### Page 1 of 29 Subpart KKKK—Standards of Performance for Stationary Combustion Turbines

Introduction §60.4300 What is the purpose of this subpart? This subpart establishes emission standards and compliance schedules for the control of emissions from stationary combustion turbines that commenced construction, modification, or reconstruction after February 18, 2005. Applicability §60.4305 Does this subpart apply to my stationary combustion turbine? (a) You are subject to this subpart if you own or operate a stationary combustion turbine that commenced construction, modification, or reconstruction after February 18, 2005, and that has a base load rating equal to or greater than 2.9 megawatts (MW) (10 million British thermal units per hour (MMBtu/h)), except as provided for in §60.4310. Any additional heat input from duct burners us ed with heat recovery steam generating units or fuel preheaters is not included in the heat input value used to determine the applicability of this subpart to a given stationary combustion turbine. (b) For the purpose of this subpart, only the combustion turbine engine itself is used to determine whether the affected facility is new or reconstruc ted. Other equipment included in the definition of a stationary combustion turbine is not included when determining if a facility is new or reconstructed. (c) A combustion turbine engine subject to this subpa rt is not subject to subpart GG of this part. (d) Duct burners that do not burn any solid fuels when used with a heat recovery steam generating unit that is part of either a combined cycle combustion turbine or a combined heat and power (CHP) combustion turbine subject to this subpart are not subject to subpart D, Da, Db, or Dc of this part, as applicable. (e) If you own or operate either a stationary combustion turbine (including a combined cycle combustion turbine or a CHP combustion turbine) that commenced construc tion, modification, or reconstruction on or before February 18, 2005, you may submit a written petition to the Administrator requesting that the stationary combustion turbine be allowed to complywith the applicable requirements for modified units under this subpart as an alternative to complying with subpart GG of this pa rt, and with subparts D, Da, Db, and Dc of this part, as applicable. If the Administrator or de legated authority a pproves the petitioner’s request, the affected facility must comply with the requirements for modified units under this subpart unless the combustion turbine engine is reconstructed or replaced with a new facility in the future. (f) If you are an owner or operator of a non-major source subject to this subpart, you are exempt from the obligation to obtain a permit under 40 CFR part 70 or 40 CFR part 71, provided you are not required to obtain a permit under 40 CFR 70.3(a) or 40 CFR 71.3(a) for a reason other than your status as a non-major source under this subpart. Notwithstanding the previous sentence, you must continue to comply with the provisions of this subpart, as applicable. §60.4310 What stationary combustion turbines are not subject to this subpart? (a) An integrated gasification combinedcycle electric utility steam generating unit subject to subpart Da of this part is not subject to this subpart. (b) A stationary combustion turbine used in a combustion turbine test cell/stand as defined in §60.4420 is not subject to this subpart. (c) A stationary combustion turbine subject to subpart Ea, subpart Eb, or subpart AAAA of this part is not subject to this subpart. (d) A stationary combustion turbine subject to an EPA approved State or Federal plan implementing under authority of Clean Air Act sections 1 11(d)/129 either subpart Cb or subpart BBBB of this part is not subject to this subpart.

Emission Standards §60.4315 What pollutants are regulated by this subpart? The pollutants regulated by this subpart are nitrogen oxides (NO X ) and sulfur dioxide (SO 2 ).
§60.4320 What NO Xemissions standard must I meet? Comment [CF1]: The turbine engine is the technology that controls emissions. If it is new or reconstructed that emissions standard must apply. When a turbine is replaced at a combined cycle or CHP facility with a new turbine it is considered a new stationary combustion turbine and not reconstructed. If an affected facility adds a HRSG to an existing turbine it is still covered by subpart GG and D, Da, Db, or Dc.
Comment [CF2]: HRSG burning a solid fuel would also have to comply with one of the steam generating units NSPS (D, Da, Db, or Dc).
Comment [CF3]: Allow units to comply with subpart KKKK in place of GG and D, Da, Db, Dc.

Comment [CF4]: Clarify title V exemption

Comment [CF5]: Exempt turbines covered by the MSW rules from all the requirements (recordkeeping, reporting, emission standards, etc) of subpart KKKK.

### Page 2 of 29 (a) For each simple cycle stationary combustion turbine, except as provided for in paragraph (d) of this section, you must not discharge into the atmosphere from the affected facility any gases that contain NO X in excess of the applicable emissions standard as determined on a 4-operating hour basis and according to the requirements specified in paragraph (c) of this section. (b) For each combined-cycle combustion turbine or CHP combustion turbine except as provided for in paragraph (d) of this section, you must not discharge into the atmo sphere from the affected facility any gases that contain NO X into the atmosphere from the affected facility in excess of the applicable emissions standard on a 30- operating day basis and according to the requirements specified in paragraph (c) of this section. (c) For the purpose of determining compliance with the applicable emissions standard in paragraphs (a) and (b) of this section, you must meet the requirements specified in paragraphs (c)(1) through (c)(4), as applicable to your affected facility. (1) The NO X emissions standard that is applicable to your a ffected facility shall be determined on an operating hour basis except as provided for in paragraph (c)(2) of this section. Determining the hourly NO X emission standards for your affe cted facility requires record ing hourly data and maintain ing records according to the requirements in §60.4390. (2) As an alternative to the requirements specified in paragraph (c)(1) of this section, you may elect to use the lowest emissions standard determined using Table 1 of this subpart that is applicable to your affected facility for the entire required compliance period. (3) During each operating hour when only natural gas is combusted in the combustion turbine engine, you must meet the applicable NO X emissions standard determined using Table 1 of this subpart for a stationary combustion firing natural gas. During each operating hour when any fuel other than natural gas is combusted in the combustion turbine engine, you must meet the applicable NO X emissions standard determined using Table 1 of this subpart for a stationary combustion firing fuels other than natural gas. If multiple fuels are combusted during a given operating hour, then the highest applicable NO X emissions standard is applied for the entire operating hour. (4) If you have two or more combustion turbine engine s connected to a single electric generator, each of the combustion turbine engines must meet the applicable NO X emissions standard determined using Table 1 of this subpart. (d) Stationary combustion turbines specified in paragraphs (d)(1) through (3) of this section are exempt from the applicable NO X emissions standard in paragraphs (a) and (b) of this section. (1) An emergency combustion turbine, as defined in §60.4420; (2) A stationary combustion turbine used for research and development of equipment for combustion turbine emissions control techniques or efficiency improvements as determined by the Administrator or delegated authority on a case-by-case basis; and (3) A stationary combustion turbine that combus ts byproduct fuels for wh ich a facility-specific NO X emissions standard has been established by the Administrator according to the requirements of paragraphs (d)(3)(i) and (ii). (i) You may request a facility-specific NO X emissions standard by submitting a written request to the Administrator or delegated authority explaining why your affected facility when burning the byproduct fuel is unable to comply with the applicable NO X emissions standard determined using Table 1 of this subpart. (ii) If the Administrator approves the request, a letter will be sent to the facility desc ribing the facility-specific NO X emissions standard. You must use the compliance procedures detailed in the letter and make the letter available to the public. If the Administrator determines itis appropriate, the condition s and requirements of the letter can be reviewed and changed at any point. (e) For affected facilities for whic h construction, modifica tion, or reconstruction commenced before [INSERT DATE 1 DAY AFTER PUBLICATION IN THE FEDERAL REGISTER], you must meet the NO X emissions standard applicable under this section to your affected facility during all times when the affected facility is operating except during periods of startup, shutdown, or malfunction. For each affected facility for which construction, reconstruction, or modification comm enced after [INSERT DATE OF PUBLICATION IN THE FEDERAL REGISTER], you must meet the NO X emissions standard applicable under this section to your affected facility during all times when the affected facility is operating (inc luding periods of startup, shutdown, Comment [CF6]: Add in equations to clarify how units with CEMS demonstrate compliance continuous compliance. The heat-input weighted average must be used for the lb/MWh and new lb/MMBtu options. The ppm option uses just the simple numerical average – compliance easier since no need to measure fuel use at the same time.

Comment [CF7]: Take comment on changing 4- hour average to an operating daily average with minimum of 3 hours of data or roll data over to next operating day

Comment [CF8]: Require the natural gas standard only if the fuel combusted in the turbine engine meets the definition of natural gas for the entire operating hou r

Comment [CF9]: Add in ability to petition for facility-specific NOx standard – similar to subpart Db.

### Page 3 of 29 and malfunction).
§60.4330 What SO 2 emissions standard must I meet? (a) For each stationary combustion turbine, except as provided for in paragraphs (b) through (g) of this section, you must not cause to be discharged into the atmosphere from the affect ed facility any gases that contain SO 2 in excess of either: (1) 110 nanograms per Joule (ng/J) (0.90 pounds per megawatt-hour (lb/MWh)) gross energy output; or (2) 26 ng SO 2 /J (0.060 lb SO 2 /MMBtu) heat input. (b) As an alternative to the requirements of paragraph (a) of this section, for each stationary combustion turbine combusting 50 percent or more low-Btu gas per calendar month based on total heat input using the higher heating value of the fuel, you may limit the sulfur content of the fuel to no more than either: (1) 650 milligrams of sulfur per standard cubic meter (mg/scm) (28 grains (gr) of sulfur per 100 standard cubic feet (scf)); or (2) 65 ng SO 2 /J (0.15 lb SO 2 /MMBtu) heat input. (c) For each stationary combustion turbine located in a noncontinental area, you must not cause to be discharged into the atmosphere from the affected facility any gases that contains SO 2 in excess of either: (1) 780 ng/J (6.2 lb/MWh) gross energy output; or (2) 180 ng SO 2 /J (0.42 lb SO 2 /MMBtu) heat input. (d) For each stationary combustion tu rbine for which the Administrator determ ines that the aff ected facility does not have access to natural gas and the removal of sulfur compounds from the fuel would cause more environmental harm than benefit, you must not cause to be discharged into the atmosphere from the affected facility any gases that contain SO 2 in excess of either: (1) 780 ng/J (6.2 lb/MWh) gross energy output; or (2) 180 ng SO 2 /J (0.42 lb SO 2 /MMBtu) heat input. (e) A stationary combustion turbine that is subject to SO 2 emission standards under either subpart J or Ja of this part is not subject to the SO 2 emission standards in this subpart. (f) A combustion turbine that is subject to a federally enforceable requirement limiting the sulfur content of gaseous fuels combusted in the stationary combustion turbine to no more than 460 mg/scm (20 gr/100 scf) and/or for liquid fuels no more than 0.050 weight percent sulfur is not subject to the SO 2 emission standards in this subpart. (g) For affected facilities for which construction, mo dification, or reconstructi on commenced before [INSERT DATE 1 DAY AFTER PUBLICATION IN THE FEDERAL REGISTER], you must meet the SO 2 emissions standard applicable under this section to your affected facility during all times whenthe affected facility is operating except during periods of startup, shutdown, or malfunction. For each affected facility for which construction, reconstruction, or modification comm enced after [INSERT DATE OF PUBLICATION IN THE FEDERAL REGISTER], you must meet the SO 2 emissions standard applicable under this section to your affected facility during all times when the aff ected facility is operating (including periods of startup, shutdown, and malfunction). General Compliance Requirements §60.4333 What are my general requirements for complying with this subpart? (a) You must operate and maintain your stationary co mbustion turbine, air pollution control equipment, and monitoring equipment in a manner consistent with good air pollution control practices for minimizing emissions at all times including during startup, shutdown, and malfunction. (b) If you own or operate a stationary combustion turbine subject to a NO X emissions standard in §60.4320, you must conduct an initial performance test according to §60.8 using the applicable methods in §60.4400 or §60.4405. Thereafter, unless you perform continuous monitoring consistent with §§60.4335, 60.4340(b), or 60.4345, you must conduct subsequent performance tests according to the applicable requirements in paragraphs (b)(1) through (b)(6) of this section. (1) Except as provided for in paragraphs (b)(2) through (b)(5) of this section, you must conduct subsequent Comment [CF10]: Amended language allows for fuel mixing to achieve the SO2 standard.
Comment [CF11]: Add in equations to clarify how units with CEMS demonstrate compliance continuous compliance. The heat-input weighted average must be used for the lb/MWh and new lb/MMBtu options. The ppm option uses just the simple numerical average – compliance easier since no need to measure fuel use at the same time.

Comment [CF12]: Changed biogas to low-Btu
gas

Comment [CF13]: Add in equivalent concentration based alternative approximately equivalent to 500 ppm S by volume

Comment [CF14]: SO 2 standards in J and Ja more stringent than on KKKK. Amendment lowers burden and does not increase emissions.

