department of public health and environment
Air Quality Control Commission
Regulation No. 6
Standards of Performance for New Stationary Sources
5 CCR 1001-8
PART A
Federal Register Regulations Adopted by Reference
The regulations promulgated by the United States Environmental Protection Agency listed below, found in Part 60, Chapter I, Title 40, of the Code of Federal Regulations (CFR) and in effect as of the dates indicated, but not including later amendments, were adopted by the Colorado Air Quality Control Commission and are hereby incorporated by reference.  Copies of the material incorporated by reference are available for public inspection during regular business hours at the Office of the Commission, located at 4300 Cherry Creek Drive South, Denver, Colorado 80222-1530, or may be examined at any state publications depository library.  Parties wishing to inspect these materials should contact the Technical Secretary of the Commission, located at the Office of the Commission.   
All new sources of air pollution and all modified or reconstructed sources of air pollution shall comply with the standards, criteria, and requirements set forth herein.  For the purpose of this regulation, the word "Administrator" as used in Part 60, Chapter I, Title 40, of the CFR shall mean the Colorado Air Pollution Control Division, except that in the sections in Table 1, "Administrator" shall mean both the Administrator of the Environmental Protection Agency or his authorized representative and the Colorado Air Pollution Control Division.  (Other deviations from these federal standards, as presented in the CFR and which the Colorado Air Quality Control Commission ordered, are noted in the affected Subpart, and/or included in Part B of this Regulation.)
TABLE 1
40 CFR Part 60 Subpart*	Section(s)	
A	60.8(b)(2) and (b)(3) and those sections throughout the standards that reference 60.8(b)(2) and (b)(3), 60.11(b) and (e).	
Da	60.45a.	
Ka	60.114a.	
Kb	60.111b(f)(4), 60.114b, 60.116b (e)(3)(iii) and (e)(3)(iv), 60.116b(f)(2)(iii).	
S	60.195(b).	
DD	60.302(d)(3).	
GG	60.332(a)(3), 60.335(a).	
VV	60.482-1(c)(2), 60.484.	
WW	60.493(b)(2)(i)(A), 60.496(a)(1).	
XX	60.502(e)(6).	
GGG	60.592(c).	
JJJ	60.623.	
KKK	60.634.	
*And any other section which 40 CFR Part 60 specifically states will not be delegated to the States.
Subpart A	General Provisions 40 CFR Part 60 (July 1, 2006), and as amended on July 6, 2006, May 16, 2007 and June 13, 2007.
(See Part B of this Regulation Number 6 for Additional Requirements Regarding Modifications)
Subpart Cb	Emission Guidelines and Compliance Times for Existing Sources: Municipal Waste Combustors That Are Constructed On or Before September 20, 1994.  40 CFR Part 60 (July 1, 2006).
Subpart Cc	Emission Guidelines and Compliance Times for Municipal Solid Waste Landfills.  40 CFR Part 60 (July 1, 2006).  
In addition for clarification regarding requirements applicable to existing municipal solid waste landfills, designated facilities as defined in 40 CFR Part 60, Section 60.32c which meet the condition in 40 CFR Part 60, Section 60.33c(a)(1) shall submit to the Division an initial design capacity report and an initial emission rate report in accordance with 40 CFR Part 60, Section 60.757 within 90 days of the effective date of this regulation.  If the design capacity report reflects that the facility meets the condition in 40 CFR Part 60, Section 60.33c(a)(2) and the initial NMOC emission rate report reflects that the facility meets the condition in 40 CFR Part 60, Section 60.33c(a)(3), the facility shall comply with the collection and control system requirements in 40 CFR Part 60, Section 60.752(b)(2)(ii), applicable control device requirements in 40 CFR Part 60, Section 60.33c(c)(1), (2) and (3), test methods and procedures requirements in 40 CFR 60.754, operational standards in 40 CFR Part 60, Section 60.753, compliance provisions in 40 CFR Part 60, Section 60.755, monitoring provisions in 40 CFR Part 60, Section 60.756 and reporting and recordkeeping provisions in 40 CFR Part 60, Sections 60.757 and 60.758, respectively.  Such facilities must complete installation of air emission collection and control equipment capable of meeting the requirements of this subpart no later than 30 months from the effective date of these requirements or the date on which the source becomes subject to this subpart pursuant to 40 CFR Part 60, Section 60.36c(b) (the date on which the condition in 60.33c(a)(3) is met (i.e., the date of the first annual report in which the nonmethane organic compounds emission rate equals or exceeds 50 megagrams per year)), whichever occurs later. These facilities must submit a final collection and control system design plan pursuant to 40 CFR Part 60, Section 60.757(c) within one year of the effective date of these requirements, which must be reviewed and approved by the state.  The final collection and control system design plan must specify: (1) the date by which contracts for control systems/process modifications shall be awarded, (which shall be no later than 20 months after the effective date); (2) the date by which on-site construction or installation of the air pollution control device(s) or process changes will begin, (which shall be no later than 24 months after the effective date); and (3) the date by which the construction or installation of the air pollution control device(s) or process changes will be complete (which shall be no later than 30 months after the effective date).  In addition, the plan shall include site-specific design plans for the gas collection and control system(s).  These facilities shall comply with the approved final collection and control system design plan and shall demonstrate compliance with these emission standards in accordance with 40 CFR Part 60, Section 60.8 not later than 180 days following initial startup of the collection and control system.  The Commission designates the effective date for these requirements applicable to designated facilities, including the state emission standard for existing municipal solid waste landfills, as the date on which the United States Environmental Protection Agency promulgates a final rule approving the state plan under Section 111(d) of the Clean Air Act.
Subpart Ce	Emission Guidelines and Compliance Times for Hospital/Medical/Infectious Waste Incinerators.  40 CFR Part 60, Subpart Ce, 40 CFR Part 60 (July 1, 2006) Paragraphs 60.31e, 60.32e, 60.33e, 60.34e, 60.35e, 60.36e, 60.37e, 60.38e, 60.39e.
The Commission designates the effective date for these requirements applicable to designated facilities as the date on which the United States Environmental Protection Agency promulgates a final rule approving the state plan (which can be obtained from the Air Quality Control Commission office) under Section 111(d) of the Clean Air Act.  Designated facilities shall comply with all requirements of this Subpart Ce on or before one year from the effective date for these requirements.
Subpart D	Standards of Performance for Fossil-Fuel-Fired Steam Generators for which Construction is Commenced after August 17, 1971. 40 CFR Part 60 (July 1, 2006), and as amended on June 13, 2007.
Subpart Da	Standards of Performance for Electric Utility Steam Generators for which Construction is Commenced after September 18, 1978.  40 CFR Part 60 (July 1, 2006) and as amended on June 13, 2007.
(See Subpart HHHH below and Part B of this Regulation Number 6 for additional requirements regarding Electric Utility Steam Generating Units)
Subpart Db	Standards of Performance for Industrial-Commercial-Institutional Steam Generating Units. 40 CFR Part 60 (July 1, 2006) and as amended on June 13, 2007.
(See Part B, Section III.D. of this Regulation Number 6 for Additional Requirements)
Subpart Dc	Standards of Performance for Small Industrial-Commercial- Institutional Steam Generating Units.  40 CFR Part 60 (July 1, 2006) and as amended on June 13, 2007.
Subpart E	Standards of Performance for Incinerators.  40 CFR Part 60 (July 1, 2006.
(See Part B, Sections V, VI and VII of this Regulation No. 6 for Additional Requirements)  
Subpart Ea	Standards of Performance for Municipal Waste Combustors For Which Construction Is Commenced After December 20, 1989 and On or Before September 20, 1994.  40 CFR Part 60 (July 1, 2006).
Subpart Eb	Standards of Performance for Municipal Waste Combustors For Which Construction Is Commenced After September 20, 1994.   40 CFR Part 60 (July 1, 2006).
(See Part B, Section VI of this Regulation No. 6 for Additional Requirements)
Subpart Ec	Standards of Performance for Hospital/Medical/Infectious Waste Incinerators for Which Construction is Commenced After June 20, 1996.  40 CFR Part 60, Subpart Ec, 40 CFR Part 60 (July 1, 2006).
(See Part B, Section V of this Regulation No. 6 for Additional Requirements)
Subpart F	Standards of Performance for Portland Cement Plants.  40 CFR Part 60 (July 1, 2006).
Subpart G	Standards of Performance for Nitric Acid Plants.  40 CFR Part 60 (July 1, 2006).
Subpart H	Standards of Performance for Sulfuric Acid Plants.  40 CFR Part 60 (July 1, 2006).
Subpart I	Standards of Performance for Hot Mix Asphalt Facilities.  40 CFR Part 60 (July 1, 2006).
Subpart J	Standards of Performance for Petroleum Refineries. 40 CFR Part 60 (July 1, 2006).
Subpart K	Standards of Performance for Storage Vessels for Petroleum Liquids Constructed after June 11, 1973 and prior to May 19, 1978.  40 CFR Part 60 (July 1, 2006).
Subpart Ka	Standards of Performance for Storage Vessels for Petroleum Liquids Constructed after May 18, 1978, and prior to July 23, 1984.  40 CFR Part 60 (July 1, 2006).
Subpart Kb	Standards of Performance for Volatile Organic Liquid Storage Vessels (Including Petroleum Liquid Storage Vessels) for which Construction, Reconstruction, or Modification Commenced after July 23, 1984. 40 CFR Part 60 (July 1, 2006.
Subpart L	Standards of Performance for Secondary Lead Smelters.  40 CFR Part 60 (July 1, 2006).
Subpart M	Standards of Performance for Secondary Brass and Bronze Production Plants.  40 CFR Part 60 (July 1, 2006).
Subpart N	Standards of Performance for Iron and Steel Plants.  40 CFR Part 60 (July 1, 2006).
Subpart Na	Standards of Performance for Basic Oxygen Process Furnaces.  40 CFR Part 60 (July 1, 2006).
Subpart O	Standards of Performance for Sewage Treatment Plants.  40 CFR Part 60 (July 1, 2006).
Subpart P	Standards of Performance for Primary Copper Smelters.  40 CFR Part 60 (July 1, 2006).
Subpart Q	Standards of Performance for Primary Zinc Smelters.  40 CFR Part 60 (July 1, 2006).
Subpart R	Standards of Performance for Primary Lead Smelters.  40 CFR Part 60 (July 1, 2006).
Subpart S	Standards of Performance for Primary Aluminum Reduction Plants.  40 CFR Part 60 (July 1, 2006).
Subpart T	Standards of Performance for the Phosphate Fertilizer Industry:  Wet-Process Phosphoric Acid Plants.  40 CFR Part 60 (July 1, 2006).
Subpart U	Standards of Performance for the Phosphate Fertilizer Industry:  Superphosphoric Acid Plants.  40 CFR Part 60 (July 1, 2006).
Subpart V	Standards of Performance for the Phosphate Fertilizer Industry:  Diammonium Phosphate Plants.  40 CFR Part 60 (July 1, 2006).
Subpart W	Standards of Performance for the Phosphate Fertilizer Industry:  Triple Superphosphate Plants.  40 CFR Part 60 (July 1, 2006).
Subpart X	Standards of Performance for the Phosphate Fertilizer Industry:  Granular Triple Superphosphate Storage Facilities.  40 CFR Part 60 (July 1, 2006).
Subpart Y	Standards of Performance for Coal Preparation Plants.  40 CFR Part 60 (July 1, 2006).
Subpart Z	Standards of Performance for Ferroalloy Production Facilities.  40 CFR Part 60 (July 1, 2006).
Subpart AA	Standards of Performance for Steel Plants:  Electric Arc Furnaces Constructed after October 21, 1974, and on or before August 17, 1983.  40 CFR Part 60 (July 1, 2006).
Subpart AAa	Standards of Performance for Steel Plants:  Electric Arc Furnaces and Argon-Oxygen Decarburization Vessels Constructed after August 17, 1983.  40 CFR Part 60 (July 1, 2006).
Subpart BB	Standards of Performance for Kraft Pulp Mills.  40 CFR Part 60 (July 1, 2006).
Subpart CC	Standards of Performance for Glass Manufacturing Plants.  40 CFR Part 60 (July 1, 2006).
Subpart DD	Standards of Performance for Grain Elevators.  40 CFR Part 60 (July 1, 2006).
Subpart EE	Standards of Performance for Surface Coating of Metal Furniture.  40 CFR Part 60 (July 1, 2006).
Subpart GG	Standards of Performance for Stationary Gas Turbines.  40 CFR Part 60 (July 1, 2006).
(See Subpart KKKK of this Regulation Number 6 for additional requirements for Stationary Combustion Turbines)
Subpart HH	Standards of Performance for Lime Manufacturing Plants.  40 CFR Part 60 (July 1, 2006).
Subpart KK	Standards of Performance for Lead-Acid Battery Manufacturing Plants.  40 CFR Part 60 (July 1, 2006).
Subpart LL	Standards of Performance for Metallic Mineral Processing Plants.  40 CFR Part 60 (July 1, 2006).
Subpart MM	Standards of Performance for Automobile and Light-Duty Truck Surface Coating Operations.  40 CFR Part 60 (July 1, 2006).
Subpart NN	Standards of Performance for Phosphate Rock Plants.  40 CFR Part 60 (July 1, 2006).
Subpart PP	Standards of Performance for Ammonium Sulfate Manufacture.  40 CFR Part 60 (July 1, 2006).
Subpart QQ	Standards of Performance for the Graphic Arts Industry:  Publication Rotogravure Printing.  40 CFR Part 60 (July 1, 2006).
Subpart RR	Standards of Performance for Pressure Sensitive Tape and Label Surface Coating Operations.  40 CFR Part 60 (July 1, 2006).
Subpart SS	Standards of Performance for Industrial Surface Coating:  Large Appliances.  40 CFR Part 60 (July 1, 2006).
Subpart TT	Standards of Performance for Metal Coil Surface Coating.  40 CFR Part 60 (July 1, 2006).
Subpart UU	Standards of Performance for Asphalt Processing and Asphalt Roofing Manufacture.  40 CFR Part 60 (July 1, 2006).
Subpart VV	Standards of Performance for Equipment Leaks of VOC in the Synthetic Organic Chemicals Manufacturing Industry.  40 CFR Part 60 (July 1, 2006).
Subpart WW	Standards of Performance for the Beverage Can Surface Coating Industry.  40 CFR Part 60 (July 1, 2006).
Subpart XX	Standards of Performance for Bulk Gasoline Terminals.  40 CFR Part 60 (July 1, 2006).
Subpart BBB	Standards of Performance for the Rubber Tire Manufacturing Industry.  40 CFR Part 60 (July 1, 2006).
Subpart DDD	Standards of Performance for Volatile Organic Compound (VOC) Emissions from the Polymer Manufacturing Industry.  40 CFR Part 60 (July 12006).
Subpart FFF	Standards of Performance for Flexible Vinyl and Urethane Coating and Printing.  40 CFR Part 60 (July 1, 2006).
Subpart GGG	Standards of Performance for Equipment Leaks of VOC in Petroleum Refineries.  40 CFR Part 60 (July 1, 2006).
Subpart HHH	Standards of Performance for Synthetic Fiber Production Facilities.  40 CFR Part 60 (July 1, 2006).
Subpart III	Standards of Performance for Volatile Organic Compound (VOC) Emissions From Synthetic Organic Chemical Manufacturing Industry (SOCMI) Air Oxidation Unit Processes (July 1, 2006).
Subpart JJJ	Standards of Performance for Petroleum Dry Cleaners.  40 CFR Part 60 (July 1, 2006).
Subpart KKK	Standards of Performance for Equipment Leaks of VOC from Onshore Natural Gas Processing Plants.  40 CFR Part 60 (July 1, 2006).
Subpart LLL	Standards of Performance for Onshore Natural Gas Processing:  SO2 Emissions.  40 CFR Part 60 (July 1, 2006).
Subpart NNN	Standards of Performance for Volatile Organic Compound Emissions from Synthetic Organic Chemical Manufacturing Industry Distillation Operations.  40 CFR Part 60 (July 1, 2006). 
Subpart OOO	Standards of Performance for Nonmetallic Mineral Processing Plants.  40 CFR Part 60 (July 1, 2006).
Subpart PPP	Standards of Performance for Wool Fiberglass Insulation Manufacturing Plants.  40 CFR Part 60 (July 1, 2006).
Subpart QQQ	Standards of Performance for VOC Emissions from Petroleum Refinery Wastewater Systems.  40 CFR Part 60 (July 1, 2006).
Subpart RRR	Standards of Performance for Volatile Organic Compounds (VOC) Emissions from Synthetic Organic Chemical Manufacturing Industry (SOCMI) Reactor Processes. 40 CFR Part 60 (July 1, 2006). 
Subpart SSS	Standards of Performance for the Magnetic Tape Manufacturing Industry.  40 CFR Part 60 (July 1, 2006).
Subpart TTT	Standards of Performance for Industrial Surface Coating of Plastic Parts for Business Machines.  40 CFR Part 60 (July 1, 2006).
Subpart UUU	Standards of Performance for Calciners and Dryers in Mineral Industries.  40 CFR Part 60 (July 1,2006).
Subpart VVV	Standards of Performance for Polymeric Coating of Supporting Substrates.  40 CFR Part 60 (July 1, 2006).
Subpart WWW	Standards of Performance for Municipal Solid Waste Landfills.  40 CFR Part 60 (July 1, 2006).
Subpart AAAA	Standards of Performance for Small Municipal Waste Combustion Units for which Construction is Commenced after August 30, 1999 or for which Modification or Reconstruction is Commenced after June 6 2001.  40 CFR Part 60 (July 1, 2006).
Subpart CCCC	Standards of Performance for Commercial and Industrial Solid Waste Incineration Units for which Construction is Commenced after November 30, 1999 or for which Modification or Reconstruction is Commenced on or after June 1, 2001.  40 CFR Part 60 (July 1, 2006).
Subpart EEEE	Standards of Performance for Other Solid Waste Incineration Units for which Construction is Commenced after December 9, 2004 or for which Modification or Reconstruction is Commenced on or after June 16, 2006.  40 CFR Part 60 (July 1, 2006, and as amended on November 24, 2006.
Subpart HHHH	Emission guidelines and compliance times for coal-fired electric steam generating units. 40 CFR Part 60 (July 1, 2006) Sections 60.4101 through 60.4108, Excluding 60.4105(B)(2); 60.4110 through 60.4114; 60.4120 through 60.4124; 60.4140; 60.4142(A)(1)(I), (A)(2)(I) and (C)(2) through (C)(4); 60.4151 through 60.4157; 60.4160 through 60.4162; and 60.4170 through 60.4176.
Any conflict between this subpart and the Federal sections incorporated by reference shall be resolved in favor of this subpart.  In addition to the requirements contained in the sections listed above, owners and operators of Hg Budget Units and Hg Budget Sources shall comply with the following provisions:
I. Definitions
The following definitions shall apply for the purposes of this Subpart:
I.A. Allocation Deficit
A circumstance wherein an Hg Budget Unit’s Hg emissions in a given Control Period, as reported in accordance with 40 CFR Part 60, Sections 60.4170 through 60.4176, exceed the amount of Hg Allowances allocated to that unit under Sections III.B.2. and III.B.3. below, for that Control Period.
I.B. Existing Unit 
An Hg Budget Unit, as defined in 40 CFR Part 60, Section 60.4102, that commenced operation before January 1, 2001 and was not permanently retired before October 31, 2006.
I.C. Inlet Hg
The average concentration of Hg in the coal burned at an Hg Budget Unit, as determined by ASTM methods, EPA-approved methods, or alternative equivalent methods approved by the Division.  Inlet Hg shall be determined prior to any Hg control-related coal treatment.
I.D. Low Emitter
An Hg Budget Unit with actual Hg emissions of no more than 29 pounds per Control Period, as determined in accordance with 40 CFR Part 75.
I.E. New Unit
An Hg Budget Unit, as defined in 40 CFR Part 60, Section 60.4102, that commences operation on or after January 1, 2001.
I.F.  Gigawatt-hour (GWh)
A unit of energy expended for one hour (one billion watts of energy for one hour) relating to electric generation and use.  Herein, the gross GWh value shall be used in association with the permit limit.
II.  Certificate of Representation 
A copy of each complete certificate of representation for a Hg Designated Representative or an Alternate Hg Designated Representative submitted to the Administrator in accordance with 40 CFR Part 60, Sections 60.4110 through 60.4114 shall also be submitted to the Division at the time of submission to the Administrator. 
