11 PROPOSED ADMINISTRATIVE RULES

SOAHR 2007-038

DEPARTMENT OF ENVIRONMENTAL QUALITY AIR QUALITY DIVISION

AIR POLLUTION CONTROL

Filed with the Secretary of State on

These rules become effective immediately upon filing with the Secretary of State unless adopted under sections 33, 44, 45a(6), or 48 of 1969 PA 306. Rules adopted under these sections become effective 7 days after filing with the Secretary of State.

(By authority conferred on the director of the department of environmental quality by sections 5503 and 5512 of 1994 PA 451, MCL 324.5503 and 324.5512, and Executive Reorganization Order No. 1995-18,

MCL 324.99903)

R 336.1801, R 336.1802a, R 336.1803, R 336.1821, R 336.1822, R 336.1823, R 336.1830,

R 336.1831, R 336.1832, and R 336.1833 of the Michigan Administrative Code are amended as follows:

PART 8. EMISSION LIMITATIONS AND PROHIBITIONS— OXIDES OF NITROGEN

R 336.1801 Emission of oxides of nitrogen from non-sip call stationary sources.

Rule 801. (1) As used in this rule:

(a) "Capacity factor" means either of the following:

(i) The ratio of a unit's actual annual electric output, expressed in megawatt hour, to the unit's nameplate capacity times 8,760 hours.

(ii) The ratio of a unit's annual heat input, expressed in million British thermal units or equivalent units of measure, to the unit's maximum design heat input, expressed in million British thermal units per hour or equivalent units of measure, times 8,760 hours.

(b) “Fossil fuel-fired” means the combustion of fossil fuel, alone or in combination with any other fuel, where the fossil fuel actually combusted comprises more than 50% of the fuel mass or annual heat input on a British thermal unit basis. Coke oven gas is a fossil fuel.

(c) "Low-NOx burners" means 1 of several developing combustion technologies used to minimize the formation of emissions of nitrogen oxides. As applicable to cement kilns, low-NOx burners means a type of cement kiln burner system designed to minimize NOx formation by controlling flame turbulence, delaying fuel/air mixing, and establishing fuel-rich zones for initial combusting, that for firing of solid fuel in the burning end zone of a kiln's main burner includes an indirect firing system or comparable technique for the main burner in the burning end zone of the kiln to minimize the amount of primary air supplied through the burner. In an indirect firing system, 1 air stream is used to convey pulverized fuel

from the grinding equipment and at least 1 or more other air streams are used to supply primary air to the burning end zone kiln burner of the kiln with the pulverized fuel, with intermediate storage of the fuel, and necessary safety and explosion prevention systems associated with the intermediate storage of fuel.

(d) "Mid-kiln system firing" means the secondary firing in a kiln system by injecting solid fuel at an intermediate point in the kiln system using a specially designed heat injection mechanism for the purpose of decreasing NOx emissions through coal burning part of the fuel at lower temperatures and reducing conditions at the fuel injection point that may destroy some of the NOx.

(e) “Non-sip call source” means any stationary source of oxides of nitrogen emissions that is not defined as an oxide of nitrogen budget source in R 336.1803.

(f) “Ozone control period” means the period of May 31, 2004, through September 30, 2004, and the period of May 1 through September 30 each subsequent and prior year.

(g) "Peaking unit" means a unit that has an average capacity factor of not more than 10% during the previous 3 calendar years and a capacity factor of not more than 20% in each of those calendar years.

(h) “Process heater” means any combustion equipment which is fired by a liquid fuel or a gaseous fuel, or both, and which is used to transfer heat from the combustion gases to a process fluid, superheated steam, or water.

(i) “Unit” means a fossil fuel-fired combustion device.

(j) “Utility system” means all interconnected units and generators which are subject to subrule (2) of this rule and which are operated by the same utility operating company or by common ownership and control.

(2) An owner or operator of a fossil fuel-fired, electricity-generating utility unit which has the potential to emit more than 25 tons each ozone control period of oxides of nitrogen and which serves a generator that has a nameplate capacity of 25 megawatts or more shall comply with the emission limits during the ozone control period as follows:

(a) By May 31, 2004, meet the least stringent of a utility system-wide average oxides of nitrogen emission rate of 0.25 pounds per million British thermal units heat input or an emission rate based on a 65% reduction of oxides of nitrogen from 1990 levels.

(b) The date listed in subdivision (a) of this subrule may be extended by up to 2 years if an owner or operator makes an acceptable demonstration to the department that the additional time is necessary to avoid disruption of the energy supply in the state or if the additional time is necessary to comply with the provisions of this rule.

(3) An owner or operator shall demonstrate compliance with the emission limits in subrule (2) of this rule as follows:

(a) To demonstrate compliance with a utility system-wide average emission rate, the owner or operator shall show that the sum of the mass emissions from all units owned or operated by a utility that is subject to subrule (2) of this rule which occurred during the ozone control period, divided by the sum of the heat input from all units owned or operated by a utility that is subject to subrule (2) of this rule which occurred during the ozone control period is less than or equal to the limits in subrule (2) of this rule.

