XV.M.1. The PAL permit shall require an owner or operator to retain a copy of all records 

necessary to determine compliance with any requirement of Section XV. of this part and 

of the PAL, including a determination of each emissions unit's twelve-month rolling total 

emissions, for five years from the date of such record. 

XV. M.2. The PAL permit shall require an owner or operator to retain a copy of the following 

records for the duration of the PAL effective period plus five years: 

XV.M.2.a. A copy of the PAL permit application and any applications for revisions to the 

PAL; and 

XV. M. 2. b. Each annual certification of compliance pursuant to Part C of this regulation, 

and the data relied on in certifying the compliance. 

XV.N. Reporting and notification requirements. 

The owner or operator shall submit semi-annual monitoring reports and prompt deviation reports 

to the Division in accordance with the requirements of the applicable Title V permit and Section 

V. C. 7. of Part C of this regulation. The reports shall meet the requirements in Sections XV. K. 11. a. 

through XV.K.11.c. below. 

XV.N.1. Semi-Annual Report. 

The semi-annual report shall be submitted to the Division within thirty days of the end of each 

reporting period. This report shall contain the information required by the Title V permit, Section 

V.C. 7.a. of Part C of this regulation, and Sections XV.N.1.a. through XV.N.1.g., below. 

XV.N.1.a. The identification of owner and operator and the permit number. 

XV.N.1.b. Total annual emissions (tons/year) based on a twelve-month rolling total for 

each month in the reporting period recorded pursuant to Section XV.K.10.a. 

XV.N.1.c. All data relied upon, including, but not limited to, any Quality Assurance or 

Quality Control data, in calculating the monthly and annual PAL pollutant 

emissions shall be made available upon request by the Division. 

XV.N.1.d. A list of any emissions units modified or added to the major stationary source 

during the preceding six-month period. 

XV.N.1.e. The number, duration, and cause of any deviations or monitoring malfunctions 

(other than the time associated with zero and span calibration checks}, and any 

corrective action taken. 

XV.N.1.f. A notification of a shutdown of any monitoring system, whether the shutdown 

was permanent or temporary, the reason for the shutdown, the anticipated date 

that the monitoring system will be fully operational or replaced with another 

monitoring system, whether the emissions unit(s) monitored by the monitoring 

system continued to operate, and calculations of emissions from those units as 

provided by Section XV. K. 7. of this part. 

XV.N.1.g. A signed statement by the responsible official (as defined in Section 1.8.40. of 

Part A of this regulation) certifying the truth, accuracy, and completeness of the 

information provided in the report. 

XV.N.2. Deviation report. 

Regulation Number 3 

Adopted: October 20, 2011 Page 183 
The major stationary source owner or operator shall promptly submit reporls of any deviations or 

exceedance of the PAL requirements, including periods where no monitoring is available. A reporl 

submitted pursuant to Section V. C. 7. b. of Pari C of this regulation shall satisfy this reponing 

requirement. The deviation reporls shall be submitted within the time limits prescribed by Section 

V.C. 7.b. of Pari C. The reporls shall contain the following information: 

XV.N.2.a. The identification of owner and operator and the permit number; 

XV.N.2.b. The PAL requirement that experienced the deviation or that was exceeded; 

XV.N.2.c. Emissions resulting from the deviation or the exceedance; and 

XV.N.2.d. A signed statement by the responsible official (as defined in Section 1.8.40. of 

Pari A of this regulation) cerlifying the truth, accuracy, and completeness of the 

information provided in the reporl. 

XV.N.3. Re-validation results 

The owner or operator shall submit to the Division the results of any revalidation test or method 

within three months after completion of such test or method. 

XV.O. If any provision of this Section, or the application of such provision to any person or circumstance, 

is held invalid, the remainder of this Section, or the application of such provision to persons or 

circumstances other than those as to which it is held invalid, shall not be affected thereby. 

PARTE RESERVED FOR ENVIRONMENTAL MANAGEMENT SYSTEMS 

Reserved for Environmental Management Systems 

PART F REGIONAL HAZE LIMITS- BEST AVAILABLE RETROFIT TECHNOLOGY (BART) 

AND REASONABLE PROGRESS (RP) 

The provisions of Section VI (Regional Haze Determinations) and VII (MRR) of Regulation 3, Part F shall 

be incorporated into Colorado's Regional Haze State Implementation Plan. All other Sections of 

Regulation 3, Part Fare State-Only. 

The provisions of Part 51, Appendix Y, Title 40, of the Code of Federal Regulations (CFR}, promulgated 

by the U.S. Environmental Protection Agency listed in this Section are hereby incorporated by reference 

by the Air Quality Control Commission and made a part of the Colorado Air Quality Control Commission 

Regulations as modified by the following Regulation Number 3, Part F. Materials incorporated by 

reference are those in existence as July 6, 2005 and do not include later amendments. The material 

incorporated by reference is available for public inspection during regular business hours at the Office of 

the Commission, located at 4300 Cherry Creek Drive South, Denver, Colorado 80246, 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. 

I. Applicability 

The provisions of this regulation apply to existing stationary facilities (BART eligible sources}, as defined in 

Section II. I. of this regulation, as well as to Reasonable Progress (RP) sources. 

II. Definitions 

II .A. Adverse impact on visibility 

Regulation Number 3 

Adopted: October 20, 2011 Page 184 
Means visibility impairment that interferes with the management, protection, preservation, or 

enjoyment of the visitor's visual experience of the Federal Class I area. This determination must 

be made on a case-by-case basis taking into account the geographic extent, intensity, duration, 

frequency and time of visibility impairments, and how these factors correlate with ( 1) times of 

visitor use of the Federal Class I area, and (2) the frequency and timing of natural conditions that 

reduce visibility. This term does not include effects on integral vistas. 

II.B. Available Technology 

Means that a technology is licensed and available through commercial sales. 

II.C. Applicable Technology 

Means a commercially available control option that has been or may soon be deployed on the 

same or a similar source type or a technology that has been used on a pollutant-bearing gas 

stream that is the same or similar to the gas stream characteristics of the source. 

II.D. Average Cost Effectiveness 

Means the total annualized costs of control divided by annual emissions reductions (the 

difference between baseline annual emissions and the estimate of emissions after controls). For 

the purposes of calculating average cost effectiveness, baseline annual emissions means a realistic 

depiction of anticipated annual emissions for the source. The source or the Division may use state or 

federally enforceable permit limits or estimate the anticipated annual emissions based upon actual 

emissions from a representative baseline period. 

II. E. BART Alternative 

Means an alternative measure to the installation, operation, and maintenance of BART that will 

achieve greater reasonable progress toward national visibility goals than would have resulted 

from the installation, operation, and maintenance of BART at BART-eligible sources within 

industry source categories subject to BART requirements. 

II. F. BART-eligible source 

Means an existing stationary facility as defined in Section 11.1. 

II. G. Best Available Retrofit Technology (BART) 

Means an emission limitation based on the degree of reduction achievable through the 

application of the best system of continuous emission reduction for each pollutant that is emitted 

by an existing stationary facility. The emission limitation must be established, on a case-by-case 

basis, taking into consideration the technology available, the costs of compliance, the energy and 

non-air quality environmental impacts of compliance, any pollution control equipment in use or in 

existence at the source or unit, the remaining useful life of the source or unit, and the degree of 

improvement in visibility which may reasonably be anticipated to result from the use of such 

technology. 

II.H. Deciview 

Means a measurement of visibility impairment. A deciview is a haze index derived from 

calculated light extinction, such that uniform changes in haziness correspond to uniform 

incremental changes in perception across the entire range of conditions, from pristine to highly 

impaired. The deciview haze index is calculated based on the following equation (for the 

Regulation Number 3 

Adopted: October 20,2011 Page 185 
purposes of calculating deciview, the atmospheric light extinction coefficient must be calculated 

from aerosol measurements): 

Deciview haze index=10 lne (bext/10 Mm-1

) 

Where bext= the atmospheric light extinction coefficient, expressed in inverse 

megameters (Mm-1

). 

II. I. Existing stationary facility 

Means any of the following stationary sources of air pollutants, including any reconstructed 

source, which was not in operation prior to August 7, 1962, and was in existence on August 7, 

1977, and has the potential to emit 250 tons per year or more of any visibility impairing air 

pollutant. In determining potential to emit, fugitive emissions, to the extent quantifiable, must be 

counted. 

11.1.1. Fossil-fuel fired steam electric plants of more than 250 million British thermal units 

(BTU) per hour heat input that generate electricity for sale 

11.1.1.a. Boiler capacities shall be aggregated to determine the heat input of a 

plant 

11.1.1.b. Includes plants that co-generate steam and electricity and combined 

cycle turbines 

11.1.2. Coal cleaning plants (thermal dryers) 

11.1.3. Kraft pulp mills 

11.1.4. Portland cement plants 

11.1.5. Primary zinc smelters 

11.1.6. Iron and steel mill plants 

11.1.7. Primary aluminum ore reduction plants 

11.1.8. Primary copper smelters 

11.1.9. Municipal incinerators capable of charging more than 250 tons of refuse per day 

11.1.1 0. Hydrofluoric, sulfuric, and nitric acid plants 

11.1.11. Petroleum refineries 

11.1.12. Lime plants 

11.1.13. Phosphate rock processing plants 

Includes all types of phosphate rock processing facilities, including elemental 

phosphorous plants as well as fertilizer production plants 

11.1.14. Coke oven batteries 

Regulation Number 3 

Adopted: October 20, 2011 Page 186 
11.1.15. Sulfur recovery plants 

11.1.16. Carbon black plants (furnace process) 

11.1.17. Primary lead smelters 

11.1.18. Fuel conversion plants 

11.1.19. Sintering plants 

11.1.20. Secondary metal production facilities 

Includes nonferrous metal facilities included within Standard Industrial Classification code 

3341, and secondary ferrous metal facilities in the category "iron and steel mill plants." 

11.1.21. Chemical process plants 

Includes those facilities within the 2-digit Standard Industrial Classification 28, including 

pharmaceutical manufacturing facilities 

11.1.22. Fossil-fuel boilers of more than 250 million BTUs per hour heat input 

11.1.22.a. Individual boilers greater than 250 million BTU/hr, considering federally 

enforceable operational limits 

11.1.22.b. Includes multi-fuel boilers that burn at least fifty percent fossil fuels 

11.1.23. Petroleum storage and transfer facilities with a capacity exceeding 300,000 barrels 

11.1.23.a. 300,000 barrels refers to total facility-wide tank capacity for tanks put in 

place after August 7, 1962 and in existence on August 7, 1977 

11.1.23.b. Includes gasoline and other petroleum-derived liquids. 

11.1.24. Taconite ore processing facilities 

11.1.25. Glass fiber processing plants 

11.1.26. Charcoal production facilities 

Includes charcoal briquette manufacturing and activated carbon production 

II.J. Incremental Cost Effectiveness 

Means the comparison of the costs and emissions performance level of a control option to those 

of the next most stringent option, as shown in the following formula: 

Incremental Cost Effectiveness (dollars per incremental ton removed)= [(Total annualized costs 

of control option) - (Total annualized costs of next control option)] + [(Next Control option annual 

emissions) - (control option annual emissions)] 

II.K. In existence 

Means that the owner or operator has obtained all necessary preconstruction approvals or 

permits required by Federal, State, or local air pollution emissions and air quality laws or 

Regulation Number 3 

Adopted: October 20, 2011 Page 187 
regulations and either has (1) begun, or caused to begin, a continuous program of physical onsite construction of the facility or (2) entered into binding agreements or contractual obligations, 

which cannot be cancelled or modified without substantial loss to the owner or operator, to 

undertake a program of construction of the facility to be completed in a reasonable time. 

II. L. In operation 

Means engaged in activity related to the primary design function of the source. 

II.M. Integral vista 

Means a view perceived from within the mandatory Class I Federal area of a specific landmark or 

panorama located outside the boundary of the mandatory Class I Federal area. 

II.N. Natural conditions 

Means naturally occurring phenomena that reduce visibility as measured in terms of light 

extinction, visual range, contrast, or coloration. 

11.0 Plant 

Means all emissions units at a stationary source. 

II.P. Visibility-Impairing Air Pollutant 

Includes the following: 

II.P.1. Sulfur dioxide (S02), 

II.P.2. Nitrogen oxides (NOx) and 

II.P.3. Particulate matter. (PM1 0 will be used as the indicator for particulate matter. 

Emissions of PM1 0 include the components of PM2.5 as a subset.). 

Ill. Sources required to Perform a BART Analysis 

Each source that the Division determines is BART-eligible and subject to BART shall complete a BART 

analysis under Section IV. The Division shall provide written notice to each source determined to be 

subject to BART. Within twenty calendar days of the mailing of such notice a source may appeal such 

determination to the Commission by filing a petition for a hearing with the Commission. Any such hearing 

shall be subject to Section 1.6.0 of the Procedural Rules. 

Ill .A. Determining Potential to Emit for a BART Source 

For the purposes of determining whether the potential to emit of an existing stationary source is 

greater than 250 tpy the potential emissions of visibility impairing pollutants from the existing 

stationary source shall include the emissions from all BART-eligible units which belong to the 

same industrial grouping, are located on one or more contiguous or adjacent properties, and are 

under the control of the same person (or persons under common control). Pollutant-emitting 

activities shall be considered as part of the same industrial grouping if they belong to the same 

Major Group (i.e., which have the same two-digit code) as described in the Standard Industrial 

Classification Manual. 

Ill. B. Identification of sources subject to BART 

Regulation Number 3 

Adopted: October 20, 2011 Page 188 
III.B.1. Identification of sources subject to BART shall be performed in accordance with 

EPA's guidelines for BART determinations under the regional haze rule 40 CFR 

Part 51, Appendix Y. A BART-eligible source described in Section liLA, above, is 

subject to BART unless valid air quality dispersion modeling demonstrates that 

the source will not cause or contribute to visibility impairment in any Class I area. 

III.B.1.a. A single source that is responsible for a 1.0 deciview change or more is 

considered to "cause" visibility impairment in any Class I area. 

III.B.1.b. A single source that is responsible for a 0.5 deciview change or more is 

considered to "contribute" visibility impairment in any Class I area. 

III.B.1.c. A single source is exempt from BART if the 981

h percentile daily change 

in visibility, as compared against natural background conditions, is less 

than 0.5 deciviews at all Class I federal areas for each year modeled and 

for the entire multi-year modeling period. 

III.B.2. The Division will perform air quality dispersion modeling for each source identified 

as BART-eligible, for all visibility impairing pollutants, for class I areas. The 

modeling results will be provided to each source. 

IV. BART Analysis 

IVA Presumptive BART for Coal Fired Power Plants 

IV.A.1. Plants with a Generating Capacity of 750 MW or Greater 

BART -eligible coal fired power plants with a generating capacity of 750 MW or 

GREATER is presumed to be able to meet the presumptive limits. Regardless of 

whether or not a unit can meet the presumptive BART limits the source must complete a 

BART analysis. 

IV.A.2. Other Coal Fired Power Plants 

The Division shall use the presumptive BART limits of section IV.A.3. as guidelines and 

may establish a BART level for the unit either above or below the presumptive BART 

level based on the BART determination. 

IV.A.3. Coal-Fired Electric Generating Units 

IV.A.3.a. Sulfur Dioxide 

Coal-Fired Electric Generating Units: 95 percent reduction or 0.15 lb 

S02/mmBTU. 

IV.A.3.b. Nitrogen Oxides 

Unit Type 

Dry bottom Wall fired 

Regulation Number 3 

Adopted: October 20,2011 

Coal Type 

Bituminous 

Sub-bituminous 

NOx limit (lb/mm BTUl 

0.39 

0.23 

Page 189 
Lignite 0.29 

Tangential Fired Bituminous 0.28 

Sub-bituminous 0.15 

Lignite 0.17 

Cell Burners Bituminous 0.40 

Sub-bituminous 0.45 

Dry-turbo-fired Bituminous 0.32 

Sub-bituminous 0.23 

Wet-bottom tangential- Bituminous 0.62 

fired 

IV. B. Each source subject to BART pursuant to Section Ill shall submit a BART application for 

a construction permit, which shall include a BART analysis, a proposal for BART at the 

source and a justification for the BART proposal to the Division by August 1, 2006. 

IV.B.1. The BART analysis must include, at a minimum: 

Regulation Number 3 

Adopted: October 20,2011 

IV.B.1.a. A list of the demonstrated and potentially applicable retrofit control 

options for the units subject to BART. Sources are not required to 

evaluate control options, which are less effective than the controls 

currently installed on the BART subject source or unit. 

IV.B.1.b. A discussion of the technical feasibility of each of the technologies 

identified in Section IV.B.1.a. This discussion should include an analysis 

of whether the proposed technology is available and applicable. If the 

source determines that a technology is not technically feasible the 

discussion shall include a factual demonstration that the option is not 

commercially available or that unusual circumstances preclude its 

application to the emission unit. 

IV. B.1.c. A ranking of all the technically feasible technologies identified in Section 

IV.B.1.b. The ranking shall take into account various emission 

performance characteristics of the technologies. The technologies 

should be ranked from lowest emissions to highest emissions for each 

pollutant and each emissions unit. The ranking should include a 

discussion of pollution control equipment in use at the unit, including 

upgrading existing equipment if technically feasible. 

IV.B.1.d. An evaluation of the impacts of the technically feasible BART 

options. The impact evaluation shall include: 

IV.B.1.d.(i). An estimate of the Average Cost Effectiveness of each of the 

control technologies identified as technically feasible in Section 

IV.B.1.b. This analysis shall specify the emissions unit being 

controlled, the design parameters for the emission controls and 

Page 190 
Regulation Number 3 

Adopted: October 20, 2011 

cost estimates based on those design parameters. The 

remaining useful life of the source or unit may be taken into 

account in the cost of the technologies. The remaining useful life 

is the difference between: (1) The date that controls will be put in 

place (capital and other construction costs incurred before 

controls are put in place can be rolled into the first year); and (2) 

The date the facility permanently stops operations. Where this 

affects the BART determination, this date should be assured by 

a federally- or State-enforceable restriction preventing further 

operation. The analysis must also include the energy and non-air 

quality environmental impacts of control options. 

IV.B.1.d.(ii). An analysis of the incremental cost effectiveness. Before a 

control technology can be eliminated the source shall evaluate 

the incremental cost effectiveness in combination with the total 

cost effectiveness in order to justify elimination of a control 

option. 

IV.B.1.d.(iii). An evaluation of the visibility impacts for each BART option 

according to modeling guidance provided by the Division. 

IV.B.1.d.(iv). An evaluation of non-air quality impacts. The non-air 

quality impacts may include water use increases, solid waste 

disposal, or other adverse environmental impacts. 

IV.B.1.d.(v). An evaluation of the energy impacts. The energy impact 

analysis should look at the energy requirements of the control 

technology and any energy penalties or benefits associated with 

the control. The analysis should also consider direct energy 

consumption and may address concerns over the use of locally 

scarce fuels or the use of locally or regionally available coal. 

IV.B.1.d.(v).(1 ). The energy impacts analysis may consider 

whether there are relative differences between 

alternatives regarding the use of locally or regionally 

available coal, and whether a given alternative would 

result in significant economic disruption or 

unemployment. 

IV.B.1.e. An evaluation and justification of the proposed averaging time to 

evaluate compliance with the proposed emission limitations. 

IV.B.1.f.Coal-fired power plants may, in their discretion, include in the BART 

analysis an evaluation of representative characteristics (including 

nitrogen content) of coal from sources they reasonably expect to use, to 

the extent such characteristics tend to result in higher NOx emissions 

than coals of the same classification from alternative sources. The 

analysis also may consider whether a particular BART limit might lead 

the power plant not to use coal from a particular mine due to such coal 

characteristics, and the extent to which such a decision might result in 

economic disruption or unemployment at the mine or in nearby 

communities. 

Page 191 
IV.B.1.g. Sources subject to a MACT standard may limit the analysis for those 

pollutants covered by the MACT to a discussion of new technologies that 

have become available since the promulgation of the MACT. 

IV.B.2. Sources with a potential to emit of less than 40 tons per year of S02 and NOx 

and less than 15 tpy of PM 1 0 may exclude those pollutants from the BART 

determination. 

IV.B.3. Selecting a best alternative 

The source shall submit a proposal for BART at the source or unit(s), including a 

justification for selecting the technology proposed. The justification shall be based on the 

following factors: (1) the technology available; (2) the costs of compliance; (3) the energy 

and non-air environmental impacts of compliance; (4) any pollution control equipment in 

use at the source or unit(s); (5) the remaining useful life of the source or unit(s) and; (6) 

the degree of improvement in visibility which may reasonably be anticipated to result from 

the use of such technology. 

IV.B.4. Schedules to comply with BART emissions limits 

IV.B.4.a. The technology analysis shall include a schedule to comply with 

BART or a BART alternative as expeditiously as practicable following 

EPA approval of the state implementation plan for regional haze that 

incorporates such BART requirements. The source must comply with 

BART or BART alternative emissions limits no later than 5 years after 

approval of the state implementation plan by EPA for regional 

haze.IV.B.4.b. A source or unit subject to BART may implement a 

BART alternative in lieu of BART if such BART alternative is authorized 

by the Division. 

IV.C. BART Alternative 

As an alternative to BART for a source or sources, the Division may approve a BART Alternative. 

If the Division approves source grouping as a BART Alternative, only sources (including BARTeligible and non-BART eligible sources) within the same source category (as defined by SIC or 

NAICS code) within the same airshed may be grouped together. 

IV.C.1. If a Source (s) proposes a BART Alternative, the resultant emissions reduction 

and visibility impacts must be compared with those that would result from the 

BART options evaluated for the source(s). 

IV.C.2. Source (s) proposing a BART alternative shall include in the BART analysis an 

analysis and justification of the averaging period and method of evaluating 

compliance with the proposed emission limitation. 

IV.D. Emission limits 

IV.D.1. Coal-Fired Electric Generating Units 

Compliance with the emission limitation is determined on a 30-day rolling average basis 

for S02 and NOx, or may be determined by the Division based on the BART analysis 

submitted by the source. The emission limit shall be included in the facility's permit. 

IV.D.2. Other Sources Subject to BART 

Regulation Number 3 

Adopted: October 20,2011 Page 192 
The Division will establish emission limits with averaging times consistent with 

established reference methods and include the limit in the facility's permit. 

IV. E. A source that has installed BART for regional haze or implemented a Division approved 

BART alternative for regional haze is exempted from the imposition of further controls 

pursuant to regional haze BART with respect to those pollutants that are controlled 

through BART or the BART alternative for Regional Haze and is exempted from the 

imposition of further controls necessary for reasonable progress during the first 

reasonable progress planning period. Sources may be subject to additional controls or 

emission reductions based on reasonable progress requirements in planning periods 

beyond the first planning period under the regional haze State Implementation Plan. 

IV. F. Divisiqn Review and Approval 

IV.F.1. The Division shall review and approve, disapprove or amend the proposed BART 

technology or BART alternative, including the emission limit, schedule for 

compliance for the facility, and averaging period. The Division shall consider 

additional information both submitted and not submitted by the source that is 

deemed relevant. The Division shall submit its BART determination to the 

Commission for review and approval. 

IV.F.2. If two or more sources are grouped together pursuant to Section IV. C. the 

Division shall establish recordkeeping and reporting requirements sufficient to 

determine that the sources meet the BART alternative emission limits. 

IV.F.3. Any source seeking to modify the BART determination for that facility must 

submit a new BART analysis for review by the Division. 

V. Challenge of Division BART Determinations and Enforceable Agreements. 

V.A. Persons affected or aggrieved by a BART determination may challenge the decision of the 

Commission pursuant to Article 4 of Title 24, C.R.S. 

VI. Regional Haze Determinations 

VIA BART Determinations 

VI. A.1. The provisions of this Section VI.A of Regulation Number 3, Part F shall be incorporated 

into Colorado's Regional Haze State Implementation Plan. 

VI.A.2. The sources listed below shall not emit or cause to be emitted nitrogen oxides (NOx), 

sulfur dioxide (S02), or particulate in excess of the following limits: 

BART Determinations for Colorado Sources 

Unit NOx Emission Limit 

Regulation Number 3 

Adopted: October 20, 2011 

S02 Emission Limit Particulate 

Emission 

Limit 

Page 193 
CENC Unit4 0.37 lb/MMBtu (30-day rolling average) 1.0 lb/MMBtu 0.07 lb/MMBtu 

or (30-day rolling average) 

0.26 lb/MMBtu Combined Average for Units 

4 and 5 (30-day rolling average) 

CENC Unit 5 0.19 lb/MMBtu (30-day rolling average) 1.01b/MMBtu 0.07 lb/MMBtu 

or (30-day rolling average) 

0.26 lb/MMBtu Combined Average for Units 

4 and 5 (30-day rolling average) 

Craig Unit 1 0.28 lb/MMBtu 0.11 lb/MMBtu 0.03 lb/MMBtu 

(30-day rolling average) (30-day rolling average) 

Craig Unit 2 0.08 lb/MMBtu 0.11 lb/MMBtu 0.03 lb/MMBtu 

(30-day rolling average)* (30-day rolling average) 

*The NOx emission limits for Craig Units 1 and 2 constitute a BART Alternative. 

Unit NOx Emission Limit 

Comanche 0.20 lb/MMBtu 

Unit 1 

(30-day rolling average) 

0.151b/MMBtu 

(combined annual average for units 1 & 2) 

Comanche 0.20 lb/MMBtu 

Unit 2 

(30-day rolling average) 

0.15 lb/MMBtu 

(combined annual average for units 1 & 2) 

Regulation Number 3 

Adopted: October 20, 2011 

502 Emission Limit Particulate 

Emission 

Limit 

0.12 lb/MMBtu 0.03 lb/MMBtu 

(individual unit 30-day 

rolling average) 

0.10 lb/MMBtu 

(combined annual average 

for units 1 & 2) 

0.12 lb/MMBtu 0.03 lb/MMBtu 

(individual unit 30-day 

rolling average) 

0.1 0 lb/MM Btu 

(combined annual average 

for units 1 & 2) 

Page 194 
Hayden Unit 1 0.081b/MMBtu 0.13 lb/MMBtu 0.03 lb/MMBtu 

(30-day rolling average) (30-day rolling average) 

Hayden Unit 2 0.07 lb/MMBtu 0.13 lb/MM Btu 0.03 lb/MMBtu 

(30-day rolling average) (30-day rolling average) 

Martin Drake 0.31 lb/MMBtu 0.26 lb/MMBtu 0.03 lb/MMBtu 

Unit 5 

(30-day rolling average) (30-day rolling average) 

Martin Drake 0.311b/MMBtu 0.131b/MMBtu 0.03 lb/MMBtu 

Unit6 

(30-day rolling average) (30-day rolling average) 

Martin Drake 0.29 lb/MMBtu 0.131b/MMBtu 0.03 lb/MMBtu 

Unit 7 

(30-day rolling average) (30-day rolling average) 

CEMEX- 255.3 lbs/hr 25.3 lbs/hr 0.275 lb/ton of 

Lyons Kiln dry feed 20% 

(30-day rolling average) (12-month rolling average) opacity 

901.0 tons/year 95.0 tons/yr 

(12-month rolling average) (12-month rolling average) 

CEMEX- 13.9 tons/yr 36.7 tons/yr 22.8 tons/yr 

Lyons Dryer 

10% opacity 

VI.A.3. Each source listed in the above tables must comply with the above limits and averaging 

times as expeditiously as practicable, but in no event later than five years after EPA 

approval of Colorado's state implementation plan for regional haze, or relevant 

component thereof. Each source listed in the above tables must maintain control 

equipment or operational practices required to comply with the above limits and 

averaging times, and establish procedures to ensure that such equipment or operational 

practices are properly operated and maintained. 