III.  Hg Allowances 
III.A.  All Colorado Hg Allowances transferred from the Administrator shall be deposited annually in the Division’s General Account and allocated by the Division as specified in Section III.B. below.
III.B. Hg Allowance Allocations 
III.B.1.  Baseline Heat Input
The baseline heat input (in MMBtu) used with respect to Hg Allowance allocations under Sections III.B.2. and III.B.3. for each Hg Budget Unit shall be determined in accordance with 40 CFR Part 60, Section 60.4142(a)(1)(i).  
III.B.2.  Base Allocations to Hg Budget Units for Compliance Purposes
III.B.2.a. For each Control Period, the Division shall hold in the Division’s General Account for allocation to subject Hg Budget Units in the State 100 percent of the State’s annual allocation of Hg Allowances pursuant to 40 CFR Part 60, Section 60.4140.  To facilitate planning by Hg Budget Units, the Division shall identify a provisional allocation of Hg Allowances to Hg Budget Units as follows:
III.B.2.a.(i).  For Existing Units, an amount equal to what the unit would receive in that Control Period under 40 CFR Part 60, Section 60.4142(a)(1)(i);
III.B.2.a.(ii).  For New Units operating each calendar year during a period of four or more consecutive calendar years, beginning in the Control Period of the unit’s fifth year of operation, an amount equal to what the unit would have received if it were an Existing Unit pursuant to Section III.B.2.a.(i)., above; and
III.B.2.a.(iii).  Section III.C.2., below, notwithstanding, for New Units not eligible to receive an allocation pursuant to Section III.B.2.a.(ii)., above:
III.B.2.a.(iii).(a).  For each Control Period from 2010 through 2017, an amount equal to five percent of the Division trading budget for the Control Period pursuant to 40 CFR Part 60, Section 60.4140 divided proportionally, based on heat input, among the number of New Units receiving Hg Allowances under this Section III.B.2.a.(iii).
III.B.2.a.(iii).(b).  For each Control Period from 2018 and beyond, an amount equal to three percent of the Division trading budget for the Control Period pursuant to 40 CFR Part 60, Section 60.4140 divided proportionally, based on heat input, among the number of New Units receiving Hg Allowances under this Section III.B.2.a.(iii).
III.B.2.b.  A New Unit shall report to the Division, within thirty days after the end of its first four calendar years of operation, its heat input value for each year and its highest three-year average heat input value. 
III.B.2.c. If actual emissions for an Hg Budget Unit during a Control Period equal or exceed the provisional allocation identified pursuant to Section III.B.2.a., above, the Hg Budget Unit shall have a right to an allocation of that base amount of Hg Allowances.  If the actual emissions for the Control Period exceed an Hg Budget Unit’s provisional allocation, the unit may utilize the safety valve provision in Section III.B.3., below.  In no instance, however, shall the allocation of Hg Allowances to an Hg Budget Unit exceed the unit’s actual emissions for such period, as provided in Section III.B.2.d., below.
III.B.2.d. The Division shall allocate Hg Allowances to each subject Hg Budget Unit’s Compliance Account in an amount equal to the actual emissions of each subject Hg Budget Unit consistent with any emission standards that may be in effect under Regulation 6, Part B, Section VIII.  If the Division has insufficient Hg Allowances in its General Account to cover all actual Hg emissions, available Hg Allowances shall be allocated to Existing Units and New Units pursuant to the priorities set forth in Section III.C.2., below.
III.B.2.e.  In order to develop an estimate of each Hg Budget Unit’s actual emissions in a Control Period for the purpose of forming a preliminary estimate of whether total actual Hg emissions from Colorado Hg Budget Sources in a Control Period may exceed the Division allowance budget for each Control Period pursuant to 40 CFR Part 60, Section 60.4140, each Hg Budget Unit shall submit to the Division a certification of Hg emissions on forms supplied by the Division, no later than thirty days following the end of each quarter of a Control Period.  The Division shall calculate the statewide Hg emissions for Existing Units and New Units for each quarter of each year and provide such calculations to the Hg Budget Sources for the purpose of creating an estimate of whether there may be excess Hg Allowances for allocation to Hg Budget Units that otherwise may need to acquire Hg Allowances through the Hg Budget Trading Program, as defined in 40 CFR Part 60, Section 60.4102.  
III.B.2.f. Beginning in 2011, each Existing Unit and New Unit shall submit to the Division no later than February 10th of each Control Period the actual emissions for the previous Control Period for each Hg Budget Unit.  
III.B.2.g.  After each Control Period, the Division shall publish a summary of the operation of the State Hg Control Program during the previous Control Period.  Such summary may include information such as the Inlet Hg or lb/GWh, the provisional allocation identified, the actual emissions and the final allocation transferred to the Hg Budget Unit. 
III.B.3.  Disposition of Unallocated Allowances
III.B.3.a.  The Division shall hold in reserve Hg Allowances not allocated to Hg Budget Units pursuant to Section III.B.2., above, if any, in the Division’s General Account for the following purposes:
III.B.3.(a).(i). safety valve allocations in accordance with Section III.B.3.(b)., below; and
III.B.3.(a).(ii). allocations for New Units in Colorado.
III.B.3.b.  Safety Valve 
If, after completion of the procedures under Section III.B.2., above, for each Control Period in 2010 and beyond, the Division has not allocated or transferred all available Hg Allowances, the Division may transfer Hg Allowances to the Compliance Accounts of Hg Budget Units having an Allocation Deficit upon request by the Hg Designated Representative.  
III.B.3.b.(i).  A request for necessary additional Hg Allowances shall be submitted to the Division on a form provided by the Division no later than February 10th of the year following the Control Period for which additional Hg Allowances are requested.  A request for additional Hg Allowances shall include: 
III.B.3.b.(i).(a).  A summary of actual Hg emissions, base Hg Allowance allocation, and the Allocation Deficit for the Hg Budget Unit in the applicable Control Period;
III.B.3.b.(i).(b)  A statement of Hg emission measurement methodologies used to determine mass of Hg emitted by the unit in the applicable Control Period; and
III.B.3.b.(i).(c).  Total annual unit operating hours and heat input.
III.B.3.b.(ii)  If the Division receives requests for a total amount of safety valve Hg Allowances greater than is available, the Division shall divide each Hg Budget Unit’s request by the total amount requested and multiply the result by the total amount of excess Hg Allowances available for allocation in the Division’s General Account for  safety valve purposes, pursuant to the following equation:
Unit A safety valve allocation = [Unit A Request ÷ Sum all requests] x account balance in Division’s General Account
III.B.3.b.(iii).  The Division shall allocate additional Hg Allowances in an amount that shall not exceed the total amount requested and shall not allocate more Hg Allowances than are available.  Any additional Hg Allowances allocated pursuant to Section III.B.3.b. shall be allocated in an amount consistent with emission standards that may be in effect under Regulation 6, Part B, Section VIII.
III.B.4.  The Division shall file a request for recordation according to 40 CFR Part 60, Section 60.4160 to transfer total allocations from the Division’s General Account into each Hg Budget Unit’s Compliance Account on or before February 20th of each year for the previous Control Period, beginning in 2011.  
III.C.  General Account
III.C.1.  The Division shall allocate Hg Allowances out of the Division’s General Account in accordance with Sections III.B.2., III.B.3., and III.B.4, above. 
III.C.2.  General Account Prioritization 
When transferring Hg Allowances pursuant to Sections III.B.2, III.B.3., and III.B.4., above, held in the Division’s General Account, if there are insufficient Hg Allowances to allocate in order to cover actual Hg emissions from Hg Budget Units, priority shall be given in the following order:
III.C.2.a. Existing Units; then
III.C.2.b.  New Units. 
III.C.3.  If the total amount of Hg Allowances allocated and transferred to an Hg Budget Unit pursuant to Section III.B., above, exceeds the amount of Hg Allowances subtracted by EPA from the unit’s Compliance Account for the applicable Control Period in accordance with 40 CFR Part 60, Section 60.4154, the Division shall withhold Hg Allowances from future transfers of additional Hg Allowances requested for that unit under this Section III.C.3., until an equivalent amount has been recovered by the Division.  
 IV.	Hg Emission StandardsAll new units, modified units and reconstructed units are subject to the emission standards identified in 40 CFR Part 60, Section 60.45Da (July 1, 2006), upon commencement of operation as defined in 40 CFR Part 60, Section 60.2.

Subpart IIII	Standards of Performance for Stationary Spark Ignition Internal Combustion Engines.  40 CFR Part 60 (July 1, 2006), and as amended on July 11, 2006.
Subpart KKKK	Standards of Performance for Stationary Combustion Turbines (July 1, 2006), and as amended on July 6, 2006.
(See Subpart GG for additional requirements for Stationary Gas Turbines)
APPENDIX A	Test Methods. 40 CFR Part 60 (July 1, 2006).
APPENDIX B	Performance Specifications.  40 CFR Part 60 (July 1, 2006).
APPENDIX C	Determination of Emission Rate Change.  40 CFR Part 60 (July 1, 2006).
APPENDIX D	Required Emission Inventory Information.  40 CFR Part 60 (July 1, 2006).
APPENDIX F	Quality Assurance Procedures.  40 CFR Part 60 (July 1, 2006).
APPENDIX I	Removable Label and Owner's Manual.  40 CFR Part 60 (July 1, 2006).
STATEMENTS OF BASIS, SPECIFIC STATUTORY AUTHORITY AND PURPOSE (For Part A)
I.	Adopted - June 20, 1996
Background
This statement of Basis, Specific Statutory Authority and Purpose complies with the requirements of the Administrative Procedures Act, C.R.S. 1973, Section 24-4-103(4) for adopted or modified regulations.
Basis
The EPA has promulgated revisions to the federal Standards of Performance for New Stationary Sources (NSPS). The state of Colorado is required under Section 110 of the federal Clean Air Act as amended to adopt such NSPS standards and revisions into its regulations in order to maintain agency authority with regard to the Standards. 
Authority
The general authority for this regulation is contained in the Colorado Air Pollution Prevention and Control Act. Sections 25-7-105(1)(b). Specific authority is found at 25-7-109, which provides authority to adopt emission control regulations. Section 25-7-1-6(6) provides the Commission authority to require testing, monitoring and recordkeeping. In addition, Section 25-7-102 requires the Commission to use all available practical methods that are technically feasible and economically reasonable to adopt federal regulations by reference. Commission action in promulgating these revisions is taken pursuant to Sections 25-7-105 to -109 and 25-7-114, C.R.S., as amended. 
Purpose
The EPA has developed emission control regulations for specific categories of new sources based upon research that examines technical and economic feasibility and the current; best demonstrated controls being used on specific source categories. The commission is adopting these revisions to the federal rules in order to maintain administrative authority and referencing accuracy.
1.	Standards of Performance for New Stationary Sources Appendix A--Reference Methods; Amendments to Method 24 for the Determination of Volatile Matter Content, Water Content, Density, Volume Solids, and Weight Solids of Surface Coatings, 40 CFR Part 60, Section 60.17(A)(63.
This rule amends those referenced analysis procedures already in the rules to include one that can be applied to non-thin film ultraviolet radiation-cured coatings. The proposed rule does not change any emission standard, nor does it impose any new emission measurement requirements. It simply amends references to existing test methods. Method 24 is used to determine volatile matter and water content, density, volume solids and weight solids of surface coatings, such as paint, varnish, lacquer, or related surface coatings. Method 24, which references the American Society for Testing and Materials (ASTM) Method D2369-81, was meant to apply to all such coatings. However, that ASTM method cannot be used to calculate the VOC content of ultraviolet radiation-cured coatings. This rule amends Method 24 to reference ASTM Method D5403-93, which is used to measure volatile organic compounds in non-thin ultraviolet radiation-cured coatings.
2.	Standards of Performance for Volatile Organic Compound Emissions from Synthetic Organic Chemical Manufacturing Industry (SOCMI) Distillation Operations, 40 CFR Part 60, Subpart NNN, Sections 60.665 and 60.667, and SOCMI Reactor Processes, 40 CFR Part 60, Subpart RRR, Sections 60.700, 60.705, and 60.707.
This amendment corrects the spelling of certain chemical names, the Chemical Abstract System (CAS) numbers for certain chemicals, and certain cross-referencing and drafting errors in the Standard of Performance for New Sources for new, modified and reconstructed distillation operations and reactor processes in the SOCMI. The proposed amendment would also clarify reporting and recordkeeping requirements for these processes--allowing them to be submitted in conjunction with semiannual reports or as a single separate report in order to avoid their duplication. Subparts NNN and RRR of Colorado Regulation No. 6 are corrected by this amendment.
3.	Standards of Performance for New Stationary Sources and Emission Guidelines for Existing Sources: Municipal Waste Combustors, 40 CFR, Subparts Cb, Ea and Eb of Section 60.
The rule applies to municipal waste combustion (MWC) units at plants with aggregate capacities to combust more than 35 megagrams (40 tons) of municipal solid waste per day, and require sources to achieve emission levels reflecting the maximum degree of reduction in emissions of air pollutants achievable. The 40-ton-per-day threshold is lower than the 50-ton threshold previously found in Colorado’s Regulation No. 6, Part B. The standards and guidelines establish emission levels for MWC dioxins, furans, cadmium, lead, mercury, particulate matter, opacity, hydrogen chloride, sulfur dioxide, oxides of nitrogen and fugitive ash. 
The standards apply to new sources that begin construction after September 20, 1994, or that begin modification or reconstruction after June 19, 1996. MWCs constructed after December 20, 1989 and on or before September 20, 1994 are subject to previously issued (1991) standards and to the 1995 retrofit guidelines for existing sources. MWCs constructed on or before September 20, 1994 are subject only to the guidelines.
Time line table for MWC NSPS:

	On or Before Dec. 20, 1989	Dec. 21, 1989 to Sept. 20, 1994	Sept. 21, 1994 to June 19, 1996	After 
June 19, 1996	
Type of Activity	Constructed, Modified, or Reconstructed	Constructed, Modified or Reconstructed	Begin Construction	Begin Modification or Reconstruction	
Applicable Regulations	Subject to the 1995 retrofit guidelines (Subpart Cb)	Subject to 1991 standards (Subpart Ea) and 1995 retrofit guidelines (Subpart Cb)	Subject to revised standards (Subpart Eb)	
II.	Adopted - February 20, 1997 - Adoption by Reference - Subpart Cc and Subpart WWW
This Statement of Basis, Specific Statutory Authority and Purpose complies with the requirements of the Colorado Administrative Procedures Act, Section 24-4-103, C.R.S. and the Colorado Air Pollution Prevention and Control Act, Section 25-7-110.5, C.R.S.
Basis
The Environmental Protection Agency on March 12, 1996 promulgated Standards of Performance for Municipal Solid Waste Landfills and Emission Guidelines and Compliance Times for Municipal Solid Waste Landfills.  The state of Colorado is required under Section 111(c) of the federal Clean Air Act as amended to adopt such New Source Performance Standards (“NSPS”) and guidelines in order to retain its authority to implement and enforce the federal Standards of Performance for New Stationary Sources.  
The Commission adopted by reference Subpart WWW of Part 60, Title 40, CFR as a New Source Performance Standard in order to obtain state authority to implement and enforce this federal standard.  In addition, the Commission adopted Subpart Cc of Part 60, Title 40, CFR, to provide the authority for the Division to proceed with preparation of the plan for existing sources required by that subpart.  
The Commission intends to review and approve a plan that meets the requirements of Section 111 of the federal act in the next few months.  The Commission contemplates that the plan will include implementation and enforcement of the New Source Performance Standard in Subpart WWW as well as the emission guidelines for existing sources that are adopted as part of this rulemaking.
The Commission adopted emissions guidelines for existing municipal solid waste landfills, consistent with the required elements of a state plan set forth in 40 CFR Part 60 Subpart Cc.  The language adopted complies with the requirements of Subpart Cc and refers to that subpart for applicability provisions and some other matters.  However, the rule also refers directly to the substantive provisions of Subpart WWW, the NSPS, which are largely adopted by reference by Subpart Cc.  This strategy was developed in discussion with the interested party to make the requirements of the emissions guidelines for existing sources clear.  
Specific Statutory Authority
The general authority for this regulation is contained in the Colorado Air Pollution Prevention and Control Act, title 25, article 7, of the Colorado Revised Statutes.  Sections 25-7-105(1)(b) and 25-7-109, C.R.S., provide authority for the Commission to adopt emission control regulations.  Section 25-7-109(1)(a)(II), C.R.S., provides authority for the Commission to adopt emission control regulations for particular types of facilities, processes and activities.  Section 25-7-106(6) provides the Commission authority to require testing, monitoring and record keeping.  Section 24-4-103 (12.5) provides authority to adopt federal regulations by reference.  Commission action in promulgating these regulations is taken pursuant to the above statutory provisions.
The only portion of this rulemaking which is not an adoption by reference or a duplication of federal requirements is the choice by the Commission of interim deadlines for tasks necessary to achieving full compliance with the federal minimum collection and control system requirements as required by EPA’s guidance.  These elements of the rule are not by themselves intended to reduce air pollution.  Accordingly, the findings and determinations outlined in Section 25-7-110.8(1), C.R.S., are not applicable to this rulemaking.
III.	Adopted:  July 17, 1998
This Statement of Basis, Specific Statutory Authority and Purpose complies with the requirements of the Colorado Administrative Procedures Act, Section 24-4-103, C.R.S. and the Colorado Air Pollution Prevention and Control Act, Section 25-7-110.5, C.R.S.
Basis
The Environmental Protection Agency promulgated New Source Performance Standards (NSPS) and Emission Guidelines (EG) for Hospital, Medical, Infectious Waste Incinerators on September 15, 1997.  The State of Colorado is required under Section 110 of the Federal Clean Air Act, as amended, to adopt such NSPS and EG standards and revisions into its regulations in order to maintain agency authority with regard to the Standards.
The action taken today is an adoption by reference of the federal regulations and in no way deviates from the federal requirements.  This regulation does impose new and more stringent requirements on the affected facilities and will cause a significant fiscal impact on the affected facilities.  
Specific Statutory Authority
The general authority for this regulation is contained in the Colorado Air Pollution Prevention and Control Act.  Sections 25-7-105(1)(b).   Specific authority is found at 25-7-109, which provides authority to adopt emission control regulations.  Section 25-7-106(6) provides the Commission authority to require testing, monitoring and record keeping.  Commission action in promulgating these revisions is taken pursuant to Sections 25-7-105 to -109 and 25-7-114, C. R. S., as amended.
Purpose
The Commission makes the following findings and determinations pursuant to Section 25-7-110.8, C.R.S.:
1.	The Commission has considered, and has based its decision, on the reasonably available, validated, reviewed and sound scientific methodologies and information made available by interested parties.
2.	Evidence in the record supports the conclusion that the operating limitations adopted will result in a demonstrable reduction in air pollution when taken in conjunction with the Federal New Source Performance Standard and Emissions Guideline.
3.	The alternative selected maximizes the air quality benefits of the emissions standards applicable.
IV.	Adopted - November 18, 1999
This Statement of Basis, Specific Statutory Authority and Purpose complies with the requirements of the Colorado Administrative Procedures Act, Section 24-4-103, C.R.S. and the Colorado Air Pollution Prevention and Control Act, Section 25-7-110.5, C.R.S.
Basis
The EPA has promulgated revisions to the federal Standards of Performance for New Stationary Sources (NSPS).  The state of Colorado is required under Section 110 of the federal Clean Air Act as amended to adopt such NSPS standards and revisions into its regulations in order to maintain agency authority with regard to the Standards.
Specific Statutory Authority
The general authority for this regulation is contained in the Colorado Air Pollution Prevention and Control Act.  Sections 25-7-105(1)(b).  Specific authority is found at 25-7-109, which provides authority to adopt emission control regulations.  Section 25-7-106(6) provides the Commission authority to require testing, monitoring and record keeping.  In addition, Section 25-7-102 requires the Commission to use all available practical methods that are technically feasible and economically reasonable to adopt federal regulations by reference.  Commission action in promulgating these revisions is taken pursuant to Sections 25-7-105 to -109 and 25-7-114, C. R. S., as amended.
Purpose
The EPA has developed emission control regulations for specific categories of new sources based upon research that examines the technical and economic feasibility and the current; best demonstrated controls being used on specific source categories.  The commission is adopting these revisions to the federal rules in order to maintain administrative authority and referencing accuracy. 