Comment [CF15]: Simplify compliance by exempting owner/operators of affected facilities burning only pipeline quality natural gas and 500 ppm S distillate oil from the SO 2 standard. Both fuels have potential SO 2 emissions of less than 0.060 lb/MMBtu.

Comment [CF16]: Facilities with water/steam injection, parametric monitoring, or CEMS not required to perform an annual test.

### Page 4 of 29 performance tests within 12 calendar months following the date the previous performance test was required to be conducted. Performance tests must be separated by a minimum of 9 calendar months. (2) If the NO X emission result from the most recent performance test is less than or equal to 75 percent of the NO X emissions standard for the stationary combustion turbine, you may reduce the frequency of subsequent performance tests to 24 calendar months following the date the previous performance test was required to be conducted. Performance tests must be separated by a minimum of 21 calendar months. If the results of any subsequent performance test exceed 75 percent of the NO X emissions standard for the stationary combustion turbine, you must resume annual performance testing. (3) An affected facility that has not op erated for the 60 calendar days prior to the due date of a performance test is not required to perform the subsequent performance test until 45 calendar days after the next operating day. The delegated permitting authority must be notified of reco mmencement of operation consistent with §60.4375(d). (4) If you own or operate an affected facility that has operated 50 operating hours or less in total or with a particular fuel since the date the previous performance test was required to be conducted you may request an extension from the otherwise required pe rformance test until after the affected facility has operate d more than 50 operating hours in total or with a particular fuel since the date of the previous performance test was required to be conducted. A request for an extension under this paragraph must be addressed to the relevant air division or office director of the appropriate Regional Office of the U.S. EPA as identified in §60.4(a) for his or her approval at least 30 calendar days prior to the date on which the performance test is required to be conducted. If an exemption is approved, a performance test must be conducted within 45 calendar days after the day the facility reaches 50 hours of operation since the date the previous performance test was required to be conducted. When the facility has operated more than 50 operating hours since the date the previous performance test was required to be conducted, the delegated permitting authority must be notified consistent with §60.4375(e). (5) For a facility at which a group consisting of no more than five similar stationary combustion turbines (i.e., same manufacturer and model number) is operated, you may request the use of a custom testing schedule by submitting a written request to the Administrator or delegated authority. The minimum requirements of the custom schedule include the conditions specified in paragraphs (5)(i) through (v) of this section. (i) Emissions from the most recent performance test for each individual affected facility are 75 percent or less of the applicable standard; (ii) Each stationary combustion turbine uses the same emissions control technology; (iii) Each stationary co mbustion turbine is operated in a similar manner; (iv) Each stationary combustion turbine and its emissions control equipment are maintained according to the manufacturer’s recommended maintenance procedures; and (v) A performance test is conductedon each affected facility at le ast once every 5 calendar years. (6) A stationary combustion turbine subject to a NO X emissions standard in §60.4320 that exchanges the combustion turbine engine for an overhauled combustion turbine engine as part of an exchange program, must conduct an initial performance te st according to §60.8 using the applicable methods in §60.4400. (c) Except as provided for in paragraphs (c)(1) or (2) of this section, for each stationary combustion turbine subject to a NO X emissions standard in §60.4320, you must demonstrate continuous compliance using a continuous emissions monitoring system (CEMS) for measuring NO X emissions according to the provisions in §60.4345. If your stationary combustion turbine is equipped with a NO X CEMS, those measurements must be used to determine excess emissions. (1) If your stationary combustion turbine uses water or steam injection but not post-combustion controls to meet the applicable NO X emissions standard in §60.4320, you may elect to demonstrate continuous compliance using either the pounds per million British th ermal units (lb/MMBtu) or the part pe r million (ppm) standard according to the provisions in §60.4335. (2) If your stationary combustion turbine does not use water injection, steam injection, or post-combustion controls to meet the applicable NO X emissions standard in §60.4320, you may elect to demonstrate continuous compliance with either the lb/MMBtu or ppm standard according to the provisions in §60.4340. (d) An owner or operator of a stationary combustion turbine subject to an SO 2 emissions standard in §60.4330 must demonstrate compliance using one of the methods specified in paragraphs (d)(1) through (4) of this section. Comment [CF17]: Avoid consecutive testing that would satisfy 2 years requirements. Allow to test 3 months early.

Comment [CF18]: Add automatic extension of performance test requirement for owner/operators of turbines that are not operating.

Comment [CF19]: Add ability of low capacity factor turbines to request an extension on the date of the required performance test. Fuel specific so can request extension on rarely fired backup fuels as well.

Comment [CF20]: Multiple similar units only have to test once every 5 years. Since less that 75% of applicable standard is required 60.4333(b)(2) automatically applies

Comment [CF21]: Turbine that are replaced as part of a turbine replacement maintenance program must be tested upon startup
Comment [CF22]: Turbine that are replaced as part of a turbine replacement maintenance program must be tested upon startup

Comment [CF23]: If facility has a CEMS it must use the readings to report excess emissions.

Comment [CF24]: Sections 60.4335 and 60.4340 do not require monitoring of the output so have to comply with one of the input-based options.

### Page 5 of 29 (1) Conduct an initial performance test according to §60.8 and use the applicable methods in §60.4415. Thereafter, you must conduct subsequent performance tests within 12 calendar months following the date the previous performance test was required to be conducted. Performance tests must be separated by a minimum of 9 calendar months. An affected facility that has not operate d for the 60 calendar days prior to the due date of a performance test is not required to perform the subsequent performance test until 45 calendar days after the next operating day; (2) Conduct an initial performance test according to §60.8 and use the applicable methods in §60.4415. Thereafter, conduct subsequent fuel sulfur analyses usin g the applicable methods specified in §60.4360 and at the frequency specified in §60.4365; (3) Conduct an initial performance test according to §60.8 and use the applicable methods in §60.4415. Thereafter, maintain records (such as a current, valid pu rchase contract, tariff sheet, or transportation contract) documenting that total sulfur content fo r the initial and subsequent fuel combusted in your stationary combustion turbine at all times does not exceed applicable conditions specified in §60.4370; or (4) Conduct an initial performance test according to §60.8 using the applicab le methods in §60.4415. Thereafter, continue to monitor SO 2 emissions using a CEMS according to the requirements specified in §60.4372. (e) If you elect to comply with an input-based standard (lb/MMBtu) and your affected facility includes use of one or more heat recovery steam generating units, then you must determine compliance with the applicable NO X and SO 2 emission standards according to the procedures specified in paragraphs (e)(1) or (2) of this section as applicable to the heat recovery steam generating un it configuration used for your affected facility. (1) For a configuration where a single combustion turbine engine is exhausted through the heat recovery steam generating unit, you must measure both the emissions at the exhaust stack for the heat recovery steam generating unit and the fuel flow to the combustion turbine engine and any associated duct burners. (2) For a configuration where two or more combustion turbine engines are exhausted through a heat recovery steam generating unit, you must measure both the total emissions at the exhaust stack for the heat recovery steam generating unit and the total fuel flow to each combusti on turbine engine and any associated duct burners. The applicable emissions standard for the affected facility is equal to the most stringent emissions standard for any individual combustion turbine engine. (f) If you elect to comply with an output-based standard (lb/MWh) and your affected facility includes use of one or more heat recovery steam generating units, then you must determine compliance with the applicable NO X and SO 2 emission standards according to the procedures in paragraphs (f)(1), (2), or (3) of this section as applicable to the heat recovery steam generating unit conf iguration used for your affected facility. (1) For a configuration where a single combustion turbine engine is exhausted through the heat recovery steam generating unit, you must measure both the emissions at the exhaust stack for the heat recovery steam generating unit and the total electrical, mechanical energy, and useful thermal output of the stationary combustion turbine (as applicable). (2) For a configuration where two or more combustion turbine engines are exhausted through a single heat recovery steam generating unit, you must measure both the total emissions at the exhaust stack for the heat recovery steam generating unit, and the total electrical, m echanical energy, and useful thermal output of the heat recovery steam generating unit and each combustion turbine engine (as applicable). The applicable emissions standard for the affected facility is equal to the most stringent emissions st andard for any individual combustion turbine engines. (3) For a configuration where your combustion turbine engines are exhausted through two or more heat recovery steam generating units which serve a common steam turbine or steam header, you must measure both the emissions at the exhaust stack for each heat recovery steam generating unit and the total electrical or mechanical energy output of each combustion turbine engine (as applicable). To determine the gross energy output of the steam produced by the heat recovery steam generating unit, you must develop a custom method and provide information, satisfactory to the Admini strator or delegated authority, apportioning the gross energy output of the steam produced by the heat recovery steam generating units to each of the affected stationary combustion turbines. §60.4334 Affirmative Defense for Violation of Emission Standards During Malfunction. In response to an action to enforce the standards set forth in paragraphs §§60.4320 and 60.4330 you may assert an Comment [CF25]: Add in grace period so facilities do not have to startup just to test.

Comment [CF26]: Clarify procedures to address more complicated (interconnected) configurations.

Comment [CF27]: Essentially treat the configuration as a single affected facility except new and reconstruction is based on each individual turbine engine and the applicable standard is the most stringent standard for each turbine.
Comment [CF28]: Include SO2 in output based option since might be firing fuel that does not meet input based standard.

Comment [CF29]: Essentially treat the configuration as a single affected facility except new and reconstruction is based on each individual turbine engine and the applicable standard is the most stringent standard for each turbine.

### Page 6 of 29 affirmative defense to a claim for civil penalties for violations of such standards that are caused by malfunction, as defined at 40 CFR 60.2. Appropriate penalties may be assessed; however, if you fail to meet your burden of proving all of the requirements in the affirmative defense, the affirmative defense shall not be available for claims for injunctive relief. (a) To establish the affirmative defense in any action to enforce such a standard, you must timely meet the reporting requirements in paragraph (b) of this section, and must prove by a preponderance of evidence that: (1) The violation: (i) Was caused by a sudden, infrequent, and unavoidable failure of air pollution control equipment, process equipment, or a process to operate in a normal or usual manner, and (ii) Could not have been prevented through careful planning, proper design or better operation and maintenance practices; and (iii) Did not stem from any activity or event that could have been foreseen and avoided, or planned for; and (iv) Was not part of a recurring pattern indicative of inadequate design, operation, or maintenance; and (2) Repairs were made as expeditiously as possible when a violation occurred. Off-shift and overtime labor were used, to the extent practicable to make these repairs; and (3) The frequency, amount and duration of the violation (including any bypass) were minimized to the maximum extent practicable; and (4) If the violation resulted from a bypass of control equipment or a process, then the bypass was unavoidable to prevent loss of life, personal injury, or severe property damage; and (5) All possible steps were taken to minimize the impact of the violation on ambient air quality, the environment, and human health; and (6) All emissions monitoring and control systems were kept in operation if at all possib le, consistent with safety and good air pollution control practices; and (7) All of the actions in response to the violation were documented by properly signed, contemporaneous operating logs; and (8) At all times, the affected source was operated in a manner consistent with good practices for minimizing emissions; and (9) A written root cause analysis has been prepared, the purpose of which is to determine, correct, and eliminate the primary causes of the malfunction and the violation resulting from the malfunction event at issue. The analysis must also specify, using best monitoring methods and engineering judgment, the amount of any emissions that were the result of the malfunction. (b) Report. The owner or operator seeking to assert an affirmative defense shall submit a written report to the Administrator or delegated authority with all nece ssary supporting documentation, that it has met the requirements set forth in paragraph (a) of this section. This affirmative defense report shall be included in the first periodic compliance, deviation report or excess emission report otherwise required after the initial occurrence of the violation of the relevant standard (which may be the end of any applicable averaging period). If such compliance, deviation report or excess emission report is due less than 45 days after the initial occurrence of the violation, the affirmative defense report may be include d in the second compliance, deviation report, or excess emission report due after the initial occurrence of the violatio n of the relevant standard. Monitoring §60.4335 How do I demonstrate compliance with my NO X emissions standard without using a NO XCEMS if I use water or steam injection? If you qualify and elect to demonstrate continuous compliance according to the provisions of §60.4333(c)(1), you must install, calibrate, maintain, and operate a continuous monitoring system to monitor and record the fuel consumption and the ratio of water or steam to fuel fired in the combustion turbine engine consistent with the requirements in §60.4342. Water or steam only needs to be injected when a fuel is being combusted that requires water or steam injection for compliance with the applicable NO X emissions standard. §60.4340 How do I demonstrate compliance with my NO X emissions standard without using a NO XCEMS if I do not use water or steam injection?

