to the requirements of 40 CFR 75 shall meet the requirements of either:

               (A)  40 CFR 75, Subpart E, §§75.40 - 75.48; or

               (B)  §117.213(f) of this title.

     (g)  Stationary gas turbine monitoring for NOx RACT.  The owner or operator of each stationary gas turbine subject to the emission specifications of §117.105 of this title (relating to Emission Specifications for Reasonably Available Control Technology (RACT)), instead of monitoring emissions in accordance with the monitoring requirements of 40 CFR 75, may comply with the following monitoring requirements:

          (1)  for stationary gas turbines rated less than 30 megawatt (MW) or peaking gas turbines (as defined in §117.10 of this title) which use steam or water injection to comply with the emission specifications of §117.105(g) of this title:

               (A)  install, calibrate, maintain and operate a CEMS or PEMS in compliance with this section; or

               (B)  install, calibrate, maintain, and operate a continuous monitoring system to monitor and record the average hourly fuel and steam or water consumption.  The system shall be accurate to within ± 5.0%.  The steam-to-fuel or water-to-fuel ratio monitoring data shall constitute the method for demonstrating continuous compliance with the applicable emission specification of §117.105 of this title.

          (2)  for stationary gas turbines subject to the emission specifications of §117.105(f) of this title, install, calibrate, maintain and operate a CEMS or PEMS in compliance with this section.

     (h)  Totalizing fuel flow meters.  The owner or operator of units listed in this subsection shall install, calibrate, maintain, and operate totalizing fuel flow meters to individually and continuously measure the gas and liquid fuel usage.  A computer which collects, sums, and stores electronic data from continuous fuel flow meters is an acceptable totalizer.  The units are:

          (1)  for units which are subject to §117.105 of this title (relating to Emission Specifications for Reasonably Available Control Technology (RACT)), and for units in the Beaumont/Port Arthur (BPA) and Dallas/Fort Worth (DFW) ozone nonattainment areas which are subject to §117.106 of this title (relating to Emission Specifications for Attainment Demonstrations):

               (A)  any unit subject to the emission specifications of this division;

               (B)  any stationary gas turbine with an MW rating greater than or equal to 1.0 MW operated more than 850 hours per year (hr/yr); and

               (C)  any unit claimed exempt from the emission specifications of this division using the low annual capacity factor exemption of §117.103(a)(2) of this title (relating to Exemptions); and

          (2)  for units in the Houston/Galveston ozone nonattainment area ozone nonattainment area which are subject to §117.106 of this title:

               (A)  utility boilers;

               (B)  auxiliary steam boilers; and

               (C)  stationary gas turbines.

     (i)  Run time meters.  The owner or operator of any stationary gas turbine using the exemption of §117.103(a)(3) or (b) of this title shall record the operating time with an elapsed run time meter approved by the executive director.

     (j)  Loss of exemption.  The owner or operator of any unit claimed exempt from the emission specifications of this division using the low annual capacity factor exemptions of §117.103(a)(2) or (3) of this title, shall notify the executive director within seven days if the applicable limit is exceeded.

          (1)  If the limit is exceeded, the exemption from the emission specifications of this division shall be permanently withdrawn.

          (2)  Within 90 days after loss of the exemption, the owner or operator shall submit a compliance plan detailing a plan to meet the applicable compliance limit as soon as possible, but no later than 24 months after exceeding the limit.  The plan shall include a schedule of increments of progress for the installation of the required control equipment.

          (3)  The schedule shall be subject to the review and approval of the executive director.

     (k)  Data used for compliance.

          (1)  After the initial demonstration of compliance required by §117.111 of this title (relating to Initial Demonstration of Compliance) the methods required in this section shall be used to determine compliance with the emission specifications of §117.105 or §117.106(a) or (b) of this title. Compliance with the emission limitations may also be determined at the discretion of the executive director using any commission compliance method.

          (2)  For units subject to the emission specifications of §117.106(c) of this title, the methods required in this section and §117.114 of this title (relating to Emission Testing and Monitoring for the Houston/Galveston Attainment Demonstration) shall be used in conjunction with the requirements of Chapter 101, Subchapter H, Division 3 of this title (relating to Mass Emissions Cap and Trade Program) to determine compliance.  For enforcement purposes, the executive director may also use other commission compliance methods to determine whether the source is in compliance with applicable emission limitations.