Landfill
June 16, 1998
Definitions 
The definition of a new source has been changed to include modification. This change makes the landfill regulation consistent with other new source performance standards. 
The definition of modification has been clarified so that changes in compaction, cover material or thickness, and bailing and compaction practices do not trigger a modification.  These changes would not typically require a capital expenditure and so would not trigger the New Source Performance Standards. 
The definition of design capacity is being clarified so that sources may state design capacity in terms of volume or mass.
Compliance Dates 
The compliance dates section is being modified to clarify that landfills have 30 months to install a collection and control system once the landfill becomes affected.
Title V permitting
This change clarifies that sources with design capacities of 2.5 million megagrams of 2.5 million cubic meters are subject to title V permit requirements.
Monitoring
This change clarifies that a temperature-measuring device does not need to be permanently installed at each wellhead.
February 24, 1999 
Clarifies the definition of modification so that it is clear that a modification is an increase in the permitted volume of the landfill.
Other changes were clarifications in the required reporting and typographical.
Electric Arc Furnaces
March 2, 1999 Changes
Amends the NSPS for electric arc furnaces under 40 CFR Part 60, Subparts AA and AAa.  The changes add alternative requirements for monitoring and capture systems. 
Coal unloading
October 5, 1998 changes
Amends 40 CFR Part 60, Subpart Y to include coal unloading that involves conveying coal to coal plant machinery and includes and fugitive emissions from coal dumping in the determination of major source status.
Utility and Industrial Steam Generation
September 16, 1998 
Amends 40 CFR Part 60, Subparts Da and Db.  This change reduces the numerical NOx emission limits for utility and industrial steam generating units to reflect the performance of best-demonstrated technology.
Test Methods
May 14, 1999
Addition of three new optional test methods for measuring velocity and volumetric flow rate of flue gas from fossil fuel fired boilers and turbines.  The new methods account for velocity drop off near the wall and yaw and pitch angles of flow.  NOTE: this Federal Register includes both final and proposed rules.  The State of Colorado is requesting adoption of the final rules not the proposed rules.
Adoption of Subpart III for Synthetic Organic Chemical Manufacturing Industries
EPA promulgated this subpart in 1990 but it has not previously been adopted into Regulation No. 6.  Colorado has seen some growth in the SOCMI industry, but currently has no sources covered by this subpart.
1.	The Commission has considered, and has based its decision, on the reasonably available, validated, reviewed and sound scientific methodologies and information made available by interested parties.
2.	Evidence in the record supports the conclusion that the operating limitations adopted will result in a demonstrable reduction in air pollution when taken in conjunction with the Federal New Source Performance Standard.
3.	The alternative selected maximizes the air quality benefits of the emissions standards applicable.
V.	Adopted: January 11, 2001: Incorporation by Reference of Federal Amendments to 40 CFR Part 60, Subparts A, Db, Ea, and WWW into Colorado Air Quality Control Commission Regulation No. 6, Part A.
Background
This Statement of Basis, Specific Statutory Authority and Purpose complies with the requirements of the Administrative Procedures Act, C.R.S. (1988), Sections 24-4-103(4) and (12.5) for adopted or modified regulations, and with the requirements of federal regulations incorporated by reference.
Section 111 of the 1990 Clean Air Act Amendments was enacted to help reduce the levels of air pollutant emissions from new stationary sources nationwide.  Pursuant to this section, the EPA was given the authority to promulgate New Source Performance Standards.  These standards are set forth at 40 CFR Part 60. 
Basis
The EPA has promulgated revisions to the following current new source performance standards (NSPS): 40 CFR Part 60, General Provisions (Appendices A and B), Guideline for Control of Existing Municipal Solid Waste Landfills, Industrial-Commercial-Institutional Steam Generating Units, and federal Plan Requirements for Large Municipal Waste Combustors Constructed On or Before September 20, 1994. The State of Colorado is required to adopt such revisions into its regulations. This rulemaking adopts these revisions to the current NSPSs.
Authority
Sections 25-7-105(1)(b) and 25-7-109, C.R.S. (2000) authorize the Commission to adopt emission control regulations, including emission control regulations relating to new stationary sources. 
Purpose
Adoption of the federal amendments to 40 CFR Part 60, Subparts A, Db, Ea, and WWW will make these revised NSPSs enforceable under Colorado law.  Adoption of the amendments will not impose upon sources additional requirements beyond the minimum required by federal law, and may benefit the regulated community by providing sources with up-to-date information. 
VI.	Adopted: February 21, 2002: 
Incorporation by Reference of Federal Amendments to and New Standards contained in 40 CFR Part 60 into Colorado Air Quality Control Commission Regulation No. 6, Part A.
Background
This Statement of Basis, Specific Statutory Authority and Purpose complies with the requirements of the Administrative Procedures Act, C.R.S. (2001), Sections 24-4-103(4) and (12.5) for adopted or modified regulations, and with the requirements of federal regulations incorporated by reference.
Section 111 of the 1990 Clean Air Act Amendments was enacted to help reduce the levels of air pollutant emissions from new stationary sources nationwide.  Pursuant to this section, the EPA was given the authority to promulgate New Source Performance Standards.  These standards are set forth at 40 CFR Part 60. 
Basis
The EPA has promulgated revisions to the following current new source performance standards (NSPS): 40 CFR Part 60, Subparts A, D, Da, Db, Dc, E, Ea, Eb, Ec, F, H, J, K, Ka, Kb, L-N, Na, O, P, S, T-Z, AA, Aaa, BB-EE, GG, HH, KK-NN, PP-XX, BBB, DDD, FFF, GGG-LLL, NNN-RRR, TTT, UUU, WWW, and Appendices A and B.  In addition, the EPA has promulgated two new standards: 40 CFR Part 60, Subparts AAAA (Standards of Performance for Small Municipal Waste Combustion Units for which Construction is Commenced after August 30, 1999 or for which Modification or Reconstruction is Commenced after June 6 2001), and CCCC (Standards of Performance for Commercial and Industrial Solid Waste Incineration Units for which Construction is Commenced after November 30, 1999 or for which Modification or Reconstruction is Commenced on or after June 1, 2001). The State of Colorado is required to adopt such revisions and new standards into its regulations. This rulemaking adopts these revisions to the current NSPSs and new NSPSs.
Authority
Sections 25-7-105(1)(b) and 25-7-109, C.R.S. (2001) authorize the Commission to adopt emission control regulations, including emission control regulations relating to new stationary sources. 
Purpose
Adoption of the federal amendments to and new standards contained in 40 CFR Part 60 will make these revised NSPSs and new NSPSs enforceable under Colorado law.  Adoption of the amendments and new standards will not impose upon sources additional requirements beyond the minimum required by federal law, and may benefit the regulated community by providing sources with up-to-date information. 
VII.	Adopted July 15, 2004
Incorporation by Reference of Federal Amendments to 40 CFR Part 60 into Colorado Air Quality Control Commission Regulation No. 6, Part A.
Background
This Statement of Basis, Specific Statutory Authority and Purpose complies with the requirements of the Administrative Procedures Act, C.R.S. (2001), Sections 24-4-103(4) and (12.5) for adopted or modified regulations, and with the requirements of federal regulations incorporated by reference.
Section 111 of the 1990 Clean Air Act Amendments was enacted to help reduce the levels of air pollutant emissions from new stationary sources nationwide.  Pursuant to this section, the EPA was given the authority to promulgate New Source Performance Standards.  These standards are set forth at 40 CFR Part 60. 
Basis
The EPA has promulgated revisions to the following current new source performance standards (NSPS): 40 CFR Part 60, Subparts A, D, Da, Db, Dc, Ea, Eb, Ec, J, Kb, CC, GG, NN, XX, SSS, GGG, CCCC, Appendix B and Appendix F.  The State of Colorado is required to adopt such revisions into its regulations. This rulemaking adopts these revisions to the current NSPSs.
Authority
Sections 25-7-105(1)(b) and 25-7-109, C.R.S. (2001) authorize the Commission to adopt emission control regulations, including emission control regulations relating to new stationary sources. 
Purpose
Adoption of the federal amendments to 40 CFR Part 60 will make these revised NSPSs enforceable under Colorado law.  Adoption of the amendments will not impose upon sources additional requirements beyond the minimum required by federal law, and may benefit the regulated community by providing sources with up-to-date information. 
VIII.	STATEMENTS OF BASIS, SPECFIC STATUTORY AUTHORITY, AND PURPOSE
This Statement of Basis, Specific Statutory Authority and Purpose complies with the requirements of the Colorado Administrative Procedures Act, Section 24-4-103, C.R.S. and the Colorado Air Pollution Prevention and Control Act, Section 25-7-110.5, C.R.S.
Annual Update
Basis
The EPA promulgated a new federal NSPS for Other Solid Waste Incineration Units (OSWI) on December 16, 2005 at 40 CFR Part 60, Subpart EEEE.  In addition, EPA promulgated amendments to the following standards: 40 CFR Part 60, Subparts Cb, Da, Db, Dc, AA, AAa, GG, and Appendix B.  
The State of Colorado is required under Sections 110 of the Federal Clean Air Act, as amended, to adopt such NSPS and Emission Guidelines into its regulations in order to maintain agency authority with regard to the Standards.  
Specific Statutory Authority
The general authority for this regulation is contained in the Colorado Air Pollution Prevention and Control Act.  Sections 25-7-105(1)(b).   Specific authority is found at 25-7-109, which provides authority to adopt emission control regulations.  Section 25-7-106(6) provides the Commission authority to require testing, monitoring and record keeping.  Commission action in promulgating these revisions is taken pursuant to Sections 25-7-105 to -109 and 25-7-114, C. R. S., as amended.
Purpose
Adoption by reference of amendments to the federal regulations at 40 CFR Part 60, Subparts Cb, Da, Db, Dc, AA, AAa, GG, and Appendix B will make these revised standards enforceable under Colorado law. Adoption of the amendments will not impose upon sources additional requirements beyond the minimum required by federal law, and may benefit the regulated community by providing sources with up-to-date information. 
Further, these revisions will include any typographical and grammatical errors throughout the regulation.
COLORADO AIR QUALITY CONTROL COMMISSION
ADOPTED:	SEPTEMBER 21, 2006
IX.	Adopted February 6, 2007
This Statement of Basis, Specific Statutory Authority and Purpose complies with the requirements of the Colorado Administrative Procedures Act, Section 24-4-103, C.R.S. and the Colorado Air Pollution Prevention and Control Act, Section 25-7-110.5, C.R.S.
Basis for the Colorado Utility Mercury Reduction Program 
The U.S. Environmental Protection Agency (EPA) promulgated the Clean Air Mercury Rule (CAMR) on May 18, 2005. The CAMR includes Emission Guidelines for Coal-Fired Electric Steam Generating Units at 40 CFR Part 60, Subpart HHHH (Model Rule); revisions to the New Source Performance Standard (NSPS) for Electric Utility Steam Generating Units at 40 
CFR Part 60, Subpart Da; and revisions to definitions for the Acid Rain Program at 40 CFR Part 72. The CAMR sets up an interstate cap and trade program for mercury (Hg) emissions. The CAMR allocates to each state an annual mercury emissions budget, wherein each “allowance” equates to one ounce of Hg allowed to be emitted in a given year. The CAMR sets a national, first phase cap for Hg emissions of 38 tons per year (tpy) for 2010-2017 (21 percent reduction), and then a second phase cap of 15 tpy (70 percent reduction) which becomes effective in 2018. 
In accordance with Section 111(d) of the federal Clean Air Act, states adopting Emission Guidelines under Subpart HHHH are required to submit plans demonstrating how mercury emissions from coal-fired power plants will be limited consistent with the federal standards of performance. In addition, the State of Colorado is required under Section 111 of the federal Clean Air Act, as amended, to adopt Standards of Performance and Emission Guidelines into its regulations in order to maintain agency authority with regard to the Standards. Section 116 of the Clean Air Act, CAMR and the Colorado Revised Statutes authorize Colorado to adopt source-specific Hg emission limitations for Coal-Fired Electric Steam Generating Units and to provide for compliance with such limitations on an advanced timetable. 
State plans were originally due to EPA on November 17, 2006. Colorado, like many other states, did not submit its state plan by that date. It is the Commission’s intention that Colorado’s state plan be submitted to EPA expeditiously, and that Colorado implement its state plan for all Hg control periods. The Commission does not intend for the Model Rule or federal plan to be imposed by default upon Colorado for any control period. The Commission’s adoption of the Colorado Utility Mercury Reduction Program on February 6, 2007 will meet minimum EPA requirements, help ensure timely EPA approval, and secure significant reductions in Hg emissions for the citizens and environment of Colorado. 
Specific Statutory Authority 
Sections 25-7-105(1)(b), 25-7-109(1)(a), (2)(h) and (4), and 25-7-109.3, C.R.S. authorize the Commission to adopt emission control regulations, including emission control regulations relating to hazardous air pollutants. Section 25-7-106(6), C.R.S. authorizes the Commission to require testing, monitoring and record keeping. 
Purpose 
Hg is a listed hazardous air pollutant under federal and Colorado law. Adoption of a state plan for controlling Hg emissions from coal-fired electric steam generating units, including incorporation by reference of certain provisions of the CAMR, coupled with technology-based performance standards, will ensure that Hg emission reduction objectives in Colorado are met. 
40 CFR Part 60 identifies the provisions of Subpart HHHH that states must adopt to secure EPA’s approval to engage in interstate trading. The CAMR provides flexibility to states to adopt methodologies for allocating Hg emission allowances, and establishes minimum guidelines for states to notify EPA of allowance allocations. The Commission adopted by reference certain provisions of Subpart HHHH, in order to secure EPA’s approval for Colorado’s state plan. The Commission has adopted by reference the text of the remaining provisions, CFR Title 40 Part 60, Sections 4140 through 4142, with adjustments (including state law limitations on allocations and promulgation of technology-based performance standards) to fulfill state emissions control objectives. 
Mercury Emission Estimates 
There is uncertainty regarding actual Hg emissions in Colorado, and a possibility that the EPA has provided Colorado with a surplus of Hg emission allowances. An excess allocation of Colorado’s Hg allowances could lead to benefits for certain facilities without any concomitant reduction of their Hg emissions. An excess allocation could also delay installation of Hg controls by units that bank any surplus they receive. Excess allowances could also be transferred or traded to facilities in other states delaying regional and national Hg reductions. Finally, there is also uncertainty regarding the ultimate fate of the CAMR, as several states have sued EPA over objections to the CAMR, and various states have indicated an unwillingness to engage in Hg emissions trading or otherwise adopt the CAMR by reference. In light of all of the foregoing, the Commission does not believe that it would be appropriate to initially allocate the full amount of Colorado’s annual Hg emissions budget. The Commission instead finds that Hg allowances shall be allocated to facilities in Colorado for the sole purpose of complying with the Colorado Utility Mercury Reduction Program, reserving remaining allowances for well-controlled new Coal-Fired Electric Steam Generating Units and maximizing the remaining allowances held in trust for the people of Colorado. 
Compliance Allowances 
Colorado General Account. Therefore, Colorado will limit its annual allocations to Hg budget units in the following manner. EPA will annually allocate all of the Hg allowances in Colorado’s budget (1412 lbs. per year in 2010-2017 and 558 lbs per year in 2018 and beyond) to the Division to be held in the Division’s Clean Air Markets Division General Account.. The Division, in turn, will allocate allowances out of its account to each Unit in an amount equal to that Unit’s actual emissions for that year. This allocation will also be consistent with the applicable technology-based emission limit included in each Unit’s permit, as discussed below. The state’s allocation methodology is intended to ensure that each Unit receives the amount of allowances it needs to cover actual emissions (to the extent possible), and achieves actual and significant Hg emission reductions in a timely manner. The Division maintaining control of allowances will achieve this result. Out of the annual state budget amount, up to 95 percent will be allocated to Existing Units, and 5 percent will be allocated to New Units in 20102017. In 2018 and beyond, these percentages will change to 97 percent (Existing Units) and 3 percent (New Units). The Division will transfer allowances to Units upon certification that the actual Hg emissions in the preceding year on the basis of advanced Hg emission monitoring systems. The state will be prohibited from distributing allowances for a control period in an amount greater than actual emissions, consistent with the applicable emission limitations. Similarly, the owners and operators of Coal-Fired Electric Steam Generating Units in Colorado will only use such allowances for compliance with Colorado’s Utility Mercury Reduction Program. At the same time, Colorado will identify in advance the allowances projected to be available for such actual emissions to aid planning and compliance for owner/operators of affected facilities. 
Unallocated allowances will also be held in this account for new Coal-Fired Electric Steam Generating Units meeting a protective Hg emission limitation. The Division intends to commence a rulemaking prior to July 2007 to evaluate the adequacy of Hg emission limitations for such New Units and, as appropriate, adopting revised limits. 
Any unallocated allowances will remain in Division’s General Account with EPA’s Clean Air Markets Division or will be transferred to the Colorado Citizens’ Mercury Reductions Trust as provided below. 
Colorado Citizens’ Mercury Reductions Trust. The state will establish a second account for unallocated allowances denominated the Colorado Citizens’ Mercury Reductions Trust. This account will be established by October 1, 2007 for the purpose of creating a durable mechanism to hold unallocated allowances in trust for the sole benefit of human health and the environment in Colorado. The Colorado Citizens’ Mercury Reductions Trust is thus provided for in these rules. On July 1, 201660 percent of all allowances held in the Division’s General Account shall be immediately transferred to the Colorado Citizens’ Mercury Reductions Trust. On July 1, 2019, and every five years thereafter, 60 percent of allowances that have been added to the Division’s General Account since the date of the last transfer of allowances to the Colorado Citizens’ Mercury Trust shall be transferred to that trust account. Provided, however, that at any time, any interested person may submit a request for rulemaking before the Commission in which it requests that a higher or lower percentage of allowances be transferred into the Colorado Citizens’ Mercury Reductions Trust on a one time or periodic basis. The Commission would promptly convene a rulemaking hearing and review such request considering: the availability of allowances to cover actual emissions for new and existing Coal-Fired Electric Steam Generating Units complying with the Colorado Utility Mercury Reduction Program and the goal of maximizing allowances permanently held in the Colorado Citizens’ Mercury Reductions Trust for the benefit of human health and the environment. 
Safety Valve 
If allowances remain in the Division’s General Account after all initial allocations to New and Existing Units have been made in any given year, any units that have an allocation deficit may request additional allowances for the sole purpose of holding allowances equivalent to actual emissions, via a “safety-valve” provision. Under this provision, the Division will allocate allowances to cover emissions from: 1) Existing Units whose actual emissions exceed their allocation amount; and 2) New Units that were not considered in the current allocation period, whose actual emissions exceed their allocation amount. If a source is allocated more allowances out of the Division’s General Account than are needed to cover its actual emissions for a control period, the Division will automatically reduce the next provision of additional allowances by the amount of the excess provided previously. This will provide a disincentive for requesting more additional allowances than is actually needed. 
If there are not enough allowances to cover the actual emissions for new and existing Coal-Fired Electric Steam Generating Units, the available allowances will be allocated to each subject Hg Budget Unit on a pro-rata basis, in an amount determined by multiplying the total amount of Hg allowances allocated for each control period by the ratio of the baseline heat input of such subject Hg Budget Unit to the total amount of baseline heat input of all such subject Hg Budget Units in the state and rounding to the nearest whole allowance as appropriate. Provided, however, that under no circumstances shall a Unit receive allowances greater than its actual emissions under the Colorado Utility Mercury Reduction Program. Any allowances remaining in the Division’s General Account after the allowance transfer deadline will continue to be held in the Division’s General Account unless transferred to the Colorado Citizens’ Mercury Reductions Trust as provided for above. 
Limitation on CAMR Allowances. 
Allowances allocated to Colorado under CAMR shall not be used for purposes other than those provided for herein. Because units only receive amounts equal to their actual emissions, units will not have extra allowances from Colorado’s Utility Mercury Reduction Program allocation to bank, trade, transfer, or sell. 
Mercury Reductions: Technology-Based Performance Standard Under the Colorado Utility Mercury Reduction Program 
Mercury Limits in Effect. The Comanche Power Station and the Lamar Power Station shall adhere to the Hg emission limits and requirements applicable to those coal-fired electric generating units under permits and agreements in effect. 