### Page 7 of 29 (a) If you qualify and elect to demonstrate continuous compliance according to the provisions of §60.4333(c)(2), you must demonstrate compliance with the NO X emissions standard using the methods specified in either paragraphs (a)(1) through (3) of this section. (1) Conduct performance tests according to requirements in §60.4400; (2) Monitor the NO X emissions rate using the methodology in appendixE to part 75 of this chapter, or the low mass emissions methodology in §75.19; or (3) Install, calibrate, maintain, and operate an operating parameter continuous monitoring system according to the requirements specified in paragraph (b) of this section a nd consistent with the requirements specified in §60.4342. (b) Continuous operating parameter monitoring must be performed using the methods specified in paragraphs (b)(1) through (4) of this section as applicable to the stationary combustion turbine. (1) Selection of the operating parameters used to comp ly with this paragraph mu st be identified in the performance test report, and are subject to the review and approval of the delegated permitting authority. (2) For a lean premix stationary combustion turbine, you must continuously monitor the appropriate parameters to determine whether the unitis operating in low-NO Xmode when low-NO X operation is required to comply with the applicable emission NO X standard. (3) For a stationary combustion turbine other than a lean premix stationary combustion turbine, you must define parameters indicative of the unit's NO X formation characteristics, and monitor these parameters continuously. (4) You must perform the parametric monitoring described in section 2.3 in appendix E to part 75 of this chapter or in §75.19(c)(1)(iv)(H).
§60.4342 How do I monitor NO X control operating parameters? (a) If you monitor steam or water to fuel ratio according to §60.4335 or other parameters according to §60.4340, the applicable parameters must be continuously monitored and recorded during the performance test, to establish acceptable values and ranges. You may supplement the performance test data with engineering analyses, design specifications, manufacturer's recommendations, and other relevant information to define the acceptable parametric ranges more precisely. You must develop and keep on-site a parameter monitoring plan which explains the procedures used to document proper operation of the NO X emission controls. The plan must include the information specified in paragraphs (a)(1) through (6) of this section: (1) Identification of the parameters to be monitored and show there is a significant relationship to emissions and proper operation of the NO X emission controls; (2) Selected parameter ranges (or designated conditions) indi cative of proper operation of the stationary combustion turbine NO X emission controls, or describe the process by which such range (or designated condition) will be established; (3) Explanation of the process you will use to make certain that you obtain data that are representative of the emissions or parameters being monitored (such as detect or location, installation sp ecification if applicable); (4) Description of quality assurance and control practices used to ensure the continuing validity of the data; (5) Description of the frequency of monitoring and the data collection pro cedures which you will use (e.g., you are using a computerized data acquisitio n over a number of discrete data points with the average (or maximum value) being used for purposes of determining whether an exceedance has occurred); and (6) Justification for the proposed elements of the mo nitoring. If a proposed performance specification differs from manufacturer recommendation, you must explain the reasons for the differences. You must submit the data supporting the justification, but you may refer to generally available sources of information used to support the justification. You may rely on engineering assessments and other data, provided you demonstrate factors which assure compliance or explain why performance testing is unnecessary to establish indicator ranges. (b) The ratio of water or steam to fuel and parameter continuous monitoring system ranges must be reestablished at least 60 calendar months followi ng the previous calibration and each time the combustion turbine engine is replaced with an overhau led turbine engine as part of an exchange program. An af fected facility that has not operated for 60 calendar days prior to the due date of a recalibration you are not required to perform the subsequent recalibration until 45 calendar days after the next operating day. §60.4345 How do I demonstrate compliance with my NO X emissions standard using a NO XCEMS? Comment [CF30]: NOx estimation protocol for gas-fired peaking and oil-fired peaking. Allow without approval.
Comment [CF31]: Optional SO2, NOx, and CO2 emission calculation for low mass emissions (LME) units. Low mass emissions excepted methodology, calculations, and values. Allow without approval.

Comment [CF32]: Add in 60 month performance test to assure the control is still working properly.

Comment [CF33]: Add in grace period so facilities do not have to startup just to verify calibration.

### Page 8 of 29 (a) Each CEMS measuring NO X emissions used to meet the requirements of this subpart, must meet the requirements in paragraphs (a)(1) through (7) of this section. (1) You must install, certify, maintain, and operate a NO X monitor to determine the hourly average NO X emissions in the units of the standard with which you are complying; (2) If you elect to comply with the ppm emissions standard, you must also install a diluent gas (oxygen (O 2 ) or carbon dioxide (CO 2 )) monitor; (3) If you elect to comply with an input-based emissi ons standard, you must instal l, calibrate, maintain, and operate either a fuel flow meter (or flow meters) or an O 2 or CO 2 CEMS and a stack flow meter to continuously measure the heat input to the affected facility; (4) If you elect to comply with an output-based emissions standard, you must also inst all, calibrate, maintain, and operate both a watt meter (or meters) to continuously measure the gross electrical output from the affected facility and a stack flow meter. If you have a CHP combustion turbine and elect to comply with an output-based emissions standard, you must also install, calibrate, ma intain, and operate meters to continuously determine the total useful recovered thermal energy. For steam this includes flow rate, temperature, and pressure. If you have a direct mechanical dive application and elect to comply w ith the output-based emission s standard you must submit a plan to the Administrator or delegated authority for approval of how gross energy output will be determined. (5) If you elect to comply with the part load NO X emissions standard, you must install, calibrate, maintain, and operate either a fuel flow meter (or flow meters) or an O 2 or CO 2 CEMS and a stack flow meter to continuously measure the heat input to the affected facility. (6) If you elect to comply with the temperature dependent NO X emissions standard, you must install, calibrate, maintain, and operate a thermo meter to continuously monito r the ambient temperature. (7) If you burn natural gas with fuels other than natural gas and elect to comply with the fuels other than natural gas NO X emissions standard, you must install, calibrate, ma intain, and operate a device to continuously monitor when a fuel other than natural gas fuel is combusted in the combustion turbine engine. (b) Each NO X CEMS must be installed and certified according to Performance Specification 2 (PS 2) in appendix B to this part. The span value must be 125 percent of the highest applicable standard or highest anticipated hourly NO X emissions rate. For stationary combustion turbines that do not use post-combustion technology to reduce emissions of NO X to comply with the requirements of this subpart, the delegated permitting authority may approve the use of the NO X and diluent CEMS that are installed and certified according to appendix A of part 75 of this chapter in lieu of Procedure 1 in appendix F to this part and the requirements of §60.13 of this part, except that the relative accuracy test audit (RATA) of the CEMS must be performed on a lb/MMBtu basis. (c) During each full operating hour, both the NO X monitor and the diluent monitor must complete a minimum of one cycle of operation (sampling, analyzing, and data recording) for each 15-minute quadrant of the hour. For partial operating hours, at least one data point must be obtained with each monitor for each quadrant of the hour in which the unit operates. For operating hours in which required quality assurance and maintenance activities are performed on the CEMS, a minimum of two data points (one in each of two quadrants) are required for each monitor. (d) Each fuel flow meter must be installed, calibrated, maintained, and operated according to the manufacturer's instructions. Alternatively fuel flow meters that meet the installation, certification, and quality assurance requirements in appendix D to part 75 of this chapter are acceptable for use under this subpart. (e) Each watt meter, steam flow meter, and each pressure or temperature measurement device must be installed, calibrated, maintained, and operated according to manufacturer's instructions. (f) You must develop, submit to the delegated permitting authority for approv al, maintain, and adhere to an onsite quality assurance (QA) plan for all of the continuous monitoring equipment you use to comply with this subpart. At a minimum, such a QA plan must address the requirements of §§60.13(d), (e), and (h) of this part. For the CEMS and fuel flow meters, the owner or operator of a stationary combustion turbine that does not use post combustion technology to reduce emissions of NO X to comply with the requirements of this subpart may, with approval of the delegated permitting au thority, satisfy the requirements of this paragraph by implementing the QA program and plan described in section 1 in appendix B to part 75 of this chapter in lieu of the requirements in §60.13(d)(1). Comment [CF34]: Mechanical output not as straight forward to measure as electrical output in all situations.

Comment [CF35]: Specifications and test procedures.

Comment [CF36]: Optional SO2 emissions data protocol for gas-fired and oil-fired units. Allow without approval.

Comment [CF37]: Quality assurance and quality control procedures

### Page 9 of 29 §60.4350 How do I use the NO X CEMS data to determine excess emissions? (a) If you demonstrate continuous compliance using a CEMS for measuring NO X emissions, excess emissions are defined as the applicable compliance period for the stationary combustion turbine (either 4-operating hours or 30- operating days), during which the average NO X emissions from your affected facility measured by the CEMS is greater than the applicable maximum allowable NO X emissions standard specified in §60.4320 as determined using the procedures specified in this section that apply to your stationary combustion turbine. (b) The NO X CEMS data for each operating hour as measured according to the requirements in §60.4345 must be used to determine the hourly average NO X emissions. The hourly average for a given operating hour is the average of all data points for the operating hour. However, for any periods during which the NO X , diluent, flow, watt, steam pressure, or steam temperature monitors (as applicable) are out-of-control, the data points are not used in determining the hourly average NO X emissions. All data points that are not collected during out-of-control periods must be used to determine the hourly average NO X emissions. (c) For each operating hour in which an hourly average is obtained, the data acquisition and handling system must calculate and record the hourly average NO X emissions in units of ppm or lb/MMBtu, using the appropriate equation from EPA Method 19 in appendix A-7 of this part. For any hour in which the hourly average O 2 concentration exceeds 19.0 percent O 2 (or the hourly average CO 2 concentration is less than 1.0 percent CO 2 ), a diluent cap value of 19.0 percent O 2 or 1.0 percent CO 2 (as applicable) may be used in the emission calculations. (d) Correction of measured NO X concentrations to 15 percent O 2 is only allowed if you elect to comply with the ppm standard in Table 1. (e) Data used to meet the requirements of this subpart shall not include s ubstitute data values derived from the missing data procedures of part 75 of this chapter, nor shall the data be bias adjusted according to the procedures of part 75 of this chapter. (f) All required fuel flow rate, steam flow rate, temperature, pressure, and megawatt data must be reduced to hourly averages. However, for any periods during which the flow, watt, steam pressure, or steam temperature monitors (as applicable) are out-of-cont rol, the data points are not used in determining the appropriate hourly average value (g) Calculate the hourly average NO X emissions rate, in units of the emissions standard under §60.4320, using either ppm or lb/MMBtu for units comp lying with the input-based standard or equation 1 of this subpart for units complying with the output-based standard: (1) For a stationary combustion turbine complying with an output-based emissions standard use Equation 1. 

##  

P Q NO E h x 

### 

 (Eq. 1)

Where: E = Hourly NO X emissions rate, in lb/MWh, (NO X ) h= Average hourly NO X emissions rate, in lb/MMBtu, Q = Hourly heat input to the stationary combus tion turbine, in MMBtu, measured using the fuel flowmeter(s), e.g. , calculated using Equation D–15a in appendix D to part 75 of this chapter, an O 2 or CO 2 CEMS and a stack flow meter, or the methodologies in appendix F to part 75 of this chapter, and P = Gross energy output of the stationary combustion turbine in MWh.

(2) The gross energy output is calculated as the sum of the total electrical and mechanical energy generated by the combustion turbine engine, the additional electrical or mechanical energy (if any) generated by the steam turbine following the heat recovery steam generating unit, and the total useful thermal energy output that is not used to generate additional electricity or mechanical output, expr essed in equivalent MWh, as calculated using Equations 2 and 3 of this subpart:

P = ሺ Pe

ሻ t T + ሺ Pe

ሻ
c T + P s + P o (Eq. 2) Comment [CF38]: Allow correction of O2 for owner/operators using the ppm standard. No need for units using the lb/MMBtu or lb/MWh standards to correct percent O2 measurements.

### Page 10 of 29 Where: P = Gross energy output of the stationary combustion turbine system in MWh, (Pe) t = Electrical or mechanical energy output of the stationary combustion turbine in MWh, (Pe) c = Electrical or mechanical energy output (if any) of the steam turbine in MWh, P s = Useful thermal energy of the steam, measured relative to ISO conditions, not used to generate additional electric or mechanical output, in MWh, and P o = Other useful heat recovery, measured relative to ISO conditions, not used for steam generation or performance enhancement of the stationary combustion turbine. T = Electric Transmission and Distribution Factor. Equal to 0.95 for CHP combustion turbine where at least 20.0 percent of the total gross useful energy output consists of electric or direct mechanical output and 20.0 percent of the total gross useful energy output consists of useful thermal output on an annual basis. Equal to 1.0 for all other combustion turbines.