     (l)  Enforcement of NOx RACT limits.  If compliance with §117.105 of this title is selected, no unit subject to §117.105 of this title shall be operated at an emission rate higher than that allowed by the emission specifications of §117.105 of this title.  If compliance with §117.107 of this title is selected, no unit subject to §117.107 of this title shall be operated at an emission rate higher than that approved by the executive director pursuant to §117.115(b) of this title (relating to Final Control Plan Procedures).

Adopted December 6, 2000, Effective January 18, 2001
**** end tx 117.113 adopted by TNRCC 12/06/2000 (7-19)**d29*ebze***c1e**

7.B.1 §117.114.  Emission Testing and Monitoring for the Houston/Galveston Attainment Demonstration.
As adopted by TNRCC December 6, 2000, effective January 18, 2001.
Approved by EPA November 14, 2001 (66 FR 57244) effective December 14, 2001.

     (a)  Monitoring requirements.  The owner or operator of units which are subject to the emission limits of §117.106(c) of this title (relating to Emission Specifications for Attainment Demonstrations) must comply with the following monitoring requirements.

          (1)  The nitrogen oxides (NOx) monitoring requirements of §117.113(a), (c) - (f) of this title (relating to Continuous Demonstration of Compliance) apply.

          (2)  The carbon monoxide (CO) monitoring requirements of §117.113(b) of this title apply.

          (3)  The totalizing fuel flow meter requirements of §117.113(h) of this title apply.

          (4)  Installation of monitors shall be performed in accordance with the schedule specified in §117.510(c)(2) of this title (relating to Compliance Schedule for Utility Electric Generation in Ozone Nonattainment Areas).

     (b)  Testing requirements.  The owner or operator of units which are subject to the emission limits of §117.106(c) of this title must test the units as specified in §117.111 of this title (relating to Initial Demonstration of Compliance) in accordance with the schedule specified in §117.510(c)(2) of this title.

     (c)  Emission allowances.

          (1)  The NOx testing and monitoring data of subsections (a) and (b) of this section, together with the level of activity, as defined in §101.350 of this title (relating to Definitions), shall be used to establish the emission factor for calculating actual emissions for compliance with Chapter 101, Subchapter H, Division 3 of this title (relating to Mass Emissions Cap and Trade Program).

          (2)  For units not operating with a continuous emissions monitoring system (CEMS) or predictive emissions monitoring system (PEMS), the following apply.

               (A)  Retesting as specified in subsection (b) of this section is required within 60 days after any modification which could reasonably be expected to increase the NOx emission rate.

               (B)  Retesting as specified in subsection (b) of this section may be conducted at the discretion of the owner or operator after any modification which could reasonably be expected to decrease the NOx emission rate, including, but not limited to, installation of post-combustion controls, low-NOx burners, low excess air operation, staged combustion (for example, overfire air), flue gas recirculation (FGR), and fuel-lean and conventional (fuel-rich) reburn.

               (C)  The NOx emission rate determined by the retesting shall establish a new emission factor to be used to calculate actual emissions instead of the previously determined emission factor used to calculate actual emissions for compliance with Chapter 101, Subchapter H, Division 3 of this title.

          (3)  The emission factor in paragraph (1) or (2) of this subsection is multiplied by the unit's level of activity to determine the unit's actual emissions for compliance with Chapter 101, Subchapter H, Division 3 of this title.

December 6, 2000, Effective January 18, 2001
**** end tx 117.114 adopted by TNRCC 12/06/2000 (7-19)**d29*ebze***c1e**


§117.115.  Final Control Plan Procedures for Reasonably Available Control Technology.
As adopted by TNRCC April 19, 2000, effective May 11, 2000.
Approved by EPA March 16, 2001 (66 FR 15195) effective April 16, 2001.

     (a)  The owner or operator of units listed in §117.101 of this title (relating to Applicability) at a major source of nitrogen oxides (NOx) shall submit a final control report to show compliance with the requirements of §117.105 of this title (relating to Emission Specifications for Reasonably Available Control Technology (RACT)).  The report must include a list of all units listed in §117.101 of this title, showing:

          (1)  the NOx emission specification resulting from application of §117.105 of this title (relating to Emission Specifications) for each non-exempt unit;

          (2) the section under which NOx compliance is being established for units specified in paragraph (1) of this subsection, either:

               (A)  §117.105 of this title;

               (B)  §117.107 of this title (relating to Alternative Plant-wide Emission Specifications);

               (C)  §117.121 of this title (relating to Alternative Case Specific Specifications); or

               (D)  Section 117.570 of this title (relating to Trading);

          (3)  the method of control of NOx emissions for each unit;

          (4)  the emissions measured by testing required in §117.111 of this title (relating to Initial Demonstration of Compliance);

          (5)  the submittal date, and whether sent to the Austin or the regional office (or both), of any compliance stack test report or relative accuracy test audit report required by §117.111 of this title which is not being submitted concurrently with the final compliance report; and

          (6)  the specific rule citation for any unit with a claimed exemption from the emission specifications of this division.