(b) To demonstrate compliance with the percent reduction requirements of subrule (2) of this rule, the owner or operator shall provide calculations showing that the utility system average emission rate during each compliance ozone control period has been reduced below the 1990 ozone control period average emission rate by the applicable percent reduction listed in subrule (2) of this rule. The 1990 ozone control period average emission rate is the sum of the mass emissions from all units owned or operated by a utility that is subject to subrule (2) of this rule which occurred during the 1990 ozone control period divided by the sum of the heat input from all units owned or operated by a utility that is subject to subrule (2) of this rule which occurred during the 1990 ozone control period.

(4) By May 31, 2004, an owner or operator of a fossil fuel-fired emission unit which has the potential to emit more than 25 tons of oxides of nitrogen each ozone control period, except for an emission unit that is subject to subrule (2) of this rule, and which has a maximum rated heat input capacity of more than 250 million British thermal units per hour shall comply with the following provisions, as applicable:

(a) An owner or operator of a fossil fuel-fired, electricity-generating utility unit which serves a generator that has a nameplate capacity of less than 25 megawatts which has a maximum rated heat input capacity of more than 250 million British thermal units per hour shall comply with the appropriate oxides of nitrogen emission limit in table 81 of this rule.

(b) An owner or operator of a fossil fuel-fired boiler or process heater shall meet the emission limits contained in table 81 of this rule.

(c) An owner or operator of a gas-fired boiler or process heater that fires gaseous fuel which contains more than 50% hydrogen by volume shall comply with an oxide of nitrogen emission limit of 0.25 pounds per million Btu heat input.

(d) An owner or operator of a stationary internal combustion engine which is subject to the provisions of this rule and which has a maximum rated heat input capacity that is the heat input at 80 degrees Fahrenheit at sea level and takes into account inlet and exhaust losses shall comply with the following oxides of nitrogen emission limits, as applicable:

(i) For a natural gas-fired stationary internal combustion engine - 14 grams of oxides of nitrogen per brake horsepower hour at rated output.

(ii) For a diesel-fired stationary internal combustion engine - 10 grams of oxides of nitrogen per brake horsepower hour at rated output.

(e) An owner or operator of a cement kiln that is subject to the provisions of this rule shall reduce kiln oxides of nitrogen emissions by any of the following methods:

(i) Low oxides of nitrogen burners.

(ii) Mid-kiln system firing.

(iii) A 25% rate-based reduction of oxides of nitrogen from 1995 levels. Compliance with this paragraph shall be based on calculations showing that the emission rate, on a pounds of oxides of nitrogen per ton of clinker produced basis, during each compliance ozone control period, has been reduced below the 1995 ozone control period emission rate by 25%.

(f) An owner or operator of a stationary gas turbine which is subject to the provisions of this rule and which has a maximum rated heat input capacity that is the heat input at 80 degrees Fahrenheit at sea level and takes into account inlet and exhaust losses shall comply with an emission limit of 75 parts per million, dry volume, corrected to 15% oxygen, at rated capacity. The provisions of this rule do not apply to a stationary gas turbine that is subject to a new source performance standard contained in 40

C.F.R. part 60, subpart gg ~~(2001)~~, which is adopted by reference in ~~subrule (7) of this rule~~ R 336.1802a.

(g) An owner or operator of an emission unit which is subject to this rule and which is not otherwise subject to the provisions of subdivisions (a) to (f) of this subrule shall submit a proposal for oxides of nitrogen control by November 17, 2000. An owner or operator shall implement the control program by May 31, 2004, or by an alternate date approved by the department. The owner or operator shall obtain department approval of the proposed control program. The proposal for oxides of nitrogen control shall include all of the following information:

(i) A listing of reasonably available oxides of nitrogen control technologies, including the costs of installation and operation, cost of control per ton of oxides of nitrogen reduced, and the projected effectiveness of the proposed control technologies. The owner or operator shall use costing methodologies acceptable to the department.

(ii) The technology selected for controlling oxides of nitrogen emissions from the emission unit, considering technological and economic feasibility.

(iii) A proposal for testing, monitoring, and reporting oxides of nitrogen emissions.

(h) The compliance date listed in this subrule may be extended by up to 2 years if an owner or operator makes an acceptable demonstration to the department that the additional time is necessary to comply with the provisions of this rule. The owner or operator of a unit subject to subrules (2) and 4(a) to (f) of this rule may request an alternate emission limit or control requirement if there is an acceptable demonstration made to the department that compliance with the limits in table 81, or other limits or control requirements, is not reasonable. The request for an alternate emission limit or control requirement shall be submitted to the department within 60 days of the effective date of this amendatory rule and shall include all of the information listed in subdivision (g)(i) to (iii) of this subrule.

(5) The method for determining compliance with the emission limits in subrule (4) of this rule is as follows:

(a) If the emission limit is in the form of pounds of oxides of nitrogen per million British thermal unit, then the unit is in compliance if the sum of the mass emissions from the unit that occurred during the ozone control period, divided by the sum of the heat input from the unit that occurred during the ozone control period, is less than or equal to the limit in subrule (4) of this rule.

(b) For an emission unit not subject to subdivision (a) of this subrule, the method for determining compliance shall be a method acceptable to the department.

(6) An owner or operator of a source of oxides of nitrogen that is subject to the provisions of this rule may participate in Michigan’s emission trading program, being R 336. 2201 to R 336.2218.