### MWh Btu

H Q P m

s 

### / 10 413

. 3 6 

###  

 (Eq. 3)

Where: P s = Useful thermal energy of the steam, measur ed relative to ISO c onditions, not used to generate additional electric or mechanical output, in MWh, Q m = Measured steam flow in lb, H = Enthalpy of the steam at measured temperature and pressure relative to ISO conditions, in Btu/lb, and 3.413 x 10 6 = Conversion factor from Btu to MWh.

(3) For mechanical drive applications complying with the output-based standard, use equation 4 of this subpart: 

##  

AL BL

NO E m x



###   (Eq. 4)

Where: E = NO X emissions rate in lb/MWh, (NO x ) m = NO X emissions rate in lb/h, BL = Manufacturer's base load rating of turbine, in MW, and AL = Actual load as a percentage of the base load rating.

(h) For each simple cycle stationary combustion turbines, excess NO X emissions are determined on a 4-operating hour averaging period basis using the NO X CEMS data and procedures specified in paragraphs (h)(1) through (4) of this section as applicable to the NO X emissions standard in Table 1 to this subpart. (1) For each 4-operating hour period, co mpute the 4-operating hour rolling average NO X emissions as the heat input weighted average of the hourly average of NO X emissions for a given operating hour and the 3 operating hours immediately preceding that operating hour using the applicable equation in paragraphs (h)(2) through (4) of this section. If the 4-operating hour period contains more than one operating hour with no data points (one or more continuous monitors was out-of-c ontrol for the entire hour), report the 4-operating hour rolling average NO X emissions rate determined for the period as occurring during a period with monitor downtime. (2) If you elect to comply with the applicable heat input-based emissions rate standard, calculate both the 4- operating hour rolling average NO X emissions rate and th e applicable 4-operatin g hour rolling average NO X emissions standard, calculated using hourly values from in Table 1, using Equation 5 of this subpart. Comment [CF39]: Add in equations to clarify how units with CEMS demonstrate compliance continuous compliance. The heat-input weighted average must be used for the lb/MWh and new lb/MMBtu options. The ppm option uses just the simple numerical average – compliance easier since no need to measure fuel use at the same time.

### Page 11 of 29 

##  



#  

  

### 

 4

1 4

1

i i i i i



### Q Q E

E (Eq. 5)

Where: E = 4-operating hour rolling average NO X emissions (lb/MMBtu or ng/J), E i = Hourly average NO X emissions rate or emissions standard for operating hour “i” (lb/MMBtu or ng/J), and Q i = Total heat input to stationary combustion turbine for operating hour “i” (MMBtu or J as appropriate).

(3) If you elect to comply with the applicable output-based emissions rate standard, calculate the 4-operating hour rolling average NO X emissions rate using equation 6-1 of this subpart. Calculate the applicable 4-operating hour rolling average NO X emissions standard, calculated using hourly values from in Table 1, using Equation 6-2 of this subpart.



##  


#  

  

### 

 4

1 4

1

i i i i i



### P Q E

E (Eq. 6-1)

Where: E = 4-operating hour rolling average NO Xemissions rate (lb/MWh or ng/J), E i = Hourly average NO Xemissions rate for operating hour “i (lb/MMBtu or ng/J), Q i = Total heat input to stationary combustion turbine for operating hour “i” (MMBtu or J as appropriate), and P i = Total gross energy output from stationary combustion turbine for operating hour “i” (MWh or J).


##  



#  

  

### 

 4

1 4

1

i i i i i



### P P E

E (Eq. 6-2)

Where: E = 4-operating hour rolling average NO Xemissions standard (lb/MWh or ng/J), E i = Hourly NO Xemissions standard for operating hour “i (lb/MWh or ng/J), and P i = Total gross energy output from stationary combustion turbine for operating hour “i” (MWh or J).

(4) If you elect to comply with the applicable concentrat ion standard using a numerical average, calculate both the 4-operating hour rolling average NO Xemissions rate and the applicable 4-operating hour rolling average NO X emissions standard, calculated using hourly values from in Table 1, using Equation 7 of this subpart.


#  

4 4

1 

# 

 

###  i i ave 

### C

E (Eq. 7)

Where: E = 4-operating hour rolling average NO Xemissions (ppm), and C avei = 1-hour average NO Xconcentration as determined using the procedure in §60.13(h) or emissions standard for operating hour “i” (ppm).

### Page 12 of 29 (i) For each combined cycle combustion turbine and CHP combustion turbine, you must determine excess emissions on a 30 operating-day rolling average basis. The measured emissions rate is the NO Xemissions measured by the CEMS for a given operating day and the 29 operating days immediately preceding that day. Once each day, calculate a new 30-operating day average measured emissions rate using all hourly average values based on non out-of-control NO Xemission data for all operating hours during the previous 30-operating day operating period. Report any 30-operating day periods for which you have less than 75 percent data availability as monitor downtime. If you elect to comply with the applicable heat input-based emissions rate standard, calculate both the measured emissions rate and emissions standard usin g Equation 8 of this subpart. If you elect to comply with the applicable output-based emissions rate standard, calculate the measured emissions rate using Equations 9-1 of this subpart and calculate the emissions standard using Equations 9-2 of this subpart. If you elect to comply with the applicable concentration standard using a numerical average, calculate the measured emissions rate and emissions standard using Equation 10 of this subpart.



##  


#  

  

### 

 n

i i n

i i i



### Q Q E

E

1 1 (Eq. 8)

Where: E = 30-operating day rolling average NO Xmeasured emissions rate or emissions standard for combined cycle combustion turbines and CHP combustion turbines (lb/MMBtu or ng/J), E i = Hourly average NO Xemissions rate or emissions standard for non out-of-control operating hour “i” (lb/MMBtu or ng/J), Q i = Total heat input to stationary combustion turbine for non out-of-control operating hour “i” (MMBtu or J as appropriate), and n = Total number of non out-of-control operating hours in the 30 operating-day period.


##  


#  

  

### 

 n

i i n

i i i



### P Q E

E

1 1 (Eq. 9-1)

Where: E = 30-operating day average NO X measured emissions rate for combined cycle combustion turbines and CHP combustion turbines (lb/MWh or ng/J), E i = Hourly average NO Xemissions rate for non out-of-control operating hour “i” (lb/MMBtu or ng/J), Q i = Total heat input to stationary combustion turbine for non out-of-control operating hour “i” (MMBtu or J as appropriate), P i = Total gross energy output from stationary combustion turbine for non out-of-control operating hour “i” (MWh or J), and n = Total number of operating non out-of-control hours in the 30 operating-day period.


##  



#  

  

### 

 n

i i n

i i i



### P P E

E

1 1 (Eq. 9-2)

Where: E = 30-operating day average NO X emissions standard for combined cycle combustion turbines and CHP combustion turbines (lb/MWh or ng/J),

### Page 13 of 29 E i = Hourly NO Xemissions standard for non out-of-control operating hour “i” (lb/MWh or ng/J), P i = Total gross energy output from stationary combustion turbine for non out-of-control operating hour “i” (MWh or J), and n = Total number of operating non out-of-control hours in the 30 operating-day period.


#  

n C

E n

i i ave 

# 

 

###  1 (Eq. 10)

Where: E = 30-operating day rolling average NO Xmeasured emissions rate or emissions standard for combined cycle combustion turbines and CHP combustion turbines (ppm), C avei = 1-hour average NO Xconcentration as determined using the procedure in §60.13(h) or emissions standard for non out-of-control operating hour “i” (ppm), and n = Total number of operating hours in the 30 operating-day period.

§60.4360 How do I use fuel sulfur analysis to determine the total sulfur content of the fuel combusted in my stationary combustion turbine? (a) If you elect to demonstrate compliance with a SO 2 emissions standard according to §60.4333(d)(2), the fuel analyses may be performed either by you, a service contractor retained by you, the fuel vendor, or any other qualified agency as determined by the delegated permitting authority using the sampling frequency specified in §60.4365. (b) Representative fuel analysis samples may be collecte d either manually or by an automatic sampling system. For automatic sampling, following ASTM D5287 (incorporated by reference, see §60.17) for gaseous fuels or ASTM D4177 (incorporated by reference, see §60.17) for liquid fuels. For reference purposes when manually collecting gaseous samples, see Gas Processors Association Standard 2166 (incorporated by reference, see §60.17). For reference purposes when manually collecting liquid samples, see either Gas Processors Association Standard 2174 or the procedures for manual pipeline sampling in section 14 of ASTM D4057 (both of which are incorporated by reference, see §60.17). (c) Each collected fuel analysis sample must be analyzed for the total sulfur content of the fuel and heating value using the methods specified in paragraphs (c)(1) or (2) of this section, as applicable to the fuel type. (1) For the sulfur content of liquid fuels, ASTM D129, or alternatively D1266, D1552, D2622, D4294, or D5453 (all of which are incorporated by reference, see §60.17). For the heating value of liquid fuels, ASTM D240 or D4809 (both of which are incorporated by reference, see §60.17); or (2) For the sulfur content of gaseous fuels, ASTM D1072, or alternatively D3246, D4468, or D6667 (all of which are incorporated by reference, see §60.17). If the total sulfur content of the gaseous fuel during the most recent compliance demonstration was less than half the applicable standard, ASTM D4084, D4810, D5504, or D6228, or Gas Processors Association Standard 2377 (all of which are incorporated by reference, see §60.17), which measure the major sulfur compounds, may be used. For the heating value of gaseous fuels, ASTM D1826, or alternatively D3588, D4891, or D7164, or Gas Processors Association Standard 2172 (all of which are incorporated by reference, see §60.17). §60.4365 How frequently must I determine the fuel sulfur content? (a) If you are complying with requirements in §60.4360, the total sulfur content of all fuels combusted in each stationary combustion turbine subject to an SO 2 emissions standard in §60.4330 must be determined according to the schedule specified in paragraphs (a)(1) or (2) of this section, as applicable to the fuel type, unless you determine a custom schedule for the stationary combustion turbine according to paragraph (b) of this section. (1) Liquid fuel. Use one of the total sulfur sampling options and the associated sampling frequency described in sections 2.2.3, 2.2.4.1, 2.2.4.2, and 2.2.4. 3 in appendix D to part 75 of this chapter ( i.e. flow proportional sampling, daily sampling, sampling from the unit's storage tank after each addition of fuel to the tank, or sampling each delivery prior to combining it with liquid fuel alread y in the intended storage tank). (2) Gaseous fuel. If the fuel is supplied without intermediate bulk storage, the sulfur content value of the gaseous Comment [CF40]: Add heating value tests since SO2 standard is in lb/MMBtu. Clarify the original intent of the rule that the initial sulfur test must measure all sulfur compounds, not just H2S.