     (b)  For sources complying with §117.107 of this title, in addition to the requirements of subsection (a) of this section, the owner or operator shall:

          (1)  assign to each affected unit the maximum NOx emission rate, expressed in units of pound per million (MM) Btu heat input on:

               (A)  a rolling 24-hour average and rolling 30-day average for gaseous fuel firing, and

               (B)  a rolling 24-hour average for oil or coal firing;

          (2)  submit a list to the executive director for approval of:

               (A)  the maximum allowable NOx emission rates identified in paragraph (1) of this subsection; and

               (B)  the maximum rated capacity for each unit;

          (3)  submit calculations used to calculate the system-wide average in accordance with §117.107(e) of this title; and

          (4)  maintain a copy of the approved list of emission limits for verification of continued compliance with the requirements of §117.107 of this title.

     (c)  The lists of information required in this section must be submitted electronically and on hard copy using forms provided by the executive director.  This requirement does not apply to calculations or other explanatory information.

     (d)  The report must be submitted by the applicable date specified for final control plans in §117.510 of this title (relating to Compliance Schedule For Utility Electric Generation).  The plan must be updated with any emission compliance measurements submitted for units using continuous emissions monitoring system or predictive emissions monitoring system and complying with an emission limit on a rolling 30-day average, according to the applicable schedule given in §117.510 of this title.

********************** end tx 117.115 *********eazs********b1c**


§117.116.  Final Control Plan Procedures for Attainment Demonstration Emission Specifications.
As adopted by TNRCC December 6, 2000, effective January 18, 2001.
Approved by EPA November 14, 2001 (66 FR 57244) effective December 14, 2001.

     (a)  The owner or operator of utility boilers listed in §117.101 of this title (relating to Applicability) at a major source of nitrogen oxides (NOx) shall submit to the executive director a final control report to show compliance with the requirements of §117.106 of this title (relating to Emission Specifications for Attainment Demonstrations).  The report must include:

          (1)  the section under which NOx compliance is being established for the utility boilers within the electric generating system, either:

               (A)  §117.106 of this title; or

               (B)  §117.108 of this title (relating to System Cap); and as applicable,

               (C)  §117.570 of this title (relating to Trading);

          (2)  the methods of control of NOx emissions for each utility boiler;

          (3)  the emissions measured by testing required in §117.111 of this title (relating to Initial Demonstration of Compliance);

          (4)  the submittal date, and whether sent to the Austin or the regional office (or both), of any compliance stack test report or relative accuracy test audit report required by §117.111 of this title which is not being submitted concurrently with the final compliance report; and

          (5)  the specific rule citation for any utility boiler with a claimed exemption from the emission specification of §117.106 of this title.

     (b)  For sources complying with §117.108 of this title, in addition to the requirements of subsection (a) of this section, the owner or operator shall submit:

          (1)  the calculations used to calculate the 30-day average and maximum daily system cap allowable emission rates;

          (2)  a list containing, for each unit in the cap:

               (A)  the average daily heat input Hi specified in §117.108(c)(1) of this title;

               (B)  the maximum daily heat input Hmi specified in §117.108(c)(2) of this title;

               (C)  the method of monitoring emissions; and

               (D)  the method of providing substitute emissions data when the NOx monitoring system is not providing valid data; and

          (3)  an explanation of the basis of the values of Hi and Hmi.

     (c)  The report must be submitted by the applicable date specified for final control plans in §117.510 of this title (relating to Compliance Schedule for Utility Electric Generation in Ozone Nonattainment Areas).  The plan must be updated with any emission compliance measurements submitted for units using continuous emissions monitoring system or predictive emissions monitoring system and complying with the system cap rolling 30-day average emission limit, according to the applicable schedule given in §117.510 of this title.