(7) The owner or operator of an emission unit subject to subrule (2) of this rule shall measure oxides of nitrogen emissions with a continuous emission monitoring system; an alternate method as described in 40 C.F.R. part 60 or 75 and acceptable to the department; or a method currently in use and acceptable to the department, including methods contained in existing permit conditions. The provisions of 40

C.F.R. parts 60 and 75 ~~(2001)~~ are adopted by reference in R 336.1802a. ~~these rules. Copies of the~~ ~~regulations may be inspected at the Lansing office of the air quality division of the department of~~ ~~environmental quality. Copies of the regulations may be obtained from the Department of~~ ~~Environmental Quality, Air Quality Division, 525 West Allegan Street, P.O. Box 30260, Lansing,~~ ~~Michigan 48909-7760, or from the Superintendent of Documents, Government Printing Office, P.O.~~ ~~Box 371954, Pittsburgh, Pennsylvania 15250-7954, at a cost at the time of adoption of these rules of~~

~~$53.00 for part 60 and $55.00 for part 75; or on the United States government printing office internet~~ ~~web site at~~ ~~www.access.gpo.gov.~~

(8) The owner or operator of a boiler, process heater, stationary internal combustion engine, stationary gas turbine, cement kiln, or any other stationary emission unit that is subject to the provisions of subrule (4) of this rule shall measure oxides of nitrogen emissions by any of the following:

(a) Performance tests described in subrule (9) of this rule.

(b) Through the use of a continuous emission monitor in accordance with the provisions of subrule

(11) of this rule.

(9) An owner or operator of an emission unit that measures oxides of nitrogen emissions by performance tests as specified in subrule (8) of this rule shall do all of the following:

(a) Conduct an initial performance test not later than 90 days after the compliance deadline. For an emission unit that is not in service on or after the compliance deadline, the owner or operator shall contact the department and schedule an alternate initial performance test as agreed to by the department.

(b) After the initial performance test, conduct a compliance performance test each ozone control period or according to the following schedule:

(i) After 2 consecutive ozone control periods in which the emission unit demonstrates compliance, an owner or operator shall conduct performance tests at least once every 2 years during the ozone control period.

(ii) After a total of 4 consecutive ozone control periods in which the emission unit has remained in compliance, an owner or operator shall conduct performance tests at least once every 5 years during the ozone control period.

(c) If an emission unit is not in compliance at the end of an ozone control period, then the owner or operator shall conduct a compliance performance test each ozone control period, but can again elect to use the alternative schedule specified in subdivision (b) of this subrule.

(d) An owner or operator shall submit 2 copies of each compliance performance test to the department within 60 days of completion of the testing. The test results shall be presented and include data as requested in the department format for submittal of source emission test plans and reports. All performance test reports shall be kept on file at the plant and made available to the department upon request.

(10) An owner or operator of an emission unit who is required to conduct performance testing under subrule (8) of this rule shall submit a test plan to the department, not less than 30 days before the scheduled test date. To ensure proper testing, the plan shall supply the information in the department format for submittal of source emission test plans and reports. The owner or operator shall give the department a reasonable opportunity to witness the tests.

(11) An owner or operator of an emission unit that measures oxides of nitrogen emissions by a continuous emission monitoring system or an alternate method, as specified in subrule (7) or (8) of this rule, shall do either of the following:

(a) Use procedures set forth in 40 C.F.R., part 60, subpart A and appendix B, and comply with the quality assurance procedures in appendix F, or 40 C.F.R., part 75, and associated appendices, as applicable and acceptable to the department. Title 40 C.F.R., parts 60 and 75, are adopted by reference in ~~subrule (7) of this rule~~ R 336.1802a.

(b) An owner or operator of an emission unit who uses a continuous emission monitoring system to demonstrate compliance with this rule and who has already installed a continuous emission monitoring system for oxides of nitrogen pursuant to other applicable federal, state, or local rules shall meet the installation, testing, operation, calibration, and reporting requirements specified by federal, state, or local rules.

(12) The owner or operator of an emission unit that is subject to this rule shall submit a summary report, in an acceptable format, to the department within 60 days after the end of each ozone control period. The report shall include all of the following information:

(a) The date, time, magnitude of emissions, and emission rates where applicable, of the specified emission unit or utility system.

(b) If emissions or emission rates exceed the emissions or rates allowed for in the ozone control period by the applicable emission limit, the cause, if known, and any corrective action taken.

(d) For continuous emission monitoring systems, system performance information shall include the date and time of each period during which the continuous monitoring system was inoperative, except for zero and span checks, and the nature of the system repairs or adjustments. When the continuous monitoring system has not been inoperative, repaired, or adjusted, the information shall be stated in the report.