Phase I Early Mercury Reduction Program in 2012. Beginning on January 1, 2012, Xcel Energy’s Pawnee Power Station in Brush, and Platte River Power Authority’s Rawhide power plant in Wellington, shall achieve either an 80% capture of inlet Hg or an Hg output-based emission limit of 0.0174 pounds of Hg per Gigawatt hour (lbs/GWh). Compliance with such limits shall be demonstrated on December 31, 2012 and on an annual rolling average basis thereafter. 
The Division and the owners and operators of Hg Budget Units recognize that achieving dates for compliance in 2012, 2014, and 2018 requires that the Division issue the relevant permits in the timeframes provided in Section IV.B. of the Rule. The Division will use its best efforts to meet the dates in the Rule for permit issuance. If a permit is not issued within the time set forth in the Rule, the parties will confer in an effort to minimize the resulting delays both in installation of Hg emissions controls and in the dates for required compliance with emissions standards. 
Phase I Hg Emissions Reduction Requirements in 2014. Beginning on January 1, 2014, all existing coal-fired electric generating units in Colorado, excluding sources with limits in effect and low emitters, will be required to install and operate Hg emission controls designed as necessary to achieve either an 80% capture of inlet Hg or an Hg output-based emission limit of 0.0174 pounds of Hg per Gigawatt hour (lbs/GWh). Beginning on July 1, 2014, such sources will need to achieve either an 80% capture of inlet Hg or an Hg output-based emission limit of 0.0174 pounds of Hg per Gigawatt hour (lbs/GWh). Compliance with such limits shall be demonstrated on December 31, 2014 on the basis of 6 months of data generated beginning on July 1, 2014, and on an annual rolling average basis beginning June 30, 2015 and thereafter. 
Phase II Hg Emission Limits in 2018. Beginning on January 1, 2018 all existing coal-fired electric generating units in Colorado, excluding sources with limits in effect and low emitters, shall achieve either a 90% capture of inlet Hg or an Hg output-based emission limit of 0.0087 lbs/GWh. Compliance with such limits shall be demonstrated on December 31, 2018, and on an annual rolling average basis thereafter. 
Low Emitters are coal-fired units emitting 29 pounds of Hg or less on an annual basis. Such units shall be exempted from the technology-based emissions standards of the Colorado Utility Mercury Reduction Program. At the end of each calendar year, if the cumulative annual Hg mass emissions from an affected unit have exceeded 29 pounds, then the owner shall install, certify, operate, and maintain a Hg concentration monitoring system or a sorbent trap monitoring system no later than 180 days after the end of the calendar year in which the annual Hg mass emissions exceeded 29 pounds. For common stack and multiple stack configurations, installation and certification of a Hg concentration or sorbent trap monitoring system on each stack (except for bypass stacks) is likewise required within 180 days after the end of the calendar year. The Low Emitter shall also be subject to the enforceability provisions of this Rule. 
Alternative Standards for Compliance. 
Sources that demonstrate that they are unable to meet the Hg emission standards under the Colorado Utility Mercury Reduction Program can request that the Division set an alternative, unit-specific standard. This “Best Available Mercury Control Technology Alternate Standard” provides for an alternative compliance mechanism for sources that cannot achieve the underlying standard, before and/or after installation of controls, despite their best efforts to do so. The Division will review requests for alternative standards and either approve or deny such requests considering information provided by the applicant, the Division’s expertise and information, and after providing adequate opportunity for public input. 
The Best Available Mercury Control Technology Alternative Standard can provide what utilities have termed a “soft landing” in the event a unit is unable to achieve the base emission standards. The Commission does not intend for alternative standards to provide a perpetual “soft landing” or a mechanism to avoid compliance with applicable standards. 
When a unit is unable to achieve the underlying base standard (and that inability is identified either before or after the installation of Hg emission controls, and either before or after the 20102017 and 2018 and beyond control periods), the unit must submit an application for an alternative standard, which shall include a compliance plan for achieving that alternative standard. Once the Division approves or disapproves the permit application, the approved alternate standard and associated compliance plan (or the underlying base standard in the event of disapproval) shall become enforceable as to that unit. The “safe harbor” or enforcement discretion provided by Section IV.D.2 is not intended to allow a unit to avoid liability by submitting multiple permit modifications. 
Review of Limits for New Sources. 
The Division intends to commence a rulemaking prior to July 2007, to review the adequacy of Colorado’s Hg emission limitations for new coal-fired electric generating units. 
Timing of Allocations 
CAMR provides states with the flexibility to determine an alternative to the EPA’s Model Rule for the timing of allocation determinations, in order to suit individual state objectives. The Commission believes that it is appropriate for Colorado sources to demonstrate actual Hg emissions at the conclusion of each year and for the state to distribute available allowances on the basis of actual emissions in accordance with the Colorado Utility Mercury Reduction Program strictly as necessary to assure compliance. The Commission understands that, at the same time, the Division will identify in advance the allowances projected to available for such actual emissions to aid planning and compliance for owners/operators of affected facilities . 
Additional Considerations 
The CAMR specifically allows states the flexibility to adopt allocation methodologies and timing that are not identical to those in the federal Model Rule. By taking advantage of this flexibility, Colorado’s rule is thus consistent with the federal rule. To the extent the adopted state rule may be viewed as differing in some respects from the federal CAMR, the Commission provides the following additional statement, consistent with §§ 25-7-110.5(5)(a) and 110.8, C.R.S. 
(I) Certain federal requirements are applicable. Colorado is required to submit a state plan for complying with the Hg new source performance standards, in accordance with Section 111(d) the federal Clean Air Act. Failure to submit a state plan will result of imposition of the federal plan. The Commission intends for Colorado to be in charge of its own Hg control strategy (including allocations), rather than deferring such regulation to EPA. 
(II) The CAMR is performance based, as it sets forth standards of performance for coal-fired power plants. The CAMR provides flexibility to states and sources that participate in the CAMR, regarding how to reduce Hg emissions and otherwise meet the performance standards, as long as the national cap on emissions is met. 
(III) Data regarding Hg emissions was considered in the federal process leading up to the CAMR. However, accurate data regarding actual Hg emissions and the fate and transport of such emissions (both in Colorado and nationwide) is limited and contains many uncertainties. The Commission concluded that the adopted rule will provide reductions in Colorado Hg emissions in a more appropriate and timely manner than the CAMR. 
(IV) The adopted rule will provide certainty to sources, by providing allocations for compliance, specified technology-based performance standards, and clear timing requirements. 
(V) The state and federal rules have similar time frames for implementation. 
(VI) The adopted rule, and in particular the provisional allocations, safety valve, state general compliance account, and ability of units to obtain shortfall allowances via purchase, will assist in establishing and maintaining a reasonable margin for accommodation of uncertainty and future growth. 
(VII) The adopted rule establishes reasonable equity for sources subject to the rule by providing the same allocation methodologies for all sources. 
(VIII) If the state rule were not adopted, public health and welfare and the environment could face increased costs associated with delays in installation of Hg controls. 
(IX) There are some different monitoring requirements in the state rule, which are necessary to demonstrate compliance with the state’s technology-based performance standard. 
(X) Demonstrated technology is available to control Hg emissions The rule is based upon reasonably available, validated, reviewed, and sound scientific methodologies, and the Commission has considered all information submitted by interested parties. 
(XI) The adopted rule will contribute to the prevention of pollution by reducing Hg emissions. 
(XII) Although alternative rules were previously presented to and considered by the Commission, the Commission determined that the adopted proposal, which had consensus support amongst all parties to the rulemaking, was the most appropriate. The adopted rule provides mechanisms for early reduction of Hg in Colorado, while also providing flexibility for sources and future growth. 
(XIII) After consideration of all the evidence in this rulemaking, the Commission determined that the rule will result in demonstrable reduction in Hg emissions and will concurrently bring about reduced risks to human health and the environment that justify the costs to implement and comply with the rule. 
(XIV) EPA apparently believes that the model cap and trade rule is the most cost effective approach to reducing Hg emissions on a national level. In light of uncertainties associated with Hg emissions in Colorado, full allocation under the Model Rule may not result in timely and meaningful Hg emission reductions in Colorado. Full adoption of the CAMR may delay installation of Hg controls in Colorado, and lead to increased costs to public health and the environment. 
(XV) The Commission determined that the selected regulatory alternative will maximize the air quality benefits of regulation, including reducing Hg emissions, in the most cost-effective manner.
X.	Adopted October 18, 2007:  Annual Update
This Statement of Basis, Specific Statutory Authority and Purpose complies with the requirements of the Colorado Administrative Procedures Act, Section 24-4-103, C.R.S. and the Colorado Air Pollution Prevention and Control Act, Section 25-7-110.5, C.R.S.
Basis
The EPA promulgated a new Federal NSPS for Stationary Spark Ignition Internal Combustion Engines on June 26, 2006 at 40 CFR Part 60, Subpart IIII and for Stationary Combustion Turbines on July 6, 2006 at 40 CFR Part 60, Subpart KKKK.  In addition, EPA promulgated amendments to the following standards: 40 CFR Part 60, Subparts A, Da, Db, Dc, EEEE, and Appendices A, B and F.
The State of Colorado is required under Sections 110 of the Federal Clean Air Act, as amended, to adopt such NSPS and Emission Guidelines into its regulations in order to maintain agency authority with regard to the Standards.
Specific Authority
The general authority for this regulation is contained in the Colorado Air Pollution Prevention and Control Act, Sections 25-7-105(1)(b).  Specific authority is found at 25-7-109, which provides authority to adopt emission control regulations.  Section 25-7-106(6) provides the Commission authority to require testing, monitoring and record keeping.  Commission action in promulgating these revisions is taken pursuant to Section 25-7-105 to –109 and 25-7-114, C.R.S., as amended.
Purpose
Adoption by reference of amendments to the federal regulation at 40 CFR Part 60, including Subparts A, Da, Db, Dc, EEEE, IIII and KKKK, and Appendices A, B and F will make these revised standards enforceable under Colorado law.  Adoption of the amendments will not impose upon sources additional requirements beyond the minimum required by federal law, and may benefit the regulated community by providing sources with up-to-date information.
Further, these revisions will include any typographical and grammatical errors throughout the regulation.
PART B

Non-Federal NSPS for Specific Facilities and Sources
I.	GENERAL PROVISIONS
A.	Except as specifically provided in the sections of this part, Subpart A (General Provisions) of Part A is incorporated herein in its entirety by reference.
B.	In addition to the provisions stated in Part A, Subpart A, Subsection 60.14 (c) (6) of the CFR, regarding applicability, the following applies: relocation of a source within the State of Colorado is not, by itself, considered to be a modification.  Relocation of a source from outside of the State of Colorado into the State of Colorado is considered to be a new source, subject to the requirements of this Regulation No. 6.
II.	STANDARDS OF PERFORMANCE FOR NEW FUEL-BURNING EQUIPMENT
A.	Applicability and Designation of Affected Facility
The provisions of this section are applicable to fuel burning equipment constructed, reconstructed, or modified after January 30, 1979.
B.	Definitions
As used in this Section, all terms shall have the meaning given to them in the Common Provisions Regulation and in Part A, Subpart A of this regulation.
C.	Standard for Particulate Matter
On and after the date on which the required performance test is completed, no owner or operator subject to the provisions of this regulation may discharge, or cause the discharge into the atmosphere of any particulate matter which is: 
1.	In excess of 0.5 lbs. per million Btu heat input for fuel burning equipment of not more than one million Btu per hour total input.
2.	For fuel burning equipment generating greater than one million but less than 250 million Btu per hour heat input, the following equation will be used to determine the allowable particulate emission limitation:
PE  = 0.5 (FI) -0.26
Where:
PE is the allowable particulate emissions in pounds per million Btu heat input.
FI is the fuel input in million Btu per hour.
If two or more units connect to any opening, the maximum allowable emission rate shall be the sum of the individual emission rates.
3.	Greater than 20 percent opacity.  
D.	Standard for Sulfur Dioxide
On and after the date on which the required performance test is completed, no owner or operator subject to the provisions of this regulation may discharge, or cause the discharge into the atmosphere sulfur dioxide in excess of:
1.	All coal-fired operations, including coal-fired steam generation:
a.	Sources converted from other fuels to coal:  1.2 lbs SO2/million Btu of coal heat input;
b.	Sources with coal heat input of less than 250 million Btu per hour:  1.2 lbs SO2/million Btu coal heat input;
c.	Sources with a coal heat input of 250 million Btu per hour or greater:  0.4 lbs. SO2/million Btu coal heat input.
d.	Industrial-commercial-institutional steam generating units with a coal heat input of greater than 250 million BTU per hour:  30 percent (70 percent reduction) of the potential combustion concentration when emissions are less than 0.60 pounds per million BTU heat input.
2.	All oil-fired operations, including oil-fired steam generation:
a.	Sources with an oil heat input of less than 250 million Btu per hour:  0.8 lbs. SO2/million Btu of oil heat input:
b.	Sources with an oil heat input of 250 million Btu per hour or greater: 0.3 lbs. SO2/million Btu of oil heat input.
c.	Industrial-commercial-institutional steam generating units with an oil heat input of greater than 250 million BTU per hour:  100 percent (zero percent reduction) of the potential combustion concentration when emissions are less than 0.20 pounds per million BTU heat input.
3.	Combustion Turbines
a.	Sources with a heat input of less than 250 million Btu per hour:  0.8 lbs. SO2/million Btu.
b.	Sources with heat input of 250 million Btu per hour or greater:  0.35 lbs. SO2/million Btu.
E.	Test Methods and Procedures
The reference methods contained in Appendix A of this regulation, except as provided under Part A, Subpart A, Section 60.8(b), shall be used to determine compliance with the standards prescribed in Subsection C. and D. as follows:
1.	Method 1 for selecting sample site and velocity traverses;
2.	Method 2 for velocity and volumetric flow rate;
3.	Method 3 for gas analysis to be used when applying Reference Methods 5 and 6;
4.	Method 5 for concentration of particulate matter and associated moisture content; and
5.	Method 6 for concentration of SO2.
III.	STANDARDS OF PERFORMANCE FOR NEW MANUFACTURING PROCESSES
A.	Applicability and Designation of Affected Facility
The provisions of this section are applicable to the following affected facilities:  new manufacturing processes, regardless of production rate, and new alfalfa dehydration plants constructed, reconstructed, or modified after January 30, 1979.
B.	Definitions
As used in this section, all terms not defined herein shall have the meaning given them in the Common Provisions Regulation and in Part A, Subpart A of this Regulation, unless otherwise required by context.
C.	Standard for Particulate Matter
On and after the date on which the required performance test is conducted, no person subject to the provisions of this regulation shall discharge, or cause the discharge, into the atmosphere from any affected facility, particulate matter in excess of:
1.	For process equipment of process weight rates up to 60,000 lbs/hr the allowable emission rate shall be determined by use of the equation:
E = 3.59(P)0.62
Where:
E is the Allowable Emission in lbs/hr. 
P is the Process Weight rate in tons/hr.
2.	For process equipment of process weight rates equal to or greater than 60,000 lbs/hr the allowable emission rate shall be determined by use of the equation:
E = 17.31(P)0.16
Where:
E is the Allowable Particulate Emissions in lbs/hr.
P is the Process Weight rate in tons/hr.
3.	Greater than 20 percent opacity.
D.	Standard for Sulfur Dioxide
On and after the date on which the required performance test is completed, an owner or operator subject to the provisions of this section shall:
1.	Limit the discharge of sulfur dioxide to a maximum of 2.0 tons/day, or
2.	Utilize best practical control technology for control of sulfur dioxide as determined by the Division, subject to review by the Air Pollution Control Commission.
This subsection shall not apply to any manufacturing process specifically covered by Section IV. of this Part.
E.	Test Methods and Procedures
The reference methods contained in Appendix A of this regulation, except as provided under Part A, Subpart A, Section 60.8(b), shall be used to determine compliance with the standards prescribed in Subsection C. and D. as follows:
1.	Method 1 for sample site and velocity traverses;
2.	Method 2 for velocity and volumetric flow rate;
3.	Method 3 for gas analysis to be used when applying reference Methods 5 and 6;
4.	Method 5 for concentration of particulate matter and associated moisture content; and
5.	Method 6 for concentration of SO2.
IV.	STANDARDS OF PERFORMANCE FOR NEW SOURCES OF SULFUR DIOXIDE
A.	Applicability and Designation of Affected Facilities
The affected facilities to which the provisions of this Section apply are:  natural gas desulfurization, petroleum refineries, production of oil from shale, shale oil upgrading facilities, refining of oil from shale and any other new source of SO2 not specifically covered by other sections of this regulation, constructed, reconstructed, or modified after January 30, 1979.  For purposes of this regulation, shale oil production facilities, and upgrading/refining facilities shall be considered separate sources and subject to separate SO2 limitations.
B.	Definitions
As used in this section, all terms not defined herein shall have the meaning given them in the Common Provisions Regulation and in Part A, Subpart A of this Regulation, unless otherwise required by the context.
1.	"Shale oil production facility"  A facility which utilizes a retorting operation (in-situ or surface retorting or both) to recover oil from shale.
2.	"Shale oil upgrading facility"  A facility which produces from raw shale oil a semi-refined oil, (or products,) substantially equivalent to petroleum crude oil (or products) through hydrogenation and/or other processing, including, but not limited to, de-arsenation, distillation, cracking, reforming and coking.
3.	"Shale oil refining facilities"  A facility engaged in refining processed (upgraded) shale oil to produce gasoline, kerosene distillate fuel oils, residual fuel oils, lubricants, or other products through distillation, cracking, or reforming of unfinished oil shale derivatives.
NOTE:  A shale oil refining facility may also refine raw shale oil, just as an upgrading facility could also refine the upgraded shale oil it produces.  In addition, a petroleum refinery could upgrade or refine shale oil.  The difference is that the standards in this section allow 0.3 lb SO2 per barrel for extraction of oil from shale, then another 0.3 lb SO2/barrel for the total combined upgrading and refining of the shale oil (e.g., if a new upgrading facility emits 0.21 lbs SO2/barrel, a new refining operation can not emit more than 0.09 lb SO2 per barrel).  Crude oil refining is allowed 0.3 lb SO2 per barrel: there is no equivalent to the extraction of oil from shale.
C.	Standard for Sulfur Dioxide
1.	On and after the date on which the required performance test has been completed,  no owner or operator subject to the provisions of this regulation may discharge, or cause the discharge, into the atmosphere from any natural gas desulfurization facilities, sulfur dioxide in excess of:
a.	2.0 lbs. SO2/1000 standard cubic feet of delivered natural gas, for sources emitting less than three (3) tons per day of SO2.
b.	0.8 lbs.SO2/1000 standard cubic feet of delivered natural gas, for sources emitting three or more tons per day of SO2.
2.	On and after the date on which the required performance test is completed, no owner or operator subject to the provisions of this regulation may discharge, or cause the discharge, into the atmosphere from any petroleum refining facility, sulfur dioxide in excess of:
a.	0.3 lbs. sulfur dioxide for the sum of all SO2 emissions from a given refining facility, per barrel of oil processed.
3.	On and after the date on which the required performance test is completed, no owner or operator subject to the provisions of this regulation may discharge, or cause the discharge into the atmosphere from the production of oil from shale, sulfur dioxide in excess of:
a.	Facilities producing 1,000 or more barrels of oil per day:
Standard.  Shale oil production facilities shall employ Best Available Control Technology (BACT) (as determined by the Division after consultation with the Commission).  In no event shall the total sulfur dioxide emissions from a production facility exceed 0.30 lbs. SO2 per barrel of oil produced.
b.	Facilities producing less than 1,000 barrels of oil per day:
There shall be no process emission standard for purposes of this regulation for sources processing less than 1000 barrels per day.
4.	On and after the date on which the required performance test is completed, no owner or operator subject to the provisions of this regulation may discharge, or cause the discharge into the atmosphere from any shale oil upgrading or refining facilities or combination thereof, sulfur dioxide in excess of:
a.	Facilities producing 1,000 or more barrels of oil per day:
(1)	0.3 lbs sulfur dioxide per barrel of oil processed for the sum of all SO2 emissions from shale oil upgrading and refining, even if such facilities are physically separated.
b.	Facilities processing less than 1,000 barrels of oil per day: no process emission standard.
D.	Test Methods and Procedures
The reference methods contained in Appendix A of this regulation, except as provided under Part A, Subpart A, Section 60.8(b), shall be used to determine compliance with the standards prescribed in Subsection C. as follows:
1.	Method 1 for selecting sample site and velocity traverses;
2.	Method 2 for velocity and volumetric flow rate;
3.	Method 3 for gas analysis to be used when applying Method 6; and
4.	Method 6 for concentration of SO2.
V.	STANDARDS OF PERFORMANCE FOR BIOMEDICAL WASTE INCINERATORS
A.	Applicability and Designation of Affected Facility
The affected facilities to which the provisions of this Section apply are all new or modified incinerators used for the disposal of biomedical waste constructed, reconstructed or modified after August 30, 1989.