Adopted December 6, 2000, Effective January 18, 2001
**** end tx 117.116 adopted by TNRCC 12/06/2000 (7-19)**d29*ebze***c1e**


§117.117.  Revision of Final Control Plan.
As adopted by TNRCC April 19, 2000, effective May 11, 2000.
Approved by EPA October 26, 2000 (65 FR 64148), effective December 26, 2000.

     A revised final control plan may be submitted by the owner or operator, along with any required permit applications.  Such a plan shall adhere to the emission limits and the final compliance dates of this division (relating to Utility Electric Generation in Ozone Nonattainment Areas).  For sources complying with §117.105 of this title (relating to Emission Specifications for Reasonably Available Control Technology (RACT)), §117.106 of this title (relating to Emission Specifications for Attainment Demonstrations, or §117.107 of this title (relating to Alternative System-Wide Emission Specifications), replacement new units may be included in the control plan. The revision of the final control plan shall be subject to the review and approval of the executive director.

********************** end tx 117.117 *********eazs********b1c**


§117.119.  Notification, Recordkeeping, and Reporting Requirements.
As adopted by TNRCC September 26, 2001, effective October 18, 2001.
Approved by EPA November 14, 2001 (66 FR 57244) effective December 14, 2001.

     (a)  Start-up and shutdown records.  For units subject to the start-up and/or shutdown exemptions allowed under §101.11 of this title (relating to Demonstrations), hourly records shall be made of start-up and/or shutdown events and maintained for a period of at least two years.  Records shall be available for inspection by the executive director, EPA, and any local air pollution control agency having jurisdiction upon request.  These records shall include, but are not limited to:  type of fuel burned; quantity of each type fuel burned; gross and net energy production in megawatt-hours (MW-hr); and the date, time, and duration of the event.

     (b)  Notification.  The owner or operator of a unit subject to the emission specifications of this division (relating to Utility Electric Generation in Ozone Nonattainment Areas) shall submit notification to the appropriate regional office and any local air pollution control agency having jurisdiction as follows:

          (1)  verbal notification of the date of any initial demonstration of compliance testing conducted under §117.111 of this title (relating to Initial Demonstration of Compliance) at least 15 days prior to such date followed by written notification within 15 days after testing is completed; and

          (2)  verbal notification of the date of any continuous emissions monitoring system (CEMS) or predictive emissions monitoring system (PEMS) performance evaluation conducted under §117.113 of this title (relating to Continuous Demonstration of Compliance) at least 15 days prior to such date followed by written notification within 15 days after testing is completed.

     (c)  Reporting of test results.  The owner or operator of an affected unit shall furnish the Office of Compliance and Enforcement, the appropriate regional office, and any local air pollution control agency having jurisdiction a copy of any initial demonstration of compliance testing conducted under §117.111 of this title or any CEMS or PEMS performance evaluation conducted under §117.113 of this title:

          (1)  within 60 days after completion of such testing or evaluation; and

          (2)  not later than the appropriate compliance schedules specified in §117.510 of this title (relating to Compliance Schedule for Utility Electric Generation in Ozone Nonattainment Areas).

     (d)  Semiannual reports.  The owner or operator of a unit required to install a CEMS, PEMS, or steam-to-fuel or water-to-fuel ratio monitoring system under §117.113 of this title shall report in writing to the executive director on a semiannual basis any exceedance of the applicable emission limitations in this division and the monitoring system performance.  All reports shall be postmarked or received by the 30th day following the end of each calendar semiannual period.  Written reports shall include the following information:

          (1)  the magnitude of excess emissions computed in accordance with 40 Code of Federal Regulations (CFR), Part 60, §60.13(h), any conversion factors used, the date and time of commencement and completion of each time period of excess emissions, and the unit operating time during the reporting period:

               (A)  for stationary gas turbines using steam-to-fuel or water-to-fuel ratio monitoring to demonstrate compliance in accordance with §117.113 of this title, excess emissions are computed as each one-hour period during which the hourly steam-to-fuel or water-to-fuel ratio is less than the ratio determined to result in compliance during the initial demonstration of compliance test required by §117.111 of this title;

               (B)  for utility boilers complying with §117.108 of this title (relating to System Cap), excess emissions are each daily period for which the total nitrogen oxides (NOx) emissions exceed the rolling 30-day average or the maximum daily NOx cap;

          (2)  specific identification of each period of excess emissions that occurs during start-ups, shutdowns, and malfunctions of the affected unit.  The nature and cause of any malfunction (if known) and the corrective action taken or preventative measures adopted;