(13) Table 81 reads as follows:

Table 81

Boilers and process heaters with heat input capacity of 250 million Btu or more oxides of nitrogen (NOx) emission limitations (pounds NOx per million Btu of heat input averaged over the ozone control period)
Fuel type	Emission limit
Natural gas	0.20
Distillate oil	0.30
Residual oil	0.40
Coal (1) Coal spreader stoker (2) Pulverized coal fired	0.40 0.40
Gas (other than natural gas)1	0.25
For units operating with a combination of gas, oil, or coal, a variable emission limit calculated as the heat input weighted average of the applicable emission limits shall be used. The emission limit shall be determined as follows: Emission limit = a(0.20) + b(applicable oil limit) + c(applicable coal limit) + d(0.25) Where: a = Is the percentage of total heat input from natural gas b = Is the percentage of total heat input from oil c = Is the percentage of total heat input from coal d = Is the percentage of total heat input from gas (other than natural gas)

1This may include a mixture of gases. In this case, natural gas may be part of the mixture.

(14) The provisions of this rule do not apply to the following emission unit or units:

(a) A unit that is subject to oxides of nitrogen standards, which have been promulgated in a federal implementation plan under section 110(c) of the clean air act, required under section 126 of the clean air act, or promulgated in a federal regulation under 40 C.F.R. part 51 or part 60 and which are equally stringent or more stringent than this rule.

(b) A unit that is subject to any other rule included in this part.

(c) A peaking unit. The owner or operator shall retain records of capacity for a period of 5 years demonstrating that the unit meets the definition of a peaking unit. The unit shall become subject to the provisions of this rule on January 1 of the year following failure to meet the peaking unit definition.

R 336.1802a Adoption by reference.

Rule 802a. The following documents are adopted by reference in these rules. Copies are available for inspection and purchase at the Air Quality Division, Department of Environmental Quality, 525

West Allegan Street, P.O. Box 30260, Lansing, Michigan 48909-7760, at the cost at the time of adoption of these rules (AQD price). Copies may be obtained from the Superintendent of Documents, Government Printing Office, P.O. Box 371954, Pittsburgh, Pennsylvania, 15250 7954, at the cost at the time of adoption of these rules (GPO price), or on the United States government printing office internet web site at http://www.gpoaccess.gov:

(a) Title 40 C.F.R., part 60, “Standards of Performance for New Stationary Sources” (2007), AQD price $68.00, appendices $67.00; GPO price $58.00, appendices $57.00.

~~(a)~~(b) Title 40 C.F.R., §72.2 definitions under the “Acid Rain Program General Provisions” ~~(2006)~~

(January 24, 2008), AQD price $72.00; GPO price $62.00.

~~(b)~~(c) Title 40 C.F.R. §72.8, “Retired Units Exemption” ~~(2006)~~ (January 24, 2008), AQD price

$72.00; GPO price $62.00

~~(c)~~(d) Title 40 C.F.R., part 75, “Continuous Emission Monitoring” ~~(2006)~~ (January 24, 2008), AQD price $72.00; GPO price $62.00.

~~(d)~~(e) Title 40 C.F.R., §97.2, 97.102, 97.103, 97.302 and 97.303, definitions under the “Federal Oxides of Nitrogen (NOx) Budget Trading Program and CAIR NOx and Sulfur Dioxide (SO2) Trading Programs” ~~(2006)~~ (October 17, 2007), AQD price $70.00; GPO price $60.00.

~~(e)~~(f) Title 40 C.F.R., part 97; §§97.180 to 97.188 and §§97.380 to 97.388, opt-in provisions under the “Federal Oxides of Nitrogen (NOx) Budget Trading Program and CAIR NOx and Sulfur Dioxide (SO2) Trading Programs” ~~(2006)~~ (October 17, 2007), AQD price $70.00; GPO price $60.00.

R 336.1803 Definitions.

Rule 803. (1) The provisions of 40 C.F.R. §96.2 are adopted by reference in this rule. The definitions for the oxides of nitrogen budget trading program in 40 C.F.R. §96.2 are applicable to

R 336.1802 to R 336.1816. In addition, all of the following definitions apply as indicated, including a modification to the “NOx budget trading program” definition:

(a) “Electric-generating unit (EGU)” means the following:

(i) For units that commenced operation before January 1, 1997, a unit serving a generator during 1995 or 1996 that had a nameplate capacity of more than 25 megawatts and produced electricity for sale.

(ii) For units that commenced operation on or after January 1, 1997, and before January 1, 1999, a unit serving a generator during 1997 or 1998 that had a nameplate capacity of more than 25 megawatts and produced electricity for sale.

(iii) For units that commence operation on or after January 1, 1999, a unit serving a generator at any time that has a nameplate capacity of more than 25 megawatts and produces electricity for sale.

(b) “Large affected unit” means the following:

(i) For units that commenced operation before January 1, 1997, a unit that has a maximum design heat input of more than 250,000,000 Btu's per hour and that did not serve during 1995 or 1996 a generator producing electricity for sale.

(ii) For units that commenced operation on or after January 1, 1997, and before January 1, 1999, a unit that has a maximum design heat input of more than 250,000,000 Btu's per hour and that did not serve during 1997 or 1998 a generator producing electricity for sale.

(iii) For units that commence operation on or after January 1, 1999, a unit that has a maximum design heat input of more than 250,000,000 Btu's per hour and to which either of the following provisions applies:

(A) The unit at no time serves a generator producing electricity for sale.

(B) The unit at any time serves a generator producing electricity for sale, if any such generator has a nameplate capacity of 25 megawatts or less and has the potential to use not more than 50% of the potential electrical output capacity of the unit.