Regulation Number 3 

Adopted: October 20,2011 Page 195 
VI.A.4. The sources shall submit to the Division a proposed compliance schedule within sixty 

days after EPA approves the BART portion of the Regional Haze SIP. The Division shall 

publish these proposed schedules and provide for a thirty-day public comment period 

following publication. The Division shall publish its final determinations regarding the 

proposed schedules for compliance within sixty days after the close of the public 

comment period and will respond to all public comments received. 

VI.B. Reasonable Progress Determinations 

VI.B.1. The provisions of this Section VI.B of Regulation Number 3, Part F shall be incorporated 

into Colorado's Regional Haze State Implementation Plan. 

VI.B.2. The sources listed below shall not emit or cause to be emitted nitrogen oxides (NOx), 

sulfur dioxide (S02), or particulate in excess of the following limits: 

RP Determinations for Colorado Sources 

Emission Unit 

Rawhide 

Unit 101 

CENC 

Unit 3 

Nixon 

Clark 

Units 1 & 2 

Shutdown 

12/31/2013 

Holcim - Florence 

Kiln 

Nucla 

Regulation Number 3 

Adopted: October 20,2011 

NOx Emission Limit 

0.145 lb/MMBtu 

(30-day rolling average) 

246 tons per year 

(12-month rolling total) 

0.21 lb/MMBtu 

(30-day rolling average) 

Shutdown 12/31/2013 

2.73 lbs/ton clinker 

(30-day rolling average) 

2,086.8 tons/year 

0.5 lb/MMBtu 

(30-day rolling average) 

502 Emission Limit Particulate Emission 

Limit 

0.11 lb/MMBtu 0.03 lb/MMBtu 

(30-day rolling average) 

1.2 lb/MMBtu 0.07 lb/MMBtu 

0.11 lb/MMBtu 0.03 lb/MMBtu 

(30-day rolling average) 

Shutdown 12/31/2013 Shutdown 12/31/2013 

1.30 lbs/ton clinker 246.3 tons/year 

(30-day rolling average) 

721.4 tons/year 

0.4 lb/MMBtu 0.03 lb/MMBtu 

(30-day rolling average) 

Page 196 
RP Determinations for Colorado Sources 

Emission Unit NOx Emission Limit ' S02 Emission Limit Particulate Emission 

Limit 

Craig 0.28 lb/MMBtu 0.15 lb/MMBtu 0.013 lb/MMBtu filterable 

PM 

Unit 3 (30-day rolling average) (30-day rolling average) 

0.012 lb/MMBtu filterable 

PM10 

Cameo Shutdown 12/31/2011 Shutdown 12/31/2011 Shutdown 12/31/2011 

Shutdown 

12/31/2011 

VI.B.3. Each source listed in the above table must comply with the above limits and averaging 

times as expeditiously as practicable, but in no event later than December 31, 2017. 

Each source listed in the above table must maintain control equipment or operational 

practices required to comply with the above limits and averaging times, and establish 

procedures to ensure that such equipment or operational practices are properly operated 

and maintained. 

VI.B.4. The sources shall submit to the Division a proposed compliance schedule within sixty 

days after EPA approves the RP portion of the Regional Haze SIP. The Division shall 

publish these proposed schedules and provide for a thirty-day public comment period 

following publication. The Division shall publish its final determinations regarding the 

proposed schedules for compliance within sixty days after the close of the public 

comment period and will respond to all public comments received. 

VI. C. Public Service Company of Colorado (PSCo) BART Alternative Program 

VI.C.1. The provisions of this Section VI.C of Regulation Number 3, Part F (with the exception of 

the S02 cap of subsection VI.C.4) shall be incorporated into Colorado's Regional Haze 

State Implementation Plan. 

VI.C.2. The sources listed below shall not emit or cause to be emitted nitrogen oxides (NOx), 

sulfur dioxide (S02), or particulate in excess of the following limits, after the following 

compliance dates: 

BART Alternative Program Determinations for PSCo Sources 

Emission Unit 

Regulation Number 3 

Adopted: October 20,2011 

NOx Emission Limit S02 Emission Limit Particulate Emission 

Limit 

Page 197 
Cherokee* 

Unit 1 

Shutdown No later than 

7/1/2012 

Cherokee 

Unit 2 

Shutdown 12/31/2011 

Cherokee 

Unit 3 

Shutdown No later than 

12/31/2016 

Cherokee 

Unit4 

Valmont 

Unit 5 

Shutdown 12/31/2017 

Pawnee 

Arapahoe** 

Unit 3 

Shutdown 12/31/2013 

Regulation Number 3 

Adopted: October 20, 2011 

0 

Shutdown No later than 

7/1/2012 

0 

Shutdown 12/31/2011 

0 

Shutdown No later than 

12/31/2016 

0.12 lb/MMBTU 

(30-day rolling average) by 

12/31/2017 

Natural Gas Operation 

12/31/2017 

0 

Shutdown 12/31/2017 

0.07 lb/MMBTU 

(30-day rolling average) by 

12/31/2014 

0 

Shutdown 12/31/2013 

0 0 

Shutdown No later than Shutdown No later 

7/1/2012 than 7/1/2012 

0 0 

Shutdown 12/31/2011 Shutdown 12/31/2011 

0 0 

Shutdown No later than Shutdown No later 

12/31/2016 than 12/31/2016 

7.81 tpy 0.03 lbs/MMBtu 

(rolling 12 month Natural Gas Operation 

average) 12/31/2017 

Natural Gas Operation 

12/31/2017 

0 0 

Shutdown 12/31/2017 Shutdown 12/31/2017 

0.12 lbs/MMBtu 0.03 lbs/MMBtu 

(30-day rolling average) 

by 12/31/2014 

0 0 

Shutdown 12/31/2013 Shutdown 12/31/2013 

Page 198 
Arapahoe 600 tpy on 1.28 tpy 0.03 lbs/MMBtu 

Unit4 (rolling 12 month average) (rolling 12 month Natural Gas operation 

average) 12/31/2014 

Natural Gas 

operation 12/31/2014 Natural Gas operation 

12/31/2014 

* 500 tpy NOx will be reserved from Cherokee Station for netting or offsets 

** 300 tpy NOx will be reserved from Arapahoe Station for netting or offsets for additional natural gas 

generation 

VI.C.3. Each source listed in the above table must either shut down or comply with the above 

limits and averaging times no later than the compliance date set forth in the above table. 

Each source listed in the above table must maintain any applicable control equipment 

required to comply with the above limits and averaging times, and establish procedures 

to ensure that such equipment is properly operated and maintained. 

VI.C.4. In addition to the above listed emission limits and compliance dates, between 1/1/2013 

and 12/31/2015, Cherokee Units 3 and 4 and Valmont, considered as a whole, shall not 

emit in excess of 4,200 tons of S02 per year as determined on a calendar year annual 

basis. Between 1/1/2016 and 12/31/2017 Cherokee Unit 4 and Valmont considered as a 

whole, shall not emit in excess of 3,450 tons of S02 per year as determined on a 

calendar year annual basis. 

VII. Monitoring, Recordkeeping, and Reporting for Regional Haze Limits 

The provisions of this Section VII of Regulation 3, Part F shall be incorporated into Colorado's Regional 

Haze State Implementation Plan. 

Federal Regulations Adopted by Reference 

The following regulations promulgated by the United States Environmental Protection Agency (EPA) were 

previously adopted by the Colorado Air Quality Control Commission and are thereby already incorporated 

by reference: 

40 CFR Part 60 and Appendices (As incorporated by reference within Commission Regulation 

Number 6, 5 CCR 1 001-8) 

40 CFR Part 63, Subpart A - National Emission Standards for Hazardous Air Pollutants General 

Provisions and Subpart LLL - National Emission Standards for Hazardous Air Pollutants From the 

Portland Cement Manufacturing Industry (As incorporated by reference within Commission 

Regulation Number 8, Part A, 5 CCR 1001-10). 

40 CFR Part 64 (As incorporated by reference within Commission Regulation Number 3, Part C 

Section XIV., 5 CCR 1001-5) 

40 CFR Part 75 including Performance Specifications and Appendices (As incorporated by 

reference within Commission Regulation Number 6, 5 CCR 1 001-8) 

VII.A. Definitions 

Regulation Number 3 

Adopted: October 20, 2011 Page 199 
VII.A.1. "BART alternative program unit" means any unit subject to a Regional Haze emission 

limit contained in the Table in Regulation Number 3, Part F, Section VI. C. 

VII.A.2. "BART unit" means any unit subject to a Regional Haze emission limit contained in the 

Table in Regulation Number 3, Part F, Section VI .A. 

VII.A.3. "Continuous emission monitoring system" or "GEMS" means the equipment required by 

Regulation Number 3, Part F, Section VII, to sample, analyze, measure, and provide 

(using an automated data acquisition and handling system (DAHS)), a permanent record 

of S02 or NOx emissions, other pollutant emissions, diluent, or stack gas volumetric flow 

rate. 

VII.A.4. "Operating day" means any twenty-four-hour period between midnight and the following 

midnight during which any fuel is combusted at any time in a BART unit, BART 

alternative program unit, or Reasonable Progress unit. 

VII.A.5. "Reasonable Progress unit" or "RP unit" means any unit subject to a Regional Haze 

emission limit contained in the Table in Regulation Number 3, Part F, Section VI. B. 

VII.A.6. "Regional Haze emission limit" means any of the emission limits specified in the Tables 

contained in Regulation Number 3, Part F, Section VI. 

VII.B. Monitoring/Compliance Determination: S02 and NOx Regional Haze Limits 

VII.B.1. BART, RP, and BART alternative program units with S02 and NOx GEMS. 

VII. B.1.a. All Boilers, except CENC and Clark boilers. 

The owner or operator of a boiler subject to this section shall comply with the Part 75 

monitoring and recordkeeping requirements as incorporated by reference into this 

regulation with the exception of the continuous emission monitoring system (GEMS} data 

substitution and bias adjustment requirements. 

At all times after the compliance deadline specified in Regulation Number 3, Part F, 

Section VI.A.3., VI.B.3. or VI.C.3., the owner/operator of each BART, RP, or BART 

alternative program unit shall maintain, calibrate, and operate a GEMS, in full compliance 

with the requirements found at 40 CFR Part 75 not excluded above, to accurately 

measure from such unit S02, NOx, diluent, and stack gas volumetric flow rate as such 

parameters are relevant to the applicable emission limit. The GEMS shall be used to 

determine compliance with the S02 and NOx Regional Haze emission limits for each 

such unit. Such limits are expressed in units of pounds per million Btu. The 

owner/operator shall calculate emissions in the applicable units. 

In determining compliance with the S02 and NOx Regional Haze limits, all periods of 

emissions shall be included, including startups, shutdowns, emergencies, and 

malfunctions. 

Regulation Number 3 

Adopted: October 20, 2011 

VII.B.1.a.(i}. Pounds Per Million Btu Regional Haze Limits 

For any hour in which fuel is combusted in the BART, RP, or BART alternative 

program unit, owner/operator shall calculate hourly average S02 and NOx 

concentrations in pounds per million Btu at the GEMS in accordance with the 

requirements of 40 CFR Part 75 except for Part 75 requirements excluded by 

Section VII. B.1.a. These hourly averages shall then be used to determine 

compliance in accordance with the particular limit's averaging period, as follows: 

Page 200 
Regulation Number 3 

Adopted: October 20,2011 

VII.B.1.a.(i).(1 ). Regional Haze limits with a 3-hour averaging period: 

Emissions shall be calculated on a 3-hour rolling average basis. 

At the end of each operating hour, the owner/operator shall 

calculate and record a new 3-hour average emission rate in 

lb/MMBtu from the arithmetic average of the valid hourly 

emission rates from the CEMS for the previous three operating 

hours. (An operating hour is any hour in which fuel is combusted 

for any time in the unit.) 

VII. B.1.a.(i).(2). Regional Haze limits with a 30-day averaging period: 

Before the end of each operating day, the owner/operator shall 

calculate and record the 30-day rolling average emission rate in 

lb/MMBtu from all valid hourly emission values from the CEMS 

for the previous 30 operating days. 

VII.B.1.a.(i).(3). Regional Haze limits with a 90-day averaging period: 

Before the end of each operating day, the owner/operator shall 

calculate and record the 90-day rolling average emission rate in 

lb/MMBtu from all valid hourly emission values from the CEMS 

for the previous 90 operating days. 

VII.B.1.a.(i).(4). Regional Haze limits with a 12-month averaging period: 

Before the end of each month, the owner/operator shall calculate 

and record the 12-month rolling average emission rate in 

lb/MMBtu from all valid hourly emission values from the CEMS 

for the previous 12 months. 

VII.B.1.a.(i).(5). Regional Haze limits with an annual calendar averaging 

period: Emissions shall be calculated on a calendar year basis. 

Within 30 days after the end of each calendar year, the 

owner/operator shall calculate and record a new emission rate in 

lb/MMBtu from the arithmetic average of all valid hourly emission 

rates from the CEMS for the preceding year. 

VII. B.1.a.(i).(6). Comanche Units 1 and 2 Regional Haze combined 

annual average limits. The combined annual limitations for NOX 

and S02 are on a 365-operating day rolling average. Before the 

end of each operating day, the owner/operator shall calculate 

and record an annual rolling average using data from the 

previous 365 operating days in accordance with the following 

equation. 

Combined emission rate (lb/MMBtu) = [(ER1)(HI1) + (ER2)(HI2)]/(HI1 + Hl2) 

Where: ER1 =average emission rate over the 365 operating day period. This is 

an average of all valid hours within the 365 operating day period for Unit 1. 

Hl1 =total heat input over the 365 operating day period for Unit 1. 

ER2 = average emission rate over the 365 operating day period. This is an 

average of all valid hours within the 365 operating day period for Unit 2. 

Hl2 =total heat input over the 365 operating day period for Unit 2. 

Page 201 
VII. B.1. b. Portland Cement Kilns and CENC and Clark Boilers: At all times after the 

compliance deadline specified in Regulation Number 3, Part F, Section VI.A.3., 

or VI.B.3., the owner/operator of each BART or RP unit shall maintain, calibrate 

and operate a CEMS in full compliance with the requirements in 40 CFR Part 60 

Section 60.13 and Part 60 Appendices A, B and F to accurately measure S02, 

NOX and diluent, if diluent is required. The CEMS shall be used to determine 

compliance with the S02 and NOX Regional Haze emission limits for each such 

unit. For particular units, such limits are expressed in units of pounds per hour, 

tons per year, pounds per ton clinker or pounds per million Btu. The 

owner/operator shall calculate emissions in the applicable units. In determining 

compliance with the S02 and NOX Regional Haze limits, all periods of emissions 

shall be included, including startups, shutdowns, emergencies and malfunctions. 

Regulation Number 3 

Adopted: October 20, 2011 

VII.B.1.b.(i). Pounds per Hour and Tons per Year Regional Haze Limits and 

Pounds per Million Btu Regional Haze Limits. 

For any hour in which fuel is combusted in the BART or RP unit, the 

owner/operator shall calculate hourly NOx and S02 emissions in the appropriate 

units (lbs/hr) or (lbs/MMbtu) in accordance with the provisions in 40 CFR Part 60. 

These hourly values shall be used to determine compliance in accordance with 

the particular limits averaging time, as follows: 

VII.B.1.b.(i).(1). Pounds per Hour or Pounds per Million Btu Regional 

Haze Limits on a 30-day rolling average, Before the end of each 

operating day, the owner/operator shall calculate and record the 

30-day rolling average emission rate in lb/MMBtu or lb/hr from all 

valid hourly emission values from the CEMS for the previous 30 

operating days. 

VII.B.1.b.i.(2). Pounds per Hour on a 12-month rolling average. Before 

the end of each month, the owner/operator shall calculate and 

record the 12-month rolling average emission rate in lb/hr from 

all valid hourly emission values from the CEMS for the previous 

12 months. 

VII.B.1.b.i.(3). Tons per year Regional Haze Limits on a 12-month rolling 

average. Before the end of each month, the owner/operator shall 

calculate and record the total emissions in tons/yr from all valid 

hourly emission values from the CEMS for the previous 12 

months. 

VII.B.1.b.(ii). 30-Day Rolling Average Pounds per Ton Clinker Regional Haze 

Limits . Hourly clinker production shall be determined in accordance with 

the requirements in 40 CFR Part 60 Subpart F Section 60.63(b). An 

operating day includes all valid data obtained in any daily 24-hour period 

during which the kiln operates and excludes any measurements made 

during the daily 24-hour period when the kiln was not operating. The 3Doperating day rolling emission rate of NOX and SOx shall be calculated 

and recorded as the total of all hourly emissions data for a cement kiln in 

the preceding 30 operating days, divided by the total tons of clinker 

produced in that kiln during the same 30-day operating period in 

accordance with the equation in 40 CFR Part 60 Subpart F Section 

60.64(c). 

VII.B.1.b.(iii). CENC Units 4 and 5 NOX Regional Haze limits: 

Page 202 
For any hour in which fuel is combusted in CENC Unit 4 or Unit 5, the 

owner/operator shall calculate hourly NOX emissions in the appropriate units 

(lbs/MMbtu) in accordance with the provisions in 40 CFR Part 60. These hourly 

values shall be used to determine compliance with the Regional Haze limits, as 

follows: 

VII.B.1.b.(iii).(1 ). Individual unit pound per Million Btu on a 30-day rolling 

average Regional Haze Limit: Before the end of each operating 

day, the owner/operator shall calculate and record the 30-day 

rolling average emission rate in lb/MMBtu from all valid hourly 

emission values from the CEMS for the previous 30 operating 

days, OR 

VII.B.1.b.(iii).(2). Combined units 4 and 5 lbs/MMbtu 30-day rolling 

average Regional Haze Limit: Before the end of each operating 

day, the owner/operator shall calculate and record a 30-day 

rolling average using data from the previous 30 operating days in 

accordance with the following equation: 

Average ER = [(ER4)(HI4)+(ER5)(HI5)] I [(HI4)+(HI5)] 

Where: 

ER4 = average NOX emission rate, in pounds per MMbtu over the 30 

day period. This is an average of all valid hours within the 30 operating 

day period for Unit 4. 

ER5 = average NOX emission rate, in pounds per MMbtu over the 30 

day period. This is an average of all valid hours within the 30 operating 

day period for ~nit 5. 

Hl4 = Total heat input over the 30 operating day period for Unit 4. 

HIS = Total heat input over the 30 operating day period for Unit 5. 

VII.B.1.b.(iii).(3). The owner or operator shall indicate in the excess 

emission reports required by Section VII.E of this Part F, which 

compliance demonstration method has been followed for the 

reporting period. 

VII.B.2. BART and RP Units without NOX and S02 CEMS. 

VII.B.2.a. CENC Unit 3. Compliance with the S02 limitations shall be determined 

Regulation Number 3 

Adopted: October 20, 2011 

by sampling and analyzing each shipment of coal for the sulfur and heat content 

using the appropriate ASTM Methods. In lieu of sampling, vendor receipts may 

be used provided the sampling and analysis was conducted in accordance with 

the appropriate ASTM Method. Each sample or vendor receipt must indicate 

compliance with the S02 limitation. Compliance with the annual NOx limits shall 

be monitored by recording fuel consumption and calculating emissions monthly 

using the appropriate AP-42 emission factor. Monthly emissions shall be 

calculated by the end of the subsequent month and shall be used in a rolling 

twelve month total to monitor compliance with the annual limitations. Each month 

a new twelve month total shall be calculated using the previous 12 months data. 

[*Note: CENC Unit 3 is not subject to annual S02 limits.] 

Page 203 
VII.B.2.b. CEMEX Dryer. Unless performance tests were completed within the 

previous 6 months, within 60 days of the compliance deadline specified in 

Regulation Number3, Part F Section VI.A.3, the owner/operator shall conduct a 

stack test to measure NOX and S02 emissions in accordance with the 

appropriate EPA test methods. Frequency of testing thereafter shall be every 

five years. Each test shall consist of three test runs, with each run at least 60 

minutes in duration. 

In addition to the stack tests described above, compliance with the annual NOx and S02 

limits shall be monitored by calculating emissions monthly using the emission factors (in 

lb/hr) determined from the most recent Division-approved stack test and hours of 

operation for the month. Monthly emissions shall be calculated by the end of the 

subsequent month and used in a twelve month rolling total to monitor compliance with the 

annual limitations. Each month a new twelve month total shall be calculated using the 

previous 12 months' data. 

VII.C. Monitoring/Compliance Determination: Particulate Regional Haze Limits 

VII.C.1. Particulate Regional Haze Limits for all boilers except CENC and Clark boilers 

Unless particulate compliance testing was completed within the previous 6 months, within 60 

days of the compliance deadline specified in Regulation Number 3, Part F, Section VI.A.3., 

VI.B.3., or VI.C.3., the owner/operator shall conduct a stack test to measure particulate emissions 

in accordance with the requirements and procedures set forth in EPA Test Method 5 as set forth 

in 40 CFR Part 60, Appendix A. Stack testing for particulate matter shall be performed annually, 

except that: (1) if any test results indicate emissions are less than or equal to 50% of the emission 

limit, another test is required within five years; (2) if any test results indicate emissions are more 

than 50%, but less than or equal to 75% of the emission limit, another test is required within three 

years; and (3) if any test results indicate emissions are greater than 75% of the emission limit, an 

annual test is required until the provisions of (1) or (2) are met. A test run shall consist of three 

test runs, with each run at least 120 minutes in duration. Test results shall be converted to the 

applicable units and compliance will the based on the average of the three test runs. 

In addition, to the stack tests described above, the owner/operator shall monitor compliance with 

the particulate matter limits in accordance with the applicable compliance assurance monitoring 

plan developed and approved in accordance with 40 CFR Part 64. 

VII.C.2. Portland Cement Plant Particulate Regional Haze Limits. 

VII.C.2.a. Kilns. Compliance with the particulate matter limitations shall be 

monitored using a PM CEMS that meets the requirements in 40 CFR Part 63 

Subpart LLL. The owner or operator shall calculate emissions in the applicable 

units. If a PM CEMS is used to monitor compliance with the PM limits, the opacity 

limits specified in this Part F do not apply. 

In the event that the provisions in 40 CFR Part 63 Subpart LLL are revised, stayed or 

vacated, such that a PM CEMS is not required, compliance with the PM limitations shall 

be monitored by conducting stack tests in accordance with the requirements of Section 

VII.C.3. except that the results of the test shall be converted to the appropriate units 

(lb/ton clinker or lb/ton dry feed) and compliance will be based on the average of three 

test runs. 

In addition, if no PM CEMS is required, as discussed in the above paragraph, the opacity 

limits specified in this Part F do apply. In order to monitor compliance with the opacity 

limit, the owner or operator shall install, calibrate, maintain, and continuously operate a 

Regulation Number 3 

Adopted: October 20,2011 Page204 
COM located at the outlet of the PM control device to continuously monitor opacity. The 

COM shall be installed, maintained, calibrated, and operated as required by 40 CFR Part 

63, Subpart A, and according to PS-1 of 40 CFR Part 60, Appendix 8 

VII.C.2.b. Dryers. Performance tests shall be conducted in accordance with the 

requirements in Section VII.C.3. Opacity monitoring shall be conducted in 

accordance with the requirements in 40 CFR Part 63 Subpart LLL. 

VII.C.3. Particulate Regional Haze Limits for the CENC and Clark boilers and the CEMEX dryer. 

Within 60 days of the compliance deadline specified in Regulation Number 3, Part F, 

Section VI.A.3. or VI.B.3., the owner/operator shall conduct a stack test to measure 

particulate emissions in accordance with the requirements and procedures set forth in 

EPA Test Method 5, 58, 50 or 17, as appropriate, as set forth in 40 CFR Part 60, 

Appendix A. Stack testing for particulate matter shall be performed annually, except that: 

( 1) if any test results indicate emissions are less than or equal to 50% of the emission 

limit, another test is required within five years; (2) if any test results indicate emissions 

are more than 50%, but less than or equal to 75% of the emission limit, another test is 

required within three years; and (3) if any test results indicate emissions are greater than 

75% of the emission limit, an annual test is required until the provisions of (1) or (2) are 

met. Each test shall consist of three test runs, with each run at least 60 minutes in 

duration. 

In addition, to the stack tests described above, compliance with the annual limitations (ton/yr 

limits) applicable to the Clark boilers and CEMEX dryer shall be monitored by calculating 

emissions monthly using the emission factors (in lb/hr) determined from the most recent Divisionapproved stack test and hours of operation for the month. Monthly emissions shall be calculated 

by the end of the subsequent month and used in a twelve month rolling total to monitor 

compliance with the annual limitations. Each month a new twelve month total shall be calculated 

using the previous 12 months' data. 

In addition to the stack tests described above, the owner/operator shall monitor compliance with 

the particulate matter limits in accordance with the applicable compliance assurance monitoring 

plan developed and approved in accordance with 40 CFR Part 64. 

VII.D. Recordkeeping 

Owner/operator shall maintain the following records for at least five years: 

VII.D.1. All CEMS data as required in the applicable regulation, stack test data, and data 

collected pursuant to the CAM plan, including the date, place, and time of sampling, 

measurement, or testing; parameters sampled, measured, or tested and results; the 

company, entity, or person that performed the testing, if applicable; and any field data 

sheets from testing. 

VII.D.2. Records of quality assurance and quality control activities for emissions measuring 

systems including, but not limited to, any records required by 40 CFR Part 60, 63, or 75. 

VII.D.3. Any other records required by 40 CFR parts 60, Subpart F, Section 60.65, 63, Subpart 

LLL, 64 or 75. 

VILE. Reporting requirements 

The owner/operator of a BART, RP or BART alternative program unit shall submit semi-annual excess 

emissions reports no later than the 30th day following the end of each semi-annual period unless more 

frequent reporting is required. Excess emissions means emissions that exceed the Regional Haze 

Regulation Number 3 

Adopted: October 20,2011 Page 205 
emissions limits. Excess emission reports shall include the information specified in 40 CFR Part 60, 

Section 60.7(c). 

The owner/operator of a BART, RP or BART alternative program unit shall submit reports of any required 

performance stack tests for particulate matter, to the Division within 60 calendar days after completion of 

the test. 

The owner/operator shall also submit semi-annual reports of any excursions under the approved 

compliance assurance monitoring plan in accordance with the schedule specified in the source's 

Title V permit. 