          (3)  the date and time identifying each period during which the continuous monitoring system was inoperative, except for zero and span checks and the nature of the system repairs or adjustments;

          (4)  when no excess emissions have occurred or the continuous monitoring system has not been inoperative, repaired, or adjusted, such information shall be stated in the report;

          (5)  if the total duration of excess emissions for the reporting period is less than 1.0% of the total unit operating time for the reporting period and the CEMS, PEMS, or steam-to-fuel or water-to-fuel ratio monitoring system downtime for the reporting period is less than 5.0% of the total unit operating time for the reporting period, only a summary report form (as outlined in the latest edition of the commission's "Guidance for Preparation of Summary, Excess Emission, and Continuous
 Monitoring System Reports") shall be submitted, unless otherwise requested by the executive director.  If the total duration of excess emissions for the reporting period is greater than or equal to 1.0% of the total operating time for the reporting period or the CEMS or steam-to-fuel or water-to-fuel ratio monitoring system downtime for the reporting period is greater than or equal to 5.0% of the total operating time for the reporting period, a summary report and an excess emission report shall both be submitted.

     (e)  Recordkeeping.  The owner or operator of a unit subject to the requirements of this division shall maintain records of the data specified in this subsection.  Records shall be kept for a period of at least five years and made available for inspection by the executive director, EPA, or local air pollution control agencies having jurisdiction upon request.  Operating records for each unit shall be recorded and maintained at a frequency equal to the applicable emission specification averaging period, or for units claimed exempt from the emission specifications based on low annual capacity factor, monthly.  Records shall include:

          (1)  emission rates in units of the applicable standards;

          (2)  gross energy production in MW-hr (not applicable to auxiliary boilers);

          (3)  quantity and type of fuel burned;

          (4)  the injection rate of reactant chemicals (if applicable); and

          (5)  emission monitoring data, in accordance with §117.113 of this title, including:

               (A)  the date, time, and duration of any malfunction in the operation of the monitoring system, except for zero and span checks, if applicable, and a description of system repairs and adjustments undertaken during each period;

               (B)  the results of initial certification testing, evaluations, calibrations, checks, adjustments, and maintenance of CEMS, PEMS, or operating parameter monitoring systems; and

               (C)  actual emissions or operating parameter measurements, as applicable;

          (6)  the results of performance testing, including initial demonstration of compliance testing conducted in accordance with §117.111 of this title; and

          (7)  records of hours of operation.

Adopted September 26, 2001, Effective October 18, 2001
**** end tx 117.119 adopted by TNRCC 09/26/2001 (7-21)**d29*ebze***c1e**

§117.121.  Alternative Case Specific Specifications.
As adopted by TNRCC December 6, 2000, effective January 18, 2001.
Approved by EPA November 14, 2001 (66 FR 57244) effective December 14, 2001.

     (a)  Where a person can demonstrate that an affected unit cannot attain the applicable requirements of §117.105 of this title (relating to Emission Specifications for Reasonably Available Control Technology (RACT)), or the carbon monoxide (CO) or ammonia limits of §117.106(d) of this title (relating to Emission Specifications for Attainment Demonstrations), the executive director may approve emission specifications different from §117.105 of this title or the CO or ammonia limits in §117.106(d) of this title for that unit.  The executive director:

          (1)  shall consider on a case-by-case basis the technological and economic circumstances of the individual unit;

          (2)  must determine that such specifications are the result of the lowest emission limitation the unit is capable of meeting after the application of reasonably available control technology; and

          (3)  in determining whether to approve alternative emission specifications, may take into consideration the ability of the plant at which the unit is located to meet emission specifications through system-wide averaging at maximum capacity.

     (b)  Any person affected by the executive director's decision to deny an alternative case specific emission specification may file a motion for reconsideration.  The requirements of §50.39 of this title (relating to Motion for Reconsideration) or §50.139 of this title (relating to Overturn Executive Director’s Decision) apply.  However, only a person affected may file a motion for reconsideration.  Executive director approval does not necessarily constitute satisfaction of all federal requirements nor eliminate the need for approval by the EPA in cases where specified criteria for determining equivalency have not been clearly identified in applicable sections of this division (relating to Utility Electric Generation in Ozone Nonattainment Areas).

Adopted December 6, 2000, Effective January 18, 2001
**** end tx 117.121 adopted by TNRCC 12/06/2000 (7-19)**d29*ebze***c1e**
******* end tnrcc reg 7 subchapter b division 1 *********ebze***c1e**