Exemption:  The affected facilities do not include crematory incinerators.
B.	Definitions
As used in this Section, all terms not defined herein shall have the meaning given them in the Common Provision Regulation and in Part A, Subpart A of this regulation, unless otherwise required by the context.
1.	Biomedical waste - waste that includes anatomical/pathological wastes, infectious wastes, chemotherapeutic wastes and other wastes generated in health care facilities and medical laboratories that require special handling.
2.	Anatomical/pathological waste - human or animal remains consisting of carcasses, tissues, organs or body parts that may or may not be infectious.
3.	Infectious wastes - For the purpose of this regulation, the definition of infectious waste contained in 25-l5-402, C.R.S. shall apply.
4.	Chemotherapeutic waste - All wastes resulting from the production or use of antineoplastic agents used for the purpose of stopping or reversing the growth of malignant cells.  Chemotherapeutic waste shall not include any waste containing antineoplastic agents that are listed as hazardous wastes.
5.	Hazardous Waste - Hazardous waste as defined in 25-15-101 C.R.S.
6.	Crematory incinerator - any incinerator designed and used solely for the burning of anatomical pathological waste, a crematory incinerator may also burn incidental items normally cremated as part of the funeral process.
7.	Design capacity - The maximum waste feed rate that the incinerator is designed to completely combust considering the rates of heat releases it can accommodate from the destruction of combustible material contained in the wastes.
C.	Emission Limitations
1.	On and after the date, which the required performance test has been completed, every affected facility subject to the provisions of this Section must comply with the following emission standards:
a.	Standard for Particulate Matter:
(1)	All incinerators located at a facility with a total incineration design capacity of 1000 pounds per hour or greater shall not exceed 0.015 grains per dry standard cubic foot corrected to 7% O2, including condensable particulate.
(2)	All incinerators located at a facility with a total incineration design capacity of 200 pounds per hour or greater shall not exceed 0.03 grains per dry standard cubic foot corrected to 7% O2, including condensable particulate.
(3)	All incinerators located at a facility with a total incineration design capacity of less than 200 pounds per hour shall not exceed 0.08 grains per dry standard cubic foot corrected to 7% O2, including condensable particulate.
b.	Standard for Hydrogen Chloride (HCl):
(1)	All incinerators located at a facility with a total incineration design capacity of 200 pounds per hour or greater shall either:
(a)	Not exceed 50 parts per million, dry volume corrected to 7% O2 over any continuous one-hour period, or
(b)	Achieve a 90% reduction, by weight, on an hourly basis.
(2)	All incinerators located at a facility with a total incineration design capacity of less than 200 pounds per hour shall either:
(a)	Not exceed four (4) pounds per hour, or
(b)	Achieve a 90% reduction, by weight, on an hourly basis.
c.	Standard for Carbon Monoxide (CO):
All incinerators shall not exceed 100 parts per million dry volume corrected to 7% O2 over any continuous one-hour period as measured at a location upstream of the control devices.
d.	Standard for Visible Emissions:
All incinerators shall not exceed a visible emission limitation of 10 percent opacity.
2.	The owner or operator of an incinerator located at a facility with a total incineration design capacity of up to 400 pounds per hour may obtain an exemption from the applicable requirements set forth in this regulation, for units equal to or greater than 200 pounds per hour provided that:
a.	The operator complies with the requirements set forth in this regulation. For incinerators located at a facility with a total incineration design capacity of less than 200 pounds per hour, and
b.	The operator obtains a permit from the Division that contains a condition limiting the operation of such an incinerator to six hours in any one-day.  The violation of such a permit condition shall also be a violation of this regulation.
D.	Design and Operating Requirements
1.	All incinerators shall be equipped with a secondary combustion chamber or zone which provides for turbulent mixing and:
a.	Two (2) seconds of residence time at 1800ºF or greater for incinerators located at a facility with a total incineration design capacity of 200 pounds per hour or greater, or
b.	One (l) second of residence time at 1800ºF or greater for incinerators located at a facility with a total incineration design capacity of less than 200 pounds per hour.
2.	Auxiliary burners must be designed to provide the combustion chamber temperatures as described in paragraph 1 of this subsection without the assistance of the heat content of the waste.  The auxiliary burner fuel and the combustion air shall be modulated automatically to maintain a secondary chamber exit temperature of at least 1800ºF.
3.	The waste charging system of any incinerator must be designed so as to prevent disruption of the combustion process as waste is charged.  Batch fed units must be equipped with a lockout mechanism to prevent charging after start-up.  Units with automatic feed systems shall be equipped with a sealed feeding device capable of preventing combustion upsets during charging.  The volume of the loading system shall be designed to prevent overcharging thereby assuring complete combustion of the waste.
4.	For batch fed incinerators, interlocks must be provided to prevent charging until: 
a.	the secondary chamber exit temperature is established and holding at 1800ºF; and,  
b.	the combustion cycle is complete.
5.	For continually fed incinerators, the charging of waste to the incinerator shall automatically cease through the use of an interlock system if:
a.	The incinerator's secondary temperature drops below 1800ºF for any continuous 15-minute period, or
b.	The carbon monoxide emissions are equal to or greater than 150 parts per million by volume, corrected to seven percent O2 on a dry basis for any continuous 15-minute period.
6.	Each incinerator shall operate so that during shutdown the incinerator continues to meet applicable emission limitations and the secondary combustion chamber or combustion zone temperature is maintained at 1800ºF or above until the waste is completely combusted.
7.	Incinerators with a capacity of 200 pounds per hour or greater must be designed such that the flue gas temperature at the outlet of the final control device does not exceed 300oF unless a demonstration is made that an equivalent collection of condensable heavy metals and toxic organics can be achieved at a higher temperature or through the use of alternate technologies.
8.	Radioactive waste and hazardous waste may not be burned in an incinerator subject to this Section unless the incinerator has met the requirements of the Radiation Control Division and the Hazardous Materials and Waste Management Division.
E.	Performance Testing and Compliance Provision
1.	The performance tests and procedures shall be in accordance with Part A, Subpart A, Section 60.8. of this regulation.  The reference method contained in Appendix A of this regulation, except as provided under Part A, Subpart A, Section 60.8(b), shall be used to determine compliance with the standards prescribed in Subsection C as applicable.  Other tests not described in Appendix A should be conducted in accordance with the Division's source testing procedures described in the compliance test manual.  All tests shall be conducted at the maximum design rate using waste that is representative of normal operation.
2.	The owner or operator of any biomedical waste incinerator that has a capacity of less than 200 pounds per hour shall conduct a performance test under the provisions of Part A, Subpart A, Section 60.8. of this regulation to demonstrate compliance with the standards for Particulate Matter (PM), Carbon Monoxide (CO) and Hydrogen Chloride (HCl).
3.	The owner or operator of any biomedical waste incinerator that has a capacity of 200 pounds per hour or greater shall conduct a performance test to demonstrate compliance with the standards for Particulate Matter (PM), Carbon Monoxide (CO), and Hydrogen Chloride (HCl).  Additional source tests shall be conducted for: a) arsenic and compounds (expressed as arsenic); b) beryllium and compounds (expressed as beryllium); c) cadmium and compounds (expressed as cadmium); d) hexavalent chromium and compounds (expressed as chromium); e) lead and compounds (expressed as lead); f) mercury and compounds (expressed as mercury); g) nickel and compounds (expressed as nickel); and h) polychlorinated dibenzo-p-dioxins (PCDD) and polychlorinated dibenzo furans (PCDF) expressed as 2,3,7,8 tetrachlorinated dibenzo-p-dioxin (TCDD).
Source tests shall be conducted for the above-specified pollutants every year, except that the Division may waive some tests if consistent emission rates are found, but in no case shall tests be conducted less than once every three years.
F.	Monitoring Requirements
1.	The owner or operator of any incinerator with a capacity of 200 pounds per hour or greater subject to the provisions of this Section must install, calibrate, operate and maintain in accordance with Appendix B instruments for continuously monitoring and recording the following emission and operating parameters:
a.	Carbon Monoxide (CO)
b.	Oxygen (O2) 
2.	The owner or operator of any incinerator must install, calibrate, operate, and maintain devices that continuously record the temperature of gases leaving the primary and secondary (or final) combustion chambers.  Such devices shall have an accuracy of + 0.75% of the temperature being measured expressed in degrees Celsius (ºC) or + 2.5ºC whichever is greater.  Sensors shall be located such that flames from the burners do not impinge on the sensors.
G.	Recordkeeping and Reporting Requirements
1.	The owner or operator of an incinerator subject to the provisions of this Section shall maintain a monthly summary file of daily burning rates and hours of operation.  The summaries shall be retained for at least two (2) years following the date of such records and summaries.
2.	The owner or operator of an incinerator subject to the provisions of this Section shall submit continuous emission/operating data gathered from the monitors to the Division on a quarterly basis.  The data shall be retained for at least two (2) years following the date of record and shall be made available to the Division during facility inspections.
3.	The owner or operator of an incinerator subject to the provisions of this Section shall notify the Division by telephone following any failure of process equipment, failure of any air pollution control equipment, failure of any monitoring equipment, or a process operational error which results in an increase in emissions above any allowable rate. Notification shall be made no later than two (2) hours after the start of next working day, followed by written notice to the Division to include the measures undertaken to correct the problem.
VI.	STANDARDS OF PERFORMANCE FOR MUNICIPAL WASTE COMBUSTORS
A.	Applicability
1.	This section applies to any facility or equipment constructed, reconstructed, or modified after August 30, 1989, that burns or is designed to burn municipal solid waste.  This regulation also applies to any facility or equipment, designed to burn Refuse Derived Fuel (RDF) either in combination with other fuels or as an only fuel constructed, reconstructed or modified after August 30, 1989.
2.	Any facility that is subject to Part A, Subparts Ea, Cb or Eb is not subject to this section, except as set forth in Subsections F. and G. of this Section VI.
3.	Any facility that is subject to this section shall comply with all applicable requirements of the Colorado Solid Waste Act and its implementing regulations as promulgated by the Colorado Board of Health (Solid Waste Regulations, 6 CCR 1007-2).
B.	Definitions
As used in this section, all terms not defined herein shall have the meaning given in the Common Provisions regulation and in Subpart A of Part A of this Regulation No. 6 unless otherwise required by the context.
1.	Municipal Solid Waste (MSW) - means solid waste  collected by a public or private hauler from more than one waste generator, but excluding hazardous waste and infectious waste as defined in Regulation 6, Part B, Section V.
2.	Municipal Waste Combustor (MWC) - Any building, structure, facility, equipment, or installation used for reducing the volume of municipal solid waste by burning.
3.	Hazardous Waste - means any waste included by definition in Section 25-15-101 (9) of the Colorado Hazardous Waste Act.
4.	Solid waste - means any garbage, refuse, sludge from a waste treatment plant, water supply treatment plant or air pollution control facility and other discarded materials, including solid, liquid, semi solid, or contained gaseous material resulting from private, public, community, industrial or commercial operations.  Solid waste does not include any untreated solid; dissolved materials in domestic sewage; agricultural wastes; solid or dissolved materials in irrigation return flows; industrial discharges which are point sources subject to the provisions of the Colorado Water Quality Control Act, Section 25-8-101, et. seq. C.R.S., or materials handled at facilities licensed pursuant to the provisions of the Radiation Control Act, Section 25-11-101, et. seq., C.R.S. or materials defined as hazardous wastes.
5.	Refuse Derived Fuel (RDF) - means a fuel derived from Municipal Solid Waste prepared by mechanical shredding, followed by air classification, magnetic or other separation such as trammeling to reduce the non-combustible content of the Municipal Solid Waste, to allow the RDF to be injected into a combustion device such as a boiler for burning.
C.	Emission Limitations
On and after the date, which the required performance test has been completed, every affected facility subject to the provision of this section must comply with the following emission standards.
1.	For sources charging 40 tons per day or less excluding those covered in paragraph 2 of this section:
a.	Standard for particulate matter (PM):  Emissions of particulate matter shall not exceed 0.1 grains per dry standard cubic foot, corrected to seven percent O2.  Condensable particulate matter shall not be included.
b.	Standard for hydrochloric acid (HCl):  Emissions of HCl shall not exceed 50 ppmv, corrected to seven percent 02 on a dry basis; or, shall be reduced 50% by weight, whichever is less stringent.
c.	Standards for carbon monoxide (CO):  Emissions of CO, as measured at a location upstream of the control device, shall not exceed 100 PPMV as a eight hour running average.  CO concentrations are to be corrected to seven percent O2 on a dry basis.
d.	Standard for Visible Emissions:  Visible emissions shall not be emitted in such a manner that the opacity of the emissions is equal to or greater than 10 percent.
2.	For sources charging less than 10 tons per day and located within and serving a municipality or county with a population less than 2500:
The unit must show compliance with the following standards during the yearly stack test:
a.	Standard for particulate matter (PM):  Emissions of particulate matter shall not exceed 0.1 grains per dry standard cubic foot, corrected to seven percent O2.  Condensable particulate matter shall not be included.
b.	Standard for hydrochloric acid (HCl):  Emissions of HCl shall not exceed 50 ppmv, corrected to seven percent O2 on a dry basis; or, shall be reduced 50% by weight, whichever is less stringent.
c.	Standards for carbon monoxide (CO):  Emissions of CO, as measured at a location upstream of the control device, shall not exceed 100 PPMV as a eight hour running average.  CO concentrations are to be corrected to seven percent O2 on a dry basis.
The unit must continuously comply with the following standard for visible emissions:
d.	Standard for Visible Emissions:  Visible emissions shall not be emitted in such a manner that the opacity of the emissions is equal to or greater than 10 percent.
D.	Operating Requirements (Unless otherwise specified all municipal waste combustors subject to this Section VI shall be operated under the following conditions.) 
1.	The combustor shall maintain the combustion gases at a temperature greater than 1800 degrees F for at least one-second residence time.  The unit shall be equipped with automatically controlled auxiliary fuel burners to maintain the combustion gases at the aforementioned conditions under all waste firing conditions; and, to insure that the combustion chamber will reach 1800 degrees F prior to the introduction of Municipal Solid Waste.
a.	The Division shall determine the operating temperature and the gas residence time requirements on a case-by-case basis for any unit proposing advanced combustion technologies or burning specially prepared Municipal Solid Waste.  The applicant must demonstrate that the combustion efficiencies and the emission rates of air contaminants are equivalent to those achieved by the operating requirements described in paragraph a. above.
2.	Combustion efficiency (C.E.): For all units the combustion efficiency shall be at least 99.9 percent as an 8 hour running average. For units burning less than 10 tons per day and located within and serving a municipality or county with a population less than 2500 the unit combustion efficiency shall be at least 99.9 percent as demonstrated during the yearly stack test. Combustion efficiency shall be computed as follows:
C.E.=	[CO2]	x 100
[CO2]+[CO]
[CO2]=Concentration of carbon dioxide
[CO]=Concentration of carbon monoxide
3.	The tipping area and Municipal Solid Waste storage area shall be totally enclosed and operated at a negative atmospheric pressure to prevent the escape of malodors.  The air drawn from the tipping or storage areas shall be used as primary combustion air in the combustor.
4.	Ash shall be loaded in an enclosed area or handled wet in closed containers.
5.	The charging of waste to the combustor shall cease if:
a.	For all units:
1.	The combustor temperature drops below 1600 degrees F for a 15-minute period, or 
2.	Visible emissions exceed 20 percent opacity.  This condition excludes the startup period.
b.	For units charging 10 tons or more per day:
The combustion efficiency drops below 99.5 percent for a l5-minute period, 
6.	For units charging less than 10 tons per day and located within and serving a municipality or county with a population less than 2500, the unit's design rate  shall be no more than 10 tons per day, or the unit shall have a physical constraint limiting the unit to no more than 10 tons per day as applied over a 24 hour period.
E.	Monitoring Requirements
The owner or operator of any Municipal Waste Combustor subject to the provisions of this Section must install, calibrate, operate, and maintain, in accordance with Appendix B, instruments for continuously monitoring and recording the following emission and operating parameters:
1.	For all sources:
Combustion Chamber Temperature - The temperature monitoring instrumentation shall be located to demonstrate compliance with Section D.1 of this regulation.  The operator may monitor the temperature at an alternate location provided the one-second residence time requirements are met.  Verification that the lower temperature at the alternate location corresponds to the required operating temperature of 1800 degrees F shall be demonstrated during source testing.
2.	For sources charging 10 tons per day or more:
Carbon Dioxide, Carbon Monoxide and Oxygen - The CO2, CO and O2 monitors shall be co-located upstream of the air pollution control devices.
F.	Test Requirements
1.	The owner or operator of any municipal waste combustor charging less than 40  tons per day, shall conduct a performance test under the provisions of Part A, Subpart A, Section 60.8 of this Regulation No. 6.
a.	Source tests shall be conducted for the following pollutants prior to final approval: (a) particulate matter; (b) hydrochloric acid; © carbon monoxide; (d) carbon dioxide.
2.	Sources subject to the requirements of Subpart Ea, Cb or Eb Part A of this regulation shall conduct tests for the following pollutants prior to final approval:  (A) arsenic and compounds (expressed as arsenic); (B) cadmium and compounds (expressed as cadmium); © hexavalent chromium and compounds (expressed as chromium); (D) nickel and compounds (expressed as nickel); (E) lead and compounds (expressed as lead); (F) beryllium and compounds (expressed as beryllium); and (G) mercury and compounds (expressed as mercury).
After final approval, source tests for these pollutants shall be conducted every calendar year.
The tests shall be conducted as required under the provisions of Part A, Subpart A, Section 60.8 of this Regulation, and as provided under Subsections 1.c and d. of this Section VI.
G.	General Application Requirements
1.	The permit application shall include estimates of the following constituents in the municipal waste and/or air contaminant emissions: (a) chlorine (as estimated in the waste) and HCl and PCDD and PCDF (expressed as 2,3,7,8 TCDD equivalents estimated potential and actual emissions); (b) sulfur (as estimated in the waste) and SO2 (estimated as potential and actual emissions); (c) NOx (expressed as NO2); (d) arsenic; (e) cadmium; (f) hexavalent chromium; (g) nickel; (h) lead; (I) beryllium; and (j) mercury and (k) carbon monoxide.  The levels of metals and their compounds (expressed as the metals) are to be estimated as expected in the waste, and as potential and actual emissions.
2.	Permit applications for sources subject to the requirements of Subparts Ea, Eb or Cb of Part A of this regulation shall include estimates of the following constituents in the municipal waste and/or air contaminant emissions:  (A) chlorine (as estimated in the waste); (B) sulfur (as estimated in the waste); © arsenic; (D) cadmium; (E) hexavalent chromium; (F) nickel; (G) lead; (H) beryllium; and (J) mercury.  The levels of metals and their compounds (expressed as the metals) are to be estimated as expected in the waste, and as potential and actual emissions.
H.	Recordkeeping and Reporting Requirements
1.	The owner or operator of a Municipal Waste Combustor (MWC) subject to the provisions of this section shall maintain a monthly summary file of daily fuel firing rates and hours of operation.  The summary shall be retained for at least two (2) years following the date of such records and summaries.
2.	The owner or operator of a MWC subject to the provisions of this section shall submit continuous emission/operating data gathered from the monitors to the Division on a quarterly basis, except that a MWC unit charging less than 10 tons per day and located within and serving county or municipality with a population less than 2500 shall not be required to submit such data.  The data shall be retained for at least two (2) years following the date of record and shall be made available to the Division during facility inspections.
3.	The owner or operator of a MWC subject to the provisions of this section shall notify the Division by telephone following any failure of process equipment, failure of any air pollution control equipment, failure of any monitoring equipment, or a process operational error which results in an increase in emissions above any allowable rate.  Notification shall be made no later than two (2) hours after the start of the next working day, followed by written notice to the Division to include the measures undertaken to correct the problem(s).
I.	Special Provisions for units charging less than ten tons per day and located within and serving a county or municipality with a population less than 2,500
1.	Training
The operators of the MWC unit shall receive initial training and a minimum of once per year refresher courses in the proper operation of the MWC unit from a program approved by the Division.