### Page 14 of 29 fuel must be determined and recorded once per operating day. (b) Custom schedules. As an alternative to the requirements of paragraph (a) of this section, you may implement custom schedules for determination of the total sulfur content of gaseous fuels, based on the design and operation of the affected facility and the characteristics of the fuel supply using the procedures provided in either paragraph (b)(1) and (2) of this section. Either you or the fuel ve ndor may perform the sampling. As an alternative to using one of these procedures, you may use a custom schedule that has been substantiated with data and approved by the Administrator or delegated authority as a change in monitoring prior to being used to comply with the applicable standard in §60.4330. (1) You may determine and implement a custom sulfur sampling schedule for your stationary combustion turbine using the procedure specified in paragraphs (b)(1)(i) through (iv) of this section. (i) Obtain daily total sulfur content measurements for 30 consecutive operating days, using the applicable methods specified in this subpart. Based on the results of the 30 daily samples, the required frequency for subsequent monitoring of the fuel's total sulfur content must be as specified in paragraph (b)(1)(ii), (iii), or (iv) of this section, as applicable. (ii) If none of the 30 daily measurements of the fuel's total sulfur content exceeds half the applicable standard, subsequent sulfur content monitoring may be performed at 12-month intervals provided the fuel source or supplier does not change. If any of the samples taken at 12-month intervals has a total sulfur content greater than half but less than the applicable standard, follow the procedures in paragraph (b)(1)(iii) of this section. If any measurement exceeds the applicable standard, follow the procedures in paragraph (b)(1)(iv) of this section. (iii) If at least one of the 30 daily measurements of the fuel's total sulfur content is greater than half but less than the applicable standard, but none exceeds the applicable standard, then: (A) Collect and analyze a sample every 30 days for 3 months. If any sulfur content measurement exceeds the applicable standard, follow the procedures in paragrap h (b)(1)(iv) of this secti on. Otherwise, follow the procedures in paragraph (b)(1 )(iii)(B) of this section. (B) Begin monitoring at 6-month intervals for 12 months. If any sulfur content measurement exceeds the applicable standard, follow the procedures in paragrap h (b)(1)(iv) of this secti on. Otherwise, follow the procedures in paragraph (b)(1 )(iii)(C) of this section. (C) Begin monitoring at 12-month intervals. If any sulfur content measurement exceeds the applicable standard, follow the procedures in paragraph (b)(1)(iv) of this se ction. Otherwise, continue to monitor at this frequency. (iv) If a sulfur content measurement exceeds the applicable standard, immediately begin daily monitoring according to paragraph (c)(1)(i) of this section. Daily monitoring must continue until 30 consecutive daily samples, each having a sulfur content no greater than the applicable standard, are obtained. At that point, the applicable procedures of paragraph (b)(1)(ii) or (iii) of this section must be followed. (2) You may use the data collected from the 720-hour sulfur sampling demonstration described in section 2.3.6 in appendix D to part 75 of this chapter to determine and implement a sulfur sampling schedule for your stationary combustion turbine using the procedure specified in paragraphs (b)(2)(i) through (iii) of this section. (i) If the maximum fuel sulfur content obtained from any of the 720 hourly samples does not exceed half the applicable standard, then the minimum required sampling frequency must be one sample at 12 month intervals. (ii) If any sample result exceeds half the applicable standard, but none exceeds the applicable standard, follow the provisions of paragraph (b)(1)(iii) of this section. (iii) If the sulfur content of any of the 720 hourly samples exceeds the applicable standard, follow the provisions of paragraph (b)(1)(iv) of this section. §60.4370 How can I demonstrate compliance with my SO 2 emissions standard using records of the fuel sulfur content? (a) If you elect to demonstrate compliance with a SO 2 emissions standard according to §60.4333(d)(3), you must maintain on-site records (such as a current, valid purchase contract, tariff sheet, or transportation contract) documenting that total sulfur content for the fuel combusted in your stationary combustion turbine at all times does not exceed the conditions specified in paragraph (b) through (e) of this section, as applicable to your stationary combustion turbine.

### Page 15 of 29 (b) If your stationary combustion turbine is subject to the SO 2 emissions standard in §60.4330(a), then the fuel combusted must have a potential SO 2 emissions rate of 26 ng/J (0.060 lb/MMBtu) heat input or less. (c) If your stationary combustion turbine is subject to the SO 2 emissions standard in §60.4330(b), then the total sulfur content of the gaseous fuel combusted must be 650 (mg/scm) (28 gr/100 scf). (d) If your stationary combustion turbine is subject to the SO 2 emissions standard in §60.4330(c) or (d), the total sulfur content of the fuel combusted must be: (1) For natural gas, 140 gr/100 scf or less. (2) For fuel oil, 0.40 weight percent (4,000 ppmw) or less. (3) For other fuels, potential SO 2 emissions of 180 ng/J (0.42 lb/MMBtu) heat input or less. (e) Representative fuel sampling data following the procedures specified in section 2.3.1.4 or 2.3.2.4 in appendix D to part 75 of this chapter documenting that the fuel meets the part 75 requirements to be considered either pipeline natural gas or natural gas. §60.4372 How do I demonstrate compliance with my SO 2 emissions standard and determine excess emissions using a SO 2 CEMS? (a) If you demonstrate continuous compliance using a CEMS for measuring SO 2 emissions, excess emissions are defined as the applicable averaging period, either 4-operating hour or 30-operating day, during which the average SO 2 emissions from your stationary combustion turbine measured by the CEMS exceeds the applicable SO 2 emissions standard specified in §60.4330 as determined usin g the procedures specified in this section that apply to your stationary combustion turbine. (b) You must install, calibrate, maintain, and operate a CEMS for measuring SO 2 concentrations and either O 2 or CO 2 concentrations at the outlet of your stationary combustion turbine, and record the output of the system. (c) The 1-hour average SO 2 emissions rate measured by a CEMS must be expressed in ng/J or lb/MMBtu heat input and must be used to calculate the average emissions rate under §60.4330. (d) You must use the procedures for installation, evaluation, and operation of the CEMS as specified in §60.13 and paragraphs (d)(1) through (3) of this section. (1) Each CEMS must be operated according to the applicable procedures under Performance Specifications 1, 2, and 3 in appendix B of this part; (2) Quarterly accuracy determinations and daily calibration drift tests must be performed according to Procedure 1 in appendix F of this part; and (3) The span value of the SO 2 CEMS at the outlet from the SO 2 control device (or outlet of the stationary combustion turbine if no SO 2 control device is used) must be 125 percent of either the highest applicable standard or highest potential SO 2 emissions rate of the fuel combusted. (e) Correction of measured SO 2 concentrations to 15 percent O 2 is not allowed. (f) If you have installed and certified a SO 2 CEMS that meets the requirements of part 75 of this chapter, the delegated permitting authority can approve that only quality assured data from the CEMS must be used to identify excess emissions under this subpart. You must report periods where the missing data substitution procedures in subpart D of part 75 are applied as monitoring system downtime in the excess emissions and monitoring performance report required under §60.7(c). (g) All required fuel flow rate, steam flow rate, temperature, pressure, and megawatt data must be reduced to hourly averages. (h) Calculate the hourly average SO 2 emissions rate, in units of the emissions standard under §60.4330, using lb/MMBtu for units complying with th e input-based standard or using equation 11 of this subpart for units complying with the output-based standard: (1) For simple-cycle operation: 

##  

P Q SO E h 

### 

 2 (Eq. 11)

Where: Comment [CF41]: No need to list 20 gr/100 scf natural gas or 500 ppm S distillate since already exempt from the SO2 standard.

Comment [CF42]: Add in procedures to use a SO 2 CEMS.

Comment [CF43]: Since no ppm standard correction is not necessary.

### Page 16 of 29 E = Hourly SO 2 emissions rate, in lb/MWh, (SO 2 ) h= Average hourly SO 2 emissions rate, in lb/MMBtu, Q = Hourly heat input rate to the stationarycombustion turbine, in MMBtu, measured using the fuel flow meter(s), e.g. , calculated using Equation D–15a in appendix D to part 75 of this chapter, an O 2 or CO 2 CEMS and a stack flow meter, or the methodologies in appendix F to part 75 of this chapter, and P = Gross energy output of the stationary combustion turbine in MWh.

(2) The gross energy output is calculated as the sum of the total electrical and mechanical energy generated by the stationary combustion turbine, the additional electrical or mechanical energy (if any) generated by the steam turbine following the heat recovery steam generating unit, and the total useful thermal energy output that is not used to generate additional electricity or mechanical output, expressed in equivalent MWh, as calculated using Equations 12 and 13 of this subpart

P = ሺ Pe

ሻ t T + ሺ Pe

ሻ
c ் + P s + P o (Eq. 12)

Where: P = Gross energy output of the stationary combustion turbine system in MWh, (Pe) t = Electrical or mechanical energy output of the stationary combustion turbine in MWh, (Pe) c = Electrical or mechanical energy output (if any) of the steam turbine in MWh, P s = Useful thermal energy of the steam, measured relative to ISO conditions, not used to generate additional electric or mechanical output, in MWh, and P o = Other useful heat recovery, measured relative to ISO conditions, not used for steam generation or performance enhancement of the stationary combustion turbine. T = Electric Transmission and Distribution Factor. Equal to 0.95 for CHP combustion turbine where at least 20.0 percent of the total gross useful energy output consists of electric or direct mechanical output and 20.0 percent of the total gross useful energy output consists of useful thermal output on an annual basis. Equal to 1.0 for all other combustion turbines.



### MWh Btu

H Q P m

s 

### / 10 413

. 3 6 

###  

 (Eq. 13)

Where: P s = Useful thermal energy of the steam, measur ed relative to ISO c onditions, not used to generate additional electric or mechanical output, in MWh, Q m = Measured steam flow rate in lb, H = Enthalpy of the steam at measured temperature and pressure relative to ISO conditions, in Btu/lb, and 3.413 x 10 6 = Conversion factor from Btu to MWh.

(3) For mechanical drive applications complying with the output-based standard, use equation 14 of this subpart: 

##  

AL BL

SO E m 2



###   (Eq. 14)

Where: E = SO 2 emissions rate in lb/MWh, (SO 2 ) m = SO 2 emissions rate in lb/h, BL = Manufacturer's base load rating of turbine, in MW, and AL = Actual load as a percentage of the base load rating.

(i) For stationary combustion turbines other than co mbined cycle combustion turbines and CHP combustion turbines, you must determine excess emissions on a 4-operating hour rolling average basis. The “4-operating hour

### Page 17 of 29 rolling average SO 2 measured emissions rate” is the SO 2 emissions measured by the CEMS for a given operating hour and the 3 consecutive operating hours immediately preced ing that hour expressed in the units appropriate for the SO 2 emissions standard that is applied to your stationary combustion turbine. Each operating hour, calculate the 4-operating hour rolling average SO 2 measured emissions rate using all of the non out-of-control SO 2 emission data obtained during the previous 4-operating hour operating period. If the 4-operating hour period contains more than one operating hour with no data points (one or more CEMS was out-of-control for the entire hour), report the 4-operating hour rolling average SO 2 emissions rate determined for the period as occurring during a period with monitor downtime. If you elect to comply with the applicable heat input-based emissions rate standard, calculate both the measured emissions rate and the emissions standard using Equation 15 of this subpart. If you elect to comply with the applicable output-based emissions standard, calculate the measured emissions rate using Equation 16-1 of this subpart and calculate the emissions standard using equation 16-2 of this subpart.



##  


#  

  

### 

 4

1 4

1

i i i i i



### Q Q E

E (Eq. 15)

Where: E = 4-operating hour rolling average SO 2 measured emissions rate or emissions standard for stationary combustion turbines other than combined cycle combustion turbines and CHP combustion turbines (lb/MMBtu or ng/J), E i = Hourly average SO 2 emissions rate or emissions standard for non out-of-control operating hour “i” (lb/MMBtu or ng/J), and Q i = Total heat input to stationary combustion turbine for non out-of-control operating hour “i” (MMBtu or J as appropriate).


##  


#  

  

### 

 4

1 4

1

i i i i i



### P Q E

E (Eq. 16-1)

Where: E = 4-operating hour rolling average SO 2 measured emissions rate for stationary combustion turbines other than combined cycle combustion turbines and CHP combustion turbines (lb/MWh or ng/J), E i = Hourly average SO 2 emissions rate for non out-of-control operating hour “i” (lb/MMBtu or ng/J), Q i = Total heat input to stationary combustion turbine for non out-of-control operating hour “i” (MMBtu or J as appropriate), and P i = Total gross energy output from stationary combustion turbine for non out-of-control operating hour “i” (MWh or J).


##  



#  

  

### 

 4

1 4

1

i i i i i



### P P E

E (Eq. 16-2)

Where: E = 4-operating hour rolling average SO 2 emissions standard for stationary combustion turbines other than combined cycle combustion turbines and CHP combustion turbines (lb/MWh or ng/J), E i = Hourly SO 2 emissions standard for non out-of-control operating hour “i” (lb/MMBtu or ng/J), and P i = Total gross energy output from stationary combustion turbine for non out-of-control operating hour “i” (MWh or J).

### Page 18 of 29 (ii) For combined cycle combustion turbines and CHP combustion turbines, you must determine excess emissions on a 30 operating-day rolling average basis. The excess emissions level is the heat input weighted-average of the SO 2 emissions measured by the CEMS for a given ope rating day and the 29 operating days immediately preceding that day. Once each day, calculate a new 30-o perating day average measured emissions rate using all hourly average values based on non out-of-control SO 2 emission data for all operating hours during the previous 30-operating day operating period. Report any 30-operating day periods for which you have less than 75 percent data availability as monito r downtime. If you elect to comply with the applicable heat input-based emissions standard, calculate the measured emissions rate and emissions rate using Equation 17 of this subpart. If you elect to comply with the applicable output-based standard, calculate the measured emissions rate using Equation 18-1 of this subpart and calculate the emissions standard using Equation 18-2 of this subpart.