PARTG STATEMENTS OF BASIS, SPECIFIC STATUTORY AUTHORITY AND PURPOSE 

I.A. Adopted June 5, 1980 

Rational and Justification for the Repeal and Repromulgation of Regulation Number 3 and 

Common Provisions Regulation as Related to Regulation Number 3 

On December 14, 1978, the Air Quality Control Commission revised Regulation Number 3 (concerning 

requirements for filing air pollution emission notices, obtaining emission permits, and payment of fees with 

respect to both) for the primary purpose of bringing Colorado's air pollutant emission permit program into 

conformity with the requirements of the Federal Clean Air Act Amendments of 1977 to the extent 

authorized by the then effective State statutory authority: "The Air Pollution Control Act of 1970, "C.R.S. 

1973, 25-7-101 et seq. The regulation as revised in 1978 and which became effective January 30, 1972, 

was submitted to the U.S. Environmental Protection Agency as a revision to the state Implementation 

Plan ("SIP") pursuant to Subsection 129(c) of the Federal Clean Air Act Amendments of 1977. 

Since that submittal, the Colorado General Assembly has repealed and reenacted the State's basic air 

pollution control statute: Article 7 of Title 25, Colorado Revised Statutes, 1973. The new article, known as 

the "Colorado Air Quality Control Act" (designated House Bill 1109 in the 1979 legislative session), 

became effective June 20, 1979, and largely brought the State statute into conformity with the Federal 

legislation, mandating the Commission to develop a comprehensive air pollution control program meeting 

the requirements of the Federal Clean Air Act. 

Revisions also respond to the requirements set forth in the October 5, 1979 Federal Register notice which 

conditionally approved portions of the Colorado SIP and set forth certain requirements for securing their 

unconditional approval. E.G., see Section IV.D.2.a.(iv) of revised Regulation Number 3, which 

incorporates the requirements of Section 172(b)(II)(A) of the Clean Air Act. 44 Fed. Reg. 57401, 57408 

(1979). 

The Commission has made an effort to formulate a permit program meeting the requirement of and 

paralleling of the provisions EPA policies and rules to the extent authorized by House Bill1109 and to the 

extent deemed appropriate by the Commission for Colorado's particular circumstances. This has been 

done in order to meet certain specific requirements expressly set forth in the Federal Clean Air Act, to 

meet certain specific requirements EPA has determined are required for compliance with the Federal Act, 

and to avoid subjecting sources of air pollution in Colorado to differing State and Federal requirements. 

The Commission considered the assurance of reasonable further progress toward attainment of National 

Ambient Air Quality Standards as the primary underlying criterion in developing permit requirements for 

sources located in or near nonattainment areas. 

Consideration has also been given to the opinion of the United States Court of appeals for the District of 

Columbia in the case of Alabama Power Company v. Castle F.2d (D.C. Cir., 1979). 

APENs 

Regulation Number 3 

Adopted: October 20,2011 Page 206 
In order to reduce the administrative burden on both the Air Pollution Control Division ("the Division") and 

owners and operators of air pollution sources, the filing of revised air pollution emission notices for the 

purpose of reporting significant changes in emissions will be required only on an annual basis, rather than 

whenever a significant change in emissions occurs. In making this revision, the Commission relied on the 

representations of the Division that annual reporting would be sufficient for purposes of keeping the 

emissions inventory current. 

Street Sanding 

With the exception of street sanding (and indirect sources), the exemptions provided in the revised 

regulation from the APEN-filing and emission permit requirements are for minor or insignificant sources of 

emissions. 

Although not finding that particulate emissions resulting from the application and re-entrainment of "sand" 

applied to snow or ice covered roadways as a traffic safety measure are insignificant, the Commission 

has exempted sanding from the APEN-filing and permit requirements out of administrative necessity. 

Little benefit can be obtained from the filing of APENs in light of the fact that the amount of emissions 

cannot be predicted with any reasonable accuracy due to varying factors such as weather. APENs would 

therefore serve little purpose as notices of expected emissions. 

It is the judgment of the Commission that protection of persons and property by sanding snow and ice 

covered roadways is an overriding consideration and that the costs of not taking such safety measures 

would far outweigh any air quality benefits resulting from requiring permits for sanding. Sanding should 

not therefore be prohibited --even without a permit. The only reason for imposing a permit requirement 

would be to facilitate enforcement of control measures to limit emissions, which the Commission believes 

may be accomplished without a permit requirement through emission control regulations and provisions in 

local elements of the State Implementation Plan. 

Major Source, Major Modifications. and the "bubble" Concept 

The Commission has retained requirements that new "major sources" locating in nonattainment areas 

and "major modifications" to existing sources in nonattainment areas meet special requirements (Offsets, 

LAER, etc.) designed to allow for continued development in such areas without interfering with 

reasonable further progress toward attainment of National Ambient Air Quality Standards. The criteria for 

determining when a new source or modification to an existing source is "major" however, have been 

extensively revised. 

Prior to the U.S. Court of Appeals Decision in Alabama Power Company v. Castle, EPA had defined 

"potential to emit" -- a key phrase in the definition of "major emitting facility" -- in terms of uncontrolled 

emissions. The court however, interpreted the phrase "potential to emit" as used in the definition of "major 

emitting facility" in Section 169(1) of the Clean Air Act as taking "into account the anticipated functioning 

of the air pollution control equipment designed into the facility," thereby drastically reducing the number of 

sources qualifying as major. In response to this decision, on September 5, 1979, EPA proposed 

amendments to its regulations concerning requirements for SIPs including those pertaining to prevention 

of significant deterioration of air quality ("PSL)") and new source review in nonattainment areas, as well 

as EPA's Emission Offset Interpretative Ruling. 44 Fed. Reg. 51924 (1979). The Commission in reviewing 

Regulation Number 3 and the Common Provisions Regulation has incorporated many of the amendments 

adopted by EPA in its regulations including classifications of sources as major or minor based on 

controlled emissions. 

The court in Alabama Power Company struck down the -PA regulation definition of "major modification" 

which definition required the imposition of the special nonattainment area requirements (Offsets, LAER, 

etc.) on sources when modifications resulted in an increase in emissions of a criteria pollutants of 100 

tons per year or more (for certain- listed categories of sources; 250 tons or more for sources not listed). 

Regulation Number 3 

Adopted: October 20,2011 Page 207 

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The court held that the special nonattainment requirements applied to all modifications of major emitting 

facilities except those resulting in only "de minimus" increases in emissions. The court stated, however, 

that it would be permissible to look at the net increase in potential emissions from a major source in 

determining whether Offsets, LAER, etc., will be required. 

In its proposed rules, EPA has adopted the "net increase" or "bubble" approach which generally allows a 

major source undergoing modification to avoid permit review as a major modification by allowing emission 

reductions elsewhere at the source to offset any increases resulting from the proposed modification. The 

Commission has adopted the "bubble" concept and many of EPA's specific regulatory provisions with 

respect to the concept as applied to modifications. 

The court in Alabama Power Company also held that fugitive emissions could be included in determining 

whether a source is "major" only to the extent, such emissions were expressly determined to be included 

by rule of the EPA administrator. In response, EPA has proposed a regulatory definition of "Potential to 

emit" by which fugitive emissions from twenty-seven (27) listed sources would be included in 

determinations of which new sources and modifications are major. 44 Fed. Reg. 51956, 51958 (1979). In 

recognition of the fact that such emissions would be included in determinations of whether a source or 

modification was major if they were emitted through a stack (as opposed to being "fugitive"), recognizing 

that generally emissions from the twenty-seven (27) listed source categories contribute to hazards to 

public health and welfare, and to be consistent with the federal scheme, the Commission has also 

decided to consider fugitive emissions from the twenty-seven source categories in major source/major 

modification determinations to the extent they are quantifiable. An owner or operator may avoid the 

inclusion of fugitive emissions of particulate matter by demonstrating that such emissions are of a size 

and substance, which do not adversely affect public health or welfare. 

Banking 

C.R.S. 1973, 25-7-304 requires the attainment program to provide that emission reduction offsets 

exceeding those required for the granting of a permit "may be preserved for sale or use in the future." 

Section V of Regulation Number 3 establishes an administrative framework and the basic requirements of 

such a procedure consistent with the "banking" provisions established by EPA in its Emission Offset 

interpretative Ruling, 44 Fed. Keg. 3274, 3280, 3285 (January 16, 1979) (to be codified as Appendix S to 

40 C.R.S. Part 51). 

Extended "Debugging" Period. 

Pursuant to C.R.S. 1973, 25-7-1 14(4)U), the Division may grant the owner or operator of a new source 

up to six months after commencement of operation in which to demonstrate compliance with all terms and 

conditions of its emission permit. The Commission determined, however, that under certain 

circumstances it would be appropriate to allow a source employing innovative control technology 

additional time in which to bring the operation of the source into full compliance. Therefore, pursuant to its 

authority under C.R.S. 1973, 25-7-109(5), the Commission has provided in paragraph IV. H.6. of 

Regulation Number 3 for such temporary relief from controls under specified limited circumstances. The 

provision is intended for very limited application. 

Regulation Number 3 does not address the subject of special permits for major sources locating in 

attainment areas to insure prevention of significant deterioration of air quality. The Commission decided 

to wait until EPA's PSD regulations to establish a fully State-operated program. State emission permits 

are nonetheless still required for sources locating in attainment areas. 

Common Provisions Regulation 

Regulation Number 3 

Adopted: October 20,2011 Page 208 
In connection with the revision of Regulation Number 3, the Commission concurrently made limited, 

related revisions in its Common Provisions Regulation. Sections I. B. and I. C. of that regulation have been 

changed to reflect the renumbering of the Sections in the State statute authorizing the Commission to 

promulgate regulations and to reflect the amended language in the declaration of legislative intent. 

Section I .F. of the regulation was amended to add new abbreviations used in revised Regulation Number 

3 and Section I. G. (definitions) was amended to delete, revise, and add terms and their definitions to 

reflect changes in the terminology used in Regulation Number 3. 

1.8. Adopted May 13, 1982 

Concerning May 13, 1982 Amendment to Section IV.C. (Public Comment) for Small Sources 

Locating in Nonattainment Areas 

The rationale for this proposed revision is based on the underlying purpose of public comment: to obtain 

public input on proposed sources that the Air Pollution Control Division (APCD) can use in considering 

whether a permit should be granted. 

Under the previous regulation all sources locating in nonattainment areas were subject to the public 

comment requirement unless the APCD exercised its discretion under Section IV.C.3. (sources of less 

than 6 month's duration) to exempt them. APCD experience has shown that there are four categories of 

small sources that frequently locate in nonattainment areas, but which did not stimulate comment from 

the public. These categories are: (I) service stations; (2) restaurants; (3) land development (houses and 

commercial); and (4) other small sources (such as concrete batch plants). Basically, all the effort put into 

preparation of public comment packages for these sources can now be used more efficiently and the 

associated expense to industry saved. 

The limit of 5 Tons Per Year (tpy) of controlled annual emissions is based on calculations that show most 

of the sources in these four categories emit less than 5 tpy of any one pollutant. Service stations, for 

example, generally emit I to 2 tpy. In many cases less than I tpy is emitted. 

Under the revised regulation, sources less than 5 tpy can still be subject to public comment if the Division 

determines it appropriate based on criteria set forth in the regulation. The difference is that the APCD 

would have discretion to decide instead of being required to provide public notice. Controversial sources 

such as gravel pits, odor sources and landfill operations are subjected to public comment by the APCD 

regardless of the level of emissions. This practice will continue in effect. 

I.C. Adopted March 10, 1983 

Prevention of Significant Deterioration Program Regulations in Regulation Number 3 

This Statement of oasis and Purpose for the Prevention of Significant Deterioration (PSD) Program 

Regulations complies with the State Administrative Procedure Act, CR5 1973, 24-4-103(4). The statutory 

authority for the PSD regulations are in the Air Quality Control Act at CR5 973, 25-7-102, 25-7-105, 25-7-

106, 25-7-108, 25-7-109, 25-7-114, 25-7-116, 25-7-201 et seq. The general purpose of these regulations 

is to prevent the significant deterioration of air quality in those Sections of the state, which has attained 

the national ambient air quality standards. The parties to this rulemaking include: 

Colorado Association of Commerce and Industry; Rocky Mountain Oil & Gas Association, Inc.; 

Chevron Shale Oil Company; Union Oil Company of California; Colorado Ute Electric Association, 

Inc.; The Colorado Mountain Club; COAL; Public Service Company of Colorado; City of Colorado 

Springs; CF&I Steel; Environmental Defense Fund, Inc.; United States Department of the Interior; 

and United States Department of Agriculture. 

Regulation Number 3 

Adopted: October 20,2011 Page 209 
The Air Pollution Control Division acted as staff for and advised the Commission during the proceeding. 

See CRS 1973, 25-7 -111(2)(g). 

The PSD regulations adopted by the Commission are in many respects identical to the U.S. 

Environmental Protection Agency (EPA) PSD regulations. See 40 CFR 51.24 et seq.; 40 CFR 52.21 et 

seq. The primary reason for this is that the State Act requires that the S-PSD program be in accordance 

with the federal Clean Air Act PSD provisions. See CRS 1973, 25-7-203. Thus, federal PSD requirements 

are generally a minimum for the State PSD Program. For these reasons, to the extent that the federal 

PSD rules are identical or substantially identical to the state regulations, the Commission incorporates 

herein the EPA statements of basis and purpose for the federal PSD rules at 43 Fed. Reg. 26380 et seq. 

(June 19, 1978) and 45 Fed. Reg. 52676 et seq. (August 7, 1980). 

The Commission has additional authorities to prevent significant deterioration of air quality. In several 

important areas the Commission has tailored these regulations to meet the concerns of Colorado citizens. 

These areas include the requirement for an impact analysis on water to determine acid deposition effects, 

the authority to make independent determinations on adverse impact to visibility in Class I areas if the 

federal land manager fails to fulfill his responsibility to do so, the requirement to establish baselines for, 

and to monitor air quality related values in, Class I areas to determine the effects of emissions on such 

values, and the application of Class I sulfur dioxide increments to several Class II primitive areas and 

national monuments. 

The proposed PSD regulations included several provisions reflecting the terms of a settlement agreement 

in the matter of Chemical Manufacturer's Association. et al. V. EPA in which EPA has agreed to propose 

amendments to its P50 rules. The Commission has rejected the adoption of such provisions for several 

reasons. They are arguably less stringent than current EPA rules in that they would appear to permit 

more air pollution. Because they may be less stringent, their adoption appeared likely on the basis of EPA 

testimony to impede the approval of the state PSD program by EPA at this time. Finally, EPA's schedule 

for consideration of such provisions is unknown. Subsequent to EPA action on the provisions of the 

settlement agreement, the Commission will reconsider those provisions. 

The PSD regulations will generally not become applicable to major sources or major modifications in 

Colorado •until EPA has approved them. See CRS 1973, 25-7-210. However, the regulations pertaining 

to attainment area designations and the enforcement of Class I sulfur dioxide increments in those areaslisted in CRS 1973,25-7-209 will be applicable upon the effective date of these regulations. These 

regulations will be effective twenty (20) days from publication in the Colorado Register. 

DEFINITION OF "ACTUAL EMISSIONS" 

The definition adopted is essentially identical to the EPA definition. 

One party proposed that reference should be made to consideration of control efficiency. The 

Commission did not adopt this proposal because the definition inferentially considers control equipment 

efficiency and the reference requested would create confusion, when actual test data were available, as 

to whether a separate "efficiency" factor was to be applied. 

Another party, in commenting on the definition of "baseline concentration," expressed concern that the 

determination of "actual emissions" could take place, for example, during a low-demand period for a 

power plant. Such determination would result in an emission rate considerably less than the full-capacity 

allowable emission rate, resulting in a low baseline concentration. The power plant, operating the next 

year at full capacity, could consume all or most of the available increment, prohibiting growth in the area. 

The Commission recognizes that, for certain sources such as power plants (i.e., fossil fuel-fired steam 

generators), the source must respond to constantly changing demands with significant changes in 

emissions from year to year. Therefore, for fossil fuel-fired steam generators, "allowable emissions" 

should generally be considered "representative of normal unit operation" rather than actual emissions in 

Regulation Number 3 

Adopted: October 20, 2011 Page 210 
determinations of "actual emissions" .for determining baseline concentration and increment consumption, 

unless it is clearly demonstrated that a lower level of emissions will never be exceeded. 

DEFINITION OF "BASELINE AREA" AND "BASELINE DATE" 

"Baseline area" is not specifically defined in the State Act but is simply referred to as "an area subject to 

this article-- in the definition of baseline concentration. CRS 1973, 25-7-202. The Federal Clean Air Act 

definition of "baseline concentration," Section 169(4}, is identical to the state's, and EPA has interpreted" 

an area subject to this article" to mean the attainment and unclassifiable areas designated pursuant to 

Section 1 07(d)(I)(D) or (E) of the Federal Clean Air Act. Such an interpretation is also reasonable under 

the Colorado Air Quality Control Act which states that the Commission shall adopt measures "to prevent 

significant deterioration of ambient air quality in each region, or portion thereof, of the state identified 

pursuant to Section 1 07{d)(1 )(D) or (E) of the Federal Act." The result of EPA's definition is that the entire 

state is the baseline area for 502, and air quality control regions for particulate matter. 

Several parties proposed alternative approaches to the definition of baseline area. These approaches 

ranged from a modeled 1-1Jg/m3 impact area (based on 7.5 minute quadrangles, the county-townshiprange-Section system, or a metric grid) to the entire state. 

The Commission adopted the EPA definition for the following reasons: 

(1) The EPA approach has been in effect for several years and has proven workable. EPA 

has wel1-developed procedures for performing source impact analyses in large baseline areas, 

which the state can use. Changing the definition of baseline area would result in use of an 

approach that has not been proven and that would cause a discontinuity for the regulated 

industries when the PSD program is delegated to the state. 

(2) The use of areas larger than the source impact area means that baseline concentrations 

will be determined at an earlier date, and increments will be consumed from an earlier date, thus 

minimizing air quality deterioration. This fulfills the primary purpose of the State Act. See CRS 

1973, 25-7-102. 

Certain parties were concerned that baseline areas larger than the impact area might 

unnecessarily inhibit economic growth in the unaffected portion of the baseline area, but should 

that occur, and there are no specific examples in the record of where that would occur, the 

Commission could consider subdividing baseline areas to allow for a new baseline date and 

concentration. 

Testimony from Pitkin County and members of the general public indicated concern that with 

small baseline areas, minor source emission increases would continue to raise the background 

ambient air concentrations, especially for particulate matter, before a major source would locate 

in an area to begin the counting of increment consumption. The baseline areas selected by the 

Commission for particulate matter represent a balance between a recognition that particulate 

matter emissions are often a more localized problem than are gaseous emissions (hence the use 

of AQCRs for particulate matter instead of the entire state, as is the approach for S02) and the 

need to begin counting increment consumption expeditiously (hence, the use of AQCRs for 

particulate matter rather than the smaller impact area). Only two AQCRs in Colorado have been 

triggered during the six years PSD has been in effect. Since triggered baseline areas can in the 

future be subdivided into triggered and untriggered areas, the Commission considers the use of 

baseline areas the size of AQCRs sufficiently flexible for purposes of reasonable application, 

economic growth, and prevention of air quality deterioration. 

(3) Use of a baseline area equivalent to the 1 ug/m3 impact area could result in a situation 

where impacts on a Class I area individually were each less than 1 ug/m3

, with the result that the 

Class I area would not be a part of a baseline area. Yet the cumulative impact of these sources 

Regulation Number 3 

Adopted: October 20,2011 Page211 
could be greater than the 1 ug/m3 increment for particulate matter 'for Class I areas, so that 

deterioration of air quality greater than that allowed by the regulation could legally occur. 

(4) The use of the entire state as an S02 baseline area provides maximum protection for all 

Class I areas in the state. This is of particular concern to the Commission, since the general flow 

of air from west to east and the long-range transport of gaseous pollutants can result in effects on 

nearly all of Colorado's Class I areas by S02 sources on the West Slope. The effects and extent 

of acid deposition, to which S02 is a major contributor, was a topic of extensive testimony at the 

hearings; the definition of the entire state as a baseline area for affords maximum protection of 

the environment while the problem of acid deposition receives additional study. 

DEFINITION OF "BASELINE CONCENTRATION" 

Two parties proposed changes to this definition, both suggesting the substitution of "allowable" for 

"actual" emissions in portions of the definition. The concern regarding power plant actual versus allowable 

emissions is discussed under "Actual Emissions," above. 

The other concern arises from the possibility of a large difference between actual and allowable 

emissions in the calculation of increment consumption or in establishing baseline concentrations. This is 

discussed extensively in the EPA preamble to the August 7, 1980 PSD regulations (Division Exhibit B, pp. 

74-76) concerning increment consumption. EPA's rationale is that actual emissions more reasonably 

represent actual air quality than allowable emissions and that because actual emissions are based on at 

least two years of operation, future emissions could be reasonably expected to remain at the same level. 

EPA therefore uses actual emissions to avoid "paper consumption" of increment (or modeled baseline 

concentrations which would exceed monitored levels) The Commission concurs with the EPA rationale 

and has adopted the EPA approach of using actual emissions to track increment consumption and 

determine baseline concentrations. 

DEFINITION OF "COMPLETE" 

The Environmental Defense Fund (EDF) proposed a list of specific elements of a PSD permit application, 

for aid in determining whether an application is "complete," which was generally incorporated in the final 

rule. The proposed list of items would add some certainty and clarification for the applicant and the 

Division of the specific items required demonstrating completeness of an application. Regarding items (i) 

and (iii)-(iv)., opposition to the list by several parties was primarily that it was redundant with other 

requirements of the rules. York, Nov. 10 Tr. at 18 et seq. and 60 et seq .. Item (ii) was retained because, 

for many or most applications, such information would be necessary to verify the applicant's modeling. 

DEFINITION OF "NET EMISSIONS INCREASE" 

Several parties proposed crediting increases or decreases in emissions, which occur up to five years after 

a modification, becomes operational. The Commission did not adopt this recommendation because EPA 

specifically prohibits states from crediting decreases, which would occur after the change occurs. 40 CFR 

51.24(b)(3). In addition, it would prove difficult to exact an enforceable agreement for a source to close 

down or otherwise decrease emissions at some future date. 

Several parties proposed in paragraph f(ii) to shift "enforceable" from time of construction to time of 

operation. This change would not be consistent with the state statutory requirements, which prohibit 

construction or operation of a non-permitted new source or modification. The suggested change would 

also needlessly complicate the correlation of permits to enforceable decreases in emissions. 

In response to a party comment that 90 days to report a reduction in emissions is too short, the 

Commission agreed and has allowed such reports to be made within a year of the decrease unless •an 

extension is granted. A longer time would make the reduction difficult to verify. · 

Regulation Number 3 

Adopted: October 20, 2011 Page 212 
DEFINITION OF "SECONDARY EMISSIONS" 

The final definition incorporates a recent amendment by EPA, 47 Fed. Reg. 27554 (June 25, 1982) and is 

consistent with CRS 1973, 25-7-202(6.5). 

DEFINITION OF "ALLOWABLE EMISSIONS" 

In several Sections of EPA's PSD rules, including its definition of "allowable emissions," EPA grants credit 

for permit conditions only if they are "federally enforceable. In each of such Sections, the Commission has 

deleted the qualification of "federally" and has in the Common Provisions Regulation defined 

"enforceable" so that it is consistent with 'S definition of 'federally enforceable." 

DEFINITION OF "SIGNIFICANT" 

Several parties commented that the proposed definition, which defined both "significant" and 

"significantly" and included a listing of "significant concentrations," was confusing and unnecessary. The 

proposed definition also gave the Division the discretion to (1) determine that certain sources were not 

significant even if the source met the definition, and (2) to determine significance levels for non-listed 

pollutants. In addition, it limited the definition for sources affecting Class I areas to those sources 

producing a "significant" impact. There were several Sections in the proposed regulations that used the 

"significant" definition of ambient concentrations to allow impacts to Class I areas not allowed under EPA 

rules. EPA and the National Park Service commented that these changes resulted in a less stringent 

definition. The Commission agreed with these comments. The final definition is essentially identical to 

EPA's and uses only emission rates to define "significant," and the use of "significant" to qualify impacts 

to Class I areas in other Sections of the rules has been deleted. 

DEFINITION OF "MODIFICATION" 

One party proposed that an existing exception for increases in - emissions caused by adding new 

emission control equipment (e.g., replacing scrubbers with fabric filters) be retained. The Commission 

acknowledges that this exemption was intended to avoid penalizing a source willing to improve particulate 

matter collection by converting from scrubbers to baghouses or electrostatic precipitators. Since 

scrubbers collect gaseous pollutants, but baghouses and precipitators do not, the amount of S02 emitted 

would increase, hence the exemption. Since there are a number of nonattainment areas for particulate 

matter, but none for S02, the Commission will continue to encourage additional control of particulate 

matter by including this exemption in the definition of "modification." 

It should, however, be noted that this exemption is not included in the definition of "major modification," so 

a significant increase in S02 emissions from a major source will result in P50 applicability. The effect of 

this is to provide the exemption only for minor sources and minor modifications. 

DEFINITION OF "STATIONARY SOURCE" 

The proposed definition was revised to include language essentially identical to that of EPA at 40 CFR 

51.24(b)(5) and (b)(6). The final rule allows more discretion to define stationary source on a case-by-case 

basis. The definition clarifies that a source in a nonattainment area may also be "an identifiable piece of 

process equipmenf' which makes it consistent with a recent federal case. See Natural Resources 

Defense Council et al. V. Gorsuch, et al., 685 F.2d 718 (D.C. Cir. 1982). 

DEFINITION OF "FUGITIVE DUST" 

The State Act exempts "fugitive dust" from regulation under the PSD program, including exemption from 

determinations of whether a source or modification is major and of increment consumption. C.R.S. 1973, 

25-7-202(4), -202(5),-204(1)(b), and -204(2)(c). "Fugitive Dust" is defined as: 

Regulation Number 3 

Adopted: October 20, 2011 Page 213 
Soil or other airborne particulate matter (excluding particulates produced directly during 

combustion) resulting from natural forces or from surface use or disturbance, including, but not 

limited to, all dust from wind erosion of exposed surfaces or storage piles and from agriculture, 

construction, forestry, unpaved roads, mining, exploration, or similar activities in which earth is 

either moved, stored, transported, or redistributed; except that fugitive dust shall not include any 

fraction of such soil or other airborne particulate matter which is of a size or substance to 

adversely affect public health or welfare. 

C.R.S. 1973, 25-7-202(3). Under such definition, fugitive particulates are regulated in the PSD program if 

they are "of a size or substance to adversely affect public health or welfare." 

The exemption of "fugitive dust" is an issue because EPA counts total suspended particulates ("TSP") in 

determining increment consumption, maintenance of primary and secondary NMQS, and source 

applicability. Therefore, to the extent that the state excludes some sizes of particulate matter in these 

determinations, its regulations are arguably less stringent than EPA's, although as explained below, 

because of depositional effects, there is generally an insignificant difference between the counting of TSP 

and the counting of smaller particulates. 