2.	Waste Sorting
a.	A MWC unit charging less than 10 tons per day and located within and serving a county or municipality with a population less than 2,500 shall not burn:
i.	Appliances, including refrigerators, ranges, freezers or other large non-combustible items 
ii.	Lead acid batteries of the type used in automobiles and motorcycles 
iii.	Tires, unless specifically prepared for use as a Refuse Derived Fuel and included in a permit issued by the Division.
iv.	Alkaline, Nickel Cadmium, or mercury batteries
v.	Any hard plastic items
3.	Siting
A MWC unit must be a minimum of 1 mile from the boundary of any class I wilderness area, and half a mile from any residence.  The incinerator shall cease operation if a residence is constructed or occupied within a half mile of the MWC.  No MWC unit may be sited in a non-attainment area.
4.	Opacity observations
A single opacity observation of the plume shall be taken by a certified observer at 15-minute intervals while the incinerator is in operation.  The observer shall log all required opacity readings and the log shall be available for Division inspection upon request.
5.	Temperature recordings
Combustion chamber temperature readings shall be recorded and kept for Division inspection for all periods of operation of the incinerator, including start-up, shutdown and general operation.
VII.	STANDARDS OF PERFORMANCE FOR INCINERATORS
In addition to the requirements of Subpart E, Part A, the following requirements apply:
A.	Applicability and Designation of Affected Facility
The provisions of this section are applicable to all incinerators constructed, reconstructed, or modified after January 30, 1979.  Incinerators that are subject to Part A, Subpart E are also subject to this section.  Incinerators that are subject to Part A, Subpart Ea, or Part B, Sections V or VI, are not subject to this section.
B.	Definitions
As used in this section, all terms shall have the meaning given to them in the Common Provisions Regulation and in Part A, Subpart A of this regulation.
C.	Standard for Particulate Matter
1.	On and after the date on which the required performance test is completed, no owner or operator of an incinerator of greater than 45 metric tons per day (50 tons per day) charging rate shall discharge, or cause to discharge into the atmosphere particulate matter which is in excess of 20% opacity AND 0.18 g/dscm (0.08 gr/dscf) corrected to 12 percent CO2.
2.	On and after the date on which the required performance test is completed, no owner or operator of an incinerator of 50 tons per day and less charging rate shall discharge, or cause to be discharged into the atmosphere particulate matter which is in excess of 20% opacity and 0.229 g/dscm (0.10 gr/dscf) corrected to 12 percent CO2.
D.	Monitoring of Operations
The owner or operator of any incinerator subject to the provisions of this section shall record the daily charging rates and hours of operation.
E.	Test Methods and Procedures
Sources subject to this section are subject to the testing requirements and procedures of Part A, Subpart A and Part A, Subpart E, Section 60.54 of this Regulation No 6.
The Division may waive all or part of the testing requirements, on a case-by-case basis where sufficient information is available to warrant such waiver.
VIII.	STANDARDS OF PERFORMANCE FOR COAL-FIRED ELECTRIC STEAM GENERATING UNITS
A.	Applicability and Designation of Affected Facilities
This section applies to all facilities identified in 40 CFR Part 60, Section 60.4Da(a) (July 1, 2006.
B.	Definitions
Unless otherwise stated, the definitions in Regulation 6, Part A, Subpart HHHH apply to this Section VIII.
1.	Alternative Emission Standard
2.	An emission control standard and associated limitation based on the maximum degree of reductions in Hg taking into account energy, environmental, and economic impacts, and other costs, determined by the Division to be achievable and compatible with existing control technology installed at the Hg Budget Unit.  In making this determination, the Division shall consider the availability of alternate methods, systems, and techniques for control of Hg, the feasibility and obstacles in achieving the emission standards under Section VIII.C.1., C.3.a, or C.4.a., and factors such as average and marginal Hg removal costs.  Alternative Emission Standards shall be determined on a cases-by-case basis.  An Alternative Emission Standard is available to existing units and modified units (as determined with reference to 40 CFR, Section 60.14), and to new units and reconstructed units (as determined with reference to 40 CFR, Section 60.15) as provided in Sections VIII.C.4.b. through d.Best Available Mercury Control Technology Standard
An emission limitation based on the maximum degree of reduction of Hg emitted from or which results from any unit subject to Section VIII.V.4. which the Division, on a case-by-case basis, taking into account energy, environmental, and economic impacts and other costs, determines is achievable for such unit through application of production processes and available methods, systems and techniques, including fuel cleaning, clean fuels, or treatment or innovative fuel combustion techniques for control of Hg.  In determining the Best Available Mercury Control Technology the Division shall consider and evaluate whether the affected unit can achieve an output-based emission standard for Hg of 0.00435 lb/GWh or a 95 percent capture of inlet Hg.  The Division’s duty to consider and evaluate the achievability of such emission standard or percent capture shall not be treated as a minimum emission limitation or a presumptive emission limitation in determining the Best Available Mercury Control Technology.  In no event shall a determination of Best Available Mercury Control Technology result in a standard that is less stringent than the Hg output-based emission standard of 0.0087 lb/GWh or 90 percent capture of inlet Hg on a 12-month rolling average basis.  This Best Available Mercury Control Technology Standard applies to new units and reconstructed units.
3.	Initial Compliance Date
For purposes of Section VIII.C.2., the initial compliance date is the date on which compliance with an emission standard created under Section VIII.C.1. shall first be determined.
For purposes of Section VIII.C.3. and VIII.C.4., the initial compliance date is the date which is 12 months after the earlier of 60 days after achieving maximum production rate or 180 days after the unit first commences operation.
4.	Low Emitter
An Hg Budget Unit with actual Hg emissions of no more than 29 pounds per control period, as determined in accordance with 40 CFR Part 75.
C.	Mercury Emission Standards
1.	Base Emission Standards
a.	Pawnee Station Unit 1, 14940 County Road 2, Brush, Colorado 80723, and Rawhide Station Unit 101, 2700 East County Road 82, Wellington, Colorado 80549, shall comply beginning January 1, 2012 with either of the following standards on a 12-month rolling average basis and compliance therewith first determined on December 31, 2012.
(i).	An Hg output-based emission standard of 0.0174 lb/GWh; or
(ii).	A minimum of 80 percent capture of Inlet Hg.
b.	Any existing Hg Budget Unit, which is not a Low Emitter as defined in Section viii.b.4, above, and is not subject to Section VIII.C.1.a., above,  shall have Hg controls installed and operating consistent with its most current Division-approved compliance plan, beginning January 1, 2014, and shall comply with either of the following standards:
(i).	An Hg output-based emission standard of 0.0174 lb/GWh; or
(ii).	A minimum 80 percent capture of Inlet Hg. 
For the year 2014, the compliance period for such standards shall be on a six-month average basis, for the period July 1 through December 31, 2014, and compliance therewith first determined on December 31, 2014.  For the years 2015 through 2017, compliance with these standards shall be on a 12-month rolling average basis, and compliance therewith first determined on June 30, 2015.
c.	Any existing Hg Budget Unit, which is not a Low Emitter as defined in Section I.E., above, shall comply, beginning January 1, 2018, with either of the following standards on a 12-month rolling average basis, and compliance therewith first determined on December 31, 2018:
(i).	An Hg output-based emission standard of 0.0087 lb/GWh; or
(ii).	A minimum 90 percent capture of Inlet Hg.
d.	In demonstrating compliance with the base emission standards set forth in Sections VIII.C.1.b and VIII.C.1.c., above, an Hg Budget Source may average the emissions or reductions from any Hg Budget Units at the Hg Budget Source that are  subject to the provisions of VIII.C.1.b. and VIII.C.1.c. and that commenced operation prior to January 1, 2010, and that have chosen the same form of emission standard (i.e. lb/GWh or percent capture) with which to comply.
e.	Comanche Station Unit 3, 2005 Lime Road, Pueblo, Colorado 81006, is subject to a mercury emission limitation under a state-issued permit, and Comanche Station Units 1-3 are subject to a December 2004 Settlement Agreement providing for, among other limitations and requirements, compliance with a plant-wide mercury emission limit that maximizes cost-effective mercury reductions on a plant-wide basis no later than two years after the initial startup of Comanche Station Unit 3.  The requirements applicable to the Comanche Station include the installation of continuous emissions monitoring systems at Comanche Station Units 1-3.
The Hg emission-related requirements contained in this settlement agreement shall apply to Comanche Station Units 1-3 in lieu of the standards set forth in Sections VIII.C.1.b. and VIII.C.1.c., above.  Lamar Station Unit 4, 100 North 2nd Street, Lamar, Colorado 81052, is subject to a permit issued purusant to Section 169 of the Clean Air Act on February 6, 2006, which contains Hg emission limitation standards.  The Hg emission standards determined by the permit shall apply to Lamar Station Unit 4 in lieu of the standards set forth in Sections VIII.C.1.b and VIII.C.1.c., above.
2.	Alternative Emission Standard
a.	An Hg Budget Unit shall be allowed to comply with the Alternative Emission Standard, instead of the base standards in Sections VIII.C.1.a., VIII.C.1.b., and VIII.C.1.c., above, if:
(i).	Prior to the compliance date thereof, the Division determines, after consultation with the owner or operator of the Hg Budget Unit, which consultaton shall include, among other relevant factors, an assessment of the feasibility of compliance with the base emission standard in the future, that the unit cannot meet the base emission standard; or
(ii).	After installation of Hg controls designed to meet the base emission standard, if the Division determines the following conditions have been met:
(ii)(a).	The owner or operator timely installed and operated Hg control technology, which the manufacturer thereof projected would meet or exceed the selected base emission standard;
(ii)(b).	The owner or operator has maintained the unit, including any associated air pollution control equipment, in a manner consistent with good air pollution control practices for minimizing Hg emissions, following all applicable manufacturers’ recommendations;
(ii)(c).	The control strategy has failed to result in Hg emissions meeting the base standards in Sections VIII.C.1.a., VIII.C.1.b., or VIII.C.1.c, above;
(ii)(d).	The owner or operator notifies the Division of the failure to comply within 6 months from the Initial Compliance Date; and VIII.C.2.a.(ii)(e).  The owner or operator files a complete construction and/or operating permit application for a significant modification pursuant to Section VIII.D., below, containing an analysis and control strategy designed to achieve the Alternative Emission Standard, within 18 months from the Initial Compliance Date.
b.	The Alternative Emission Standard shall consist of an emission limit in lbs/GWh or percent reduction rate.
3.	Standards for Modified Units 
a.	Except as provided in Section VIII.C.3.fbelow, Any modified unit (as determined with reference to 40 CFR Part 60 Section 60.14) that is issued an Initial Approval for a construction permit pursuant to Regulation 3, Part C or D subsequent to the effective date of this rule, shall have Hg controls installed and operating consistent with its most current Division-approved compliance plan beginning with the date of re-commencement of operation following the modification and shall comply with the following standards based on a 12-month rolling average:
(i).	An Hg output-based emission standard of 0.0174 lb/GWh or a minimum of 80% percent capture of Inlet Hg from the date of re-commencement of operation through December 31, 2014; and  
(ii).	An Hg output-based emission standard of 0.0087 lb/GWh or a minimum of 90% percent capture of Inlet Hg  from January 1, 2015 forward.  
b.	If after installation of Hg controls designed to meet the standards of Section VIII.C.3.a., the owner or operator of a modified unit does not achieve the emission limitation determined in accordance with Section VIII.C.3.a., above, that unit:
(i).	shall be eligible for an Alternative Emission Standard pursuant to Section VIII.C.2.a(ii);
(ii).	shall be considered to be in compliance with the emission limitation requirement of this section, if; 
(a).	The owner or operator timely installed and operated Hg control technology, which the manufacturer thereof projected would meet or exceed the selected base emission standard;
(b).	The owner or operator has maintained the unit, including any associated air pollution control equipment, in a manner consistent with good air pollution control practices for minimizing Hg emissions, following all applicable manufacturers’ recommendations;
(c).	The control strategy has failed to result in Hg emissions meeting the emission standards in Section VIII.C.3.a., above;
(d).	The owner or operator notifies the Division of the failure to comply within 6 months from the Initial Compliance Date; and
(e).	The owner or operator files a complete construction and/or operating permit application for a significant modification pursuant to Section VIII.D., below, containing an analysis and control strategy designed to achieve the Alternative Emission Standard, within 18 months from the Initial Compliance Date.
c.	The Alternative Emission Standard shall consist of an emission limit in lbs/GWh or percent reduction rate.
d.	In demonstrating compliance with the Hg emission standards for modified units set forth in Section VIII.C.3.a. above, an Hg Budget Source may average the emissions or reductions from any Hg Budget Units at the Hg Budget Source that are subject to the provisions of Section VIII.C.3.a., that commenced operation prior to January 1, 2010, and that have chosen the same form of emission standard (i.e. lb/GWh or percent capture) with which to comply.  
e.	If a modified unit was originally subject to an Alternative Emission Standard instead of the base emission standard set forth in Section VIII.C.1., and subsequently the unit was modified and intends to make use of the plant-wide averaging provisions of Section VIII.C.1.d., the value identified in Section VIII.C.3.a. shall be used as the modified unit’s applicable emission standard when determining the plant-wide average.  
f.	The following Hg Budget Units which have undergonea Modification as defined in 40 CFR 60, Section 60.2., shall be subject to the emission standards identified in 40 CFR Part 60, Section 60.45Da upon Commencement of Operation, as defined in 40 CFR Part 60, Section 60.2, but shall not be required to comply with the state-only emission standards for modified units contained in Section VIII.C.3.a. above: 
(i).	Low Emitters as defined in Regulation 6, Part B, Section VIII.B.4.; 
(ii).	Hg Budget Units that have undergone a Modification solely because of the installation of air pollution control technology required by Colorado’s Regional Haze SIP.
4.	Best Available Mercury Control Technology Standards for New and Reconstructed Units
a.	Any New Unit or reconstructed unit (as determined with reference to 40 CFR Section 60.15) that is issued an Initial approval for a construction permit pursuant to Regulation 3, Part C or D, subsequent to the effective date of this rule shall have Hg controls installed and operating consistent with its most current Division-approved compliance plan beginning with the date of commencement of operation and shall comply with the Best Available Mercury Control Technology Standard. 
b.	If after installation and operation of Hg controls designed to meet the Best Available Mercury Control Technology Standard, the owner or operator of such unit does not achieve the emission limitation determined in accordance with Section VIII.B.2. above, that unit:
(i). shall be eligible for an Alternative Emission Standard pursuant to Section VIII.C.2.a(ii);
(ii). shall be considered to be in compliance with the emission limitation requirement of this section, if; 
(a).	The owner or operator timely installed and operated Hg control technology, which the manufacturer thereof projected would meet or exceed the selected emission standard;
(b).	The owner or operator has maintained the unit, including any associated air pollution control equipment, in a manner consistent with good air pollution control practices for minimizing Hg emissions, following all applicable manufacturers’ recommendations;
(c).	The control strategy has failed to result in Hg emissions meeting the emission standards in Section VIII.C.4.a., above;
(d).	The owner or operator notifies the Division of the failure to comply within 6 months from the Initial Compliance Date; and
(e).	The owner or operator files a complete construction and/or operating permit application for a significant modification pursuant to Section VIII.D., below, containing an analysis and control strategy designed to achieve the Alternative Emission Standard, within 18 months from the Initial Compliance Date; and
(iii).	The division shall incorporate this Alternative Emission Standard into the unit’s permit as an applicable standard in  lieu of those standards specified in Section VIII.C.4.a. 
c.	The Alternative Emission Standard shall consist of an emission limit in lbs/GWh or percent reduction rate, and may be less stringent than the Hg output-based emission standard of 0.0087 lb/GWh or 90 percent capture of Inlet Hg, on a 12-month rolling average basis.  
d.	A New Unit or reconstructed unit that receives an Alternative Emission Standard pursuant to Section VIII.C.2.a.(ii) has a continuing duty to try to achieve its original Best Available Mercury Control Technology Standard as specified in Section VIII.B.2, up through the second operating permit renewal application submittal that occurs after the date the owner or operator notifies the Division that it cannot meet the Best Available Mercury Control Technology Standard. During this time, a New Unit or reconstructed unit shall re-evaluate its ability to comply with its Best Available Mercury Control Technology Standard with each operating permit renewal application.  The re-evaluation shall primarily focus on whether the unit’s existing, Division-approved control technologycan either achieve the original Best Available Mercury Control Technology Standard or close the gap between the Alternative Emission Standard and the original Best Available Mercury Control Technology Standard. The scope of the re-evaluation shall include such considerations as alternative sorbents for activated carbon injection systems, and other changes that do not require major capital investment at the unit..  
e.	The Division shall review the re-evaluation of the unit required by Section VIII.C.4.d. above, and 
(i) 	If the Division determines that the unit can achieve either the Best Available Mercury Control Technology Standard, or if not achieve that standard, can achieve a more stringent standard than the Alternative Emission Standard, the owner or operator of that unit shall submit a permit application pursuant to Section VIII.D., to modify the permit to incorporate the more stringent achievable standard as the applicable emission limitation for the unit in accordance with Section VIII.B.2, including public notice and opportunity for public comment.  
(ii).	If the Division determines that the unit cannot achieve either the Best Available Mercury Control Technology Standard or a more stringent standard than the Alternative Emission Standard, the owner or operator of that unit shall submit a permit application pursuant to Section VIII.D., to modify the permit to incorporate the Alternative Emission Standard as the applicable emission limitation for the unit in accordance with Section VIII.B.2, including public notice and opportunity for public comment.  
f.	A Best Available Mercury Control Technology analysis shall not be required for a New Unit or reconstructed unit with projected annual mercury emissions of no more than 29 pounds per Control Period prior to commencing construction, and by considering actual emissions the unit is later demonstrated to be a Low Emitter, as determined in accordance with the monitoring provisions of 40 CFR Part 75.  If a New Unit’s or reconstructed unit’s projected annual mercury emissions were no more than 29 pounds per Control Period, but actual emissions were more than 29 pounds per control period, that unit shall not be considered to be in compliance with the emission limitation requirement of this section.  In addition, the owner or operator shall be required to:  
(i).	Maintain the unit, including any associated air pollution control equipment, in a manner consistent with good air pollution control practices for minimizing Hg emissions, following all applicable manufacturers’ recommendations;
(ii).	Comply with the most current Division-approved compliance plan until the Division issues a permit that incorporates the Best Available Hg Control Technology Standard for that unit.
(iii).	Notify the Division of the failure to comply within  30 daysafter the Initial Compliance Date; and 
(iv).	File a complete construction and/or operating permit application for a significant modification pursuant to Section VIII.D., below, containing an analysis and control strategy designed to achieve the Best Available Mercury Control Technology Standard, within 18 months from the Initial Compliance Date. 
g.	In demonstrating compliance with the Hg emission standards for New Units and reconstructed units set forth in Section VIII.C.4. above, except as provided for in Section VIII.C.1.e., an Hg Budget Source may not average the emissions or reductions from that unit with any other Hg Budget Unit.  
D.	Permitting Requirements  
1.	The emission standards (including any Alternative Emission Standard or Best Available Mercury Control Technology Standard), Low Emitter provisions, and permitting, monitoring, and enforceability requirements found in this Section VIII. are applicable requirements and shall be incorporated into the permit for each subject Hg Budget Unit.
2.	The owner or operator of an existing Hg Budget Unit shall submit a complete permit applicationto the Division to incorporate the applicable requirements of this Section VIII. at least 18 months prior to commencement of construction of the control equipment, and, for Low Emitters by July 1, 2012.  For purposes of Section VIII.C.1.a, above, Rawhide Unit 101 and Pawnee Unit 1 shall submit their applications by January 1, 2009, and the Division shall issue a permit revision by January 1, 2010.
3.	The owner or operator of a new, reconstructed or modified Hg Budget Unit shall submit a complete permit applicationto the Division to incorporate the applicable requirements of this Section VIII. and obtain necessarypermit(s) prior to commencement of construction.  
4.	Such permit application and/or modification  application shall include:
a.	A statement indicating that Hg Budget Units in the State under the control of the owner or operator shall comply with the emission standards and other requirements of this Section VIII.;
b.	A detailed compliance plan for each applicable emission standard, or schedule for achieving compliance with that standard, for each Hg Budget Unit under the control of the owner or operator, including monitoring and reporting; and
c.	A description of the assumptions on which the plan is based. 