(i) Allegan.

(ii) Barry.

(iii) Bay.

(iv) Berrien.

(v) Branch.

(vi) Calhoun.

(vii) Cass.

(viii) Clinton.

(ix) Eaton.

(x) Genesee.

(xi) Gratiot.

(xii) Hillsdale.

(xiii) Ingham.

(xiv) Ionia.

(xv) Isabella.

(xvi) Jackson.

(xvii) Kalamazoo.

(xviii) Kent.

(xix) Lapeer.

(xx) Lenawee.

(xxi) Livingston.

(xxii) Macomb.

(xxiii) Mecosta.

(xxiv) Midland.

(xxv) Monroe.

(xxvi) Montcalm.

(xxvii) Muskegon.

(xxviii) Newaygo.

(xxix) Oakland.

(xxx) Oceana.

(xxxi) Ottawa.

(xxxii) Saginaw.

(xxxiii) Saint Clair.

(xxxiv) Saint Joseph.

(xxxv) Sanilac.

(xxxvi) Shiawassee.

(xxxvii) Tuscola.

(xxxviii) Vanburen.

(xxxix) Washtenaw.

(xl) Wayne.

(d) “NOx budget trading program” means a multi-state nitrogen oxides air pollution control and emission reduction program established pursuant to 40 C.F.R. part 96 and part 97. The provisions of 40

C.F.R. part 96 and part 97 are adopted by reference in subrule (2) of this rule.

(e) “Ozone control period” means the period of May 31, 2004, through September 30, 2004, and the period of May 1 to September 30 each subsequent and prior year. The term "ozone control period" replaces the term “control period.”

(2) For R 336.1803 to R 336.1816, the provisions of 40 C.F.R. part 96 and part 97 ~~(2006)~~(2007) are adopted by reference, except as modified in R 336.1804, R 336.1805, R 336.1808, R 336.1811, R 336.1813, and R 336.1815. Copies may be inspected at the Lansing office of the air quality division of the department of environmental quality. Copies of the regulations may be obtained from the Department of Environmental Quality, Air Quality Division, 525 West Allegan Street, P.O. Box 30260, Lansing, Michigan 48909-7760, at a cost as of the time of adoption of this rule of $70.00. A copy may also be obtained from the Superintendent of Documents, Government Printing Office, P.O. Box 371954, Pittsburgh, Pennsylvania 15250-7954, at a cost as of the time of adoption of this rule of $60.00; or on the United States government printing office internet web site at www.access.gpo.gov.

(3) Definitions under the clean air interstate rule NOx ozone season and annual trading programs in 40 C.F.R. §97.102 and §97.302 are applicable to R 336.1821 to R 336.1834. In addition, all of the following definitions apply as indicated:

(a) “Biomass” means ~~wood, wood residue, and wood products (for example, trees, tree stumps, tree~~ ~~limbs, bark, lumber, sawdust, sander dust, chips, scraps, slabs, millings, and shavings); animal litter;~~ ~~vegetative agricultural, and silvicultural materials, such as logging residues (slash), nut and grain hulls,~~ ~~and chaff (for example, almond, walnut, peanut, rice, and wheat), bagasse, orchard prunings, corn stalks,~~ ~~coffee bean hulls and grounds~~ the same as defined in 40 C.F.R §97.102 and §97.302.

(b) “CAIR” means clean air interstate rule.

~~(c) “Commence commercial operation" means the following:~~

~~(i) For a unit not serving a generator producing electricity for sale, the unit's date of commencement~~ ~~of operation shall also be the unit's date of commencement of commercial operation.~~

~~(ii) For a unit with a date of commencement of operation as defined in this subrule and that~~ ~~subsequently undergoes a physical change (other than replacement of the unit by a unit at the same~~ ~~source), such date shall remain the date of commencement of operation of the unit, which shall continue~~ ~~to be treated as the same unit.~~

~~(iii) For a unit with a date for commencement of operation as defined in this subrule and that is~~ ~~subsequently replaced by a unit at the same source (for example, repowered), such date shall remain the~~ ~~replaced unit's date of commencement of operation, and the replacement unit shall be treated as a~~ ~~separate unit with a separate date for commencement of operation as defined in this subrule as~~ ~~appropriate.~~

(c) “Cogeneration unit” means the same as defined in 40 C.F.R §97.102 and §97.302.

(d) “Commence commercial operations” means the same as defined in 40 C.F.R §97.102 and

§97.302.

(e) “Commence operations” means the same as defined in 40 C.F.R §97.102 and §97.302. (f)~~(d)~~ Electric generating unit or “EGU” means any of the following:

(i) For the purposes of the CAIR NOx ozone season trading program; a CAIR NOx ozone season unit as defined under 40 C.F.R. §97.304,

(ii) For the purposes of the CAIR NOx ozone season trading program, electric generating units required to be in Michigan's NOx SIP budget trading program that are not already included under 40

C.F.R. §96.304, which are defined as the following units located in Michigan’s fine grid zone:

(A) For units that commenced operation before January 1, 1997, a unit serving a generator during 1995 or 1996 that had a nameplate capacity of more than 25 megawatts and produced electricity for sale.