##  


#  

  

### 

 n

i i n

i i i



### Q Q E

E

1 1 (Eq. 17)

Where: E = 30-operating day rolling average SO 2 measured emissions rate or emissions standard for combined cycle combustion turbines and CHP combustion turbines (lb/MMBtu or ng/J), E i = Hourly average SO 2 emissions rate or emissions standard for non out-of-control operating hour “i” (lb/MMBtu or ng/J), Q i = Total heat input to stationary combustion turbine for non out-of-control operating hour “i” (MMBtu or J as appropriate), and n = Total number of non out-of-control operating hours in the 30 operating-day period.


##  


#  

  

### 

 n

i i n

i i i



### P Q E

E

1 1 (Eq. 18-1)

Where: E = 30-operating day average SO 2 measured emissions rate for combined cycle combustion turbines and CHP combustion turbines (lb/MWh or ng/J), E i = Hourly average SO 2 measured emissions rate for non out-of-control operating hour “i” (lb/MMBtu or ng/J), Q i = Total heat input to stationary combustion turbine for non out-of-control operating hour “i” (MMBtu or J as appropriate), P i = Total gross energy output from stationary combustion turbine for non out-of-control operating hour “i” (MWh or J), and n = Total number of non out-of-control operating hours in the 30 operating-day period.


##  



#  

  

### 

 n

i i n

i i i



### P P E

E

1 1 (Eq. 18-2)

Where: E = 30-operating day average SO 2 emissions standard for combined cycle combustion turbines and CHP combustion turbines (lb/MWh or ng/J), E i = Hourly SO 2 emissions standard for non out-of-contr ol operating hour “i” (lb/MWh or ng/J), P i = Total gross energy output from stationary combustion turbine for non out-of-control operating

### Page 19 of 29 hour “i” (MWh or J), and n = Total number of non out-of-control operating hours in the 30 operating-day period.

Recordkeeping and Reporting §60.4375 What reports must I submit? (a) An owner or operator of a stationary combustion turbine that elects to continuously monitor parameters or emissions, or to periodically determine the fuel sulfur content under this subpart, must submit reports of excess emissions and monitor downtime, according to §60.7(c). Ex cess emissions must be reported for all periods of unit operation, including startup, shutdown, and malfunction. (b) An owner or operator of a stationary combustion turbine that performs performance tests to demonstrate compliance with this subpart must subm it a written report of the results of e ach performance test before the close of business on the 60th day following the completion of the performance test, except as specified in paragraph (c) of this part. (c)(1) Within 60 days after the date of completing each performance test (see §60.8) as required by this subpart you must submit the results of the performance tests required by this subpart to EPA’s WebFIRE database by using the Compliance and Emissions Data Reporting Interface (CEDRI) that is accessed through EPA’s Central Data Exchange (CDX) (www.epa.gov/cdx). Performance test data must be submitted in the file format generated through use of EPA’s Electronic Reporting Tool (ERT) (see http://www.epa.gov/ ttn/chief/ert/index.html ). Only data collected using test methods on the ERT website are subject to this requiremen t for submitting reports electronically to WebFIRE. Owners or operators who clai m that some of the inform ation being submitted for performance tests is confidential business information (CBI) must submit a complete ERT file including information claimed to be CBI on a compact disk or ot her commonly used electroni c storage media (including, but not limited to, flash drives) to EPA. The electronic media must be clearly marked as CBI and mailed to U.S. EPA/OAPQS/CORE CBI Office, Attention: WebFIRE Administrator, MD C404-02, 4930 Old Page Rd., Durham, NC 27703. The same ERT file with the CBI omitted must be submitted to EPA via CDX as described earlier in this paragraph. At the discretion of the de legated authority, you must also submit these reports, including the confidential business information, to the delegated authority in the format specified by the delegated authority. (2) Within 60 days after the date of completing each CEMS performance evaluation test (see §60.13), you must submit the relative accuracy test audit data electroni cally into EPA’s Central Data Exchange by using the Electronic Reporting Tool as mentioned in paragraph (c)(1) of this section. Only data collected using test methods compatible with ERT are subject to this requirement to be submitted electronically to EPA’s CDX. (3) All reports required by this subpart not subject to the requirements in paragraphs (c)(1) and (2) of this section must be sent to the Administrator or delegated authority at the appropriate address listed in §63.13. The Administrator or delegated authority may request a report in any form suitable for the specific case (e.g., by commonly used electronic media such as Excel spreadsheet, on CD or hard copy). The Administrator or delegated authority retains the right to require submittal of reports subject to paragraph (c)(1) and (2) of this section in paper format. (d) The notification requirements of §60.8 apply to the initial and subsequent performance tests. (e) An owner or operator of an a ffected facility complying with §60.4 333(b)(3) must noti fy the delegated permitting authority within 15 calendar days after the facility recommences operation. (f) An owner or operator of an affected facility complying with §60.4333(b)(4) must notify the delegated permitting authority within 15 calendar days after the fac ility has operated more than 50 operating hours since the date the previous performance test was required to be conducted.
§60.4380 How are NO X excess emissions and monitor downtime reported? (a) For reports required under §60.4375(a), periods of excess emissions and monitor downtime for stationary combustion turbines using water or steam to fuel ratio monitoring are reported as specified in paragraphs (a)(1) through (3) of this section. (1) An excess emission that must be reported is any ope rating hour for which the 4-operating hour rolling average steam or water to fuel ratio, as measured by the continuous monitoring system, is less than the acceptable steam or water to fuel ratio needed to demonstrate compliance with §60.4320, as established during the most recent Comment [CF44]: Updated language for electronic reporting.

### Page 20 of 29 performance test. Any operating hour during which no water or steam is injected into the turbine when the specific conditions require water or steam injection for NO X control will also be considered an excess emission. (2) A period of monitor downtime that mu st be reported is any operating hour in which water or steam is injected into the turbine, but the parametric data needed to determine the steam or water to fuel ratio are unavailable or out-of-control. (3) Each report must include the average steam or water to fuel ratio, average fuel consumption, and the stationary combustion turbine load during each excess emission. (b) For reports required under §60.4375(a), periods of excess emissions and monitor downtime for stationary combustion turbines using a CEMS, excess emissions are reported as specified in paragraphs (b)(1) through (3) of this section. (1) An excess emission that must be reported is any unit operating period in which the 4-operating hour or 30- operating day rolling average NO X emissions rate exceeds the applicable emissions standard in §60.4320 as determined in §60.4350. (2) A period of monitor downtime that must be reported is any operating hour in which the data for any of the following parameters are either missing or out-of-control: NO X concentration, CO 2 or O 2 concentration, stack flow rate, heat input rate, steam flow rate, steam temperature, steam pressure, or megawatts. You are only required to monitor parameters used for compliance purposes. (3) For hours with multiple emission standards, the appli cable standard for that hour is determined based on the condition, excluding periods of monitor downtime, that corresponded to the highest emissions standard. (c) For reports required under §60.4375(a), periods of excess emissions and monitor downtime for stationary combustion turbines using combustion parameters or parameters that document proper operation of the NO X emission controls excess emissions and monitor downtime are reported as specified in paragraphs (c)(1) and (2) of this section. (1) Excess emissions that must be reported are each 4-operating hour rolling average in which any monitored parameter (as averaged over the 4 operating-hour period) does not achieve the target value or is outside the acceptable range defined in the parameter monitoring plan for the unit. (2) Periods of monitor downtime that must be reported are each operating hour in which any of the required parametric data are either not recorded or are out-of-control.
§60.4385 How are SO 2 excess emissions and monitor downtime reported? (a) If you choose the option to monitor the sulfur content of the fuel, excess emissions and monitor downtime are defined as follows: (1) For samples obtained using daily sampling, flow prop ortional sampling, or sampling from the unit's storage tank, excess emissions occur each operating hour included in the period beginning on the date and hour of any sample for which the sulfur content of the fuel being fired in the stationary combustion turbine exceeds the applicable standard and ending on the date and hour that a subsequent sample is taken that demonstrates compliance with the sulfur standard. (2) If the option to sample each delivery of fuel oil has been selected, you must immediately switch to one of the other oil sampling options (i.e., daily sampling, flow proportional sampling, or sampling from the unit's storage tank) if the sulfur content of a delivery exceeds 0.05 weightpercent, 0.15 weight percent, or 0.40 weight percent as applicable. You must continue to use one of the other sampling options until all of the oil from the delivery has been combusted, and you must evaluate excess emissions acco rding to paragraph (a) of this section. When all of the fuel from the delivery has been combusted, you may resume using the as-delivered sampling option. (3) A period of monitor downtime begins when a required sample is not taken by its due date. A period of monitor downtime also begins on the date and hour of a required sample, if invalid results are obtained. The period of monitor downtime ends on the date and hour of the next valid sample. (b) If you choose the option to maintain records of the fuel sulfur content, excess emissions are defined as any period during which you burn a fuel that you do not have appropriate fuel records or that fuel contains sulfur greater than the applicable standard. (c) For reports required under §60.4375(a), periods of excess emissions and monitor downtime for stationary Comment [CF45]: If you don’t need water injection to meet the low load standard then you don’t have to report those periods as excess emissions if you don’t inject water during those periods.

### Page 21 of 29 combustion turbines using a CEMS, excess emissions are reported as specified in paragraphs (c)(1) through (2) of this section. (1) An excess emission that must be reported is any unit operating period in which the 4-operating hour or 30- operating day rolling average SO 2 emissions rate exceeds the applicable emissions standard in §60.4330 as determined in §60.4372. (2) A period of monitor downtime that must be reported is any operating hour in which the data for any of the following parameters are either missing or out-of-control: SO 2 concentration, CO 2 or O 2 concentration, stack flow rate, heat input rate, steam flow rate, steam temperature, steam pressure, or megawatts. You are only required to monitor parameters used for compliance purposes.
§60.4390 What records must I maintain? (a) You must maintain records of your information used to demonstrate compliance with this subpart as specified in §60.7. (b) An owner or operator of a stationary combustion turbine that uses the other fuels, part-load, or low temperature NO X standards in the compliance demonstration must ma intain concurrent record s of the hourly heat input, percent load, ambient temperature, and emissions data as applicable. (c) An owner or operator of a stationary combustion turbine that uses the tuning NO X standard in the compliance demonstration must identify the hours on which the maintenance was performed and a description of the maintenance. (d) An owner or operator of a stationary combustion turbine that demonstrates compliance using the output-based standard must maintain concurrent records of the total gross energy output and emissions data. (e) An owner or operator of a stationary combustion turbine that demonstrates compliance using the water or steam to fuel ratio or a parameter continuous monitoring system must maintain continuous records of the appropriate parameters. (f) An owner or operator of a stationary combustion turbine complying with the fuel based SO 2 standard must maintain records of the results of all fuel analyses or a current, valid purchase contract, tariff sheet, or transportation contract. §60.4395 When must I submit my reports? Consistent with §60.7(c), all reports required under §60.7(c) must be postmarked by the 30th day following the end of each 6-month period.

Performance Tests §60.4400 How do I conduct performance tests to demonstrate compliance with my NO Xemissions standard if I do not have a NO X CEMS? (a) You must conduct the performance test according to the requirements in §60.8 and paragraphs (b) through (d) of this section. (b) You must use the methods in either paragraph (b)(1) or (2) of this section to measure the NO X concentration for each test run. (1) Measure the NO X concentration using EPA Method 7E in appendix A-4 of this part or EPA Method 20 in appendix A-7 of this part. In addition, when only natural gas is being combusted ASTM D6522 (incorporated by reference, see §60.17) can be used instead of EPA Method 20 in appendix A-7 of this part to determine the oxygen content in the exhaust gas. For units complying with the output-based standard, concurrently measure the stack gas flow rate, using EPA Methods 1 and 2 in appendix A-1 of this part, and measure and record the electrical and thermal output from the unit. Then, use Equation 19 of this subpart to calculate the NO X emissions
rate: 

##  

P Q

NO 10 194

. 1 E std c x 7 

### 

 

  (Eq. 19)

Where: E = NO X emissions rate, in lb/MWh,

### Page 22 of 29 1.194×10 − 7 = Conversion constant, in lb/dscf-ppm, (NO x ) c = Average NO X concentration for the run, in ppm, Q std= Average stack gas volumetric flow rate, in dscf/h, and P = Average gross electrical and mechanical energy output of the stationary combustion turbine, in MW (for simple-cycle operation), for combined-cycle opera tion, the sum of all electrical and mechanical output from the combustion and steam turbines, or, for CHP operation, the sum of all electrical and mechan ical output from the combustion and steam turbines plus all useful recovered thermal output not used for additional electric or mechanical generation or to enhance the performance of the stationary combustion turbine, in MW, calculated according to §60.4350.