5.	The Division shall issue a permit modification pursuant to Section VIII.D.2. within 18 months from receiving a complete permit modification application.  All permits issued pursuant to Section VIII.D.2. and 3. shall incorporate all applicable requirements, including:
a.	Requirements to comply with the emission standards in Section VIII.C.; and 
b.	Requirements to comply with the permitting and monitoring requirements of Sections VIII.D. and VIII.E., hereof, and 40 CFR Part 75.
E.	Monitoring
Hg Budget Units demonstrating compliance with any of the percent capture emission standards set forth in this Section VIII., shall submit to the Division for approval a monitoring plan, including the information in Section VIII.E.1. or VIII.E.2., below. ] 
1.	For Hg Budget Units that choose to demonstrate compliance with a percent Hg capture emission standard, coal Inlet Hg monitoring and emission standard demonstration methodology including, but not limited to: coal sampling location, frequency, analysis method, results documentation and calculation for incorporation into the rolling 12-month total emission standard.
2.	For  Hg Budget Units that choose to demonstrate compliance with a pounds Hg per GWh emission standard, GWh monitoring and emission standard demonstration methodology including, but not limited to: GWh monitoring, frequency, results documentation and calculation for incorporation into the rolling 12-month total emission standard.
F.	Enforceability
1.	The emission standards, including Alternative Emission Standards and Best Available Mercury Control Technology Standards, permitting and monitoring requirements under Sections VIII.C., VIII.D., and VIII.E., above, are enforceable.  Any violations of permit terms may be enforced by the Division pursuant to Section 25-7-115, C.R.S.
2.	If an Hg Budget Unit demonstrates compliance with the  compliance plan required by Sections VIII.D.4.b. and c., above, but did not comply with the applicable emission standards in Sections VIII.C.1.a. through d. or Sections VIII.C.2., VIII.C.3.a., and VIII.C.4.b., above, that unit shall be considered to be in compliance with such emission standards. 
G.	Colorado Citizens’ Mercury Reductions Trust Account
1.	By October 1, 2007, the Division shall establish a separate account with EPA’s Clean Air Markets Division, called the “Colorado Citizens’ Mercury Reductions Trust Account.”  In addition to the disposition of allowances by the Division as set forth in Regulation 6, Part A, Section III.B.3., the Division may also transfer available allowances in accordance with this Section VIII.G.
2.	On July 1, 2016, the Division shall transfer 60 percent of the balance of the Division’s General Account to the Colorado Citizens’ Mercury Reductions Trust Account.  The Hg Allowances in the Colorado Citizens’ Mercury Reduction Trust Account shall be held in trust for the benefit of public health and the environment of the people of Colorado.  The remaining 40 percent shall remain in the Division’s General Account, and shall only be allocated for safety valve and New Unit and Existing Unit purposes, in accordance with Regulation 6, Part A, Sections III.B.2. and III.B.3.a.. 
3.	On July 1, 2019, and on a periodic five-year basis thereafter, the Division shall transfer 60 percent of the incremental increase in the Division’s General Account which has accrued since the date of the last transfer to the Colorado Citizens’ Mercury Reductions Trust Account.  The remaining 40 percent of the incremental increase shall remain in the Division’s General Account, and can be allocated for safety valve and new power generation purposes, in accordance with Regulation 6, Part A, Section III.B.3.a. 
4.	The default allocations of Sections VIII.G.2. and VIII.G.3. shall not occur if a rulemaking is timely commenced by the Commission prior to any default transfer date.  For purposes of Sections VIII.G.2. and VIII.G.3., the receipt of a petition for rulemaking, if filed after January 1st of the year in which the default would occur, commences the rulemaking.
5.	Hg Allowances in the Colorado Citizens’ Mercury Reductions Trust Account shall not be sold, traded, or transferred.  The foregoing prohibition does not preclude the possibility of future transfer of Hg Allowances in the Colorado Citizens’ Mercury Reductions Trust Account to a private trust or similar mechanism designed to permanently retire such allowances. 
6.	Any person may request that the Commission hold a rulemaking hearing to consider the proper disposition of any unallocated Hg Allowances in the Division’s General Account, at any time.  In any such rulemaking, the Commission shall consider the following factors and criteria, in determining the disposition of such allowances:
a.	the balance of Hg Allowances in the Division’s General Account; 
b.	projections regarding future energy generation needs in Colorado;
c.	the goal of maximizing Hg Allowances held in trust for the benefit of public health and environment for the citizens of Colorado; and
d.	any other factors deemed relevant by the Commission.
IX.	STATEMENTS OF BASIS, SPECFIC STATUTORY AUTHORITY, AND PURPOSE (For Part B) 
A.	September 21, 1995 for Section VI
This Statement of Basis, Specific Statutory Authority and Purpose complies with the requirements of the Colorado Administrative Procedures Act, Section 24-4-103, C.R.S. and the Colorado Air Pollution Prevention and Control Act, Section 25-7-110.5, C.R.S.
Regulation No. 6 prescribes emissions standards and testing, monitoring and record keeping requirements for municipal waste combustors.  The revisions adopted provide a more technically feasible and economically reasonable method for assuring proper operation and determining emissions standard compliance for small municipal waste combustors (those charging less than ten tons per day).
The Colorado Air Pollution Prevention and Control Act provides the authority for the Colorado Air Quality Control Commission to adopt and modify Regulation No. 6.  Section 25-7-106(6), C.R.S., grants the Commission the authority to prescribe testing, monitoring and record keeping requirements for sources of air pollution, including municipal waste combustors.  The Commission's action is taken pursuant to authority granted and procedures set forth in Sections 25-7-105, 25-7-106, 25-7-110, 25-7-110.5 and 25-7-114, C.R.S.  In adopting these revisions, the Commission is guided by Section 25-7-102, C.R.S., which mandates that the Commission use all available practical methods, which are technically feasible and economically reasonable to reduce, prevent and control air pollution.
These revisions to Regulation No. 6 are intended to allow operators of small municipal waste combustors to avoid the expense of installing and operating continuous emissions monitors as currently required by Regulation No. 6.  The continuous emissions monitoring requirements were intended to provide both continuous performance indicators for the operator and information to demonstrate compliance with applicable emissions standards.  The Commission acknowledges, however, the economic and practical burden the requirement for continuous emissions monitors places on small communities, particularly where the municipal waste combustor is operated only intermittently and at temperatures that may make effective use of some continuous emissions monitors, such as those that measure opacity, questionable.  The Commission believes some flexibility in the regulations, therefore, is warranted for smaller municipal waste combustors to allow for operation without the use of continuous emission monitors.  The Commission is limiting this flexibility to municipal waste combustors charging less than ten tons per day and located within and serving a municipality or county with a population of less than 2,500, however, because of the uncertainties and potential risks to human health and the environment associated with incineration.
The Commission concludes that, with certain additional conditions to assure proper operation, an annual emissions test under normal operating conditions is sufficient to determine whether small municipal waste combustors are operating in accordance with applicable emissions standards.  These revisions impose requirements for an annual emissions test, operator training, waste sorting, regular opacity observations, temperature recording and feed rate limitations (similar to auger feed) in order to provide substitute protections for public health and the environment from emissions related to municipal waste combustion.  The Commission's intent is that the regular opacity observations will be made substantially in accordance with EPA Method 9, (40 CFR, Part 60, Appendix A (July, 1992)) with the exception that an observation shall consist of a single reading at fifteen-minute intervals rather than a series of twenty-four consecutive readings at fifteen-second intervals.  In addition, the Commission imposes site and population service limitations on municipal waste combustors in order to protect both populations and sensitive natural areas from impacts associated with incineration. 
Based upon economic impact analyses submitted and considered as required by Section 25-7-110.5, C.R.S., the Commission makes the following findings and determinations pursuant to Section 25-7-110.8, C.R.S.:
1.	The Commission has considered, and has based its decision, on the  reasonably available, validated, reviewed and sound scientific methodologies and information made available by interested parties.
2.	Evidence in the record supports the conclusion that the operating limitations adopted will result in a demonstrable reduction in air pollution compared with the alternative of deleting the continuous monitoring requirement without imposing such operating limitations.
3.	The alternative chosen is the most cost-effective method of providing both performance indicators for the operator and information to demonstrate compliance with applicable emissions standards while retaining some assurance that the most hazardous emissions from incineration are minimized.  This alternative increases the flexibility available to the operators of small municipal waste combustors but will not result in an increase in air pollution compared to the previous requirements for continuous emissions monitoring.
4.	The alternative selected maximizes the air quality benefits of the emissions standards applicable to small municipal waste combustors in the most cost-effective manner by reducing the cost of  providing both performance indicators for the operator and information to demonstrate compliance with applicable emissions standards while retaining some assurance that the most hazardous emissions from incineration are minimized.  
B.	June 20, 1996 for Section VI (for sources burning more than 40 tons) 
This Statement of Basis, Specific Statutory Authority and Purpose complies with the requirements of the Colorado Administrative Procedures Act, Section 24-4-103, C.R.S. and the Colorado Air Quality Control Commission procedural rules.
Basis
Regulation No. 6 prescribes emissions standards and testing, monitoring and record keeping requirements for municipal waste combustors.  The revisions adopted help keep the state rule consistent with the Federal New Source Performance Standard for municipal waste combustors.
Specific Statutory Authority
The Colorado Air Pollution Prevention and Control Act provides the authority for the Colorado Air Quality Control Commission to adopt and modify Regulation No. 6.  Section 25-7-106(6), C.R.S., grants the Commission the authority to prescribe testing, monitoring and record keeping requirements for sources of air pollution, including municipal waste combustors.  The Commission's action is taken pursuant to authority granted and procedures set forth in Sections 25-7-105, 25-7-106, 25-7-110, 25-7-110.5 and 25-7-114, C.R.S.  These changes are not required by federal law and are not currently included in the State Implementation Plan.
Purpose
These revisions to Regulation No. 6 are simply intended to keep Regulation No. 6, Section VI (Standards of Performance for Municipal Waste Combustors) consistent with the Federal New Source Performance Standard as promulgated by the EPA on December 19, 1995. 
The Commission finds and determines pursuant to Section 25-7-110.8, C.R.S. that these revisions are administrative in nature and are not intended to reduce air pollution.
C.	December 23, 1996, for Section II.C.3.a and for revisions to Regulation No. 1, Section II.A.1, 4 and 10  (regarding opacity limitations and sulfur dioxide averaging provisions for coal-fired electric utility boilers during periods of startup, shutdown and upset.) 
This Statement of Basis, Specific Statutory Authority and Purpose complies with the requirements of the Colorado Administrative Procedures Act, Section 24-4-103, C.R.S. and the Colorado Air Pollution Prevention and Control Act, Sections 25-7-110 and 25-7-110.5, C.R.S.
Basis
Regulations 1 and 6 deal with opacity and sulfur dioxide emissions from various sources.  This rule change addresses only coal-fired electric utility boilers.  The Colorado Utilities Coalition ("CUC") requested that the Commission modify the existing regulations to provide additional flexibility in meeting  the opacity requirements and sulfur dioxide averaging, for coal-fired electric utility boilers during periods of start-up, shutdown, upset, process modification and adjustment of control equipment.
Specific Statutory Authority
The Colorado Air Pollution Prevention and Control Act, Section 25-7-109(2), C.R.S., provides the authority for the Commission to adopt and modify emissions control regulations pertaining to visible pollutants, particulates and sulfur oxides. Section 25-7-109(5) authorizes the commission to grant a rule change it feels is appropriate for periods of start-up, shutdown or malfunction or other conditions, which justify temporary relief from controls.  Section 25-7-105(1) provides the authority for the Commission to make SIP revisions.  Section 25-7-133(4)(a) provides the Commission with the flexibility to determine what are necessary elements for the SIP.  The Commission's action is taken pursuant to authority granted and procedures set forth in Sections 25-7-105, 25-7-109, and 25-7-110, C.R.S.
Purpose
The revisions to Regulation No. 1 and No. 6 are intended to provide a specific amount of flexibility related to compliance with opacity limitations and sulfur dioxide averaging provisions for coal-fired electric utility boilers during periods of startup, shutdown and upset.  These revisions replace what is believed to be a problematic standard for these specific sources.  CUC has demonstrated that there are instances during which these sources cannot comply with the 30% opacity limit and the SO2 emissions limit during start-ups and shutdowns.  Although these sources may exceed the opacity limit, CUC has presented the Commission with a study prepared by Radian Corporation, which concludes that removing the 30% opacity limit for these sources will not result in such an increase in emissions that Colorado will likely violate the National Ambient Air Quality Standards or other federal requirements.  CUC proposed replacement of the 30% limit with a standard that more closely mimics the federal standard, and which these sources will have more certainty complying with, particularly for Title V compliance certification requirements.  CUC also provided an ambient air analysis related to SO2 emissions, which concluded that allowing a modification of SO2 limitations for the periods of startup, shutdown and malfunction would have no adverse impact on related federal requirements. 
The Division agreed that some flexibility in complying with the 30% opacity limit was appropriate for these sources.  The Division also proposed replacing the 30% opacity limit.  
Action Taken
The Commission concludes that a rule change is appropriate for this category of sources and is removing the application of the 30% opacity limitation to these sources during periods of start-up, shutdown and upset.  In addition, the Commission agrees that a rule change is merited from the current treatment of SO2 emissions during periods of start-up, shutdown and malfunction.  The Commission also concludes that this rule can be made clearer and easier to implement through the changes adopted.
The Commission adopts language substantially similar to the federal New Source Performance Standard requirement that, during periods of startup, shutdown and malfunction, these sources, to the extent practicable, shall maintain and operate associated air pollution control equipment in a manner consistent with good air pollution control practice for minimizing emissions.  In the Commission's view, incorporating this standard will provide an important balance to the removal of the 30% limit.  
The federal New Source Performance Standard refers to “malfunctions,” while the Commission has adopted an “upset” provision.  The Commission finds that these two terms are substantially similar, with the exception that an upset must be properly reported to the Division to be excused.  In order to avoid confusion, the Commission decided to use the term upset consistent with the Common Provisions Regulation.
The Division expressed concern that the "good practices" standard is subjective and requires substantially more resources to enforce than a numerical limit.  In addition, without the 30% limit, opacity from these facilities could be at very high levels for periods of time.  The Commission concurs and in this regulation adopts the Division's proposed measures to limit the overall time during which a source may exceed the underlying 20% opacity restriction. 
Good Air Pollution Control Practices
This regulation sets overall limits, by percentage of operating time, during which opacity may exceed 20% and SO2 emissions may exceed regulatory maximums.  In the Commission's view, this will allow more flexibility for the utilities without leaving them free of reasonable restriction.  The percentages were determined based on a percentile of the exceedance times for all such sources within the state.  Exceedance times were calculated based on the excess emissions reports submitted by each of the utilities over the last several years.  These times included the periods of excess emissions due to the events listed in Regulation No. 1, Section II.A.4 [fire building, cleaning of fire boxes, soot blowing, start-up, process modification and adjustment or occasional cleaning of control equipment], as well as shutdowns and upsets.  Accordingly, the data upon which the Commission based its adoption of the percentages used to define good air pollution control practices included all times during which a source exceeded the applicable opacity limitation.  In turn, the percentages adopted as the definition of good air pollution control practices include all times during which a source exceeds the 20% opacity limitation.  Thus, all periods of start-up, shutdown, upset, fire building, process modification and adjustment or occasional cleaning of control equipment will be counted against the unit’s compliance with the percentages.  
This general rule does not apply in two circumstances.  First, start-ups following planned maintenance outages that require significant changes at the facility are treated separately, because the Commission concluded that these infrequent events posed particular difficulties for the utilities.  It appears that the duration of these events cannot be reasonably predicted and they are not to be included in the calculation of the source’s compliance percentages.  However, in order to ensure accountability of these sources during planned outages, the Commission is imposing requirements for advance notice to the Division.  Advance notice will ensure that these are, indeed, planned outages.  The notice must include a plan for minimizing emissions and an estimate of the time during which controls will not be operable while the unit is in operation, both in order to prevent inordinate startups beyond reasonable limits.  During start-ups, the source must still use good air pollution control practices.  An additional definition of start-up is provided to add certainty for all concerned about the duration of these significant planned outage start-ups.  In addition, the Commission restricts the application of the planned maintenance outage exception to events requiring significant changes at the facility, such as replacement of major facility components or installation of new processes (e.g., installation of low NOx burners).  This exception addresses changes from which the resulting impact on plant operations cannot accurately be predicted.  The exception is not intended to allow exclusion of excess emissions resulting from routine maintenance outages, such as annual replacement of standard equipment, from calculation of the exceedance percentage time allowance. 
Second, opacity emissions that are not a result of the combustion of fuel in the steam-generating unit are excluded from the calculation of the compliance percentage.  This approach is consistent with the federal New Source Performance Standard found at 40 CFR Part 60, Subpart Da.  The Commission concludes that these emissions control measures are not intended to limit emissions from cleaning of fire boxes, soot blowing and other activities when a unit is off-line, i.e., when no fuel is being fed to the unit.  In addition, there are technical concerns related to the ability of monitoring devices to operate accurately when the unit is off-line.
The Commission agrees that all of these sources can perform somewhat better and intends that the percentages will serve as an as an achievable measure of good air pollution control practices during these specific periods.  This approach will also force poorer-performing facilities to improve their operations and maintenance practices and bring their exceedance levels down to one more consistent with that at other facilities.  For baghouse-equipped boilers, a single percentage will suffice for the indefinite future.  However, utility units using electrostatic precipitators to control particulate emissions present more complicated issues.  Accordingly, the Commission elected to provide an interim period of approximately three years during which these units will have a higher allowance percentage.  
The Commission does not impose at this time a requirement for electrostatic precipitator-equipped facilities to achieve the same exceedance percentage time allowance as baghouses.  However, the Commission’s ultimate goal is for ESP-equipped facilities to meet the same compliance standard as is today imposed on baghouses. 
The Commission endorses the concept that the utilities conduct a study to evaluate operations and maintenance practices and equipment modifications at ESP-equipped facilities.  The purpose for this study is to improve understanding of the operators, the Division and the Commission related to ESP operations and potential improvements.  The results of this study are not intended for use as evidence that pre-study operations do not constitute good air pollution control practices.
The Commission did not agree with the CUC proposal for limitations on the duration of individual incidents of start-up and shutdown because this approach also is subjective and would require more resources to enforce.  The Sierra Club proposal, although substantially similar to that presented by the Division, would require enforcement with exceedance allowances calculated for each ESP-equipped facility.  The Commission is not convinced that the benefits of a more specific exceedance allowance justify the resources required to enforce these percentages. 
The allowance percentages will give both sources and the Division a clear definition and reasonable limits to the concept of "good air pollution control practices."  This definition limits sources from arguing that longer periods of exceedance are good practices.  The definition is also intended to allow the Division to investigate the source’s practices and determine whether, in light of their compliance history, process and control equipment and operations and maintenance procedures, the source is using good practices.  This treatment of good practices will in no way prevent the Division from initiating an enforcement action if the Division determines that a source is not using "good air pollution control practices," regardless of the amount of time the source has been in violation of the 20% opacity standard.  The Division may use any available information in order to evaluate whether the source is using good practices.
Federal and State Statutory, and State Implementation Plan, Issues
The Commission is cognizant that §193 of the federal Clean Air Act precludes revisions to the state implementation plan relating to nonattainment areas which do not provide equivalent or greater emissions reductions to the existing provisions of the plan.  Even under this federal law, however, the Commission is entitled to modify its plan to make it more cost-effective and to improve overall compliance and implementation.  The Commission concludes that the Division's proposal does not represent a relaxation of the existing rule.  The regulatory change removing application of the 30% opacity limit appears on first impression to relax requirements for these units.  However, by limiting the overall time during which the units may exceed the 20% opacity limit, the Commission believes this approach will result in at least the same levels of compliance with the opacity standard and will likely result in lower overall emissions.
The Commission is also aware that Section 110 of the federal Clean Air Act imposes additional limitations on revisions to the state implementation plan.  CUC presented information relating to the impact of its proposal on ambient air concentrations.  The Commission relied on this information, although it did not adopt the CUC proposal for defining and limiting "good air pollution practices."  The Commission concludes that the changes made in this rulemaking will not lead to increased emissions in amounts substantial enough to interfere with the state's programs to attain and maintain the NAAQS or any other federal requirements.