(B) For units that commenced operation on or after January 1, 1997, and before January 1, 1999, a unit serving a generator during 1997 or 1998 that had a nameplate capacity of more than 25 megawatts and produced electricity for sale.

(C) For units that commence operation on or after January 1, 1999, a unit serving a generator at any time that has a nameplate capacity of more than 25 megawatts and produces electricity for sale.

(iii) For purposes of the CAIR NOx annual trading program; a CAIR NOx unit as defined under 40

C.F.R. §97.104.

(g) “Equivalent,” for the purpose of allocating allowances pursuant to Michigan’s CAIR programs, is determined using equation F.5 in 40 C.F.R. part 75, appendix F.

~~(e)~~(h) “Existing EGUs” for allocation purposes under R 336.1821 to R 336.1834, means electric generating units that commenced operations prior to the most recent year of the 5-year period used to calculate the allocations pursuant to these rules.

~~(f)~~(i) “Fossil fuel-fired,” means as defined in 40 C.F.R. §97.2 for the purposes of determining applicability for units that are considered either of the following:

(i) EGUS as defined pursuant to R 336.1803(3)(d)(ii) (f).

(ii) Non-EGUs as defined pursuant to R 336.1803(3)(k) (p).

~~(g)~~(j) “Fuel types,” for the allocation of allowances under Michigan’s CAIR programs only, means solid, liquid, and gaseous fuel. The following definitions apply to fuel:

(i) “Solid fuel” includes, but is not limited to coal, biomass, tire-derived fuels, and pet coke.

(ii) “Liquid fuel” includes, but is not limited to petroleum-based oils, glycerol, vegetable-based and animal waste-based liquids.

(iii) “Gaseous fuel” includes, but is not limited to coke oven gas, natural gas, propane, coal gas, blast furnace gas, and methane derived from animal wastes.

(k) “Maximum design heat input” means the same as defined in 40 C.F.R §97.102 and §97.302.

~~(h)~~(l) “Michigan fine grid zone” means the geographical area that includes all of the following counties:

(i) Allegan.

(ii) Barry.

(iii) Bay.

(iv) Berrien.

(v) Branch.

(vi) Calhoun.

(vii) Cass.

(viii) Clinton.

(ix) Eaton.

(x) Genesee.

(xi) Gratiot.

(xii) Hillsdale.

(xiii) Ingham.

(xiv) Ionia.

(xv) Isabella.

(xvi) Jackson.

(xvii) Kalamazoo.

(xviii) Kent.

(xix) Lapeer.

(xx) Lenawee.

(xxi) Livingston.

(xxii) Macomb.

(xxiii) Mecosta.

(xxiv) Midland.

(xxv) Monroe.

(xxvi) Montcalm.

(xxvii) Muskegon.

(xxviii) Newaygo.

(xxix) Oakland.

(xxx) Oceana.

(xxxi) Ottawa.

(xxxii) Saginaw.

(xxxiii) Saint Clair.

(xxxiv) Saint Joseph.

(xxxv) Sanilac.

(xxxvi) Shiawassee.

(xxxvii) Tuscola.

(xxxviii) Vanburen.

(xxxix) Washtenaw.

(xl) Wayne.

(m) “Nameplate capacity” means the same as defined in 40 C.F.R §97.102 and §97.302.

(n) ~~(i)~~ “New EGUs,” for allocation purposes under R 336.1821 to R 336.1834, means electric generating units that are commencing operation or projected to commence operation on or after January 1 of the most recent year of the 5-year period used to calculate the allocations pursuant to these rules.

(o)~~(j)~~ “Newly-affected EGUs,” for allocation purposes under R 336.1821 to R 336.1834, means existing EGUs located outside the Michigan fine grid zone or existing EGUs located within the Michigan fine grid zone which were exempt from the federal NOx budget program. This definition is applicable for the 2009 CAIR NOx ozone season program only and after that time the newly affected EGUs are considered existing EGUs. This definition excludes the Harbor Beach power plant which was previously included as an EGU in the NOx SIP Budget trading program and is considered existing for the purposes of CAIR NOx ozone season program.

(p)~~(k)~~ “Non-EGUs” means the following units located in Michigan’s fine grid zone:

(A) The unit at no time serves a generator producing electricity for sale.

~~(l)~~(q) “Ozone Season” means May 1 to September 30 of each calendar year.

~~(m)~~(r) “Renewable energy source,” for allocation purposes under R 336.1821 to R 336.1826, means a source, located in Michigan, that generates electricity by solar, wind, geothermal, or hydroelectric processes, excluding nuclear, that has commenced operation or is projected to commence operation on or after January 1 of the most recent year of the 5-year period used to calculate the allocations pursuant to these rules, which meets all of the following:

(i) Serves a generator at 25 megawatts or greater of electrical output.

(ii) Is not subject to R 336.1801(4)(a) or covered by any other definitions in this rule.

(iii) Captures energy from on-going natural processes.

(iv) Is considered a non-emitting, having zero emissions, source.

~~(n)~~(s) “Renewable energy projects,” for allocation purposes under R 336.1821 to R 336.1826, means renewable energy sources, located in Michigan and located within the same geographic area that when added together equal a generator greater than 25 megawatts of electrical output.