(2) Measure the NO X and diluent gas concentrations, using either EPA Method 7E in appendix A-4 of this part and EPA Method 3A in appendix A-2 of this part, or EPA Method 20 in appendix A-7 of this part. In addition, when only natural gas is being combusted ASTM D6522 (incorporated by reference, see §60.17) can be used instead of EPA Method 3A in appendix A-2 of this part or EPA Method 20 in appendix A-7 of this part to determine the oxygen content in the exhaust gas. Concurrently measure the heat input to the unit, using a fuel flowmeter (or flowmeters), an O 2 or CO 2 CEMS along with a stack flow meter, or the methodologies in appendix F to part 75 of this chapter, and for units complying with the output-based standard measure the electrical, mechanical, and thermal output of the unit. Use EPA Method 19 in appendix A-7 of this part to calculate the NO X emissions rate in lb/MMBtu. Then, use Equations 1 and, if necessary, 2 and 3 of this subpart in §60.4350(f) to calculate the NO X emissions rate in lb/MWh. (c) You must use the methods in either paragraph (c)(1) or (2) of this section to select the sampling traverse points for NO X and (if applicable) diluent gas. (1) You must select the sampling traverse points for NO X and (if applicable) diluent gas according to EPA Method 20 in appendix A-7 of this part or EPA Method 1 in appendix A-1 of this part (non-particulate procedures), and sampled for equal time intervals. The sampling must be performed with a traversing single-hole probe, or, if feasible, with a stationary multi-hole probe that samples each of the points sequentially. Alternatively, a multi-hole probe designed and documented to sample equal volumes from each hole may be used to sample simultaneously at the required points. (2) As an alternative to paragraph (c)(1) of this s ection, you may select the sampling traverse points for NO Xand (if applicable) diluent gas according to requirements in paragraphs (c)(2)(i) and (ii) of this section. (i) You perform a stratification test for NO X and diluent pursuant to the procedures specified in section 6.5.6.1(a) through (e) in appendix A of part 75 of this chapter. (ii) Once the stratification sampling is completed, you use the following alternative samp le point selection criteria for the performance test specified in paragraphs (c)(2)(ii)(A) through ( (A) If each of the individual traverse point NO X concentrations is w ithin ±10 percent of the mean concentration for all traverse points, or the individual traverse point diluent concentrations differs by no more than ±0.5 percent CO 2 (or O 2 ) from the mean for all traverse points, then you may use three points (located either 16.7, 50.0 and 83.3 percent of the way across the stack or duct, or, for circular stacks or ducts greater than 2.4 meters (7.8 feet) in diameter, at 0.4, 1.2, and 2.0 meters from the wall). The three points must be located along the measurement line that exhibited the highest average NO X concentration during th e stratification test; or (B) For a stationary combustion turbine subject to a NO X emissions standard greater than 15 ppm at 15 percent O 2 , you may sample at a single point, located at least 1 meter from the stack wall or at the stack centroid if each of the individual traverse point NO X concentrations is within ±5 percent of the mean concentration for all traverse points, or the individual traverse point diluent concentrations differs by no more than ±0.3 percent CO 2 (or O 2 ) from the mean for all traverse points; or (C) For a stationary combustion turbine subject to a NO X emissions standard less than or equal to 15 ppm at 15 percent O 2 , you may sample at a single point, located at least 1 meter from the stack wall or at the stack centroid if each of the individual traverse point NO X concentrations is within ±2.5 percent of the mean concentration for all traverse points, or the individual traverse point diluent concentrations differs by no more than ±0.15 percent CO 2 (or O 2 ) from the mean for all traverse points.

### Page 23 of 29 (d) The performance test must be done at any load condition within plus or minus 25 percent of 100 percent of the base load rating. You may perform testing at the highest achievable load point, if at least 75 percent of the base load rating cannot be achieved in practice. You must conduct three separate test runs for each performance test. The minimum time per run is 60 minutes. (1) If the stationary combustion turbine combusts both natural gas and fuels other than natural gas as primary or backup fuels, separate performance testing is required for each fuel. (2) For a combined cycle or CHP combustion turbine with supplemental heat (duct burner), you must measure the total NO X emissions downstream of the duct burner. The duct burner must be in operation during the performance
test. (3) If water or steam injection is used to control NO X with no additional post-combustion NO X control and you choose to monitor the steam or water to fuel ratio in accordance with §60.4335, then that monitoring system must be operated concurrently with each EPA Method 20 in appe ndix A-7 of this part or EPA Method 7E in appendix A-4 of this part run and must be used to determine the fuel consumption and the steam or water to fuel ratio necessary to comply with the applicable §60.4320 NO X emissions standard. (4) If you elect to install a CEMS, the performance evaluation of the CEMS may either be conducted separately or (as described in §60.4405) as part of the initial performance test of the affected unit. (5) The ambient temperature must be greater than 0°F during the performance test. The delegated permitting authority may approve performance testing below 0 o F if the timing of the required performance test and environmental conditions make it impractical to test at ambient conditions greater than 0 o F. §60.4405 How do I conduct a performance test if I use a NO X CEMS? (a) If you use a CEMS the performance test must be performed according to the procedures specified in paragraph (b) of this section. (b) The initial performance test must use the procedure specified in paragraphs (b)(1) through (4) of this section. (1) Perform a minimum of nine RATA reference method runs, with a minimum time per run of 21 minutes, at a single load level, within plus or minus 25 percent of 100 percent of the base load rating. You may perform testing at the highest achievable load point, if at least 75 percen t of the base load rating cannot be achieved in practice. The ambient temperature must be greater than 0 °F during the RATA runs. The delegated permitting authority may approve performance testing below 0 o F if the timing of the required performance test and environmental conditions make it impractical to test at ambient conditions greater than 0 o F. (2) For each RATA run, concurrently measure the heat input to the unit using a fuel flow meter (or flow meters) or the methodologies in appendix F to part 75 of this chapter, and for units complying with the output-based standard, measure the electrical and thermal output from the unit. (3) Use the test data both to demonstrate compliance with the applicable NO X emissions standard under §60.4320 and to provide the required reference method data for the RATA of the CEMS described under §60.4342. (4) Compliance with the applicable emissions standard in §60.4320 is achieved if the sum of the NO X emissions divided by the heat input (or gross energy output) for all the RATA runs, expressed in units of lb/MMBtu or lb/MWh, does not exceed the emissions standard. §60.4415 How do I conduct performance tests to demonstrate compliance with my SO 2 emissions standard? (a) An owner or operator of an affected facility complying with the fuel based standard must submit fuel records (such as a current, valid purchase contract, tariff sheet, tran sportation contract, or resu lts of a fuel analysis) to satisfy the requirements of §60.8. (b) An owner or operator of an affected facility complying with the SO 2 emissions standard must conduct the performance test by measuring the SO 2 emissions in the stationary combustion turbine exhaust gases using the methods in either paragraph (b)(1) or (2) of this section. (1) Measure the SO 2 concentration using EPA Methods 6, 6C, 8 in appendix A-4 of this part, or EPA Method 20 in appendix A-7 of this part. In addition, the American Society of Mechanical Engineers (ASME) standard, ASME PTC 19–10–1981–Part 10, “Flue and Exhaust Gas Analyses,” manual methods for sulfur dioxide (incorporated by reference, see §60.17) can be used instead of EPA Method 6 in appendix A-4 of this part or EPA Method 20 in appendix A-7 of this part. For units complying with the output based standard, concurrently Comment [CF46]: Make consistent with other NSPS rules. Performance test should be for a nominal hour.

Comment [CF47]: Allow permitting authority to account for site specific conditions and approve testing below 0 o F in special circumstances

Comment [CF48]: Allow permitting authority to account for site specific conditions and approve testing below 0 o F in special circumstances

### Page 24 of 29 measure the stack gas flow rate, using EPA Methods 1 and 2 in appendix A-1 of this part, and measure and record the electrical and thermal output from the unit. Then use Equation 20 of this subpart to calculate the SO 2 emissions rate: 

##  

P Q

SO E std c 

###   

  2 7 

### 10 664

. 1 (Eq. 20)

Where: E = SO 2 emissions rate, in lb/MWh, 1.664×10 − 7 = Conversion constant, in lb/dscf-ppm, (SO 2 ) c = Average SO 2 concentration for the run, in ppm, Q std= Average stack gas volumetric flow rate, in dscf/h, and P = Average gross electrical and mechanical energy output of the stationary combustion turbine, in MW (for simple-cycle operation), for combined-cycle opera tion, the sum of all electrical and mechanical output from the combustion and steam turbines, or, for CHP operation, the sum of all electrical and mechan ical output from the combustion and steam turbines plus all useful recovered thermal output not used for additional electric or mechanical generation or to enhance the performance of the stationary combustion turbine, in MW, calculated according to §60.4350(f)(2).

(2) Measure the SO 2 and diluent gas concentrations, using either EPA Methods 6, 6C, or 8 in appendix A-4 of this part and EPA Method 3A in appendix A-2 of this part, or EPA Method 20 in appendix A-7 of this part. In addition, you may use the manual methods for sulfur dioxide ASME PTC 19–10–1981–Part 10 (incorporated by reference, see §60.17). Concurrently measure the heat input to the unit, using a fuel flowmeter (or flowmeters), an O 2 or CO 2 CEMS along with a stack flow meter, or the methodologies in appendix F to part 75 of this chapter, and for units complying with the output based standard measure the electrical and thermal output of the unit. Use EPA Method 19 in appendix A-7 of this part to calculate the SO 2 emissions rate in lb/MMBtu. Then, use Equations 11 and, if necessary, 12 and 13 of this subpart in §60.4372 to calculate the SO 2 emissions rate in lb/MWh.

Definitions §60.4420 What definitions apply to this subpart? As used in this subpart, all terms not defined herein wi ll have the meaning given them in the Clean Air Act and in subpart A (General Provisions) of this part. Affirmative defense means, in the context of an enforcement proceeding, a response or defense put forward by a defendant, regarding which the defendant has the burden of proof, and the merits of which are independently and objectively evaluated in a judicial or administrative proceeding. Base load rating means 100 percent of the manufacturer's design heat input capacity of the combustion turbine engine at ISO conditions using the higher heating value of the fuel. Biogas means gas produced by the anaerobic digestion or fermentation of organic matter including manure, sewage sludge, municipal solid waste, biodegradable waste, or any other biodegradable feedstock, under anaerobic conditions. Biogas is comprised primarily of methane and CO 2 . Byproduct means any liquid or gaseous substance produced at chemical manufacturing plants, petroleum refineries, or pulp and paper mills (e xcept natural gas and fuel oil) and combusted in a stationary combustion turbine. Gaseous substances with CO 2 levels greater than 50 percent or carbon monoxide levels greater than 10 percent are not byproduct. Combined cycle combustion turbine means any stationary combustion turbine which recovers heat from the combustion turbine engine exhaust gases to generate stea m that is used exclusively to create additional power output in a steam turbine. Combined heat and power (CHP) combustion turbine means any stationary combustion turbine which recovers heat from the combustion turbine engine exhaust gases to heat water or another medium, generate steam for useful purposes other than exclusively for add itional electric generation, or directly uses the heat in the exhaust gases for Comment [CF49]: Removed unnecessary definitions and added “Byproduct”, “Federally enforceable”, “Combustion turbine engine”, “turbine tuning,” “Offshore turbine”, “Out-of-control period”, “solid fuel”, and “fuel oil.” Changed “peak load” to “base load,” and “unit operating hour” and “unit operating day” to “operating hour” and “operating day.” Clarified “stationary combustion turbine” to include additional components. Amended “natural gas” to include synthetic natural gas - If consistent quality & meets the definition of natural gas then the same NOx standard should apply.