The Commission also has evaluated the proposal adopted pursuant to the standards of Section 25-7-105.1, C.R.S.  This rule change and the compliance levels adopted today for these limited periods for coal-fired electric utility boilers clarify the federal narrative standard adopted, providing both the utilities and the Division with greater levels of certainty.  The levels also put a practical limit on excursions by these sources above the opacity and SO2 emissions limits and aid in ensuring that the NAAQS are attained or maintained and that no other applicable requirements are adversely affected.  
The Commission has determined that continued enforcement of the Regulation No. 1 opacity provisions were relied on in development of the Denver PM10 element of the state implementation plan.  The provisions deleted from Regulation No. 1 pertaining to electric power plants therefore must be replaced with substantially equivalent requirements.  In the past, the Division’s enforcement discretion has been exercised to effectively allow 5% noncompliance by these sources.  Substantial regulatory ambiguity in the opacity limitations applicable to startup and other periods also led to uncertainty and lower compliance levels.  These revisions are substantially equivalent or better in their impact on emissions to the results of current law and practice because that past practice led to lower compliance than the anticipated compliance levels, which will result from these changes.  The Commission finds that these modifications are necessary as parts of the state implementation plan.  The Commission also concludes that these revisions are not more stringent than federal requirements, considering the historical “5% policy” used by the Division and EPA.  Accordingly, the Commission concludes that these changes should be forwarded to the General Assembly for review and then to EPA for inclusion in the state implementation plan.
Finally, the Commission adopts these rule changes subject to a delayed effective date insofar as the revisions apply to sources within the Denver PM10 nonattainment area.  The Environmental Protection Agency has expressed concerns about the potential effect of this rule change on the pending approval of the PM10 element of the state implementation plan for the Denver nonattainment area.  In order to ensure that the proposed approval of the PM10 element for the Denver nonattainment area is not endangered, the Commission designates the effective date for these revisions as they apply to sources within this nonattainment area as the date on which EPA approves these changes as a revision to the state implementation plan.
The Commission has taken into consideration the items enumerated in Section 25-7-109(1)(b), C.R.S.  The Commission also makes the following findings regarding the adoption of these rule changes:
1.	The Commission has considered, and has based its decision, on the reasonably available, validated, reviewed and sound scientific methodologies and information made available by the parties.
2.	Where these revisions are not administrative in nature, the record supports the conclusion that the provisions adopted will result in a demonstrable reduction in air pollution.  This reduction is accomplished because the overall exceedance levels of the facilities will be lowered under the proposal adopted.
3.	The revisions selected maximize the air quality benefits of the emissions standards that apply.  The revisions selected are the most cost-effective based on the documents submitted by the parties under Section 25-7-110.5, and provide the regulated community with flexibility in meeting emissions limitations.  Although the overall level of exceedances should be reduced under this rule change, operators of the units affected will have greater flexibility in start-up and shutdown of the facilities without incurring a violation. In addition, the greater levels of certainty provided by these changes will allow operators of affected facilities to more readily certify compliance with these applicable requirements under the Title V operating permit program.
D.	Adopted: February 21, 2002
Deletion of Section II.C.3.a., to be consistent with recent revisions to Regulation No.1.
Background
This Statement of Basis, Specific Statutory Authority and Purpose complies with the requirements of the Administrative Procedures Act, C.R.S. (2001), Sections 24-4-103(4) and (12.5) for adopted or modified regulations.
Basis
The rule deletes Section II.C.3.a., in Part B (and associated footnote) in order to conform the regulation to revisions made by the commission to Regulation No. 1 on August 16, 2001. 
Authority
Sections 25-7-105(1)(b) and 25-7-109, C.R.S. (2001) authorize the Commission to adopt emission control regulations, including emission control regulations relating to new stationary sources. 
Purpose
The removal of the provision in Section II.C.3.a., of Part B (and associated footnote), concerning coal-fired electric utility boilers was made to conform the regulation to changes made to Commission Regulation No. 1 on August 16, 2001. The provision was added to Regulations No. 1 and 6 in 1996, but was never approved by the EPA. In April 2001, the commission adopted an affirmative defense rule in the Common Provisions Regulation to address the technical concerns related to continuous opacity monitors when boilers and process equipment at coal-fired electric utility plants are shut off. As a result, the commission removed conflicting and confusing language from Regulation No. 1 in August 2001. Deletion of this provision conforms Part B with the action taken by the commission in Regulation No. 1 and removes any potential confusion or conflict with respect to the regulated community.
E.	Adopted:  October 18, 2007 (for Section VIII)
Adoption of changes that address June 9, 2006 revisions to the federal New Source Performance Standards for Coal-fired Power Plants, changes associated with reorganizing Regulation 6, and corrections to rule language.  
Background
This Statement of Basis, Specific Statutory Authority and Purpose complies with the requirements of the Administrative Procedures Act, Section 24-4-103, C.R.S. and the Colorado Air Pollution Prevention and Control Act, Section 25-7-110.5, C.R.S.
Basis
On June 9, 2006, EPA revised the New Source Performance Standards for Coal-fired Power Plants specific to mercury and corrected the applicability thereof to include modified units.  New Units, Modified Units and Reconstructed Units are all subject to the revised New Source Performance Standards for Coal-fired Power Plants.  
These amendments to Regulation 6, Part B set more stringent state-only Hg standards for new, modified and reconstructed units than the federal New Source Performance Standards for Coal-fired Power Plants.  Specifically for subject new, modified and reconstructed units, these amendments set more stringent mercury emissions limitations.
Additionally, the state-only provisions of regulation 6 adopted by the Commission on february 6, 2007 and that were initially placed in Regulation 6, Part A, Subpart HHHH were moved to Part B.  This was done for consistency, as all other state-only New Source Performance Standards are located in Part B.  
Authority
Sections 25-7-105(1)(b) and 25-7-109, C.R.S.  authorize the Commission to adopt emission control regulations, including emission control regulations relating to new stationary sources. 
Purpose
This regulation addresses changes in the federal New Source Performance Standards for Coal-fired Power Plants, including changes in applicability to include new, modified and reconstructed units, and changes in Hg emission standards.  
In addition, the Commission has moved the state-only provisions of regulation 6 adopted by the Commission on february 6, 2007 and that were initially placed in Regulation 6, Part A, Subpart HHHH, to Part B.  This was done for consistency; all other state-only New Source Performance Standards are located in Part B. 
Further, these revisions will include any typographical and grammatical errors throughout the regulation. 
Hg Emissions Limitations 
This regulation establishes Hg emission standards for units that are new, modified or reconstructed, and may require mercury control technology installation.  There are three separate types of Hg emissions standards addressed in this regulation: base emission standards, Alternative Emission Standards (AES), and Best Available Mercury Control Technology (BAMCT) Standards.  Generally, Hg Budget Units are subject to the Hg emission limitations, and if the Division agrees that the unit cannot achieve compliance with that emission limitation, then the unit is conditionally able to establish an AES (i.e. they must notify the Division, comply with their compliance plan, submit permit modification applications, etc.).  
February 2007 Rule Hg Emission Limitations (moved from Regulation 6, Part A, Subpart HHHH):
Hg Limits in Effect. The Comanche Power Station and the Lamar Power Station shall adhere to the Hg emission limits and requirements applicable to those coal-fired electric generating units under permits and agreements in effect. 
Phase I Early Mercury Reduction Program in 2012. Beginning on January 1, 2012, Xcel Energy’s Pawnee Power Station in Brush, and Platte River Power Authority’s Rawhide power plant in Wellington, shall achieve either an 80% capture of inlet Hg or an Hg output-based emission limit of 0.0174 pounds of Hg per gigawatt hour (lbs/GWh). Compliance with such limits shall be demonstrated on December 31, 2012 and on an annual rolling average basis thereafter. 
The Division and the owners and operators of Hg Budget Units recognize that achieving dates for compliance in 2012, 2014, and 2018 requires that the Division issue the relevant permits in the timeframes provided in Section IV.B. of the Rule. The Division will use its best efforts to meet the dates in the Rule for permit issuance. If a permit is not issued within the time set forth in the Rule, the parties will confer in an effort to minimize the resulting delays both in installation of Hg emissions controls and in the dates for required compliance with emissions standards. 
Phase I Hg Emissions Reduction Requirements in 2014. Beginning on January 1, 2014, all existing coal-fired electric generating units in Colorado, excluding sources with limits in effect and low emitters, will be required to install and operate Hg emission controls designed as necessary to achieve either an 80% capture of inlet Hg or an Hg output-based emission limit of 0.0174 pounds of Hg per gigawatt hour (lbs/GWh). Beginning on July 1, 2014, such sources will need to achieve either an 80% capture of inlet Hg or an Hg output-based emission limit of 0.0174 pounds of Hg per gigawatt hour (lbs/GWh). Compliance with such limits shall be demonstrated on December 31, 2014 on the basis of 6 months of data generated beginning on July 1, 2014, and on an annual rolling average basis beginning June 30, 2015 and thereafter. 
Phase II Hg Emission Limits in 2018. Beginning on January 1, 2018 all existing coal-fired electric generating units in Colorado, excluding sources with mercury limits in effect as of 2006 and low emitters, shall achieve either a 90% capture of inlet Hg or an Hg output-based emission limit of 0.0087 lbs/GWh. Compliance with such limits shall be demonstrated on December 31, 2018, and on an annual rolling average basis thereafter. 
Low Emitters are coal-fired units emitting 29 pounds of Hg or less on an annual basis. Existing low emitter units shall be exempted from the technology-based emissions standards of the Colorado Utility Mercury Reduction Program. At the end of each calendar year, if the cumulative annual Hg mass emissions from an affected unit have exceeded 29 pounds, then the owner shall install, certify, operate, and maintain a Hg continuous emission monitoring system or a sorbent trap monitoring system no later than 180 days after the end of the calendar year in which the annual Hg mass emissions exceeded 29 pounds. For common stack and multiple stack configurations, installation and certification of a Hg concentration continuous emission monitoring system or sorbent trap monitoring system on each stack (except for bypass stacks) is likewise required within 180 days after the end of the calendar year. The Low Emitter shall also be subject to the enforceability provisions of this Rule.  New units that qualify as Low Emitters are subject to the new unit monitoring requirements adopted into Regulation No. 6, Part A.
October 2007 Rule Hg Emission Standards 
Modified Units. The Commission intends that modified units, as defined in the regulatory text, meet a 0.0174 lb/GWh or 80% removal through December of 2014 and a 0.0087 lb/GWh or 90% removal beginning in January of 2015.  
New and Reconstructed Units. The Commission intends that new and reconstructed units, as defined in the regulatory text, will meet a BAMCT standard, which may not be less stringent than the Hg output-based emission standard of 0.0087 lb/GWh or 90 percent capture of Inlet Hg on a rolling 12-month basis and shall use 95 percent capture of Inlet Hg on a rolling 12-month basis as a non-binding guideline for the associated analysis.  This guideline is not intended to restrict the Division from determining either a higher or lower standard as determined under the BACT criteria established by EPA and used for other criteria pollutants during a PSD permit action.  
BAMCT Analysis Process and Factors
The Commission intends that a BAMCT Determination is a case-by-case decision.  In Making BAMCT Determinations, the Commission expects the Division to follow a technology review that is similar to the work it undertakes in making Best Available Control Technology Determinations under the Prevention of Significant Deterioration Program.  The factors to be considered in a BAMCT analysis are contained in Section VIII.B.2.  
Alternative Emission Standard (AES)
Originally named the Best Available Mercury Control Technology Alternative Standard in the February 2007 rule, this standard was renamed with this rulemaking the Alternative Emission Standard for clarification, since conceptually this is an alternative standard and not reflective of a best available control technology standard.  
Sources that demonstrate that they are unable to meet the Hg emission standards under the Colorado Utility Mercury Reduction Program can request that the Division set an alternative, unit-specific standard. This Alternative Emission Standard (AES) provides for an alternative compliance mechanism for sources that cannot achieve the underlying standard, before and/or after installation of controls, despite their best efforts to do so. The AES provides what is referred to as a “soft landing” in the event a unit is unable to achieve the subject Hg emission standards. 
Generally the process to obtain such an AES is as follows: 1) the unit must submit a permit modification application requesting an AES, which shall include a compliance plan for achieving that alternative standard; 2) the Division will review requests for an AES and either approve or deny such request considering information provided by the applicant, the Division’s expertise and information, and after providing adequate opportunity for public input; 3) once the Division approves or disapproves the permit application, the approved AES and associated compliance plan (or the underlying base standard in the event of disapproval) shall become enforceable as to that unit. Note that the “safe harbor” or enforcement discretion provided by Section IV.D.2 is not intended to allow a unit to avoid liability by submitting multiple permit modifications.
The Commission intends that the compliance plan identify the applicable emission limitation, the process for demonstrating compliance with that emission limitation, the underlying assumptions made in determining an associated AES, and a list of activities and associated milestones in evaluating progress towards an original BAMCT standard with which the unit was not able to demonstrate compliance.  
Existing units subject to this Part B’s base emission standards (see Section VIII.C.1.) may identify their inability to meet the base emission standard either before or after the installation of Hg emission controls, and either before or after the 2010-2017 and 2018 and beyond control periods.  Modified units subject to this Part B’s New Source Performance Standards for coal-fired power plants (see Section VIII.C.3.a.) may identify their inability to meet the applicable Hg emission standard only after the installation of Hg emission controls designed to meet the applicable Hg emission standard.  New and reconstructed units subject to this Part B’s BAMCT Standard may identify their inability to meet the BAMCT Standard only after the installation of Hg emission controls designed to meet the applicable Hg emission standard.  With respect to new and reconstructed units, the Commission does not intend for an AES to provide an unqualified, perpetual “soft landing” or a mechanism to avoid compliance with applicable standards.  Specifically, if the new or reconstructed unit applies for an AES, progress towards compliance with the original BAMCT Standard must be re-evaluated with the next two operating permit renewals.  The scope of the re-evaluation is described in the regulation; it is to include such considerations as alternative sorbents for activated carbon injection systems, and other changes that do not require major capital investment at the unit.  The focus of the re-evaluation is to be on how to make the mercury control system in place operate at improved levels of performance as opposed to replacement of the system in place with another type of mercury control system.  As a result of the re-evaluations, if the Division determines that the new or reconstructed unit can meet the original BAMCT standard without requiring a major capital investment at the unit, the owner or operator shall modify its permit to include the BAMCT standard.  If the new or reconstructed unit cannot meet the original BAMCT standard without making a major capital investment at the unit, it shall either modify its permit to include the AES or a more stringent emissions limitation than the AES, if it can achieve a more stringent emissions limitation than the AES. 
For clarification, a new or reconstructed unit whose BAMCT standard is greater than 90 percent capture of Inlet Hg, may establish an AES that is less than 90 percent capture of Inlet Hg, and that AES may become the applicable standard if the unit demonstrates to the Division’s satisfaction after public notice and opportunity for comment that the unit cannot achieve compliance with the original BAMCT standard and cannot achieve compliance with an emissions limitation greater than the AES. 
Initial Compliance Date
The Commission intends that unless otherwise stated, the initial compliance date be interpreted to mean 12-months after the earlier of 60 unit operating days after achieving maximum production rate or 180 days after the unit first operates.  This interpretation is consistent with 40 CFR Part 75.  It is intended that New, Modified and Reconstructed Units subject to this rule and required to install continuous emission monitoring systems (CEMS), be allowed time to break in the associated equipment prior to having to utilize the CEMS data to demonstrate compliance.
Plant-wide Averaging
The Commission intends that plant-wide averages be determined on a capacity-weighted basis.  The following specifies how such plant-wide averages are to be determined.
Plant-wide Standard and Compliance Calculations:
Note – If a modified unit opts to comply with the AES and utilize the plant-wide averaging provisions of Section VIII.C.3.b., the numeric standard identified in Section VIII.C.3.a. shall be used to determine the plant-wide average.  New or reconstructed units cannot make use of or be included in plant-wide averaging.    
Key:
Hg Std. = Emissions Standard (%, lbs/GWh )
Alt. Std. = Alternative Emission Standard
PW Std. = Plant-wide Standard
#1,#2, #3, …  = Unit ID
GMWr = Unit Rated Output (gross MW)
GMWt = Unit Output Total (gross MW) (12-month rolling actual)
Hg Rate = lbs/GWh (12-month rolling average)
PW Hg Rate = lbs/GWh (12-month rolling average)
Plant-wide Standard determination:
Case 1 – Emission standard applies to each unit: 
PW Std. = Hg Std., unless different modification standard applies to one of the units, then;
PW Std. =    ((#1Hg Std. x #1GMWr) + (#2Hg Std. x #2GMWr) + (#3Hg Std. x #3GMWr))
(#1GMWr + #2GMWr + #3GMWr)
Case 2 – Mix of Emission standard and Alternative Emission Standard units:
PW Std. =    ((#1Hg Std. x #1GMWr ) + (#2Alt.Std. x #2GMWr ) + (#3Hg Std. x #3GMWr))
(#1GMWr + #2GMWr + #3GMWr)
Case 3 – Each unit has an alternate standard:
PW Std. =    ((#1Alt.Std. x #1GMWr) + (#2Alt.Std. x #2GMWr) + (#3Alt.Std. x #3GMWr))
(#1GMWr + #2GMWr + #3GMWr)
Plant-wide compliance determination:
PW Hg Rate. =((#1Hg Rate. x #1GMWt) + (#2Hg Rate. x #2GMWt) + (#3Hg Rate x #3GMWt))
(#1GMWt + #2GMWt + #3GMWt)
Regulation 6, Part A, Subpart HHHH state-only Provisions’ Incorporation
The state-only provisions of Regulation 6, Part A, Subpart HHHH were moved to this  Regulation 6, Part B, with all other state-only New Source Performance Standards.  Specifically, these provisions were incorporated into Regulation 6, Part B, Section VIII. and merged with this rule’s state-only New Source Performance Standards for Coal-Fired Power Plants for new, modified and reconstructed units.
Corrections
Several corrections were made as a consequence to moving Regulation 6, Part A, Subpart HHHH:
changes in citations;
changes in Subsection Titles; and
changes in Definitions Titles. 
Additional Considerations 
The Commission provides the following additional statement, consistent with §§ 25-7-110.5(5)(a) and 110.8, C.R.S. 
(I) Certain federal requirements are applicable. Colorado is required to submit a state plan for complying with the Hg new source performance standards, in accordance with Section 111(d) of the federal Clean Air Act. 
(II) The federal NSPS is performance based, as it sets forth standards of performance for coal-fired power plants. The NSPS provides flexibility to states and sources regarding how to reduce Hg emissions and otherwise meet the performance standards. 
(III) Data regarding Hg emissions and control technologies was presumably considered in the federal process leading up to the NSPS.  However, accurate data regarding actual Hg emissions and the fate and transport of such emissions (both in Colorado and nationwide) is limited and contains many uncertainties. The Commission concluded that the adopted rule will provide reductions in Colorado Hg emissions in a more appropriate and timely manner than the NSPS. 
(IV) The adopted rule will provide certainty to sources, by providing specified technology-based performance standards and clear timing requirements. 
(V) The state and federal rules have similar time frames for implementation. 
(VI) The adopted rule will assist in establishing and maintaining a reasonable margin for accommodation of uncertainty and future growth. 
(VII) The adopted rule establishes reasonable equity for sources subject to the rule by providing the same standards for similarly-situated sources. 
(VIII) If the state rule were not adopted, public health and welfare and the environment could face increased costs associated with delays in installation of appropriate Hg controls. 
(IX) There are some different monitoring requirements in the state rule provisions that are being transferred from Part A to Part B of this rule, which are necessary to demonstrate compliance with the state’s technology-based performance standard. 
(X) Demonstrated technology is available to control Hg emissions.  The rule is based upon reasonably available, validated, reviewed, and sound scientific methodologies, and the Commission has considered all information submitted by interested parties. 
(XI) The adopted rule will contribute to the prevention of pollution by reducing Hg emissions. 
(XII) A no action alternative would not address the required standard.  The Commission determined that the adopted proposal, which had consensus support amongst all parties to the rulemaking, was appropriate. 
(XIII) After consideration of all the evidence in this rulemaking, the Commission determined that the rule will result in demonstrable reduction in Hg emissions and will concurrently bring about reduced risks to human health and the environment that justify the costs to implement and comply with the rule. 
(XIV) Mere adoption of the federal NSPS may delay or avoid installation of appropriate Hg controls in Colorado, and lead to increased costs to public health and the environment. 
(XV) The Commission determined that the selected regulatory alternative will maximize the air quality benefits of regulation, including reducing Hg emissions, in the most cost-effective manner.