The basis for setting the primary NAAQS is health effects; the basis for setting the secondary NAAQS is 

welfare effects. These are. also the bases under the State Act for counting fugitive particulates in the PSD 

program. Because the bases for the State's inclusion of fugitive particulates and for EPA'S promulgation 

of particulate matter NAAQS are essentially identical, it is appropriate to consider whether the NAAQS 

should be the standard for determining which particulates are "of a size or substance to adversely affect 

public health or welfare." However, EPA's current primary and secondary NAAQS for particulates are 

based on the "Air Quality Criteria for Particulate Matter" (1969), Div. Ex. R., which has generally been 

superseded by more recent research and analysis. For that reason, EPA in the CMA v. EPA Settlement 

Agreement has agreed in the near future to promulgate new primary, and perhaps secondary, NAAQS for 

particulates which would exclude particulates above a size posing no health or welfare risks. 

EPA's staff review, in anticipation of revisions to the particulate matter definition and NAAQS, of the 

effects of particulate matter on health concludes that the size counted should be less than 10 urn, which 

includes those particles capable of penetrating the thoracic regions. "Review of the National Ambient Air 

Quality Standards for Particulate Matter: Assessment of Scientific and Technical Information," EPA 450/5-

82-001 (January 1982). 

EPA staff review of welfare impacts indicates that visibility impacts are generally caused by fine 

particulates of less than 2.5 um. ld. at 122. However, such review recognizes that "the full size range of 

particles including dustfall can contribute to soiling, become a nuisance and result in increased cost and 

decreased enjoyment of the environment." I d. At 140. Further, the EPA "staff recommends consideration 

of the economic and other effects associated with soiling and nuisance when determining whether a 

secondary standard for TP or for TSP or other large particle indicator is desirable," id. at 141, and that 

"the basis for selecting a particular level for a secondary TP or TSP standard is a matter of judgment." 

(emphasis added) ld. at 147. The EPA staff review indicates that EPA will probably propose fine 

particulate secondary standard but is undecided as to whether to establish a TSP or large particulate 

secondary standard, and that there is a basis for concluding that welfare impacts are being caused by all 

sizes of particulates. Additionally, there was public and party testimony on welfare effects from fugitive 

particulates, some of which can be assumed to be large particles. See Markey, November 10 Tr. at 2 et 

seq. 

One of the apparent concerns of parties and persons opposing the use by the Commission of TSP as a 

welfare standard is that the increment would be consumed and that no further development could occur. 

Division Exhibit W, which compares the modeled ambient impacts of TSP using a deposition model with 

particulates of 1 0 urn or less using the same model, shows that the larger particles deposit quickly and 

that the ambient impact is relatively the same at a distance of 1000 meters or greater. The implication of 

this is that for many sources the modeling of increment consumption would have the same general results 

Regulation Number 3 

Adopted: October 20,2011 Page 214 
whether TSP is counted or whether only particles 10 urn or less are counted (assuming the boundary of 

the source is 1000 meters or farther from the emissions point). Another implication is that welfare impacts 

from large particulates can only result within relatively short distances of a source. 

Another concern was that the legislative intent was not to count TSP, although there was not clear 

evidence of legislative intent presented to the Commission. In any event, statutory language leaves the 

determination to the Commission to decide what particulates are of a size or substance to adversely 

affect health or welfare. 

Given the foregoing considerations and the Commission's general interest in interpreting health and 

welfare effects of particulates consistent with EPA, but also given the uncertainty surrounding the revision 

of the particulate NAAQS by EPA, the Commission determines that in applying the definition of "fugitive 

dust", the adverse effects on health or welfare of fugitive particulate emissions should be determined 

individually for each source. Adverse welfare effects of nuisance and soiling will be presumed to occur if 

the source would have offsite, ambient, particulate impacts unless the permit applicant rebuts such 

presumption with clear and convincing evidence. The result of this presumption will be that in most cases, 

large particulates will be counted and there will be no difference between EPA s treatment of particulates 

and the states. Other health and welfare effects shall generally be evaluated based on EPA's most recent 

research and analysis, but the permit applicant shall have the burden of proof of demonstrating with clear 

and convincing evidence, which, if any, sizes or substances of fugitive particulates do not adversely 

affect, health or welfare. This presumption of health and. welfare effects has been incorporated in the 

definitions of "major stationary source" and "major modification," Section XI.A.4 on Exclusions from 

Increment Consumption, and Section V.D.3.c.(i)(B). 

Upon EPA's adoption of revised NAAQS for particulates, the Commission may consider whether to revise 

this Statement of Basis and Purpose or the definition of "fugitive dust~' to reflect such revisions., Should 

EPA decide not to have a secondary NAAQS incorporating nuisance and soiling (welfare) impacts of 

large particulates, the Commission will consider whether the welfare effects of large particulates are 

significant enough to be included, or whether they are relatively insignificant and, thus, should not be 

counted in the state PSD Program. 

DEFINITION OF "MAJOR SOURCE" AND "MAJOR MODIFICATION" 

The State Act permits the counting of fugitive emissions in determining whether a source or modification 

is major "only if the Commission adopts regulations to include fugitive emissions for that source category." 

CR5 1973, 25-7-202(4) and (5). The Federal Clean Air Act has a similar requirement at Sec. 302U). EPA 

has interpreted the rulemakingrequirement to mean simply a consideration in rulemaking of whether 

fugitive emissions should be counted and a requirement that affected industries be allowed to present 

policy or factual reasons why fugitive emissions should not be counted. 45 Fed. Reg. 52676 (August 7, 

1980). Based on this rationale, EPA's rules currently list 26 categories of sources for which fugitive 

emissions are counted. A similar interpretation of the State Act is reasonable and has been adopted by 

the Commission. 

One party recommended the addition of uranium mills and coal mines to the list of sources for which 

fugitive emissions would be counted. However, those sources could not be considered in this proceeding 

due to inadequate public notice. The Commission intends to consider those sources for listing as soon as 

practicable. 

In the CMA v. EPA Settlement Agreement, the EPA has agreed to remove these 26 listed sources on the 

basis of industry's argument that the rulemaking requirement means that EPA must identify reasonable 

methods for measuring and modeling fugitive emissions from a category of sources. Although not 

agreeing that this is legally required under state or Federal law, the Commission has determined that 

Division Exhibit F, primarily, makes that demonstration for the ten categories located or expected to 

locate in Colorado. 

Regulation Number 3 

Adopted: October 20, 2011 Page 215 
It should be noted that measurement methods are not only available, but have been in use for a number 

of years and have provided test results that are the basis for the fugitive emission factors used by EPA 

and other control agencies, including the Colorado Air Pollution Control Division. 

The following important parallels between stack emission 'factors and fugitive emission factors support 

the conclusion that fugitive emission factors are relatively as reliable and as reasonably available as stack 

emission factors: 

Both are based on numerous test data at different locations on different equipment or 

operations. 

Both are influenced by many variables (e.g., for a stack, flow rate, temperature, process 

variations; for a fugitive plume, wind speed, moisture content of the material, size distribution of 

the material). 

Neither is intended to represent actual emissions from a specific source. Actual 

acceptable test data for a specific or similar source would always be used in lieu of an emission 

factor. 

Both are intended as air management tools to allow pre-construction assessment of a 

source impact or as a representative value to average total emissions from a number of similar 

sources (e.g., all waste incinerators, commercial boilers, or coal storage piles) for such air quality 

management purposes as determining "reasonable further progress" in nonattainment areas. 

Stack and fugitive emission factors are both estimates; such factors are nevertheless widely used by 

control agencies and applicants alike. However, control agencies generally have no objection to, and 

would prefer, actual test data in lieu of factors whenever such information is submitted. (See Testimony of 

McCutchen, October 28, 1982; Egley, November 18, 1982, pp. 72-75 and p. 99; Bertolin, October 29, 

(am), p.39.) 

One party's concern involved whether the emission factors for a facility can be extrapolated to a larger 

facility, specifically, from a 7000 ton per day oil shale processing facility to a 50,000 ton per day facility. 

Scale-up is a widely used and accepted approach throughout industry for estimating the feasibility of 

larger-scale facilities from results at smaller-scale facilities. There are a number of well-known 

precautions that should always be considered when extrapolating, and a control agency should be at 

least as cautious in extrapolating emission levels as the applicant is in extrapolating process data. Of 

course, if different equipment, such as a retort, is to be used at a proposed facility, an emission estimate 

would be based on mining and handling practices and on different processing equipment emission factors 

(e.g., refinery emission factors) which are similar to oil shale processing activities where such would be 

more accurate than extrapolation. Therefore, either through extrapolation or through the application of 

other more applicable and available emissions factors, relatively accurate emissions levels from all types 

of oil shale facilities can be calculated. 

The same modeling techniques used to model stack emissions can be and are used to model fugitive 

emissions (Division Appendix F). One modeling parameter, deposition, is more critical in modeling fugitive 

particulate emissions and should be carefully evaluated. Fugitive particulate emissions usually contain 

more large particles than do controlled stack emissions. These large particles generally settle out rapidly, 

so that the impact at a plant boundary is usually much less than would be anticipated by the quantity of 

emissions at the source. See "Fugitive Dust." However, acceptable models exist which incorporate 

deposition and thereby provide a reasonably accurate assessment of fugitive particulate emission impact. 

Models without deposition can be used for gaseous and fine particulate fugitive emissions. Models have 

recognized limitations, but they are as accurate for fugitive emissions as for stack emissions. 

The following information, which is primarily from Division Exhibit F, concerns the major policy and factual 

reasons for counting fugitive emissions from each of ten source categories: 

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Adopted: October 20, 2011 Page 216 
Coal Cleaning. A typical plant would process 10,000 tons per year (tpy) of coal and emit approximately 

280 tpy of particulate matter, 96% of which would be fugitive emissions. Over 100 tpy of the fugitive 

emissions are less than 15 microns in diameter and are considered inhalable particulate (IP). 

Portland Cement. The typical plant produces 500,000 tpy of cement and emits approximately 370 tpy of 

particulate matter, 60% of which would be fugitive emissions. 

Iron & Steel Mills (Including Coke Ovens). A typical plant would produce several million tons of steel per 

year and emit approximately 3,600 tpy of particulate matter, 64% of which would be fugitive emissions. 

The coke plant would produce over half a million tons of coke per year and emit approximately 700 tpy of 

particulate matter, 1 0% of which would be fugitive emissions, and 1,500 tpy of uncontrolled fugitive 

hydrocarbon emissions. 

Petroleum Refineries. A typical plant would process 25,000 barrels of oil per day and emit approximately 

1,100 tpy of hydrocarbons, 57% of which would be fugitive emissions. 

Lime Plants. A typical plant would produce 300,000 tpy of lime and emit approximately 1,800 tpy of 

particulate matter, 33% of which would be fugitive emissions. 

Fuel Conversion. A typical shale oil plant would produce 50,000 barrels per day of oil and emit 4,800 tpy 

of particulate matter, 12% (500 tpy) of which would be fugitive emissions, and 8,611 tpy of hydrocarbons, 

12% (1,080 tpy) of which would be fugitive emissions. 

Sintering Plants. A typical plant would emit approximately 400 tpy of particulate matter, 20% (80 tpy) of 

which would be fugitive emissions. 

Power Plants and Boilers. A typical, but well-controlled, new 500 MW power plant burns 2.1 million tpy of 

coal and emits approximately 620 tpy of particulate matter, 18% ( 110 tpy) of which would be fugitive 

emissions. These fugitive emissions are from coal handling and storage, among the most visible and 

complaint-related of all fugitive emission sources. 

Petroleum Transfer and Storage. A typical plant has a capacity of 476,000 barrels and an annual 

throughput of 7,123,000 barrels per year and emits 267 tpy of hydrocarbons, 72% of which are fugitive 

emissions. 

In conclusion, the Commission has determined that fugitive emissions from the above sources should be 

included in determining whether the source or modification is major for the following general reasons: 

(a) Fugitive emissions consist of the same pollutants that are emitted through stacks and 

regulated as stack emissions; 

(b) The quantity of fugitive emissions, both in absolute and in relative terms, is significant; 

and 

(c) Although this finding is not legally required, there are methods reasonably available for 

measuring and modeling fugitive emissions. 

PUBLIC COMMENT AND HEARING REQUIREMENTS 

The Commission has adopted a regulation designed to offer maximum opportunity for any interested 

person to learn about, and become involved in, the PSD permit review process. Adopted in the final rule 

are proposals by one party that (a) the public notice be printed not only in a newspaper of local 

distribution, but also in one of state-wide distribution to increase the number of potential interested 

persons reached by the notice, (b) that the public hearing be held at least 60 days after the Federal Land 

Manager (FLM) has received the notice and permit application, to allow the FLM adequate response time, 

Regulation Number 3 

Adopted: October 20, 2011 Page 217 
and (c) that any interested person receive notice of public hearing. In addition, the Commission agrees 

with the Division proposal to implement and maintain an "interested party" mailing list as described in 

Division Exhibit M. 

The proposed rule contained a requirement that the Division notify the county Commissioners in affected 

counties when a proposed source would consume 50 percent or more of the remaining PSD increment. 

Two parties proposed that this requirement be deleted as allowing local land use decision-makers to 

unduly influence air permit decisions. The intent of this requirement, which has been modified to notify 

county Commissioners of any PSO permit applications, is not to provide opportunity for counties to 

comment to the Division on land use; rather, it is to provide information to the counties on proposed 

sources so that the counties can more adequately assess their priorities and needs. PSD permit approval 

or denial is to be based solely on the criteria specified in this regulation; land use decisions are, and will 

remain, the responsibility of local governments. 

Regarding the issue of land use decisions, one party commented that Section IV.C.4.e.(iii) of this final 

rule, which solicits comments from interested parties on alternatives to a proposed PSD source or 

modification, constitutes the inclusion of land use factors in permit approval determinations. The 

Commission did not remove this Section because it is required by the State Act, CRS 1973, 25-7-

114(4)(f)(I)(B). Furthermore, the intent of soliciting such alternatives is for the assessment of alternatives 

with respect to control technology and source impact, not land use. 

CONTROL TECHNOLOGY REVIEW 

One party proposed that the last sentence in Section IV.D.3.a.(i)(C), which requires the owner or operator 

of a phased project to demonstrate the adequacy of a previous best available control technology (BACT) 

determination, be deleted. The Commission did not delete this sentence because (1) an EPA regulation 

requires such a condition and deletion of this requirement could be considered less stringent, and (2) the 

requirement is intended to provide for the possibility of a different BACT determination if new technology 

has developed between the time of permit review and the next phase of a project for which construction 

has not yet commenced, a time period which can easily exceed five years on large projects. 

POST -CONSTRUCTION MONITORING 

Five parties proposed that post-construction monitoring requirements be limited to a maximum of one 

year. The Commission recognizes the concern of lessening the burdens on owners or operators, 

particularly if the information being gathered is unnecessary. But in many cases, there can be a very real 

need for monitoring for periods of time greater than a year to obtain reliable data. Accordingly, the final 

rule requires post-construction ambient monitoring for a period up to one year; additional ambient 

monitoring can be required only if it is necessary to determine the effect of emissions from the source on 

air quality. This necessitates an evaluation by the Division regarding the adequacy of the data, and a 

showing by the Division that additional monitoring is needed, before more than a year of monitoring could 

be required. 

OPERATION OF MONITORING STATIONS 

Three parties proposed that the rule be written to allow the latest changes in EPA-approved methods to 

be used without first having to amend the rule. The Commission agrees with the need to use the most upto-date approved methods. Accordingly, the final rule specifies that "EPA accepted procedures ... as 

approved by the Division" can be used. 

ADDITIONAL IMPACT ANALYSIS 

Section IV.D.3.a.(vi) of the final rule requires an owner or operator of a proposed PSD source to provide 

an analysis of the impairment to water that would occur as a result of emissions associated with the 

source. 

Regulation Number 3 

Adopted: October 20, 2011 Page 218 
This analysis is not required by the EPA rules. The Inclusion of water in the additional impact analysis 

reflects a strong concern by the Commission based in the record regarding acid deposition. At this time 

there is neither the information nor the evidence of damage to justify regulating acid deposition in 

Colorado. However, the vulnerability of high altitude lakes to acid deposition and the potential increases 

in acid-forming pollutants such as S02 and NOxon the Western Slope from sources subject to the PSD 

program, particularly oil shale processing and large power plants, clearly demonstrate a need for a 

program to gather data, track and analyze this potential environmental problem. The inclusion of water in 

the additional impact analysis is intended to gather information on the problem; this analysis is not 

intended to affect permit approval or denial or control technology review decisions except for 

determinations of adverse impact to AQRVs in Class I areas. The issues, which have been raised 

concerning water impact analysis, are discussed in detail below. 

a. Legal Authority to Require an Impact Analysis of Acid Deposition 

b. 

The State Air Quality Control Act requires a PSD permit hearing to consider "air quality impacts of 

the source ... and other appropriate considerations." C.R.S. 1973, 25-7-114(4)(f). Acid deposition 

can be construed as an indirect but potentially significant air quality impact which should be 

analyzed, especially in light of one of the stated purposes of the PSD Program "to protect public 

health and welfare from any actual or potential adverse effect which .... may reasonably be 

anticipated to occur from air pollution or from exposures to pollutants in other media, which 

pollutants originate as emissions to the ambient air (emphasis added). Section 160(1) of the 

Clean Air Act. Acid deposition in water is those pollutants in other media originating as emissions 

to the ambient air. 

The Federal Land Manager (FLM) of a Class 1 area is responsible for determining whether a 

source has an adverse impact on air quality related values which is generally defined as follows: 

Any value of an area, which may be affected by a change in air quality. Examples include flora, 

fauna, soil, water, visibility, culture, and odors. Forest Service Comments, October 7, 1982, p.1. 

Acid deposition may adversely affect such values, and thus an analysis of its effects should be 

required for review by the federal land managers of affected Class I areas. 

Major Issues 

The major issues discussed during the hearings are summarized below: 

1. Are Colorado's watersheds sensitive to acid deposition? 

John Turk of the USGS is involved in acid deposition research in Colorado and stated that 370 

lakes in the Flattops Wilderness area comprising 157 hectares would be sensitive to potentially 

harmful degrees of acidification if precipitation attains an average pH of 4.0. (Exhibit 3, Nov. 10 

Tr. at 153) 

Ben Parkhurst maintains that there is talk of Colorado's lakes being sensitive (Oct. 29 Tr. at 146), 

but states that sensitivity must be considered together with acid inputs. Thus, if acid input to the 

water system is not sufficiently large the sensitivity question is not important. 

Dr. William Lewis stated that Colorado's lakes are sensitive to acid deposition as demonstrated 

by the measured loss in buffering capacity he found in his studies. (Nov. 18 Tr. at 136-138) 

In conclusion it can be inferred that some Colorado lakes are poorly buffered and if sufficient 

levels of acidity are introduced into the lakes, these poorly buffered "sensitive" lakes could 

develop acidification problems. 

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Adopted: October 20,2011 Page 219 
2. Has acidification occurred in any Colorado lakes? 

John Turk of the USGS states that there has not been any large degree of acidification taking 

place in the lakes or streams he has studied in the Flattops. (Nov. 10 Tr. at 172) 

Ben Parkhurst also states that there is no evidence to show that any acidification has taken place 

in Colorado Lakes. (Oct. 29 Tr. at 144 and 150-152) 

Dr. William Lewis states that he has noted pH changes in lakes he has studied (Nov. 18 Tr. at 

140), but he does not consider that to be the major point in regard to the acidification question. 

Lewis considers the loss of buffering capacity to be the best indicator of acidification effects on 

lakes and he has found statistically valid evidence to show that this has occurred. (Nov. 18 Tr. At 

13 6-138) 

In summary, there is some evidence that pH has dropped slightly in some of the lakes Lewis has 

studied, however, it does not appear that acidification (drop in pH) has occurred to any large 

degree in Colorado, however, in the prediction of future impacts, buffering capacity should be 

examined and this has dropped in the lakes examined by Lewis. 

3. Is there a potential for acidification in the future? 

Paul Ferraro has done some research on estimating potential acid deposition impacts on 

Colorado and has determined that under different energy development scenarios, there is a 

potential for acidification in sensitive lakes. (Nov. 10 Tr. at 158-159) 

Parkhurst states that he would not expect acidification to be a problem in the future, unless the 

acid deposition reaches levels similar to those found in the Northeast. (Oct. 29 Tr. at 154-156) 

Parkhurst states that Ferraro's study is conservative and a pH drop to 5.8 would not affect fish. 

Oppenheimer (EDF Exhibit 32 p. 6) states that if a 1-~g/m3 increase in S02 (annual average) 

occurs, acid deposition levels could result which would be damaging to sensitive lakes. 

In summary, it can be inferred that there is a potential for energy development activities to cau~e 

increased levels of acids to be deposited in the watershed, and effects on pH may occur 

depending on the buffering capacity of the water. The degree of the effect will depend on the 

amount of acid, thus the amount of emissions. 

4. Are there adequate methods of modeling for acid deposition effects on 

watersheds? 

Paul Ferraro has utilized what he refers to as a "first cut" approach in estimating impacts due to 

acid deposition. The approach utilizes methods employed by John Turk for determining sensitivity 

of waters and methods for estimating deposition rates developed by Systems Applications, Inc. 

(Nov. 10 Tr. at 154-176) 

Oppenheimer (EDF Exhibit 32 p. 12-13) states that acid deposition modeling could be conducted 

using presently available plume models (approved by EPA), which incorporate a plume depletion 

function to account for deposition. Results from this model could then be compared to deposition 

standards. 

In summary, there appear to be only screening techniques available at this time for estimating the 

impacts of acid deposition. 

5. What level of acidification is dangerous to aquatic ecosystems? 

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Adopted: October 20, 2011 Page 220 
Parkhurst stated that fish could survive in pH's as low as 4.1. (Oct. 29 Tr. 143) 

Lewis states that he feels that trout would be adversely impacted if pH dropped significantly 

below six as an average. He would not expect trout populations to be able to reproduce and grow 

at a pH below six. (Nov. 18 Tr. at 152, 153) 

Parkhurst also states that a permanent pH decrease from 6.0 to 5.0 is not a natural variation and 

that many species would probably be eliminated and species numbers and diversities reduced. 

(Nov. 10 Tr. at 11 0) 

Parkhurst also testified that there is not any evidence to show that trout are capable of both 

reproducing and maturing in an environment, which is consistently of a pH of 4.5 or less. (Nov. 10 

Tr. at 114) 

In conclusion, the record does not clearly identify the point at which damage to fish will occur. 

However, testimony indicates that below a pH of 4.5, and maybe below 6, fish populations would 

not be able to reproduce and mature. 

Summary 

Few definitive conclusions could be drawn from the evidence and testimony. The main point of agreement 

was that at the present time there has not been any adverse acidification identified in any of Colorado's 

watersheds. The buffering capacity of lakes appears to be the important factor to consider in determining 

sensitivity of lakes. Testimony was given that buffering capacity has diminished in certain mountain lakes; 

however, the cause of this loss has not been identified. No agreement was reached on what level of pH 

could be tolerated by aquatic ecosystems without causing adverse impact. It could be agreed by all 

parties that more research must be conducted on acid deposition so that its effects may be better 

understood and predicted by appropriate models. 

Although more information is needed, studies in the Northeastern United States, Canada, and Europe 

show that acid deposition can be a serious problem (Oct. 29 Tr. at 144-145 and EDF Exhibit 32 p.3). 

Colorado contains many lakes, which are sensitive, exhibiting low buffering capacities. If energy 

development occurs on the Western Slope emissions of acid precursors will grow substantially, which will 

result in increased acid deposition levels. The nature of energy industry in Colorado may result in rapid 

growth in a short period of time, which will occur before all information on acid deposition is understood. If 

a large industry develops and new information shows that ambient air standards and increments do not 

protect the state from acidification problems, a valuable resource may be damaged. For these reasons, 

the Commission intends to remain vigilant in monitoring this problem, and as analytical capabilities are 

developed or a problem develops, to re-address this issue for possible regulatory and/or legislative 

solutions. A subcommittee should be formed, if resources permit, to develop specific guidelines for acid 

deposition analyses based on recent modeling innovations. In the interim, proposed PSD sources 

emitting acid or acid precursors will be required to analyze the impact of these emissions on water, 

utilizing the most up-to-date techniques available. 

AREA CLASSIFICATIONS 

Several parties objected to the application of Class I sulfur dioxide increments to those areas of Colorado 

listed in Section VIII. B. which are otherwise Class II areas. The sulfur dioxide Class I increments are 

required to be enforced in these areas by CRS 1973, 25-7-209. However, pursuant to CRS 1973, Section 

25-7-105(8) (Supp. 1982), this Section VJII.S. may not be made a part of the State Implementation Plan 

(SIP) until these areas are redesignated as Class I under the procedures of Section IX. Until they are 

redesignated, they may only be enforced under state law and regulations. However, unlike Class I areas, 

the increment in these areas may be protected now. See CR5 1973,25-7-210. 

Regulation Number 3 

Adopted: October 20,2011 Page 221 
The Commission has also determined that the variances from increment consumption allowed by 

Sections XIV.C., XIV. D., XIV.E., and XIV.F. for Class I areas should also apply to the areas listed in 

Section VIII. B. It is a reasonable interpretation of CRS 1973, 25-7-209 that if the Class I (sulfur dioxide) 

increments are to apply to such areas, the variances from the increments should also apply. There is 

nothing in the State Act to indicate that the areas listed in CRS 1973, 25-7-209, are to be given better air 

quality protection than Class I areas, which would be the result if the variances did not apply. 

REDESIGNATIQN 

Several parties objected to what were considered burdensome requirements for redesignating areas to 

Class I. The adopted rule incorporates only the minimal requirements for redesignation from state and 

federal law. See CR5 1973, 25-7-208; Sec. 164 of the Federal Clean Air Act; 40 CFR 517-(g). However, 

the Commission did lessen the burden imposed by the proposed rule on those persons requesting a 

redesignation by allowing such requests to be made without providing all of the information necessary for 

a redesignation. Who would provide such information is not specified so that it could be any combination 

of federal, state and private entities. 

TECHNICAL MODELING & MONITORING REQUIREMENTS 

Several parties proposed the inclusion of future EPA amendments or guidelines in this Section of the 

regulation, which specifies the air quality model, monitoring and stack height requirements to be used. In 

response, the Commission adopted the use of "EPA approved" terminology instead of references to 

specific documents. 

Two parties proposed language making EPA or the state responsible for any needed meteorological data. 

The Commission did not adopt this proposal because it is the applicant's responsibility to demonstrate 

that it will not cause exceedance of an NAAQS or increment, and meteorological data are nearly always 

needed to make such determinations. If the Division has such data, it has an obligation to make that data 

available to the applicant. 

INNOVATIVE CONTROL TECHNOLOGY 

Several parties proposed that the phrase "greater than or" be deleted from Section XIII.B.2. which 

specifies that the innovative system achieve emission reductions "greater than or equivalent to" BACT. 

The EPA regulation uses the phrase "equivalent to" and the parties considered the proposed state rule 

more stringent. The Commission does not consider the phrase "greater than or equivalent to" (emphasis 

added) to be more stringent, but instead to be a clarification that an acceptable innovation can result in 

either equivalent or lesser emissions from the source, but not a higher level of emissions. The preamble 

to the EPA RSD regulation (Div. Exhibit B, p. 84) clearly specifies that the " ... final emission limitation must 

at least represent the BACT level that would have been initially defined." 