### Page 25 of 29 a useful purpose. Combustion turbine engine means the air compressor, combustor, and turbine sections of a stationary combustion turbine.
Combustion turbine test cell/stand means any apparatus used for testing uninstalled stationary or uninstalled mobile (motive) combustion turbines.
Distillate oil means fuel oil that complies with the specifications for fuel oil numbers 1 or 2, as defined by the American Society for Testing and Materials in ASTM D396 (incorporated by reference, see §60.17), diesel fuel oil numbers 1 or 2, as defined by the American Society for Testing and Materials in ASTM D975 (incorporated by reference, see §60.17), kerosine, as defined by the American Society of Testing and Materials in ASTM D3699 (incorporated by reference, see §60.17), biodiesel as defined by the American Society of Testing and Materials in ASTM D6751 (incorporated by reference, see §60.17), or biodiesel blends as defined by the American Society of Testing and Materials in ASTM D7467 (incorporated by reference, see §60.17). Dry standard cubic foot (dscf) means the quantity of gas, free of uncombined water, that would occupy a volume of 1 cubic foot at 293 Kelvin (20.0 o C) and 101.325 kPa of pressure.
Duct burner means a device that combusts fuel and that is placed in the exhaust duct from another source, such as a stationary combustion turbine, internal combustion engine, kiln, etc., to allow the firing of additional fuel to heat the exhaust gases. Emergency combustion turbine means any stationary combustion turbine which operates in an emergency situation. Examples include stationary combustion turb ines used to produce power for critical networks or equipment, including power supplied to portions of a facility, when electric power from the local utility is interrupted, or stationary combustion turbines used to pump water in the case of fire or flood, etc. Emergency stationary combustion turbines do not include stationary combustion turbines used as peaking units at electric utilities or stationary combustion turbines at industrial facilities that typically operate at low capacity factors. Emergency combustion turbines may be operated for maintenance checks and readiness testing to retain their status as emergency combustion turbines, provided that the tests are required by the manufacturer, the vendor, or the insurance company associated with the turbine. Required testing of such units should be minimized, but there is no time limit on the use of emergency combustion turbines.
Excess emissions means a specified averaging period over which either (1) the NO X or SO 2 emissions rate are higher than the applicable emissions standard in §60.4320 or §60.4330; (2) the total sulfur content of the fuel being combusted in the af fected facility or the SO 2 emissions exceeds the standard specified in §60.4330; or (3) the recorded value of a particular monitored parameter, including ration of water or steam to fuel, is outside the acceptable range specified in the parameter monitoring plan for the affected unit. Federally enforceable means all limitations and conditi ons that are enforceable by th e Administrator or delegated authority, including the requirements of 40 CFR parts 60 and 61, requirements within any applicable State Implementation Plan, and any permit requirements established under 40 CFR 52.21 or under 40 CFR 51.18 and 51.24
Fuel oilmeans a fluid mixture of hydrocarbo ns that maintains a li quid state at ISO cond itions. Additionally, fuel oil must meet the definition of either distillate oil or residual oil as defined by the American Society for Testing and Materials in ASTM D396 (incorporated by reference, see §60.17) or diesel fuel as defined by the American Society for Testing and Materials in ASTM D975 (incorporated by reference, see §60.17). Gross useful energy output means: (1) For simple cycle and combined cycle combustion turbines, the gross useful work performed is the gross electrical or direct mechanical output from both the combustion turbine engine and any associated steam turbine(s). (2) For a CHP combustion turbine, the gross useful work performed is the gross electri cal or direct mechanical output from both the combustion turbine engine and any associated steam turbine(s) plus any useful thermal output measured relative to ISO conditions that is not used to generate additional electrical or mechanical output or to enhance the performance of the unit ( i.e. , steam delivered to an industrial process). (3) For a CHP combustion turbine where at least 20.0 percent of the total gross useful energy output consists of electric or direct mechanical output and 20.0 percent of the total gross useful energy output consists of useful Comment [CF50]: Need to add definition for SO2 exemption.

Comment [CF51]: Delete “before the exhaust gases enter a heat recovery steam generating unit” to clarify that any additional combustion with turbine engine exhaust is a duct burner.

### Page 26 of 29 thermal output on an annual basis, the gross useful work performed is the gross electrical or direct mechanical output from both the combustion turbine engine and any associated steam turbine(s) divided by 0.95 plus any useful thermal output measured relative to ISO conditions that is not used to generate additional electrical or mechanical output or to enhance the performance of the unit ( i.e. , steam delivered to an industrial process). Heat recovery steam generating unit means a unit where the hot exhaust gases from the combustion turbine engine are routed in order to extract heat from the gases and generate useful output. Heat recovery steam generating units can be used with or without duct burners. Integrated gasification comb ined cycle electric utility st eam generating unit (IGCC) means an electric utility steam generating unit that burns solid-derived fuels in a combined-cycle combustion turbine. No solid fuel is directly combusted in the unit during operation.
ISO conditions means 288 Kelvin (15 o C), 60 percent relative humidity and 101.325 kilopascals (kPa) pressure. Lean premix stationary combustion turbine means any stationary combustion turbine where the air and fuel are thoroughly mixed to form a lean mixture before delivery to the combustor. Mixing may occur before or in the combustion chamber. A lean premixed turbine may operate in diffusion flame mode during operating conditions such as startup and shutdown, extreme ambient temperature, or low or transient load. Low-Btu gas means biogas or any gas with a heating value of less than 26 megajoules per standard cubic meter (MJ/scm) (700 Btu/scf). Natural gas means a fluid mixture of hydrocarbons, composed of at least 70 percent methane by volume or that has a gross calorific value between 35 and 41 MJ/scm (950 and 1,100 Btu/scf), that maintains a gaseous state under ISO conditions. In addition, natural gas contains 460 mg/scm (20.0 gr/100 scf) or less of total sulfur. Finally, natural gas does not include any gaseous fuel produced in a process which might result in highly variable heating value.

Noncontinental area means Guam, American Samoa, the Northern Mariana Islands, or offshore platforms. Offshore turbine means a stationary combustion turbine located on a platform in an ocean Operating day means a 24-hour period between 12 midnight and the following midnight during which any fuel is combusted at any time in the unit. It is not necessary for fuel to be combusted continuously for the entire 24-hour period. Operating hour means a clock hour during which any fuel is combusted in the affected unit. If the unit combusts fuel for the entire clock hour, it is considered to be a full operating hour. If the unit combusts fuel for only part of the clock hour, it is considered to be a partial operating hour. Out-of-control period means any period beginning with the quadrant corresponding to the completion of a daily calibration error, linearity check, or qua lity assurance audit that i ndicates that the instrument is not measuring and recording within the applicable performance specifications and ending with the quadrant corresponding to the completion of an additional calibration error, linearity check, or qua lity assurance audit following corrective action that demonstrates that the instrument is measuring and recording within the applicable performance specifications. Simple cycle combustion turbine means any stationary combustion turbine which does not recover heat from the combustion turbine engine exhaust gases for purposes other than enhancing the performance of the stationary combustion turbine itself. Solid fuelmeans any fuel that has a definite shape and volume, has no tendency to flow or disperse under moderate stress, and is not liquid or gaseous at ISO conditions. This includes, but is not limited to, coal, biomass, and pulverized solid fuels. Stationary combustion turbine means all equipment, including but not li mited to the combustion turbine engine, the fuel, air, lubrication and exhaust gas systems, control systems, heat recovery system, steam turbine, fuel compressor, heater, and/or pump, post-combustion emissi on control technology, and any ancillary components and sub-components. Stationary means that the combustionturbine is not self prop elled or intended to be propelled while performing its function. It may, however, be mounted on a vehicle for portability. Standard cubic foot (scf) means the quantity of gas that would occupy a volume of 1 cubic foot at 293 Kelvin (20.0 o C) and 101.325 kPa of pressure. Comment [CF52]: Add definition of low btu gas to include blast furnace gas, coke oven gas, etc. Digester gas can have a heating value of slightly more than 600 Btu/scf, but to account for variability lets say 700 Btu/scf (HHV).
Comment [CF53]: Make similar to part 75 definition of natural gas

Comment [CF54]: Remove Hawaii, Puerto Rico, and Virgin Islands from definition.

Comment [CF55]: CAMD definition in 40 CFR 72.2 uses hour as the time period, but since KKKK allows the use of any data to determine an hourly average only the quadrant of out-of-control data is excluded.

### Page 27 of 29 Standard cubic meter (scm) means the quantity of gas th at would occupy a volume of 1 cubic meter at 293 Kelvin (20.0 o C) and 101.325 kPa of pressure. Turbine tuning means planned maintenance of a lean premix combustion turbine engine involving adjustment of the operating configuration to mainta in proper combustion dynamics. Turbine tuning is limited to 30 hours annually. Useful thermal output means the thermal energy made available for processes and applications other than electrical or mechanical generation or to enhance the perf ormance of the stationary combustion turbine (i.e., the thermal energy made available for use in any industrial or commercial process or used in any heating application). Useful thermal output for this subpart is measured relative to the enthalpy of the thermal output in its most prevalent form at ISO conditions (e.g., liquid water).

### Page 28 of 29 Table 1 to Subpart KKKK of Part 60 - Nitrogen Oxide Emi ssion Standards fo r Stationary Comb ustion Turbines Note: all numerical values have two significant figures

Combustion turbine type Combustion turbine heat input at base load rating (HHV) NO X emissions standard Alternate NO X emissions standard in ppm at 15 percent O 2

New turbine firing natural gas, electric generating ≤ 15 MW (50 MMBtu/h) 67 ng/J (0.16 lb/MMBtu) heat input or 290 ng/J of gross energy output (2.3 lb/MWh) 42

New turbine firing natural gas, mechanical drive ≤ 15 MW (50 MMBtu/h) 160 ng/J (0.37 lb/MMBtu) heat input or 690 ng/J of gross energy output (5.5 lb/MWh) 100

New turbine firing natural gas > 15 MW (50 MMBtu/h) and ≤

250 MW (850

MMBtu/h) 40 ng/J (0.093 lb/MMBtu) heat input or 150 ng/J of gross energy output (1.2 lb/MWh) 25

New, modified, or reconstructed turbine firing natural gas > 250 MW (850 MMBtuh) 24 ng/J (0.056 lb/MMBtu) heat input or 54 ng/J of gross energy output (0.43 lb/MWh) 15

New turbine firing fuels other than natural gas, electric generating ≤ 15 MW (50 MMBtu/h) 160 ng/J (0.38 lb/MMBtu) heat input or 710 ng/J of gross energy output (5.6 lb/MWh) 96

New turbine firing fuels other than natural gas, mechanical drive ≤ 15 MW (50 MMBtu/h) 250 ng/J (0.59 lb/MMBtu) heat input or 1,100 ng/J of gross energy output (8.7 lb/MWh) 150

New turbine firing fuels other than natural gas > 15 MW (50 MMBtu/h) and ≤

250 MW (850

MMBtu/h) 120 ng/J (0.29 lb/MMBtu) heat input or 470 ng/J of gross energy output (3.7 lb/MWh) 74

New, modified, or reconstructed turbine firing fuels other than natural gas > 250 MW (850 MMBtu/h) 73 ng/J (0.17 lb/MMBtu) heat input or 160 ng/J of gross energy output (1.3 lb/MWh) 42

Modified or reconstructed turbine ≤ 15 MW (50 MMBtu/h) 250 ng/J (0.59 lb/MMBtu) heat input or 1,100 ng/J of gross energy output (8.7 lb/MWh) 150

Modified or reconstructed turbine firing natural gas > 15 MW (50 MMBtu/h) and ≤

250 MW (850

MMBtu/h) 67 ng/J (0.16 lb/MMBtu) heat input or 250 ng/J of gross energy output (2.0 lb/MWh) 42

### Page 29 of 29 Modified or reconstructed turbine firing fuels other than natural gas > 15 MW (50 MMBtu/h) and ≤

250 MW (850

MMBtu/h) 160 ng/J (0.38 lb/MMBtu) heat input or 600 ng/J of gross energy output (4.8 lb/MWh) 96

Turbines located north of the Arctic Circle (latitude 66.5 degrees north), turbines operating at less than 75 percent of the base load rating, turbines operated during periods of turbine tuning, startup, or shutdown, modified and reconstructed offshore turbines, or turbines operating at temperatures less than minus 17 °C ≤ 100 MW (340 MMBtu/h) 250 ng/J (0.59 lb/MMBtu) heat input or 1,100 ng/J of gross energy output (8.7 lb/MWh) 150

Turbines located north of the Arctic Circle (latitude 66.5 degrees north), turbines operating at less than 75 percent of the base load rating, turbines operated during periods of turbine tuning, startup, or shutdown, modified and reconstructed offshore turbines, or turbines operating at temperatures less than minus 17 °C > 100 MW (340 MMBtu/h) 160 ng/J (0.38 lb/MMBtu) heat input or 610 ng/J of gross energy output (4.8 lb/MWh) 96

Heat recovery units operating independent of the combustion turbine engine All sizes 86 ng/J (0.20 lb/MMBtu) heat input or 110 ng/J of gross energy output (0.90 lb/MWh) 50