~~(o)~~(t) “Unit” means a fossil fuel-fired stationary boiler, combustion turbine, or combined cycle system, pursuant to EGUs as defined under R 336.1803(3)(d)(ii)(f) and non-EGUs as defined under R 336.1803(3)(k) (p).

R 336.1821 CAIR NOx ozone season and annual trading programs; applicability determinations.

Rule 821. (1) This rule establishes Michigan’s CAIR ozone season and annual emission budgets and trading programs for all of the following units:

(a) CAIR NOx units as defined pursuant to 40 C.F.R. §97.104.

(b) CAIR NOx ozone season units as defined pursuant to 40 C.F.R §97.304.

(c) All units required to be in the state's NOx SIP call trading program that are not already included under 40 C.F.R. §96.304 and are defined in R 336.1803(3)(d)(ii)(f) and ~~(k)~~ (p).

(d) For purposes of allocating allowances under R 336.1821 to R 336.1826, the following units which are not addressed in subparagraphs (a), (b) and (c) of this subrule are CAIR NOx ozone season units:

(i) Renewable energy sources.

(ii) Renewable energy projects.

(2) An EGU located in Michigan and subject to the requirements pursuant to R 336.1821(a), (b) or

(c) shall apply for and receive an annual or ozone season CAIR NOx permit. In addition, non-EGUs as defined in R 336.1803(3)(k)(p) shall apply for and receive an ozone season CAIR NOx permit. This permit shall be administered under R 336.1214 and shall be incorporated into the source's renewable operating permit as an attachment. A federally enforceable NOx budget permit issued under the federal NOx budget program pursuant to R 336.1808 shall remain in effect until the CAIR NOx ozone season permit has been approved by the department.

(3) The fuel type adjusted allocations for each existing EGU shall be determined by multiplying the appropriate NOx emission rate and heat input as determined in accordance with R 336.1822 and R 336.1830 with an appropriate fuel adjustment factor coefficient as follows:

(a) For a solid fuel-fired EGU, the allocation calculations shall be adjusted by multiplying the allocation values by 100%, i.e. 1.0.

(b) For a liquid fuel-fired EGU, the allocation calculations shall be adjusted by multiplying the allocation values by 60%, i.e. 0.60.

(c) For a gaseous fuel-fired EGU, the allocation calculations shall be adjusted by multiplying the allocation values by 40%, i.e. 0.40.

(d) For a multi-fueled EGU, the allocation adjustment calculation shall be a weighted average based on the percentage heat input from each type of fuel burned in the unit, unless the source can demonstrate that certain types of fuel used in the process provided less than 10% of the annual heat input. If so, then the allocation adjustment is calculated based on only those fuel types which contributed 10% or more of the annual heat input.

(4) The owner or operator of any CAIR NOx ozone season or annual unit shall submit ~~all~~ both of the following data within 30 days upon request by the department:

(a) A unit’s ozone season and annual heat input values or megawatt energy produced, which shall be the same data reported in accordance with 40 C.F.R. part 75 to the extent the unit is subject to 40 C.F.R. part 75 for the period involved.

(b) A unit’s total tons of oxides of nitrogen emissions during specified calendar years or ozone seasons as determined under 40 C.F.R. part 75, adopted by reference in R 336.1802.

(5) Effective January 1, 2009, the provisions of R 336.1802, R 336.1803(1) and R 336.1803(2),

R 336.1804, R 336.1805, R 336.1806, R 336.1807, R 336.1808, R 336.1809, R 336.1810, R 336.1811,

R 336.1812, R 336.1813, R 336.1814, R 336.1815, and R 336.1816 shall not apply to the control period beginning in 2009 or any control period thereafter.

(6) Pursuant to the provisions in 40 C.F.R. 96.54 and for the 2009 control period only, if the U.S. environmental protection agency determines that there were excess emissions during the 2008 control period, deductions for excessive emission penalties shall be taken from the 2009 CAIR NOx ozone season allowances.

(7) Pursuant to any NOx SIP unused set-aside allowances through 2008 that are accumulated within the state account, the department shall allocate these allowances according to R 336.1823.

(8) Permitted emission rate equal to or less than 0.1 pounds per million Btu or its equivalent, for the purposes of allocating allowances pursuant to R 336.1822 and R 336.1830, shall be in a legally enforceable permit to install or renewable operating permit issued on or before August 1, 2008, for the October 2008 allocating time period; on or before August 1, 2011, for the October 2012 allocating time period and thereafter each August 1 of the year that is 3 years after the last year of allocation submittal time period.

R 336.1822 CAIR NOx ozone season trading program; allowance allocations.

Rule 822. (1) The CAIR NOx ozone season trading program budget allocated by the department under subrule (3) of this rule for the CAIR NOx ozone season control periods to the EGUs, non-EGUs, and renewable energy sources shall annually equal the total number of tons of oxides of nitrogen emissions as indicated in the following manner:

(a) The total CAIR NOx ozone season budget for the ozone season time period of 2010 to 2014 is 31,180 tons. These allocations shall be distributed as follows:

(i) The CAIR NOx ozone season budget available to existing and newly-affected EGUs. The following applies:

(A) For 2010 and 2011 ozone season control periods equals 28,321 tons.