FEDERALCLASSIAREAS 

1. (Section XIV.A.) The State's Independent Determination of Adverse Impact to Visibility 

Section XIV.A. allows the Division or the Board (if applicable) to determine independently if there are an 

adverse impact to visibility in Class I areas if the federal land manager (FLM) fails to make such 

determination or such determination is in error. This authority is intended to allow the state to fulfill the 

FLM's responsibility for protection of visibility if for whatever reason, including political, the Flt4 fails to do 

so. The Commission recognizes that scenic vistas are an important resource of the State of Colorado. 

(Colorado Mountain Club Exhibit #1) A subcommittee may be formed to further develop visibility 

protection for the State of Colorado. 

Several parties suggested problems with the state's independent authority' to make such visibility 

determinations. These consisted of (1) measuring or predicting visibility impairment, (2) quantifying manRegulation Number 3 

Adopted: October 20, 2011 Page 222 
induced , as opposed to naturally-occurring, visibility impairment, (3) the subjectiveness of visibility 

impairment, (4) the lack of correlation of current particulate standards to visibility impairment, and (5) the 

lack of guidance in the regulation regarding determinations of significant and adverse visibility impacts. 

The Commission's response to these concerns is as follows: 

(1) Although it is true that there are not federal reference methods for measuring visibility at 

this time, there are reliable means to accurately measure and predict visibility 

impairment. Scientific instruments such as the telephotometer, nephelometer, and the 

fine particulate monitor are recognized as being capable of obtaining objective 

information on visibility-related parameters. Photographs are also useful in visibility 

assessment. 

Visibility theory involving scattering and absorption of light is well documented and has been 

incorporated into the models described in the Workbook for Estimating Visibility Impairment 

(EPA-450/4-8-031). The preface to the Workbook for Estimating Visibility Impairment states: 

"EPA believes these techniques are at a point where the results should now be employed to 

assist decision-makers in their assessments." "These techniques" include the Plu-Vu Model. Div. 

Ex. J at iii. Thus, these models are appropriate for use at this time. 

(2) It is possible to determine if a source of visibility impairment is natural or anthropogenic 

through various chemical/physical analysis techniques. Improvements in air sampling and 

analytical techniques have made available, for the first time, detailed information on the 

chemical and physical nature of the ambient aerosol and of source •emissions. Using 

these chemical "fingerprints," particle morphology and the natural variability of airshed 

sources, recent developments in receptor models have provided new techniques of 

assigning source contributions. 

(3) Perception of visibility impairment is subjective and involves individual variability; 

however, norms do exist around which an assessment can be made. As noted above, 

EPA supports the use of its Workbook for Estimating Visibility Impairment as a guide to 

decision-makers. 

(4) Particulate standards do not address visibility-related effects. It is also true that the major 

anthropogenic visibility impairing pollutant is fine particulate matter. Since the Class I 

increment for particulate is in terms of total mass concentration, rather than fine 

particulates, visibility impairment could occur without the increment being violated. 

Furthermore, the particulate increment is a maximum allowable ground level 

concentration; consequently it will not protect visibility impaired by plumes at elevations 

above ground level. These facts form the basis for the Clean Air Act requirement that 

visibility should be assessed and regulated in a separate analysis. Div. Ex. S. 

(5) The primary guidance for determinations of adverse impact to visibility would be the 

Workbook for Estimating Visibility Impairment, which has very specific guidelines. 

2. (Section XIV. B.) Pre-Application and Operational Monitoring of Air Quality Related Values 

(AQRVs) 

Section XIV. B. of the regulation allows the Division to require a source, which will have or is likely to have 

an impact on any Class 1 area to conduct monitoring to establish the baseline status of and impacts on 

AQRVs in such Class 1 areas. EPA has not imposed this requirement on applicants, although under EPA 

rules and the Commission rule, Section IV.D.3.(a)(vi), an Additional Impact Analysis is required which 

would include an analysis of impacts on AQRVs based on available data, for example, through literature 

searches. The data gathered from such monitoring are important and necessary in aiding the federal land 

manager of a Class 1 area in determining whether or not a source will cause an adverse impact on 

Regulation Number 3 

Adopted: October 20, 2011 Page 223 
AQRVs and the state in deciding on concurrence with such determination. The data also aid the public 

information function of the Additional Impacts Analysis. The authority to require submission of such 

Information includes, but is not limited to, CRS 1973, 25-7-206(2), 25-7-106(5) and (6), and 25-7-114(4). 

A. National Park Service and Forest Service Testimony and Positions 

The National Park Service ("NPS") and the Forest Service ("FS") supported the rule as a supplement to 

their current monitoring activities on the basis that the data is necessary to determining adverse impacts 

on AQRV5, including visibility. See Mitchell, Nov. 18 Tr. at 122 et seq., 161 et seq.; Haddow, Oct. 28 

(p.m.) Tr. At 22 et seq., Nov. 10 Tr. at 68 et. Seq.; Region 2-USDA Forest Service Comments on 

Proposed PSD Rule; Comments on the May 19, 1982 Proposed Colorado PSD Regulation by National 

Park Service Air Quality Division. 

The NPS stated its willingness to provide a list of sensitive receptors of AQRVs to applicants for 

monitoring Mitchell, Nov. 18 Tr. at 162. 

The Forest Service recognized severe technical difficulties and high costs of monitoring some pollutants 

and visibility in wilderness areas. Haddow, Oct. 28 (p.m.) Tr. at 22 -. However, lichen monitoring could 

be done without great difficulty and special use permits are available for some complex monitoring. 

Haddow, Nov. 10 (p.m.) Tr. at 112., The FS intends to identify sensitive indicators of AQRVs for each 

Class 1 area, e.g. 2 or 3 species of lichen and 2 or 3 scenic views, and proposes that the state require the 

monitoring of such indicators ld. at 82-83. 

B. Environmental Defense Fund's (EDF) and Friends of the Earth's (FOE Position 

EDF's and FOE's general contentions in support of the proposed monitoring requirements were: 

1. the technology for monitoring of AQRV's exist; 

2. the Forest Service has identified AQRV's for wilderness areas; 

3. although some monitoring is being done, most areas are not being monitored and will not 

be without the participation of industry; 

4. decisions on adverse impacts to AQRV5 cannot be made rationally without reliable 

scientific evidence; and 

5. the state is required to have a visibility monitoring program by EPA rules, 40 CFR 51.305. 

"EDF and FOE Final Recommendations; Summaries of the Record and Legal and Policy Analyses," 

Section IV. 

C. Trade Association Parties' Position 

The Trade Association Parties' general contentions in opposition to the monitoring requirements were: 

1. The Clean Air Act places the responsibility on the federal land manager to determine 

adverse impacts on AQRVs and, thus, the responsibility to obtain the data necessary to 

make such determination; 

2. There is insufficient information available at this time to develop an AQRV monitoring 

program in that sensitive receptors for each Class 1 area have not been identified, there 

is no monitoring reference method available and no validated models to project impacts 

of particular emissions levels; 

Regulation Number 3 

Adopted: October 20, 2011 Page 224 
3. In some Class 1 areas monitoring is either physically impossible or inordinately 

expensive; and 

4. The Division's discretion in specifying sensitive receptors is too vague and broad. 

Trade Association Parties' Closing Argument at 31-34. 

D. Commission Analysis and Decision 

The above-cited testimony and evidence and other portions of the record support the conclusion that 

monitoring of AQRVs or sensitive receptors of AQRVS would be helpful, and in many cases necessary, to 

determine whether adverse impacts on AQRVs would occur. It is also evident that baseline data are not 

available and may never be developed by federal land managers for some AQRVs and sensitive 

receptors and for some Class 1 areas. Thus, the primary issue is where to place the responsibility for 

obtaining background data on AQRVs - the federal land manager, the state and/or the applicant. 

As the Forest Service suggested, it is traditional permitting practice to require a permit applicant to obtain 

the data upon which the agency decides. Haddow, Nov. 10.(p.m.) Tr. at 89. This practice is consistent 

with the economic philosophy that companies should internalize their environmental costs. Furthermore, 

the Clean Air Act does not change such practice; it places the "affirmative responsibility" on federal land 

managers to protect AQRVs and to consider whether there will be an adverse impact on AQRVs but does 

not expressly state whose responsibility it is to provide necessary data upon which to exercise their 

responsibility. 

The Commission has determined that there is available research and test methods, for obtaining 

background data and impact data on many AQRVs that will be critical in making adverse impact 

determinations, even though there are not generally adopted reference methods or modeling techniques. 

For example, to perform a reasonably accurate visibility impairment analysis, background data is needed. 

Div. Ex. J. Although there are no generally accepted reference methods for estimating visibility impacts, 

methods for estimating visibility Impairment have been developed and are relatively sophisticated. See 

Div. Ex. J.; Geier, Oct. 28 (a.m.) Tr. at 62-71. The rule recognizes this potential limitation on monitoring 

AQRVs by only allowing monitoring if "monitoring methods are reasonably available and research and 

development of monitoring methods are unnecessary." 

In response to the objection that the Division's discretion in selecting AQRVs for monitoring is too vague 

and broad, the rule provides: 

1. A definition of AQRVs (in the Common Provisions Regulation); 

2. That the Division will consult with the federal land manager in the selection of AQRVs; 

and 

3. That the AQRVs selected must be important to the affected Class I area and there must 

be cause to believe that monitoring of the AQRVs will provide a basis for evaluating 

effects to the AQRVs. 

In response to the objection that the monitoring of AQRVs may not be economically reasonable, the rule 

provides that: 

1. no duplication of monitoring may be required; 

2. not more than three AQRVs may be required to be monitored; 

3. monitoring methods must be reasonably available; 

Regulation Number 3 

Adopted: October 20,2011 Page 225 
4. monitoring may only be required if the source is a major contributor to the expected 

effects on the AQRV; and 

5. it is economically reasonable as compared to other monitoring and analysis expenses 

required of a PSD permit applicant. 

SULFUR DIOXIDE AMBIENT AIR STANDARDS FOR THE STATE OF COLORADO 

The proposed rule would have revised the Colorado ambient air quality standard for sulfur dioxide to be 

consistent with the federal standard. Because the Colorado standard is not enforceable in the permitting 

process, see CRS 1973, 25-7-114(4)(g), the Commission ordered on November 10, 1982 That revisions 

of the state ambient air quality standard for S02 be removed as a subject of this rulemaking. 

The Commission agreed to reconsider the state standard if and when it becomes enforceable. 

PUBLIC ACCESS TO CONFIDENTIAL INFORMATION 

One party raised the issue of whether Section VII of Regulation NO. 3 improperly restricts access to 

confidential information, which would be available under the Federal Clean Air Act. Section VII may not 

be considered for amendment in this rulemaking due to lack of public notice. 

1.0. Adopted March 10, 1983 

Revisions to Regulation Number 3 (Excluding PSD Program Revisions) 

This Rationale complies with the requirement of the Administrative Procedures Act, C.R.S. 1973, 24-4-

103(4), to prepare a Statement of Basis and Purpose for adopted regulations. The statutory authority for 

these amendments are at C.R.S. 1973, 25-7-102, 25-7-105, 25-7-106, 25-7-109, and 25-7-114. These 

revisions to Regulation Number 3, adopted February 10, 1982, are intended to clarify and further define 

certain portions of the regulation adopted June 5, 1980. The 1980 revisions were extensive changes 

designed to reflect the new provisions of the 1979 Colorado Air Quality Control act (HB 11 09); these 

changes reflect policy changes and clarifications to the existing rule. The basis and purpose of each 

revision is discussed below. 

I. MINOR SIGNIFICANCE DETERMINATIONS FOR PERMIT AND APEN EXEMPTIONS 

Section II.C.1.j. of Regulation Number 3 allows the Division to exempt sources from Air Pollutant 

Emission Notice (APEN) filing and permit requirements if the criteria in this Section are met. Since mid1980, the Division has granted approximately 25 exemptions under Section II.C.1.j .. Of the approximately 

700 permits issued by the Division annually, 55 percent are to sources with uncontrolled emissions of less 

than 5 tons per year (tpy); 35 percent of the total permits are to sources with uncontrolled emissions 

below 1 tpy. Thus, except for the specific source categories exempted by the Commission under Section 

II.C.1. of Regulation Number 3, nearly every air pollution source, no matter how minimal its emissions, 

has had to file an APEN and obtain a permit. The record supports a finding that most sources of less than 

one ton per year emissions and some of less than five tons per year emissions will have a negligible 

impact on air quality and should be exempted from the APEN and/or permit requirement. 

On that basis and for the following more specific reasons and purposes the adopted revisions to Section 

II regarding APEN filing exemptions and to Section Ill regarding permit exemptions are intended to: 

(a) require APEN filing and permits for any source of hazardous, toxic or odorous air pollutants, 

however small the source. The Commission considers the gathering of information on, and the 

regulation of, such pollutants to be of high priority. 

Regulation Number 3 

Adopted: October 20,2011 Page 226 
(b) exempt sources of all other pollutants from both APEN filing and permit requirements when 

uncontrolled emissions from the source would be less than one tpy. Such sources, according to a 

Division study, account for less than 1 percent of total uncontrolled emissions and would be 

anticiJ)ated to have 24-hour impacts, at a maximum, of less than 2 micrograms per cubic meter 

(uglm3

) assuming 24 hours per day operation, a negligible impact given the localized area of the 

Impact. 

(c) require sources of other than hazardous, toxic or odorous pollutants whose uncontrolled 

emissions are less than five tpy but greater than or equal to one tpy to file an APEN. These 

sources would be exempt train permit requirements (with one exception) unless the Division 

demonstrated using specific guidelines that the source was significant. The Division would have 

to notify the source that a permit was required; otherwise, the source would be exempt from 

permit requirements. The APEN should provide all needed information to preclude unnecessary 

delay in making such determinations. 

Emissions from these 1 to 5 tpy sources, according to a Division study, account for no more than 

two percent of total emissions, yet comprise 20 percent of the total sources obtaining permits. 

Such sources could, however, produce 24-hour ambient air impacts as high as 10 ug/m3

, which 

could be significant in certain cases, especially if such source would cause a violation of a 

NAAQS or increment or by itself or in combination with similar sources cause a health or welfare 

problem or interfere with reasonable further progress towards attainment. 

Volatile Organic Compound (VOC) sources are treated differently. The record demonstrates that 

45 percent of the total of all uncontrolled stationary source VOC emissions are emitted by 

sources ranging from 1 to 5 tpy in size. Most of these sources locate in urban areas such as 

Denver, which is nonattainment for ozone. Since VOC emissions are an ozone precursor, such 

sources should be subject to permitting requirements to ensure compliance with applicable VOC 

emission limitations. 

Therefore, VOC sources equal to or exceeding 1 tpy (uncontrolled) locating in nonattainment 

areas must both file an APEN and obtain a permit. VOC sources ranging from 1 tpy to 5 tpy 

locating in attainment areas where there is less concern for ozone will be treated like other 

sources and will be at least required to file an APEN. 

(d) require sources of other pollutants whose uncontrolled emissions equal or exceed five tpy to file 

APENs and obtain permits unless specifically exempted from such requirements. These sources 

constitute approximately 98 percent of total uncontrolled emissions, and the Commission feels 

that such sources should be required to submit APENs and obtain permits unless specifically 

exempted as a class or as an individual source. 

II. "SIGNIFICANT CHANGE" IN EMISSIONS REQUIRING THE FILING OF A REVISED APEN 

The purpose of this revision to Sections II.B. and II.C. is to clarify and revise the requirements for 

reporting changes in emissions (either increases or decreases) to the Division. 

The record shows that an acceptable emissions inventory, usually referred to as the EIS (for Emissions 

Inventory Subsystem), is essential for effective air quality management and that the revised APENs 

provide an effective system for obtaining EIS data. Revised APENs reporting significant changes in 

emissions are required by statute, C.R.S. 1973, 25-7-114(1), and the $40 fee for a revised APEN defrays 

the cost of processing the information (see "Fiscal Impact"). The levels set for reporting emissions 

changes are significant and will allow the effective tracking of air quality changes and use for air quality 

management. 

It is obvious, however, that there has been confusion concerning these requirements in the past. The 

following statements should clarify the confusion: 

Regulation Number 3 

Adopted: October 20, 2011 Page227 
A. Revised APENs reporting significant changes in emissions are to reflect actual emissions for the 

preceding year, not projected or maximum emissions. Actual emissions are the emissions 

actually emitted by a source into the atmosphere on an annual basis, determined as accurately 

as is feasible using production or processing or combustion rates, and emission factors, or test 

results, or other accepted methods for estimating emission rates. These actual emission rates are 

the "actual emissions used in the PSD definition of "actual emissions", except that for PSD, an 

"actual emission" rate can be ignored if it is not representative of "normal" operation. The APEN 

forms should clearly distinguish an APEN filed with a permit application (which estimates 

maximum anticipated production or emission levels) and a revised APEN (which reports actual 

emissions when a significant change in emissions has occurred). Changes in emission rates 

reported on a revised APEN shall not be used to modify allowable emissions rates or permit 

conditions for the source unless the revised APEN is filed specifically for the purpose of modifying 

an existing permit or obtaining a new'permit, in which case the APEN must (1) be accompanied 

by an application, written request, or letter of explanation from the applicant and (2) reflect 

maximum anticipated production or emission level changes resulting from the requested action, 

not "actual" emissions from the existing source. 

B. Each affected source should discuss with the Division the most efficient format in which 

significant changes can be reported and the degree to which similar emission sources can be 

combined for reporting purposes. It is the intent of the Commission that the Division carry out this 

flexible approach to the maximum extent possible in order to reduce the burden on regulated 

sources. 

The Commission has made these revisions economically reasonable by easing the burden of 

reporting by allowing the use of any mutually convenient reporting format in lieu of a "standard" 

form and by allowing individual, but similar, emission point sources to be grouped. It should be 

stressed that this grouping of emission point sources for purposes of reporting significant 

changes to the Division does not constitute, nor does it set any precedent for, any netting or 

bubbling or other emission trading approach; emission trading can be conducted only through 

specific regulations pertaining to this activity. These APEN groupings also do not relieve the 

source of any obligation to meet any emission control limitations for specific point sources within 

the group. 

In general, the reporting requirements for significant changes have been given greater latitude 

than existed before, partly in response to concerns that, at certain reporting levels, the accuracy 

requested exceeds the accuracy of the available data, and in response to EPA requirements for 

reporting EIS changes which are in the range of 5 tpy for small sources or 5 percent for 100 tpy or 

larger sources. The adopted "significant change" definition reflects a deliberate selection based 

on the public hearing testimony and the exhibits and testimony submitted by the Division and 

interested parties during these deliberations. For odorous, hazardous or toxic pollutants, any 

emissions change must be reported (again, on an annual basis). With changes of only 0.0004 tpy 

(for beryllium), for example, considered "significant" by EPA, close scrutiny of all hazardous, toxic 

and odorous pollutants is needed. 

Ill. REVISED APEN FEES 

An issue raised is whether the Commission has statutory authority to require a $40.00 filing fee with a 

revised APEN. The statutory authority for a fee states, "Any person required by the Commission to file an 

air pollutant emission notice shall pay a nonrefundable fee of forty dollars .... " C.R.S. 1973, 25-7 -114(5)(a). 

The statutory authority for requiring the filing of APENs and revised APENs refers to: "air pollutant 

emission notice" and "revised emission notice", C.R.S. 1973, 25-7-114, the latter reference being to 

"revised (air pollutant) emission notice". Section 25-7-114(5)(a) does not limit the $40.00 fee to initial 

APENs filed for a source but refers simply to "air pollutant emission notice" which may be interpreted to 

include both initial and revised APENs. Testimony by the Division estimated the administrative costs of 

Regulation Number 3 

Adopted: October 20, 2011 Page 228 
processing a revised APEN at over $40.00. For these reasons, the Commission finds that it has authority 

and should charge a $40.00 filing fee for revised APENs. 

IV. NON-PERMITIED SOURCE APPLICABILITY 

A source existing before the adoption of the first Colorado Air Quality Control Act and the date of its 

implementing regulations of February 1, 1972, is not required to obtain a permit. This revision is intended 

to clarify the date prior to which existing sources are considered "grandfathered" and exempt from a 

permit requirement. 

V. STATIONARY INTERNAL COMBUSTION ENGINE EXEMPTION 

The purpose of this revision is to decrease the extent of the exemption for stationary internal combustion 

engines. Prior to this revision, stationary internal combustion engines less than 1000 HP in attainment 

areas and less than 250 HP in nonattainment areas were exempt from permit requirements. The record 

shows that these sources not only constitute large individual sources (a 1000 HP engine can emit 96 tpy 

of NOx), but also can be situated close to each other (one compressor station in Colorado consists of 15 

925 HP stationary internal combustion engines which can emit a total of 1340 tpy NOx). Small stationary 

internal combustion engines in terms of emissions (less than 5 tpy) or size (less than 50 HP) are excluded 

from permit requirements. In addition, the Commission has retained the exclusion from permit 

requirements for emergency power generators and added exclusion for stationary internal combustion 

engines powering portable oil drilling rigs. 

The exclusion for stationary internal combustion engines on portable oil drilling rigs is based on testimony 

and on information developed by the Division which indicates that these sources move frequently 

(average 10 days per well site), generally are located at remote sites, and emit only 1.3 tons N02 per well 

drilled. The Division indicated that the total estimated NOx emissions from portable oil drilling rigs in 

Colorado could be as high as 2200 tpy and that this could increase the total NO emissions inventory in 

specific active drilling areas by as much as 50 percent. To determine if an air quality problem exists for 

these sources, testimony from the Colorado Petroleum Association (CPA) indicates a willingness to 

provide the information needed by the Division to assess emissions by modifying existing data-gathering 

reports. 

One party requested a delayed effective date for this revision so that compressor stations planned for 

construction during the summer of 1983 would not be held up by an unanticipated requirement that 

permits be obtained. Such a request is reasonable, and the delayed effective date of October 1; 1983, 

has been adopted. 

VI. PUBLIC COMMENT FOR DEMOLITION AND NONATIAINMENT AREA PERMITS 

Since the record shows that sources for which public comment has been received are in every case 

either large (greater than 25 tpy) or controversial (e.g., odorous emissions), the public comment 

requirement for sources in nonattainment areas is being raised from 5 tpy to 25 tpy, which makes it the 

same as for sources locating in attainment areas. Demolition projects have been exempted from public 

comment requirements because they often need to be completed, by contract agreement, in a short 

period of time, and the need for public comment has on occasion been an unnecessary time delay. Very 

few public responses have been received for small demolition projects. The Division retains the authority 

to require public comment for demolition projects if considered warranted for reasons of asbestos 

emissions or other significant concerns. 

VII. CONSTRUCTION SCHEDULE DEADLINES 

Under previous rules, owners and operators applying for new permits have not been held to any time 

limits for coml')'lencing construction or operation once the permit to operate has been obtained. Sources 

must be evaluated (C.R.S. 1973, 25-7-114(4)(b)) to determine whether operation of the source will 

Regulation Number 3 

Adopted: October 20,2011 Page 229 
comply with all applicable regulations, an evaluation that can be made with an acceptable degree of 

certainty provided that the source actually does construct and operate within a reasonable period of time 

following receipt of the permit. However, a source which delays construction for a number of years may 

finally initiate operation at a time when ambient air concentrations or other factors used in evaluating 

compliance have changed; in addition, delaying construction and operation results in the reserving of 

emissions that could have been used by other applicants. 

This provision implements an 18-month construction deadline, imposed by the Division, to all sources, 

major and minor, statewide. Owners and operators will be prevented from applying for a permit without 

intending to construct in the near future, a form of "reserving" emissions or increments which makes 

compliance analysis difficult and could inhibit real economic growth in the state. Under these provisions, 

the Division will grant necessary extensions to permits that are issued, so a source with good reason for 

delaying a project would not be penalized by loss of a permit. 

VIII. NON-REACTIVE VOLATILE ORGANIC COMPOUNDS (NRVOCs) 

The EPA maintains a list of NRVOCs, which are considered either totally non-reactive or insignificantly 

reactive in the formation of ozone. NRVOCs can therefore be used to replace reactive VOCs as offsets. 

A list of additions to this list appeared in the July 22, 1980 Federal Register. The revision to Regulation 

Number 3 updates the list of NRVOC5, which are non-hazardous, to conform to EPA's revised list of 

NRVOC. In addition to this, the revision extends the concept of NRVOC Statewide (instead of 

nonattainment areas only), and clarifies that NRVOCs will be reviewed separately during initial approval 

analysis of a new source. Previously, NRVOCs pertained to nonattainment areas only and were used 

only based on emission-offset credit. The revision clarifies that NRVOCs can be substituted for VOCs for 

banking and other emission reduction credits. 

IX. CLEAN PORTION OF NON-ATTAINMENT AREA 

No revisions to Sections IV.D.2.c. or IV.D.3.b. were made because the State Act provides for the 

exemption of Section IV.D.2.c. at C.R.S. 1973, 25-7-303. 

I.E. Adopted March 19, 1987 

Revisions to Regulation Number 3 Section II.C.1 

The specific statutory authority under which the Commission shall hold and conduct this hearing is 

prescribed by 24-4-103, 25-7-105, -106, -110, and the hearing will be conducted in accord with provisions 

of 24-4-103 and 25-7-110, C.R.S. 1982 and the Procedural Rules. 

The revision to Regulation Number 3 Section II. C. 1. is an addition to the list of sources, which are 

exempt from filing Air Pollution Emission notices. Addition of Part I. (small L) to this regulation exempts 

petroleum industry flares, approved by the Oil and Gas Conservation Commission, from having to file an 

Air Pollution Emission Notice (APEN) if emissions of any pollutant do not exceed five (5) tons per year. 

This exemption only applies to flares, which do not combust gas containing hydrogen sulfide (H2S) 

except in trace amounts, since H2S is classified as a hazardous air pollutant. Previously APENS were 

required for these flares when emissions exceeded 1 ton per year. 

The Air Quality Control Commission adopts this change for the following reasons: 

1) Records of the amount of gas flared will be kept by the Oil and Gas Commission and 

made available to the Division; 

2) The flaring is a temporary activity in most cases; 

Regulation Number 3 

Adopted: October 20, 2011 Page 230 
3) Statewide emissions from flares are relatively low, with nitrogen oxides (NOx) being the 

main pollutant emitted (emissions of NOx from flares is approximately 200 tons per year 

statewide, while total stationary source NOx emissions are over 160,000 tons per year in 

Colorado); 

4) Ambient impacts from flares are low; 

5) No hazardous pollutants will be emitted; 

6) Larger flares will still have to be permitted by the Division. 

I.F. Adopted November 19, 1987 

Addition of Section XV to Air Quality Control Commission Regulation Number 3 Regulation 

Requiring an Air Contaminant Emission Notice, Emission Permit Fees 

This Statement of Basis, Specific Statutory Authority and Purpose complies with the requirement of the 

Administrative Procedures Act, C.R.S. 1973, Section 24-4-103 (4) for adopted or modified regulations. 

This revision to Regulation Number 3, adopted November 19, 1987, is intended to bring the Colorado 

regulations into conformance with current U.S. EPA regulations. U.S. EPA's regulations were revised in 

response to a court order which required each state to develop a program to assess and remedy visibility 

impairment in Class I areas from new and existing sources, as established in Section 169A of the Clean 

Air Act. 

Section XV. is added to Regulation Number 3 as part of the State's plan to meet the national goal of 

preventing future, and remedying existing, visibility impairment in Class I areas. Section XV. Together 

with this Statement of Basis, Specific Statutory Authority and Purpose and the monitoring and long-term 

strategies represents Colorado's State Implementation Plan (SIP). 

This Regulation addresses a type of visibility impairment, which can be traced to a single source or small 

group of sources known as reasonably attributable impairment. The U.S. EPA deferred action on the 

regulation of regional haze and urban plumes due to scientific and technical limitations in visibility 

monitoring techniques and modeling methods. 

The FLMs were consulted and their suggestions considered in developing the plan. In addition, the 

Commission provided public notice 60 days prior to the public hearing stating that interested parties 

would be given the opportunity to provide testimony concerning the Regulation and its requirements at 

the hearing. Wyoming, Utah and New Mexico were also sent notice of the hearing. 

Section XV. D. allows the FLMs to certify visibility impairment to the Division Director at any time. At such 

time of certification the Division must assess the impairment, identify the contributing source(s), and 

conduct a Best Available Retrofit Technology (BART) analysis for any contributing sources located in 

Colorado. The FLMs have not certified reasonably attributable impairment as of this adoption date. 

Section D. also requires BART and is incorporated for future use, if necessary. 

Any source subject to the BART requirements of this Section may apply to the U.S. EPA Administrator for 

an exemption. The application to the U.S. EPA must include a written concurrence from the Division and 

Commission; therefore, the source must first apply to the Division, as set forth in Section D.2.c. An 

exemption granted by the Division and approved by the Commission will constitute the written 

concurrence required by U.S. EPA 

The New Source Review requirement of Section XV.E. is included for purpose of reinforcing Sections 

IV.D.2.a. (vi) and IV.D.3.a. (vi). 

Regulation Number 3 

Adopted: October 20,2011 Page 231 
In addition to existing and new source review, the Division must develop a visibility monitoring strategy to 

collect information on visibility conditions and must develop a long-term (10-15 year) strategy to assure 

progress towards the national goal. The monitoring plan and the long-term strategy are set forth in the 

SIP submitted to the U.S. EPA. Section XV. F. provides procedures for reviewing and revising the longterm strategy. 

State Implementation Plan for Class I Visibility Protection State of Colorado 

The purpose of this plan is to assure reasonable progress towards meeting the national goal of 

preventing future, and remedying existing, visibility impairment in Class I areas. 

The plan includes provisions for existing and new source review (attached as Regulation Number 3, 

Section XV.), a monitoring strategy, a long-term strategy, and consultation with FLMs. 

Monitoring Strategy 

The State of Colorado's Class I Visibility monitoring strategy is based on meeting four goals: 

1. Provide information for new source visibility impact analysis; 

2. Determine existing conditions, in Class I areas and the source(s) of any certified impairment; 

3. Determine actual effects from the operation of new sources or modifications to major sources 

on nearby Class I areas; and 

4. Establish visibility trends in Class I areas in order to evaluate progress toward meeting the 

national goals of visibility protection. 

The goals will be achieved through a combination of objectives concerning monitoring, gathering and 

evaluating existing visibility data, and mechanisms for the use of visibility data in decision-making. 

Potential new major stationary sources or major modifications to existing stationary sources subject to the 

Air Quality Control Commission (AQCC) Regulation Number 3, Section IV.3, are required to perform an 

analysis of visibility impacts on potentially affected Class I areas. The analysis must be conducted 

utilizing existing visibility data, if any. The Division must consider and evaluate available data from 

potentially affected Class I areas or other areas that may be representative of background conditions in 

the Class I area(s) of interest. If data is adequate, the permittee will be notified of the background or base 

level of visibility against which impacts will be assessed (Regulation Number 3, Section IV.3.(a)(iii)(D)). If 

visibility data is not adequate, Regulation Number 3, Section XIV. allows the Division to require any 

source, which will have or is likely to have an impact on any Class I area to conduct monitoring to 

establish baseline status of visibility. The monitoring information will be used in the new source review 

analysis and will add to the background and trend data bank of that Class I area. No monitoring shall be 

required if it is currently being conducted by any federal, state, or local agency (AQCC Regulation 

Number 3, Section XIV.B.1). 

FLMs may at any time identify to the Division Class I areas where emissions from a specific source or 

small group of sources may be causing or contributing to visibility impairment in the Class I area. The 

Division will determine if emissions from any local sources can be reasonably attributed to cause or 

contribute to the documented visibility impairment. In making this determination the Division will consider 

all available data including the following: 

1. Data supplied by the FLM; 

2. The number and type of sources likely to impact visibility in the Class I area; 

Regulation Number 3 

Adopted: October 20, 2011 Page 232 
3. The existing emissions and control measures on the source{s); 

4. The prevailing meteorology near the Class I area; and 

5. Any modeling, which may have been done for other air quality programs. 

The Division may be unable to make a decision regarding "reasonable attribution" of visibility impairment 

from an existing source or sources using available data. The Division will make available to the affected 

FLML and the U.S. EPA a discussion of what data was considered and what measures the Division is 

taking, if any, to resolve the situation. The Division may consider modeling the impact of nearby 

suspected sources with existing visibility models. Funding and other factors may limit the Division's ability 

to unilaterally initiate studies designed to establish "reasonable attribution". Therefore, the Division may 

join with the FLMs, the suspected source(s), the U.S. EPA, and others in implementing special 

monitoring and analysis programs to address the specific problem. 

The Division will sponsor or share in the operation of visibility stations with FLMs as the need arises and 

resources allow. Fiscal, logistical, and other considerations may constrain the Division in conducting 

visibility monitoring in Class I areas. 

The Division will request from each FLM responsible for Class I areas in Colorado copies of any and all 

past or existing programs designed to monitor or evaluate visibility. All future visibility data gathered by 

each FLM will also be requested, including any analysis and interpretation. 

The Division will assemble and evaluate the visibility data supplied by the FLM in addition to any other 

data collected by the Division or any other appropriate l)ource (such as a proposed major stationary 

source) on an annual basis. 

Long-Term Strategy (l TS) 

The Commission shall review the strategy set forth below and prepare a public report as required in 

Section XV.F. The FLMs shall be consulted throughout all phases of the L TS development and revisions. 

A Commission subcommittee will be established to address the following components of the L TS: 

1. Statewide visibility standards 

2. Smoke management 

3. Vistas 

4. PM10 and PM2.5 emissions 

5. Any other components the subcommittee deems applicable. 

The Division is pursuing the adoption of statewide visibility standards. The subcommittee will determine 

how and if standards should be set and how the standards will apply to various areas of the state. 

Although the end result may apply to regional haze, Class I areas will benefit from statewide standards. 

The Division presently has smoke management agreements with the FLMs. The affected agencies are 

required to obtain an open burning permit from the Division. Virtually all controlled burns are for wildlife 

habitat and range management; little slash/timber management burning occurs. 

The Division believes existing smoke management techniques do not adversely affect visibility in Class I 

areas. The subcommittee will address this issue to determine how smoke management should be 

integrated into the L TS. If necessary, the existing agreements may be revised during the L TS review 

Regulation Number 3 

Adopted: October 20,2011 Page 233 
process. The Division will continue to coordinate with the FLMs to insure that best smoke management 

techniques are employed. 

The FLMs declined to identify integral vistas (important views of landmarks or panoramas that extend 

outside of the boundaries of the Class I areas and considered critical to the enjoyment of the areas). The 

Commission is therefore not required to address vistas but may do so under their own authority. The 

subcommittee shall determine if integral vistas and/or other scenic vistas should be identified, and if so, 

the criteria to be used for such identification. Any vistas shall be identified using the specific criteria 

developed by the subcommittee. 

The Division is in process of studying PM 1 0 emissions and their role in the formation of Denver's brown 

cloud. Conceivably, such studies could lead to information and strategies related to visibility impairment. 

The subcommittee will address the integration of this component into the L TS. 

The FLMs and Division have not identified reasonably attributable impairment at this time, therefore the 

Commission will not address source retirement and replacement, construction activities, and 

enforceability of emission limitations. Should the FLMs or Division identify impairment from a specific 

source or small groups of sources, the Commission will address these issues during the L TS review 

process. 

Each time the L TS is reviewed, the following six factors (at minimum) must be addressed. 

1. Emission reductions due to ongoing air pollution control programs. 

2. Additional emission limitations and schedules for compliance. 

3. Measures to mitigate the impacts of construction activities. 

4. Source retirement and replacement schedules. 

5. Smoke management techniques for agricultural and forestry management purposes including 

such plans as currently exist within the State for these purpose, and 

6. Enforcement of emission limitations and control measures. 

Consultation with Federal Land Managers (FLMs) 

The Division as part of the implementation of this Regulation will send within 30 days of its adoption 

written notification to the FLMs stating that the Division Director is the official to whom any 

recommendations may be sent regarding Colorado's SIP for Class I visibility protection, including but not 

limited to: 

1. Integral vistas to be listed by the state; 

2. Identification of impairment of visibility in any Class I area(s), and 

3. Identification of elements for inclusion in the monitoring strategy. 

The Division will provide the opportunity for consultation with the FLMs, in person and at least 60 days 

prior to any public hearing on any element of the SIP. The Division is interested in the FLMs opinion 

regarding: 

1. Assessment of impairment of visibility in any Class I area, and 

2. Recommendation on the development of the long-term strategy. 

Regulation Number 3 

Adopted: October 20, 2011 Page 234 
The FLMs may contact the Division Director at any time regarding the implementation of the SIP for Class 

I visibility protection. 

I.G. Adopted August 8, 1988 

Revisions to Regulation Number 3 and the Common Provisions Definitions 

Revisions are made to Regulation Number 3 and definitions in the Common Provisions. Prevention of 

Significant Deterioration (PSD) and New Source Review (nonattainment) requirements are revised to 

conform to the Federal regulations. Provisions for the regulation of the National Ambient Air Quality 

Standard (NAAQS) for particulate matter (PM-10) are added. Section V, concerning certification of 

Emission reduction, is revised to conform to Federal requirements. Other minor changes are made to 

clarify existing policies. Requirements for Revised Air Pollution Emission Notices (APENS), Air Quality 

Related Value (AQRV) monitoring, solid waste fuel, and temporary sources are revised. 

Dual Definition of Source 

Federal regulations require the use of the dual definition of source for nonattainment areas. (See 

discussion, in the August 7, 1980 Federal Register, 45 FR52680 and 52693). The concept is intended to 

provide for more air pollution control in nonattainment areas, such that more rapid progress can be made 

toward attaining the standards. 

When determining if a source locating in an attainment area is major, emission increases and decreases 

at the entire facility are considered. When determining if a source located in a nonattainment area is 

major, two cases are examined. First, if the single piece of equipment or modification itself represents a 

major source or significant increase, nonattainment review applies. Second, if the piece of equipment 

itself is not major, examine the entire facility as for attainment area sources. If a significant increase 

occurs, nonattainment review applies. 

The definition of "Stationary Source" in the Common Provisions indicates the Commission intended to use 

the dual definition (see also the Statement of Basis and Purpose, March 10, 1983). The definition of "Net 

Emission Increase", Part K, however, incorrectly stated that only the single piece of equipment is 

examined. This was less stringent than Federal law and allowed facilities to install a series of de minimus 

units whose aggregate emissions could be significant, without undergoing nonattainment review. Part K is 

corrected to allow the Division to use the dual definition. 

When the dual definition is used, nonattainment review applies to reconstructed sources. Section IV.D.2.a 

clarifies this. 

Section IV.D.2.a also clarifies that nonattainment review applies only to nonattainment pollutants emitted 

in major amounts. This differs from PSD requirements, which apply to attainment pollutants emitted in 

significant amounts if the source is major for any pollutant (attainment or nonattainment). (See discussion, 

45FR52676.) 

Fugitive Emissions 

The Colorado Air Quality Control act includes fugitive emissions when calculating a source's potential to 

emit only if the Commission adopts regulations to include fugitive emissions for that source category. 

(See Statement of Basis and Purpose, March 10, 1983). Federal law requires that fugitive emissions are 

included for all "listed" sources (those listed in the definition of major source). The Commission is 

adopting the requirement to include fugitive emissions for all listed sources. 

Portions of the Colorado Act not Allowed in Federal Act 

Regulation Number 3 

Adopted: October 20, 2011 Page 235 
Portions of Regulation Number 3 are not allowed in the Federal Regulations, but are contained in the 

Colorado Act and therefore cannot be removed from regulation Number 3 until removed from the 

Colorado Act. The items are discussed below. The Division will not honor these items unless an applicant 

insists, in which case a permit from the EPA will be required to meet Federal law. 

Best Available Control Technology (BACT): 

The Colorado Act's definition of BACT states that revisions to New Source Performance Standards 

(NSPS, Regulation 6) or National Emission Standards for Hazardous Air Pollutants (NESHAPS, 

Regulation 8) made after April 10, 1983 (the effective date of the definition) can't be used to determine 

BACT. The Federal Act requires that BACT can't exceed the NSPS or NESHAP in effect at the time of 

application. The Division will make BACT determinations taking into consideration the most current NSPS 

and NESHAP regulations. 

Clean area in nonattainment area: The Colorado Act and Section IV.d.2.B.ii allows exemption from 

nonattainment requirements if the source proves they are located in a clean portion of a nonattainment 

area. This is not allowed in the Federal Act. 

Shale oil exemption: The Colorado Act and Section I.B.2.C.viii excludes from the definition of major 

modification a fuel switch to shale oil or coal/oil mixtures. This is not allowed in the Federal Act. 

Fugitive Dust Exemption: The Colorado Act and Regulation Number 3 does not include fugitive dust that 

does not adversely affect public health or welfare when calculating a source's potential to emit. The 

March 10, 1983 Statement of Basis, Authority, and Purpose discusses the Commission's previous 

position. •The discussion indicates that when the EPA promulgates new standards for particulate matter 

the fugitive dust issue will be resolved. The EPA has promulgated a new NAAQS for PM-10, which 

replaces the TSP NAAOS. The PSD increments, however, are still based on TSP. PM-10 fugitive 

emissions can thus be used to determine potential to emit, but some question remains as to whether or 

not TSP fugitive emissions should be used. The EPA is developing PM-10 increment standards. In the 

interim, if a source does not want to include fugitive dust (TSP or PM-1 0) for a State permit, an EPA 

permit may have to be obtained. 

Permit Review Time Frame: The Colorado act contains specific time frames for processing permits (60 

days, etc.). Section IV.F of Regulation Number 3 states that a permit is automatically issued if the Division 

fails to meet the time constraints. This is not acceptable for major source review. PSD and major 

nonattainment applications are often complex. The Federal Act allows one year to complete the review 

process (including public notice, hearings, etc). The Division will automatically ask for a time extension for 

major source applications. If an extension is not granted and/or the time frame is not met, an EPA permit 

will be required. 

Other Minor Revisions 

These definitions are revised as follows to conform to the Federal Act: "construction" now includes 

demolition and modification; "enforceable" now includes Regulations Number 6 and 8; "Lowest 

Achievable Emission Rate" does not allow BACT to be exceeded. 

References to the "Board" are deleted and replaced with "Commission" throughout the Regulation. The 

(Hearings) Board no longer exists. 

Class I areas in neighboring states are recognized in Section VIII. 

Section VIII.K is added to allow redesignation of an area to class Ill if a permit can't be obtained unless 

the area is redesignated and sufficient public notice is given. The Federal Act requires this. 

Regulation Number 3 

Adopted: October 20,2011 Page 236 
Section XIII.B exempts Innovative Control Technology from BACT only, not all of the PSD requirements. 

This conforms to the Federal Act. 

Public notice procedures (Section IV. C) for major sources are expanded and clarified to conform to the 

Federal Act. 

The word "new' is removed from Section IV.D.2.a.iv to clarify that alternate sitting studies apply to new 

and modified sources. 

Exemption c under the definition of modification is removed. This exemption allowed sources choosing to 

improve control of particulate matter to increase S02 emissions without the need for>additional S02 

control. (See Statement of Basis, Authority and Purpose, March 10, 1983). This exemption is no longer 

allowed, since it is inconsistent with the Federal Act. 

The language pertaining to interim PSD authority is deleted. The State received full authority on 

September 2, 1986. 

Annual fee requirements are added to Section VI. This provision was added to Section 25-7-114(5)(a) of 

the Colorado Act on July 1, 1987. 

Household use of paints and solvents is exempt from APEN and permit requirements. The Division 

classifies these materials as toxic air pollutants which would require permits if emitted in any amount. The 

Division does not have available resources to regulate this activity. 

The six-month, 25 acre APEN and permit exemption clarifies that all mining operations must obtain a 

permit (unless exempt elsewhere). 

Temporary sources operating less than one month may receive initial and final permits at the same time. 

The Division will thus avoid issuing final permits for sources that no longer exist. The Division has 

discretion to issue the permits separately if the operator or owner of the source or the source type has a 

history of compliance problems. 

PM-10 NAAQS 

This new standard replaces the Total Suspended Particulate (TSP) standard for Federal purposes only. 

The State is adopting the PM-10 requirements and is also retaining the TSP standard at least until the 

EPA approves our PM-10 State Implementation Plan. This will ensure that Reasonable Further Progress 

will be maintained in the interim. 

The PM-1 0 standard is implemented under Section 11 0 of the Federal clean Air Act. The other criteria 

pollutants are regulated under Section 1 07, which includes provisions for designated nonattainment 

areas, emission offsets, and sanctions for areas where the standard is exceeded. Section 110 does not 

utilize nonattainment areas; it requires that the standard be met in all areas. The State regulations applied 

specifically to designated attainment and nonattainment areas. Since there are no PM-1 0 designated 

areas, reference to pollutants regulated under Section 11 0 is added in several places to ensure regulation 

of PM-10. 

PM-1 0 sources that impact an area where the standard is exceeded are "major" if they emit 1 00 tons per 

year or more of PM-10. Such a source is then subject to PSD requirements (Section 1.4.a). Such sources 

must also offset their impact to the degree which it exceeds the standard (as opposed to sources of other 

criteria pollutants, which must offset total emissions). Offsets will be required as part of the PSD source 

impact analysis, as necessary. 

PM-10 fugitive emissions are included when calculating potential to emit. (See discussion under Portions 

of the Colorado Act not allowed in Federal Act in this Statement of Basis, Authority and Purpose). 

Regulation Number 3 

Adopted: October 20, 2011 Page 237 
PSD increments are still regulated in the TSP form, therefore significant emissions and impact levels exist 

for both PM-10 and TSP. PSD will apply to TSP until the EPA promulgates PM-10 increments. 

New definitions are added to the Common Provisions to differentiate between particulate matter, PM-1 0 

and TSP. 

The EPA has left regulation of minor sources to the state. Section IV.D.3.E is added to require minor 

sources locating in areas where the PM-10 standard is being exceeded to apply BACT. 

The Commission had the option to add PM-10 monitoring "phase in" provisions. Methods and equipment 

are reasonably available, therefore, phase in is not necessary. 

Corrections to typographical errors are made for significant ambient levels of beryllium, lead, and 

hydrogen sulfide. (Section IV.D.3.b.iii) 

Revised Air Pollution Emission Notices (APENS) 

Section II.B requires Revised APENS when a significant change in emissions occurs. The definition of net 

emission increase requires that a Revised APEN be filed to receive credit for decreases. Historically, the 

Division has not received all of the APENS required. The April 1 deadline and calendar year requirement 

are added for clarification. The removal of a piece of equipment represents a significant change and the 

requirement for submittal of an APEN to cancel a permit is added for clarification. These clarifications will 

help the Division update the Emission Inventory System; proper credit will be received for emission 

decreases; and sources will avoid being charged an annual fee for equipment, which no longer exists. 

The Regulation now requires all portable sources to submit revised APENS prior to relocating, regardless 

of the length of time at the new site. This helps the Division track sources in the event complaints are 

received. 

Air Quality Related Value (AQRV) Monitoring 

Section XIV.B.4.c limited the cost of AORV monitoring to 1/4 of the cost of the Additional Impact Analysis, 

including preconstruction monitoring. The Federal Land Managers testified that such a limit is not 

sufficient to provide even minimal AQRV monitoring. The limit is removed and the Division will determine 

economic feasibility on a case-by-case basis. 

Section XIV.B.1. is revised to require joint monitoring among all major sources affecting an AQRV in the 

same Class I area. This will provide for ongoing, high quality data. · 

Waste Fuel Exemptions 

Sections I.B.2.C.iii and IV.D.1.c.i (F) exempted switches to fuel derived from municipal solid waste from 

new source review. Due to the public's increased concern for toxic/hazardous emissions, many sources 

now undergo scrutiny for such emissions. All sources should be treated equally when proposing to burn 

municipal solid waste and should be required to apply the best control for reducing toxic/hazardous 

emissions. The exemptions for solid waste fuel are deleted. 

Emission Reduction Credits 

Revisions made to this portion of the Regulation are based on the Emission Trading Policy Statement; 

General Principles for Creation, Banking and Use of Emission Reduction Credits as published in 

51 FR43814. That Policy set out general principles that EPA will use to evaluate emission trades under 

the Clean Air Act. The goal of that Policy is to create more flexibility for the states and industry to help 

meet the goals of the Clean Air Act more quickly and inexpensively. The purpose of Colorado adopting 

the salient points of that Policy is to create a generic regulation, which is acceptable to EPA, and thereby 

Regulation Number 3 

Adopted: October 20, 2011 Page 238 
eliminate the need for a SIP revision for every banking or emission trading action. Other than clarifications 

and procedural changes the key changes to this portion of the Regulation include: 

a. A greater than 20% discount will be taken in areas without approved SIPs. The discount 

will be based on the level of reduction in emissions needed in that area to achieve 

attainment status. 

b. Added provisions for trading of PM-10, lead and NOx 

c. Added new criteria for modeling to determine ambient equivalence of trades. 

d. Shutdowns and curtailments in production emission reductions may be used for on-site 

replacement of equipment only. 

e. Specify no credit allowed for reduction in emissions from mobile sources unless those 

sources were subject to ambient impact and new source review. 

f. Credit for switching to a cleaner fuel is given only if a permit is conditioned to require 

control equipment to achieve the same reduction if the source switches back to the dirtier 

fuel. 

I.H. Adopted September 15, 1998 

"A Regulation Requiring Air Contaminant Emission Notices, Emission permits and Fees" 

With the passage of HB 1372, 1st session of the 56TH GA, two stationary source fees were established 

for FY 1987-88. An annual compliance-monitoring fee of $60.00 per source was to be charged .to each 

permitted source. An hourly rate of $96.00 was to be applied to all permit processing time. After 1987-88 

these fees were to be set by the Commission. These fees were to cover the "direct and indirect costs of 

such permit] processing. In establishing such fees, the Commission shall provide a higher per hour 

charge for permits which require five hours or more than for permits which require less than five hours to 

process; except that for the fiscal year 1987-88, the fee shall be ninety six dollars per hour for all permits. 

In addition to such fee for processing, the Commission shall establish and as necessary revise nonrefundable annual fees for each emissions source covered by a stationary source permit sufficient to 

cover the direct and indirect costs of administration and periodic inspections; except that for the fiscal 

year 1987-88, the fee shall be sixty dollars per year for each emissions source." 

The Division has performed a thorough analysis of the direct and indirect costs of the permit and 

compliance monitoring programs and has proposed fees to the Commission designed to meet statutory 

requirements. 

Statutory Authority 

The statutory authority for this regulation is Section 25-7-114. 

Section VI - Fees 

A General 

Paragraph 1 of this Subsection requires that all persons required to obtain an emission permit or file an 

air pollution emission notice pay fees sufficient to recover the direct and indirect costs of processing and 

issuing permits in accordance with the fee schedule shown in the Regulation. With this regulatory change, 

the following language was struck to be consistent with the statutory language: ' ... to include the 

reasonable costs of such processing or administration, and of enforcement of the permit provisions. Such 

Regulation Number 3 

Adopted: October 20, 2011 Page 239 
costs shall include the cost of predictive model utilization when the use of such models is deemed 

necessary by the Division for proper evaluation of the permit application." Paragraph 2 is unchanged. 

Sub-Sections B and C are unchanged 

D. Annual Fees 

Sub-Section D is changed by noting that the annual fees to be charged are in accordance with the 

schedule shown in the Regulation. 

Fee Schedule 

The fee schedule shows what the fees are for the hourly processing charge, the annual charge, and the 

APEN. 

1.1. Adopted August 20, 1992 

Revisions Concerning the Long-Term Strategy to Protect Visibility in Class I Areas (Section XV.F) 

Authority 

Colorado Air Quality Control Act 

The Colorado Air Quality Control Commission's (Commission) authority to revise Regulation Number 

3.XV.F, concerning the Long-Term Strategy Review of Colorado's State Implementation Plan for Class I 

Visibility Protection, is in the Colorado Air Quality Control Act. Relevant Sections are 25-7-102 Legislative 

declaration and 25-7-105(1 )(a){l) Duties of Commission. 

Federal Clean Air Act 

Additional authority for the Commission to make the regulatory revisions can be traced to the 1977 

Amendments to the Federal Clean Air Act. Section 169(A) requires the federal Environmental Protection 

Agency to promulgate regulations that in turn require states to amend their State Implementation Plans 

(SIPs) to provide for Class I visibility protection -including a long-term strategy for making reasonable 

progress toward the national visibility goal. On December 2, 1980, EPA released final regulations to 

states detailing the specific requirements - including the development and periodic revision of a long-term 

strategy as specified by federal law. 

Statement of Basis and Purpose of Changes to Regulation Number 3 Section XV. F. 

Section XV.F.1.c. 

Commission Regulation Number 3 required a Long-Term Strategy (L TS) review/revision report from the 

Colorado Air Pollution Control Division (Division) to the Commission every three years following the 

effective date of the regulation (November 1987). The August 1992 L TS report from the Division is late in 

arriving to the Commission. The purpose of the regulatory change is to clarify when subsequent L TS 

review and revision report cycles will occur. Without a regulatory change, the next L TS review would be 

due September 1993 - approximately a year from adoption of the August 1992 report. 

In order to maintain the intent that a report is to arrive to the Commission, and ultimately EPA, at least 

every three years and to allow the Division to get back on schedule with a report to the Commission in 

approximately three years, Section XV.F.I.c. was altered. 

Old language: 

Regulation Number 3 

Adopted: October 20,2011 Page 240 
(c) The Division shall prepare a report for the Commission on any progress made toward the 

national visibility goal since the last long-term strategy revisions. The report will be made 

available on September First of every third year following the effective date of this 

regulation. This report shall include an assessment of: 

New language (changes underlined): 

(c) The Division shall prepare a report for the Commission on any progress made toward the 

national visibility goal since the last long-term strategy revisions. The report will be made 

available by September First at least every third year following the submittal of the 

previous report. This report shall include an assessment of: 

Section XV.F.I.c.vii 

EPA regulations (CFR Part 40 Section 51.306) require that the L TS be reviewed in seven areas. There 

was a discrepancy between EPA requirements and State regulations regarding the seventh item to be 

assessed. The purpose of the regulatory change is to bring Commission Regulation Number 3 into 

conformance with EPA requirements. 