(B) For 2012 to 2014 ozone season control periods equals 28,021 tons.

(ii) The CAIR NOx ozone season budget available to existing non-EGUs for the 2010 to 2014 ozone season control periods is 1,309 tons.

(iii) The CAIR NOx ozone season budget available to new non-EGUs and EGUs. The following applies:

(A) For 2010 and 2011 ozone season control periods is 700 tons.

(B) For 2012 to 2014 ozone season control periods is 1,000 tons.

(iv) The CAIR NOx ozone season budget available to renewable energy sources and projects in the 2010 to 2014 ozone season control periods is 200 tons.

(v) The CAIR NOx ozone season budget available to all existing EGUs and non-EGUs that have submitted an acceptable demonstration of a hardship to the department, in the 2010 to 2014 ozone season control periods is 650 tons.

(b) The total CAIR NOx ozone season budget for the ozone season time period of 2015 and thereafter is 26,351 tons. These allocations shall be distributed as follows:

(i) The CAIR NOx ozone season budget available to existing EGUs in the 2015 and thereafter ozone season control periods is 22,792 tons.

(ii) The CAIR NOx ozone season budget available to existing ozone season non-EGUs for the 2015 and thereafter ozone season control periods is 1,309 tons.

(iii) The CAIR NOx ozone season budget available to new non-EGUs and EGUs in the 2015 and thereafter ozone season control periods is 1,400 tons.

(iv) The CAIR NOx ozone season budget available to renewable energy sources and projects in the 2015 and thereafter ozone season control periods is 200 tons.

(v) The CAIR NOx ozone season budget available to all existing EGUs and non-EGUs that have submitted an acceptable demonstration of hardship to the department, in the 2015 and thereafter ozone season control periods is 650 tons.

(2) CAIR NOx allowances for the 2009 ozone season control period shall be the same allowances as were allocated under the NOx budget trading program. For newly-affected EGUs which were not subject to the federal NOx budget program, these units are eligible to apply for allowances from the CAIR NOx ozone season new source set-aside pool for the 2009 ozone season, pursuant to R 336.1823.

(3) The department shall allocate CAIR NOx ozone season allowances to existing EGUs and non- EGU ozone season units for calendar years 2010 and thereafter according to the following schedule:

(a) A 3-year allocation that is 3 years in advance of the 2010 ozone season and 4 years in advance of each subsequent ozone season control period. The 3-year allocation shall be as follows:

(i) By 60 days after the effective date of this rule or April 30, 2007, whichever is earlier, the department shall submit to the U.S. environmental protection agency the CAIR NOx ozone season allowance allocations, under this subrule, for the ozone season control periods in 2010 and 2011.

(ii) By October 31, 2008, the department shall submit to the U.S. environmental protection agency the CAIR NOx ozone season allowance allocations, under this subrule, for the ozone season control periods in 2012, 2013, and 2014.

(iii) By October 31, 2011, and thereafter each October 31 of the year that is 3 years after the last year of allocation submittal, the department shall submit to the U.S. environmental protection agency the CAIR NOx ozone season allowance allocations as indicated under this subrule.

(4) For the CAIR NOx ozone season control periods under subrule (3) of this rule, the department shall allocate allowances to existing EGU and non-EGU ozone season units that commenced operation before January 1 of the most recent year of the 5-year period used to calculate heat input as follows:

(a) The department shall allocate allowances to each existing EGU ozone season unit as follows:

(i) During calendar years 2010 to 2014 as follows:

(A) Existing EGUs with a permitted NOx emission rate equal to or less than 0.10 pounds per million Btu shall receive an initial unadjusted allocation of allowances determined by calculating the arithmetic average of the CAIR target emission rate multiplied by the appropriate fuel adjustment factor plus the unit’s permitted emission rate, which is then multiplied by the heat input as determined under subrule (6) of this rule, divided by 2,000 pounds per ton, and rounded to the nearest whole oxides of nitrogen allowance, as appropriate.

⎡⎧(CTER x FAF )+ PER ⎫ ⎤

⎢⎩ 2 ⎭ ⎥

⎢ ⎥

⎣⎢ ⎥⎦

Where:
Allocation =	The initial unadjusted NOx allowance allocation, in tons.
CTER =	The CAIR target emission rate for 2009 to 2014 of 0.15 pounds per mm Btu.
FAF =	Fuel adjustment factor as defined in R 336.1821.
PER =	The unit’s permitted NOx emission rate as defined in R 336.1821

11 PROPOSED ADMINISTRATIVE RULES

(a) Title 40 C.F.R., part 60, “Standards of Performance for New Stationary Sources” (2007), AQD price $68.00, appendices $67.00; GPO price $58.00, appendices $57.00.

(c) “Cogeneration unit” means the same as defined in 40 C.F.R §97.102 and §97.302.

(g) “Equivalent,” for the purpose of allocating allowances pursuant to Michigan’s CAIR programs, is determined using equation F.5 in 40 C.F.R. part 75, appendix F.

(k) “Maximum design heat input” means the same as defined in 40 C.F.R §97.102 and §97.302.

(m) “Nameplate capacity” means the same as defined in 40 C.F.R §97.102 and §97.302.

Document Information