Old language: 

(vii) The progress achieved in developing the components of the strategy. 

New language (changes underlined): 

(vii) The need for BART to remedy existing impairment in an integral vista declared since plan 

approval. I.D. Adopted November 19, 1992 

I.J. Adopted November 19, 1992 

Revisions to Regulation Number 3, Common Provisions and Regulation Number 7 

This Statement of Basis, Specific Statutory Authority and Purpose complies with the requirements of the 

Administrative Procedure Act, C.R.S. 1973, Section 24-4-103(4) for adopted or modified regulations. 

The EPA has identified portions of the State's Prevention of Significant Deterioration and New Source 

Review (PSD and NSR) rules, which do not conform to the Federal rules. The State rules must be at 

least as stringent as the Federal rules in order for the EPA to approve the State Implementation Plans. In 

addition, the State must revise the rules to include the addition of new requirements that were set forth in 

the 1990 Federal Clean Air Act. The EPA has also identified additional non-reactive volatile organic 

compounds, and a significant level for municipal waste combustor emissions. All of these revisions must 

be made for EPA approval. 

The 1992 State Legislature revised the Colorado Clean Air Act to include new definitions and fee 

requirements. In addition, the revisions allow the Commission to make necessary revisions to the State's 

PSD and NSR rules, as described above. 

Specific Authority 

The specific authority for this regulation is contained in the Colorado Air Quality Control Act, 1992 as 

amended. Section 25-7-103 sets forth definitions for use in implementing the new Colorado Act. Section 

25-7-105 (1)(A)(I) requires the Commission to adopt into the State Implementation Plan all requirements 

of the federal act. Sections 25-7-105(1){c), 203, 204, 205, 206, 210 and 301 provide authority to adopt a 

Regulation Number 3 

Adopted: October 20,2011 Page 241 
PSD and NSR program in conformance with the Federal and Colorado Acts. Section 25-7-105.1 sets 

forth the Commission's authority regarding Federal enforceability. Section 25-7-106 (1)(c) provides 

authority for adopting regulations, which are applicable to entire state, or only within specific areas or 

zones, or only to a particular pollutant. Section 25-7-114.5 sets forth time frames for the Division to 

review permit applications, and procedures for owners and operators to demonstrate compliance with 

construction permits. Section 25-7-114.7 sets forth fee requirements. Commission action in promulgating 

these revisions is taken pursuant to Sections 25-7-105 through 25-7-109 and 25-7-114, C.R.S., as 

amended. 

Purpose 

New Source Review Rules 

Regulation Number 3 contains the permit requirements for major sources (Prevention of Significant 

Deterioration, PSD and New Source Review, NSR). The Common Provisions Regulation contains 

definitions that are used in the permit requirements of Regulation Number 3. The PSD and NSR 

requirements and definitions must be equivalent to the Federal requirements. The EPA has identified the 

portions of Regulation Number 3 and the Common Provisions, which do not conform to the Federal rules. 

On October 17, 1991, the Commission adopted revisions to Regulation Number 3 and the Common 

Provisions, to address some of the EPA's concerns. Additional concerns remained, however, because 

some of them could not be addressed until the Colorado Clean Air Act was revised. On May 27, 1992, 

the Governor signed Senate Bill 1 05, which revised the Colorado Clean Air Act to allow the Commission 

to proceed with the remaining necessary revisions to Regulation Number 3 and the Common Provisions. 

The new Colorado Act is effective as of July 1, 1992. 

The 1990 Federal Clean Air Act revisions set forth additional revisions, which must be made to all State 

PSD and NSR rules. 

The Commission has adopted the necessary revisions, which address the remaining EPA concerns 

regarding the State's PSD and NSR rules. These revisions are required to eliminate discrepancies 

between the State and Federal rules, and for approval of our State Implementation Plan. The required 

revisions are as follows. 

Regulation Number 3 

1. The regulation previously allowed sources of fugitive emissions to be exempt from the 

NSR and PSD requirements. The Federal Act does not allow the exemptions. Several 

Sections throughout the regulation needed to be revised or eliminated: 

Section I. E. - Eliminate the reference to the definitions of major stationary source and 

major modification from the definition of fugitive dust; 

Section I.B.3.e. and f- Eliminate the references to fugitive dust from the definition of 

major source; 

Section IV.D.3.b.(i)(B)- Eliminate the fugitive dust exemption from the PSD rules; 

Section XI - Eliminate the fugitive dust exemption from increment consumption 

requirements. 

2. Section I. 8.2, Section (vii) of the regulation allowed sources, which switched from oil or 

gas to a coal-derived fuel (shale oil) to be exempt from the PSD and NSR requirements. 

This is not allowed under the Federal Act, therefore (vii) is removed from the definition of 

major modification. 

Regulation Number 3 

Adopted: October 20, 2011 Page 242 
3. The new Federal Act requires major sources in nonattainment areas obtain to offsets 

from sources that are also located in the same nonattainment area, unless a source 

outside of the area contributes to nonattainment in the area in which the major source is 

located. Section IV.D.2.a(iii) is revised to add this new requirement. 

4. The Federal Act does not allow major sources located in a "clean portion" of a 

nonattainment area to be exempt from the NSR requirements. Section IV.D.2.c.(ii) is 

revised to eliminate the clean portion of a nonattainment area exemption. 

5. Section IV.D.3.e. required minor sources which contribute to the exceedance of an 

ambient air standard in a non-designated area (not designated attainment or 

nonattainment) to apply best available control technology. This requirement was 

previously adopted to comply with the EPA's interim policy for the PM-10 ambient air 

quality standards. The provision applied until the EPA was able to formally designate 

areas as attainment or nonattainment for PM-10. Now that the EPA has designated 

areas, the PSD and NSR (nonattainment) rules apply and Section IV.D.3.e. has been 

removed. 

6. The regulation previously stated that certain permit conditions had to be removed from 

the permit upon issuance of final approval. The conditions on a final permit were limited 

to the list of items required to obtain a permit. The Federal Act requires that permits must 

contain all conditions necessary to ensure compliance with all applicable requirements, 

and any conditions necessary to make limits on production rates, hours of operation, the 

potential to emit, etc. federally enforceable. The language that limits the enforceability of 

permit conditions after Final Approval is removed from Section IV. E. 

7. The Federal Act does not allow automatic approval of permits if the State fails to meet 

processing deadlines. The language that provides for automatic approval of permits if 

processing deadlines are not met is removed from Section IV.F. Likewise, confidentiality 

determinations do not affect the time constraints in the regulation. Section VII is revised 

to reflect this. 

8. The new Federal Act does not allow reductions of pollutants required to meet any Act 

requirements to be credited for use as offsets. Language is added to Section V.E.9 of 

the State's Emission Reduction Credit rules to clarify this requirement. 

9. The new Federal Act no longer limits the boundaries of Class I areas to those that existed 

in 1977. Section VIII is revised to eliminate this restriction. 

10. The Federal rules state that if innovative technology is used by a PSD source, they are 

only exempt from the BACT requirements, not all of the PSD requirements, and that the 

consent of governors of other affected states must be obtained. Section XIII previously 

exempted such source from all PSD requirements. The Section is revised to clarify this 

allowance. 

Common Provisions Definitions: 

1. The EPA has added visible emission standards to applicable emission limitations under 

the definition of Best Available Control Technology. The State's definition is likewise 

revised. 

2. Under the new Federal Act, Asbestos, Beryllium, Mercury, and Vinyl Chloride are now 

regulated under new hazardous pollutant requirements (Maximum Achievable Control 

Technology). These compounds are no longer subject to Prevention of Significant 

Deterioration (PSD) requirements (which would require Best Available Control). The 

Regulation Number 3 

Adopted: October 20, 2011 Page 243 
definition of significant, which determines when a source is subject to PSD, is revised to 

omit these pollutants. 

The Federal rules do not allow an exemption from PSD and NSR rules for right of ways, pipelines, etc. 

The definition of stationary source is revised to delete this exemption. 

Non-Reactive VOCs: 

On March 18, 1991, the EPA added five halocarbon compounds and four classes of perfluorocarbons to 

the list of organic compounds, which are negligibly reactive, and thus exempt from regulation as Volatile 

Organic Compounds under Regulation Number 3, the Common Provisions, and Regulation Number 7. In 

addition, the EPA revised the definition of Volatile Organic Compound. 

The Non-reactive Volatile Organic Compound (VOC) list, as amended by the EPA, is incorporated into 

Regulation Number 3, Section IV.D.4, the Common Provisions (definition of Net Emission Increase, 

paragraph h.), and Regulation Number 7, Section II.B. The State is not allowed to take credit for 

controlling these compounds in our SIP. In other words, sources cannot use reductions of emissions of 

these compounds to offset VOC emissions, and we are not allowed to include emissions of these 

compounds in our SIP inventory. The EPA has determined that these compounds do not react in the 

atmosphere to produce ground level ozone. 

The EPA also revised the definition of "Volatile Organic Compound" to make slight clarifications. The 

definition in the Common Provisions and in Regulation Number 7, Section II.A.1. is likewise revised. 

Municipal Waste Combustor Emissions Significant Level: 

On February 11, 1991, the EPA promulgated New Source Performance Standards for Municipal Waste 

Combustors. In addition, the EPA promulgated "significant emission levels" for municipal waste 

combustor emissions. These significant levels are used to determine if PSD requirements apply to major 

sources. 

The Commission revised the definition of "Significant" in the Common Provisions Regulation, to add the 

emission level for municipal waste combustqr emissions. This addition is required in order to conform to 

the Federal PSD and NSR rules. 

Senate Bill92-105 Revisions 

Senate Bill 105 revised the Colorado Clean Air Act. The new Colorado Act contains some new and 

revised provisions which are relatively simple and straightforward, and which could therefore be easily 

adopted into Regulation Number 3 and the Common Provisions at this time. These particular revisions 

were adopted to facilitate transition from the old Act to the new Act, and to eliminate confusion that could 

occur due to differences between the new Act and the existing regulations. The proposed revisions are 

as follows. 

Regulation Number 3 

1. Sections IV.B.3, 4 and 5- The new Act gives the Division 60 days (instead of the 

previous 20 days) to determine if an application is complete. In addition, the Division has 

12 months to complete the application process for PSD construction permit applications 

(previously limited to 135 days). 

2. Section IV.C.1.c- Change the reference date for the definition of hazardous pollutant. A 

new definition has been adopted in the new Act. The definition includes the list of 189 

chemicals from the Federal Act, and an additional list contained in the Colorado Act. 

Regulation Number 3 

Adopted: October 20,2011 Page 244 
3. Section IV.H- Change the procedures for granting of final approval construction permits. 

Previously, the Division had only 30 days once a source commenced operation to inspect 

the source to determine that all permit conditions were being met. The source now has 

180 days to demonstrate compliance. Also previously, the Division could allow a source 

additional time to come into compliance before Final Approval was issued. Now the 

Division must grant Final Approval or revoke the permit. 

4. Section VI- The new Act sets forth new fee schedules for permits, annual fees, and 

APENS. The permit fees have changed from a schedule based on the type of facility to 

$50 per hour for all applications. The Division cannot exceed 30 hours in processing time 

unless the applicant is first notified that 30 hours will be exceeded. The annual fees are 

no longer based on the number of sources at, or the size and complexity of a facility. 

Instead annual fees are based on actual emissions. The APEN fee has changed from 

$60 to $75 for fiscal year 92. 

Common Provisions 

1. Section I.C- Incorporates the new Legislative Declaration of the new Act. The new 

declaration adds to the existing declaration that an accurate emission inventory is 

necessary for implementation of the air quality requirements.. 

2. Incorporates the new Acts definition of Air Pollutant. The definition is the same as 

previous except that precursors are now also considered" air pollutants." Precursors can 

be emissions such as nitrogen and sulfur oxides, which can contribute to particulate 

matter emissions. 

3. Revise definition of Emission Control Regulation. The new definition is the same, except 

such regulations can now include work practices and design, equipment, and operational 

standards. In addition, such regulations that apply to hazardous pollutants must be 

consistent with the new Act requirements concerning hazardous pollutants. 

4. Revise definition of Federal Act to reference 1990. (Previously referenced 1977.) 

5. Revise the definition of Federally Enforceable to indicate that the Division has authority to 

issue permits to synthetic minor sources. 

6. Revise definition of Hazardous Air Pollutant. The new definition includes the pollutants 

listed under the Federal and Colorado Acts. 

7. Refers to Adverse Environmental Effect, therefore this definition is added. 

8. Add definition of Ozone Depleting Compound. The fee schedule requires the Division to 

charge fees for emissions of such compounds, therefore the definition is added. I.E. 

I.K. Adopted June 22, 1993 

Revisions to Regulation Number 3 Regarding Construction Permits 

This Statement of Basis, Specific Statutory Authority and Purpose complies with the requirements of the 

Administrative Procedure Act, C.R.S. 1973, Section 24-4-103(4) for adopted or modified regulations. 

The Colorado Clean Air Act requires stationary sources to report their emissions, obtain construction 

permits, and be subject to public notice before construction occurs. The Commission has authority to 

Regulation Number 3 

Adopted: October 20, 2011 Page 245 
exempt sources from these requirements, if the sources do not have a significant adverse impact on air 

quality. Regulation Number 3 has been in effect for approximately twenty years, and contains exemption 

lists for APEN and permit requirements. Based on twenty years of experience, the Commission believes 

it is appropriate at this time to revise the exemption lists to include additional sources, which do not 

adversely affect air quality in Colorado. In addition, it is appropriate to revise the public notice 

requirements to address the sources for which is public comment is most likely to be received. 

The 1992 State Legislature revised the Colorado Clean Air Act to include new provisions concerning noncriteria pollutants. The Commission needs to address these provisions and revise the APEN reporting, 

permitting, and public notice requirements regarding these pollutants. 

A technical revision must be made to the definition of "significant," contained in the Common Provisions, 

to address major sources in nonattainment areas, as required under the Federal Act. 

Specific Authority 

The specific authority for this regulation is contained in the Colorado Air Quality Control Act, 1992 as 

amended. The Legislative Declaration, Section 25-7-102, recognizes that an accurate emission inventory 

is needed in order to adequately manage air resources in Colorado. Section 25-7-105 (1)(A)(1) requires 

the Commission to adopt into the State Implementation Plan all requirements of the federal act. Sections 

25-7-105(1)(c), 203, 204, 205, 206, 210 and 301 provide authority to adopt a PSD and NSR program in 

conformance with the Federal and Colorado Acts. Section 25-7-105(12) provides authority to adopt 

regulations to implement the emission notice and construction permit programs. Section 25-7-106 (1)(c) 

provides authority for adopting regulations, which are applicable to the entire state, or only within specific 

areas or zones, or only to a particular pollutant. Section 25-7-109.3 provides authority for regulating noncriteria pollutants. Section 25-7-111 provides authority for the Division to administer regulations adopted 

by the Commission. Section 25-7-114.1 provides authority for requiring APENS, and for allowing 

exemptions from the requirement. Section 25-7-114.2 provides authority for requiring construction 

permits, and for allowing exemptions from the requirement. Section 25-7-114.5 provides authority for 

requiring public notice of construction permits. 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 

Definition of "Significant" 

The Common Provisions Regulation contains definitions that are used in the Prevention of Significant 

Deterioration (PSD) and New Source Review (nonattainment, NSR) permit programs of Regulation 

Number 3. The PSD and NSR requirements and definitions must be equivalent to the Federal 

requirements. The definition of significant lists emission levels at which modifications at major sources 

become subject to the PSD and NSR requirements. Currently, the language in the definition indicates 

that the emission levels only trigger PSD requirements. The definition is changed to indicate that the 

levels also apply to the NSR nonattainment rules. 

APEN Requirements - General 

This language is revised to clarify what emission estimates must be included in an APEN (actual 

emissions for annual fee purposes, and requested amount for permit limits). In addition, language is 

added to clarify that a source need not perform a stack test for the sole purpose of providing an APEN 

emission estimate. Other acceptable estimation methods are usually available for APEN purposes. In 

some instances, it is possible that an emission factor may supply a more accurate estimate than mass 

balance calculations, and vice versa. In such cases, a source may choose to use either mass balance, or 

emission calculations. If the Division believes that estimates can be better made using the method of 

these two that the source does not choose, the Division may question that source regarding the choice. 

The emission estimate included in an APEN is not required to be an exact calculation of emissions, but 

Regulation Number 3 

Adopted: October 20, 2011 Page 246 
rather the source's best estimate, to the extent practical, of emissions. As stated in the Legislative 

Declaration of the Colorado Air Quality Control Act, the APEN information is to be used to achieve the 

most accurate and complete inventory possible, and to provide for the most accurate enforcement 

program achievable based upon that inventory. 

The Colorado Clean Air Act states that APENs are valid for five years, unless a significant change in 

emissions occurs. This provision is added to the regulation. 

Language is added to clarify that each unit is considered to be a "source" for APEN purposes, unless 

similar sources can be grouped together. 

Emission calculations for purposes of determining if a de minimis emission level is triggered will be based 

on actual uncontrolled emissions. Sources will not be allowed to take credit for control devices in the de 

minimis calculation because the Commission has no method of determining if the control equipment will 

be used, or used continuously and properly. 

The Commission believes there may be cases where the source demonstrates that it is not feasible to 

estimate the control efficiency of a device for non-criteria pollutants. In such instances, the Commission 

gives the Division discretion to allow the de minimis level to be triggered based on actual, instead of 

uncontrolled actual, emissions. New language is added regarding non-criteria pollutant APEN 

requirements. 

Revised APEN Requirements 

The Colorado Act requires revised APENs to be submitted whenever a "significant change" in emissions 

occurs. The significant levels for criteria pollutants remain unchanged from the previous regulation, 

except that a significant level has been added for lead emissions. For non-criteria pollutants, the 

significant change level is set at 50% or five (5) tons per year, whichever is less. 

Sources should note that APENs must be submitted if the source begins to emit a pollutant which was 

previously not included on an APEN. Also, the Commission may add pollutants to the list of non-criteria 

reportable pollutants. When chemicals are added, the Commission will determine the schedule for 

submitting new or revised APENs to report the new pollutant emissions. 

NOTE: Significant change criteria are used to report changes in emissions for inventory purposes only. If 

a planned change in emissions requires a new permit, or modification of an existing permit (violates an 

emission limit, triggers PSD or NSR), then an APEN must be filed and the permit must be revised before 

the change at the facility occurs. 

Revised APENs for emission updates must be submitted by April 30 of the following year. The EPA 

requires states to update the emission inventory by July 1 of each year, to include the previous year's 

emissions (Code of Federal Regulations, 40 CFR 51.321 ). The Commission believes the April 30 date 

should give sources enough time to compile their inventory, and will also give the Division enough time to 

update the system by July 1. Sources should plan ahead and have as much of their inventory completed 

as possible before the end of the year. In this way, the source would then only need to add December, or 

at worst information for the last couple of months of the year, to the data in order to meet the April 30 

deadline. 

Revised APENs are required when a change in the type of control equipment being used is made. This 

allows the Commission to ensure that the new control equipment will meet the applicable requirements, 

and to verify that actual emissions have decreased or increased due to the use of the new equipment. 

Oftentimes, stack tests are required to ensure that control equipment meets applicable requirements. A 

change in the control equipment can affect this compliance determination. Revised APENs will not be 

required for routine maintenance, repair and replacements. These routine activities should not affect the 

effectiveness of the equipment. 

Regulation Number 3 

Adopted: October 20,2011 Page 247 
Permit applications must include an APEN on which the owner or operator indicates what production or 

emission level the source wishes to be permitted at. Any desire to increase the permitted emission level 

requires the submittal of a revised APEN, so that the Division can evaluate the change against the 

regulations before modifying the permit. 

Portable Facilities 

Revised APENs are no longer required when a portable source changes location. The Commission does 

not believe it is reasonable to charge the APEN filing fee each time a source moves. Portable sources 

will still be required to notify the Division at least ten (1 0) days before relocating. This allows the Division 

to be aware of a source's location if any concerns regarding the source are raised by the public. 

Emergency and Backup Generators 

Electric utilities may use emergency or backup generators to ensure that blackouts do not occur in the 

electrical grid. These units are usually operated instead of, or for short periods in addition to, main utility 

boilers. Facilities that include the main boilers are usually major sources, and therefore have a major 

source construction permit, or will in the future have a major source-operating permit. Once the facility is 

covered under one of these permits, the Commission sees no need for the owner or operator to submit 

annual updates regarding the emissions from the emergency units. 

Other emergency units are not located at the main unit facility, but are located individually in the field. 

These units will most likely obtain a synthetic minor permit to avoid major source permit requirements, 

since operation is usually intermittent. Once such sources obtain a synthetic minor permit, the 

Commission again will not require the source to submit annual emission updates. 

APEN Requirements - Non-Criteria Pollutants 

There are 363 non-criteria reportable pollutants. The Commission divided the pollutants in two major 

groups: those that are required to be reported in 1993, and those that have to be reported in 1994 and 

subsequent years. There are also two groups of chemicals (Radionuclides and Polycyclic Organic 

Matter) whose reporting requirements were postponed until such time as the Commission determines that 

they can be accurately quantified and reported. 

APEN Requirements - De Minimis Levels 

All de minimis levels are based on uncontrolled actual emissions (except where the control efficiency 

cannot be estimated), as discussed above under General APEN Requirements. 

APENs are required of sources in attainment areas when the emissions of any criteria pollutant from a 

source exceed two tons per year (except for lead). 

Sources in nonattainment areas must file when emissions of any criteria pollutant exceed one ton per 

year. Note that the pollutant being emitted above the de minimis level does not have to be a 

nonattainment pollutant. Any pollutant triggers the one-ton per year level, regardless of the pollutant's 

attainment designation. 

Because the area is a growth area, and inversions occur in the area, a Grand Junction group requested 

that APENs be filed when emissions of any criteria pollutant exceed one ton per year. The Commission 

determined that hearings should be held in the Grand Junction area, and that Grand Junction should 

pursue their own rules. Language that would have treated Pueblo likewise is not included, due to 

requests from industries in Pueblo, and the Pueblo County Health Department. 

The de minimis level for lead in all areas is 1 00 pounds per year. 

Regulation Number 3 

Adopted: October 20, 2011 Page 248 
For non-criteria pollutants, the Commission assigned each pollutant to one of three "bins" based on 

information concerning the health effects of the pollutant. The Commission also developed a series of 

three scenarios for an emission point based on the release height of the pollutant and the distance from 

the release point to the property boundary. The resulting three by three grid as well as instructions on 

how to apply it can be found in Appendix A. Note that future actions by EPA may effect the de minimis 

reporting levels for certain chemicals that appear on the EPA fist of 189 toxic chemicals. 

APEN Requirements - Exemption List 

Numerous new source categories have been added to the APEN exemption fist. Each category was 

examined for its impact on air quality in Colorado before being added to the fist. Each category that was 

added is believed to have a negligible impact on air quality. 

The source category exemptions override the de minimis levels. Sources that fit into the category are 

exempt, even if emissions exceed the de minimis levels. 

Each category will not be addressed individually in this statement, however the following categories 

deserve specific comment. 

Fires and equipment used for cooking of food for human consumption: Not all cooking equipment has 

been exempted in this category. The Commission has concerns regarding equipment in which grease 

from the food being cooked comes into contact with the flame of the equipment, thus leading to potential 

opacity and particulate matter problems. This is especially of concern in PM-10 nonattainment areas. 

This exemption applies only to noncommercial cooking and to food service establishments, such as 

restaurants and cafeterias. The exemption does not apply to manufacturing facilities. 

Fuel burning equipment: The design rate cutoff for fuel burning equipment has been raised from 750,000 

BTU/hour to 5 MMBTU/hour. The fuel use is still restricted to gas, and does not include oil or coal, since 

the fatter two fuels may result in significant sulfur dioxide emissions. Fuel burning equipment which uses 

gaseous fuel and which is used solely for building heat is exempt if the design rate is below 10 

MMBTU/hour. The Commission has determined that the emissions from the exempted unit, based on 

EPA AP-42 emission factors, are negligible. 

Chemical storage areas where chemicals are stored in closed containers ... : This exemption only applies 

to the storage of chemicals at qualifying facilities. The exemption does not include facilities where 

chemicals are loaded into or out of, or transferred between, storage containers. Bulk storage tanks would 

not qualify for this exemption, since often the material is loaded and unloaded, and such tanks have vents 

from which emissions occur due to breathing losses. See Sections ff.D.1.n., ee., uu., ddd. and fff. for 

storage tank exemptions. 

The Commission will require APENs only for pollutants that are defined as "criteria" pollutants or 

"reportable non-criteria" pollutants (HAPs, CFCs, SARA 313). Any other pollutants such as carbon 

dioxide, methane, nitrogen, oxygen, do not require APEN submittals. 

Aerosol Can Usage: There may be instances where a source may exclusively use farge amounts of 

aerosol cans, or may use farge amounts in addition to other processes. The Commission expects that 

these instances will be rare. If the Division, a focal agency, or others discover such a source, and if the 

source emits amounts of pollutants, which are believed not to be negligible, such concern can be brought 

before the Commission as a request to require such source to fife APENs and/or obtain a permit. (See 

discussion under "Adding and Deleting Exemptions," below) 

Odorous emission sources: This exemption only applies to odor emissions, and not to any other 

emissions of criteria or non-criteria pollutants, which may be associated with the odor. This exemption 

does not absolve any source from the requirements of Regulation Number 2 (regarding odor limits) . .!.f..g 

Regulation Number 3 

Adopted: October 20, 2011 Page 249 
source emits any pollutant that is above an APEN de minimis level, the source must file an APEN, 

regardless of odor. 

Portable 5 mm btu/hour engines: One party requested that these sources be exempt from APEN and 

permit requirements. The Commission has determined that sufficient evidence is not available to indicate 

that emissions from these sources have a negligible impact on air quality in Colorado, therefore they are 

not exempt until such evidence is forthcoming. 

Laboratory equipment and pilot plants: The subcommittee for these rule revisions held extensive 

discussions regarding exemptions for laboratory equipment and pilot plant activities. More work is 

needed to define these activities, determine if the emissions are negligible, and if such activities should 

be exempt from APENS, permits, or both. The Commission recommends that subcommittee discussion 

of this issue continue, and that it be addressed when Regulation Number 3 is revised to include the Title 

V operating permit rules (currently ~cheduled to occur in July of 1993). 

Adding and Deleting Exemptions 

The Commission has delegated authority to the Division for adding source categories and activities to the 

APEN and permit exemption lists. If any person believes that a source category or activity should be 

removed from the exemption lists, because it is discovered that emissions have an impact on air quality or 

health that is not negligible, such person may at any time go before the Commission to request that such 

source category or activity be required to file APENs and/or obtain permits. 

Oil and Gas Exploration Activities 

Oil and gas exploration activities are activities for which it is difficult for the owner or operator to estimate 

what emission equipment will be required, and therefore what emissions will occur, until the exploration 

activities are already underway, and near completion. For this reason, the Commission has extended a 

temporary exemption from APEN and permit requirements for such activities. Before commencing 

exploration activities, the source must notify the Division. In this way, the Division is aware of the 

activities and will be able to address any concerns that are raised by the public. Once an owner or 

operator has determined that an oil or gas well will be produced, and has filed well completion 

information, the owner or operator must file an APEN and a permit application within 30 days of that 

completion filing. The permit application must indicate what regulations are applicable to the source, and 

how compliance will occur, until the construction permit is issued. This helps the source and the Division 

to ensure that air pollution regulations are being met. If the well will not be produced, the source must 

notify the Division so that the Division does not expend resources following up on unproduced wells. 

APEN Reporting Deferrals for Source Categories 

Due to ongoing studies aimed at quantifying their emissions of non-criteria pollutants, the Commission 

has deferred APEN reporting requirements for five source categories until six (6) months after the studies 

have been completed or December 31, 1994, whichever is earlier. The categories are industrial boilers, 

municipal wastewater treatment plants, publicly owned water treatment plants, municipal power 

generators of less than ten (10) megawatts, which operate for 250 hours or less per year, and natural gas 

glycol dehydration units. The EPA is conducting studies regarding the first four categories. The oil and 

gas industry is conducting studies to quantify emissions from dehydration units. This study is currently 

underway and is expected to be completed in the near future. 

In addition, sources which are not undergoing study, but which believe sufficient information is not 

available for estimating their non-criteria pollutant emissions, may petition the Division for deferral of 

those emissions until sufficient information is available. 

HAP Permit Requirements 

Regulation Number.3 

Adopted: October 20, 2011 Page 250 
Of the 363 non-criteria pollutants/compounds, 330 are defined as hazardous air pollutants (HAPs). 

Sources emitting HAPs are required to obtain permits if they are subject to Colorado MACT or GACT or 

the Federal Title Ill or Title V provisions. 

Synthetic Minor HAP Sources 

Some parties to the hearing requested that sources which emit HAPs be allowed to avoid future 

Maximum Achievable Control Technology (MACT) and operating permit requirements by obtaining 

"synthetic minor'' permits. These permits would contain federally enforceable limits, which would keep 

emissions below the levels, which trigger the MACT and operating permit requirements. The Colorado 

Act appears to restrict synthetic minor permits to criteria pollutants only. The subcommittee 

recommended that this issue be deferred to the HAP subcommittee, which will meet in the near future to 

address Colorado MACT and other HAP issues. Synthetic minor permits for HAP sources are therefore 

not addressed in this revision. 

Permit Transfer of Ownership 

The party to which a permit is issued, whose name is included on the permit, is legally responsible for 

ensuring that all conditions and terms in the permit are met. The permit must contain the correct legal 

name, reflecting the correct responsible party, in case an enforcement action needs to be taken. In some 

cases, the legal name of a company may change, while no modifications are made to the equipment. In 

such cases, the source need only file a single APEN indicating the change. In all cases, the Division 

must have on file an application and APEN form with the correct name of the responsible party, and 

including the signature of the person legally responsible for the information. 

Permit Requirements - De Minimis Levels 

Permit de minimis levels for criteria pollutants have been increased. Levels differ based on the 

attainment status of the area. As for the APEN de minimis levels, the nonattainment area levels are 

triggered by any pollutant, not just the nonattainment pollutants. 

Language, which would have set permit levels for the Grand Junction area lower than the levels for 

attainment areas, was not adopted. See discussion above under APEN de minimis levels. 

Emissions are compared against the de minimis levels by adding emissions from all sources at the facility 

that are required to file and APEN. In some cases, a source may initially be below the de minimis levels, 

but as new units are added to the facility, the de minimis level is eventually exceeded. At such time that 

addition of new units causes the permit de minimis level to be exceeded, the source must file a permit 

application for all units at the facility. 

Permit de minimis levels for sources of HAPs will be set at the time that the MACT or GACT for that 

source category is determined. 

Permit Requirements - Exemption List 

A few new source categories have been added to the permit exemption list. As for APENs, the source 

category exemptions override the de minimis levels. 

Domestic wastewater treatment works: This exemption applies only to treatment facilities which handle 

wastewater strictly from domestic homes, or wastewater that is similar in nature. It does not include 

facilities that treat wastewater from municipalities or other sources. The facility may be publicly or 

privately owned. Wastewater other than domestic wastewater, including municipal wastewater, may 

contain contaminants from industry and other sources which would result in emissions which are much 

more significant than the emissions from domestic wastewater. 

Regulation Number 3 

Adopted: October 20, 2011 Page 251 
Fuel burning equipment: Fuel burning equipment with a design rate less than 10 MMBTU/hour, using 

natural gas as a fuel, are exempt from permit requirements because this is the rate at which the New 

Source Performance Standard for small boilers is applicable (Regulation Number 6). 

Surface Mining Activities: 70,000 tons per year is the production rate at which the Mine Land 

Reclamation Bureau exempts mining operations from MLRB permit requirements. Oftentimes, these small 

operations are only temporary, in order to provide material for highway construction projects. The source 

has often ceased operation before an Air Pollution Control inspector can visit the source to determine 

compliance. Crushers, screens and other processing equipment are not exempt because these activities 

may be subject to specific air quality emission limit regulations. 

Applicable Requirements Override APEN and Permit Exemptions 

To ensure that sources comply with all applicable air quality regulations, an APEN or permit exemption 

may not be used if taking the exemption would allow a source to avoid any air quality regulation 

requirements. This provision applies to the source category exemptions and to the de minimis level 

exemptions. For example, a source may not claim that it is exempt from permit requirements because it 

has numerous sources, which are below a de minimis level, if the potential emissions from those sources 

would exceed the PSD major source limit of 100 or 250 tons per year. In such a case, the source would 

be required to apply for a PSD permit, or must obtain a permit to limit its potential to emit. In order to limit 

potential to emit, the permit must contain federally enforceable conditions, which limit the physical or 

operational capacity of the source so that emissions are below the 1 00 or 250 ton per year level. 

Sources, which are subject only to the opacity or general fuel burning and manufacturing requirements of 

Regulation Number 1, may take any applicable exemption. Likewise, sources, which are subject to the 

general RACT requirements (but not the specific RACT requirements) of Regulation Number 7, and 

sources, which are subject to the current Regulation Number 8 provisions, may take any applicable 

exemptions (i.e., they are exempt if their emissions are below de minimis levels). RACT for sources that 

would qualify for the APEN exemptions is usually "no control." 

Similarly, sources which are subject only to Regulation Number 1 opacity, general fuel burning, and 

general manufacturing requirements are exempt from permit requirements. Sources which are subject to 

Regulation 7, but which must adopt only work practice standards, are exempt from permit requirements if 

their emissions fall below the de minimis level (two tons per year of VOC). Sources, which are subject to 

State-only requirements of Regulation Number 8, are exempt from permit requirements. 

Regulation Number 1, 7 and 8 sources, which take APEN or permit exemptions must still meet the 

regulation requirements, even though an APEN or permit is not required. The provisions that would apply 

to these sources are straightforward and can therefore be easily enforced by the Commission through the 

regulation, without requiring a permit. 

Public Notice Requirements 

The criteria pollutant emission level at which a source in an attainment area must go to public notice has 

been increased from 25 to 50 tons per year (except for lead). In nonattainment areas, the level remains 

at 25 tons per year. Lead sources are required to go to public notice when the emissions exceed 200 

pounds per year. The Commission has determined that raising these levels will not impact the number of 

public comments the Division receives. Any source requiring a permit for HAPs is required to go to public 

notice. 

Note that Section I IV.C.3 provides that the Division may require any source to be subject to public 

comment, if it is determined that such source warrants public comment. The EPA requires that all 

sources subject to PSD or NSR go to public comment. In addition, in order to make limits on potential to 

emit federally enforceable, permits containing such limits must go to public notice. At this time, the 

Commission will use this Section to ensure the EPA requirements are met. Language will be added to 

Regulation Number 3 

Adopted: October 20,2011 Page 252 
clarify these requirements when the next revision to Regulation Number 3 occurs (currently scheduled to 

occur in July of 1993). 

I.L. Adopted July 15, 1993 

Revisions to Regulation Number 3 

This Statement of Basis, Specific Statutory Authority and Purpose complies with the requirements of the 

Administrative Procedure Act, C.R.S. 1973, Section 24-4-103(4) for adopted or modified regulations. 

The 1990 Amendments to the Federal Clean Air Act requires states to implement an operating permit 

program. This program is applicable to certain sources, and requires the sources to obtain detailed 

permits, which are to be renewed every five years. 

Failure of a state to implement an operating permit program will result in EPA sanctions, such as loss of 

highway funds and increased offset requirements for sources wishing to locate in Colorado nonattainment 

areas. In addition, the EPA may implement the operating permit program if a state fails to implement a 

program. 

The existing construction permit program will continue to exist, however changes have been made to the 

program so that the two permit programs (construction and operating) compliment each other. 

Specific Authority 

The specific authority for this regulation is contained in the Colorado Air Quality Control Act, 1992 as 

amended. Section 25-7-105(1)(A)(I) requires the Commission to adopt into the State Implementation 

Plan all requirements of the federal act. Sections 25-7-105(12) provide authority to implement the 

operating permit provisions of Title V of the Federal Act. Section 25-7-1 05.1 sets forth federal 

enforceability provisions. Section 25-7-1 06(6) provides authority for monitoring, record keeping and 

reporting requirements, Section 25-7- 109.3 provides authority for regulating hazardous air pollutants 

(HAPs). Section 25-7-111 provides authority for the Division to administer regulations adopted by the 

Commission. Section 25-7-114.1 provides authority for requiring APENS, and for allowing exemptions 

from the requirement. Sections 25-7-114.2 through 114.5 set forth construction and operating permit 

requirements, and application and public participation requirements. 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 

NOTE: Subcommittee documents, which discuss the issues and decisions regarding this regulation in 

detail, and provide fact sheets for various provisions, are available at the Division and Commission 

offices. 

I. Operating Permit Program: 

A Who is subject to the Operating Permit Program? 

Regulation Number 3 

Adopted: October 20,2011 

1. Definition of Air Pollutant 

Sources with potential to emit* 100 tons per year of any air pollutant must obtain 

an operating permit (these sources are referred to as 'major sources"). For 

purposes of the operating permit program, air pollutant means any pollutant for 

which an ambient air quality standard has been set (and their precursors), any 

pollutant which is regulated under the New Source Performance Standard 

Page 253 

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regulations (NSPS, Regulation Number 6), any Class I or Class II ozone 

depleting compound, and any hazardous air pollutant (all HAPs listed in either 

the Federal or Colorado Acts). 

The Commission has determined that it is not appropriate to use the Colorado 

Act definition of air pollutant for operating permit purposes. The Act defines air 

pollutant as being any substance emitted to the ambient air, except for water 

vapor. Since many substances occur naturally in ambient air, and others will 

never be subject to any air regulations, operating permits are not needed for 

emissions of such pollutants. 

Major sources of any air pollutant as defined for operating permit purposes must 

obtain an operating permit, even if no specific standard has been set for the 

particular air pollutant (see further discussion under "regulated pollutant," below). 

2. Major HAP Sources 

Sources, which have potential to emit 10 tons per year or more of a single HAP 

or 25 tons per year or more of a combination of HAPs, are considered" major 

sources," and must obtain an operating permit, even if no standard for the HAP 

has yet been set. 

Major sources of Colorado HAPs must obtain an operating permit. Permit 

conditions related to Colorado HAPs will be treated as state only conditions (see 

further discussion below). 

*See definition of potential to emit, Part A of this regulation. Potential emissions are calculated assuming 

the source operates continuously, at full design rate, using no pollution control equipment. See additional 

information and details in subcommittee papers (Group D, Synthetic Minors Issue Paper and Fact Sheet). 

Regulation Number 3 

Adopted: October 20, 2011 

3. Fugitive Emissions 

Fugitive emissions must be included when determining if a source is major for 

HAPS. Fugitive emissions must be included when using the 1 00-ton per year 

threshold (to determine if the source is major) if the source is listed, or if the 

source and pollutant is subject to any NSPS or Title Ill regulation. 

Fugitive emissions must be included as required for the Prevention of Significant 

Deterioration (PSD) and nonattainment new source review (NSR) programs. 

The Commission has not included language,· which exempts fugitive dust 

sources from the major source definitions at this time. Further investigation is 

occurring regarding HAP emissions from such sources, and discussions with 

EPA will continue to determine how to treat such sources. Once these activities 

are completed, the Commission will consider this issue. 

4. Applicability Determinations 

Sources are ultimately responsible for determining if they are subject to operating 

permit requirements. The Small Business Assistance Program is available to 

assist small businesses in understanding the requirements, in determining 

applicability, and in complying with the requirements. No "applicability 

determinations" are available for other sources. The Division must recover the 

cost of implementing the operating permit program. Time spent reviewing 

informal requests for applicability determinations would not be recovered. 

Page 254 
Regulation Number 3 

Sources who believe they are subject to the operating permit program should file 

an application. During the sixty-day completeness determination, if the Division 

discovers that the source is not subject to the operating permit requirements, the 

source will be notified. In addition, if the source has obtained a construction 

permit, it will most likely have been determined then if an operating permit is 

required. Also, preapplication meetings with the Division are available to 

sources. All time spent by the Division in reviewing applications will be charged 

to the source. 

5. Synthetic Minor Sources 

Existing sources are subject to the operating permit requirements. Some existing 

sources may want to obtain federally enforceable limits on their production rates 

or hours of operation, or emission limits in order to avoid the operating permit 

requirements (known as synthetic minor sources because such limits are needed 

to make them minor). Construction permits can be obtained to keep emissions 

below the major source thresholds. Some existing sources do not have 

construction permits. Others may have construction permits, which do not 

currently limit emissions below the major source thresholds. Sources may avoid 

the operating permit requirements by obtaining an emission-limiting construction 

permit before they are required to apply for operating permits. Sources must 

obtain a synthetic minor construction permit before the November 1994 due date, 

or before one year after EPA program approval, whichever applies (see 

discussion below). If a synthetic minor permit is not obtained before the 

applicable date, an operating permit application must be submitted. 

The Division will review all existing construction permits over a period of time as 

resources allow, to determine if the existing permits are federally enforceable. In 

the interim, the Division will assume that all previously issued construction 

permits are federally enforceable. 

New sources may likewise obtain synthetic minor construction permits before 

they construct in order to avoid the operating permit requirements. All synthetic 

minor permits must go to public notice in order to be federally enforceable (see 

discussion below). 

"Once in always in" does not apply to the operating permit program (however it 

does apply to the PSD program). If a major source has an operating permit and 

reduces its emissions below major source levels, the source may apply for a 

synthetic minor permit in order to cease being subject to operating permit 

requirements. 

6. Minor Source Exemption 

The EPA allows states to give minor sources subject to existing New Source 

Performance Standards (NSPS) a five-year deferral from the operating permit 

requirements. Within five years of the approval of any State program, the EPA 

will determine if the deferral should be extended further, or if some or all minor 

sources should be permanently exempt from operating permit requirements. If 

the EPA first approves any State program in November of 1994, this means that 

minor sources may be exempt until November of 1999. The EPA will decide if 

minor sources subject to new MACT or GACT (Maximum or Generally Available 

Control Technology) standards and NSPS should be exempt on a case-by-case 

basis as the new rules are promulgated. 

Adopted: October 20, 2011 Page 255 
The Commission has exempted existing minor NSPS sources from the operating 

permit program at this time. New NSPS and MACT standards will be adopted by 

the Commission as EPA promulgates them, and at such time, the Commission 

shall determine operating permit applicability. 

7. Voluntary Operating Permits 

Any source which is not required to obtain an operating permit (minor sources) 

can request an operating permit, if desired. An operating permit allows minor 

sources to obtain the operational flexibility and permit shield provisions allowed in 

the operating permit program (note, however, that most of the operational 

flexibility provisions are available under the construction permit program, see 

discussion under construction permit program Section). The operating permit will 

replace the source's construction permit. A construction permit is a SIP 

requirement, and conditions in the construction permit are federally enforceable 

(except for state only conditions). All conditions in the operating permit must 

therefore be federally enforceable. Operating permits, which are issued to 

sources voluntarily applying, will be subject to all of the operating permit 

procedural requirements (public notice, EPA review, etc.). 

B. When is operating permit applications due? 

Regulation Number 3 

Adopted: October 20, 2011 

1. Existing Sources 

The federal act allows states to phase in processing of existing source 

applications over a three-year period. One third of the applications must be 

acted upon within each year after EPA approves the state's program. The 

program will be submitted to the EPA by November 15, 1993. The EPA has one 

year to approve the program, therefore the Division must begin processing 

applications beginning November 15, 1994. 

The Commission has directed the Division to divide the existing sources into 

thirds. One third of the existing sources must submit their operating permit 

applications by November 15, 1994. The Division will use the new APEN 

information to identify the first third, and will notify the first third by November 15, 

1993. The first third will consist of the least complex sources. The least 

complex sources should find it easier to prepare their operating permit 

applications, and the Division should find it easier to process these applications 

first. The Division will be able to identify any problems with the review 

procedures, etc. during the first year. 

NOTE: The Division cannot issue an operating permit until the EPA has 

approved the program and is thus ready to begin receiving permits for review. 

The Division will therefore "hold" applications processed during the first year until 

the EPA is ready to accept them for review. Once EPA has reviewed and 

approved the permits, the permits can be issued. 

The remaining existing source applications will be due one year after the EPA 

approves the state's program. The Division will provide notice of the EPA 

approval date and sources are responsible for submitting their applications on 

time. 

The Division must determine if each application is complete within 60 days of 

receipt. This may not be possible during the three-year phase in, as many 

applications will be received at once. The Division will make its best effort to 

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Regulation Number 3 

Adopted: October 20, 2011 

make the completeness determination for all permits within 60 days. If the 

Division fails to do this, the application shield applies, and the Division cannot 

enforce against the source for failure to have a complete application on file .. The 

Federal rule provides, however, that the Division has the authority to ask for 

additional information at any time during the process, and to set a reasonable 

date by which the information must be submitted. If the source fails to submit the 

additional information by the due date, the application shield no longer applies. 

The Commission is confident that under these provisions sources and the 

Division can effectively work together to ensure that applications are processed 

in a timely fashion. 

2. New Sources and Relationship to the Construction Permit Program 

New sources that wish to locate in Colorado must obtain a construction permit, or 

a combined construction/operating permit before commencing construction. The 

source may choose to obtain a construction permit or a combined permit. 

Sources that choose to obtain a construction permit must apply for a construction 

permit according to the provisions of Part 8 of this regulation. Once a 

construction permit is obtained, the source can commence construction and 

begin operating. Within 180 days of commencing operation the source must 

undergo a "final approval" inspection to demonstrate that all permit conditions are 

being met. Within 12 months of commencing operation, the source must apply 

for its operating permit. Once a complete operating permit application is 

submitted, the source can continue to operate under its construction permit until 

it receives its operating permit. 

Sources that choose to obtain a combined construction/operating permit must 

apply for such permit before commencing construction. The application for a 

combined permit must contain all of the required information for an operating 

permit. The Division will issue the permit, which will essentially be an operating 

permit. The source can then commence construction and operation. Within 180 

days of commencing operation, the source must demonstrate compliance with all 

permit conditions (this 180 day requirement will be a permit condition, and the 

appropriate hourly processing fee will be charged for the associated inspection). 

The source continues to operate under its operating permit and no further action 

is required until permit renewal. 

The procedures for obtaining construction permits are not as intense as those 

required to obtain an operating permit. More extensive public and EPA 

participation is required in the operating permit process. In addition, more 

information and requirements must be incorporated into an operating permit than 

into a construction permit. Nevertheless, it may be advantageous for sources to 

combine the processing of these two types of permits in order to avoid 

duplication of effort. 

The advantage of a combined permit is that an additional application step is 

avoided. Sources should note, however, that an operating permit application 

requires more specific information regarding compliance monitoring, 

recordkeeping, etc., than a construction permit application. Sources that choose 

to obtain an operating permit before construction must be able to supply all of the 

required information for a complete operating permit application. 

Sources that choose to obtain an operating permit before construction will be 

subject to the operating permit timeframes for processing instead of the shorter 

Page 257 
construction permit timeframes. Construction permit applications can take up to 

90, 135, or 365 days, depending on type and size of source. Operating permit 

applications can take up to 540 days. Construction permits require public notice 

and opportunity for comment only for sources emitting more than 25 or 50 

tons/year of any criteria pollutant, and requires opportunity for public hearing for 

Prevention of Significant Deterioration (PSD) sources only. The operating permit 

program requires public notice and opportunity for hearing for all sources. If the 

programs are not combined, a source may have to undergo public notice twice, 

once under each process. PSD sources may have to undergo public hearings 

twice. The EPA only reviews certain applications and draft permits under the 

construction permit program, and usually does so during the public comment 

period. The EPA is allowed 45 days to review draft operating permits near the 

end of the process, and then the Division has 90 days to revise the permit, if 

necessary. 

Sources should consider carefully their confidence in their ability to operate as 

expected or planned after construction before choosing to obtain a combined 

permit. 

3. Application Shield 

Once a source has submitted a complete operating permit application the source 

is protected from enforcement action for operating without an operating permit, 

and can continue to operate until the operating permit is issued. 

Sources that submit an application for a combined permit may not construct the 

source until they receive their combined permit. 

C. What must be addressed in operating permit applications and permits? 

Regulation Number 3 

Adopted: October 20, 2011 

1. Configuration and Grouping of Sources 

Total emissions at an entire site (including fugitive emissions at listed and HAP 

sources) must be considered to determine if a source is subject to the operating 

permit requirements. Once a source is subject, however, the owner or operator 

may choose how many operating permits to obtain for the source. A single 

permit may be issued for the entire source, or individual permits may be issued 

for individual units, buildings, processes, etc. For example, research and 

development activities may be permitted separately from the rest of a facility, in 

order to take full advantage of the operational flexibility provisions for constantly 

changing research and development activities. In addition, portions of a source 

could be covered under general permits. See discussions below under 

operational flexibility and general permits. 

The configuration for operating permits may, but is not required to, conform to the 

way in which a source chooses to file APENS. For example, a source may file 

separate APENs for all of the units at its facility, but a single operating permit can 

be obtained. Similarly, a source may file grouped APENs for similar units at its 

facility, and the operating permit could contain a general statement that the types 

of units exist at the facility, and could then state what the applicable requirement 

and associated monitoring, recordkeeping and reporting requirements are for that 

group of sources. The permit does not have to list the requirements separately, 

and the monitoring, recordkeeping and reporting requirements can be tailored to 

meet the needs of the source and the Division for that group of sources. 

SPECIFIC EXAMPLE: Numerous degreasers are located throughout a facility, 

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Regulation Number 3 

Adopted: October 20,2011 

which is located in the ozone nonattainment area (metro-Denver). A grouped 

APEN is filed for all of the degreasers. Since Regulation Number 7 applies to the 

degreasers, they must be addressed in the operating permit. The operating 

permit choices are: 1) obtain an operating permit for the degreasers only, 

separate from the rest of the facility; 2) obtain a single permit for the whole 

facility, and include a general statement/applicable requirement condition as 

described above for the degreasers; 3) obtain more than one operating permit for 

the facility, placing the degreasers in whatever permit(s) the owner or operator 

chooses. The Commission believes substantial flexibility is available for issuing 

operating permits that the source can most efficiently deal with, while still 

meeting the Clean Air Act requirements. 

2. "Regulated Pollutants" 

Once subject to operating permit requirements, a major source must include all 

applicable requirements and emission units in their application and must address 

each "regulated pollutant" associated with the source (except for insignificant 

activities, see below). 

The definition of regulated pollutant is to be used strictly for determining what 

must be addressed in an operating permit once a source is required to obtain the 

permit. The definition of regulated pollutant has nothing to do with the definition 

of major source. (See discussion above, regarding the definition of air pollutant). 

Pollutants to be addressed in the application include each pollutant for which an 

ambient standard has been set (and precursors to such standards, such as 

volatile organic compounds), ozone depleting chemicals (CFCs), any pollutant 

subject to a standard under regulation Number 6, and any pollutant subject to a 

standard under the HAPs requirements (including Colorado HAPs). 

"Regulated HAPs" 

Note that a HAP must be subject to a standard before the applicant is required to 

address it in the permit application. Once the EPA adopts a MACT standard for 

a particular HAP, all sources, even those not subject to the particular MACT 

standard, and even those not in the source category, must address that HAP in 

applications. In cases where the Commission or Division determines MACT on a 

case-by-case basis because the EPA has not, the HAP becomes regulated only 

for the particular source subject to the case-by-case standard. Once the EPA 

promulgates the list of 112(r) (accidental release) pollutants, those pollutants will 

be considered to be "regulated" for all sources. 

Fees 

The definition of regulated pollutant contained in Part A of this regulation is not 

used for fee purposes. The Colorado Act specifically sets forth which pollutants 

are to be assessed fees, and the fee pollutants are set forth in Section VI of Part 

A A pollutant does not need to be subject to a standard before the Commission 

can assess fees. 

3. Insignificant Activities 

Once subject to operating permit requirements, a major source must include all 

applicable requirements and emission units in their application and must address 

each "regulated pollutant" associated with the source except for activities, which 

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the Commission has determined are "insignificant." This regulation sets forth to 

what extent each activity or piece of equipment at a facility needs to be fully 

described and included in an operating permit. 

The Commission has tailored the insignificant list after the Air Pollution Emission 

Notice (APEN) and construction permit exemptions, to promote consistency and 

reduce confusion. The lists are repeated in Part C of the regulation, for 

convenience. The activities and sources listed in the APEN and construction 

permit exemption Sections are considered to be insignificant activities, with two 

exceptions. The lower APEN emission de minimis levels are used instead of the 

higher construction permit de minimis levels for insignificant activity purposes. 

Since the permit de minimis levels apply to the facility, the Commission does not 

believe it is appropriate to use the permit levels. The APEN 5 MMBTU per hour 

boiler design rate is controlling, rather than the higher 1 0 MMBTU per hour 

permit boiler exemption. All boilers with design rates greater than 5 MMBTU per 

hour must be addressed in the application and operating permit. 

Exemptions based on emissions, size or production rate must still be listed in the 

permit. Enough information must be submitted in the application just to identify 

the equipment as qualifying for an exemption. An asterisk appears next to each 

activity listed in Part C, which must be listed in the application. 

Applications do not have to list activities that are exempted based on category. 

Applications cannot omit information needed to determine the applicability of, or 

to impose any applicable requirements on a source. In addition, the exemptions 

cannot interfere with fee determinations. Since the mechanism used to assess 

fees is the APEN and not operating permits, this should not pose a problem for 

purposes of insignificant activities. 

The Commission has added APEN exemptions for research and development 

and laboratory activities. The exemptions apply to small research and 

development facilities, and to lab activities that the Commission has determined 

have a negligible impact on air quality in Colorado. Owners and operators of 

research and development facilities that are subject to APEN reporting are 

expected to report emissions from samples received from clients for evaluation, 

but only to the extent, the information is available. The Commission believes that 

facilities that accept material for evaluation should have some responsibility and 

knowledge regarding what is being accepted. 

Research and development facilities may continually change the types of 

projects under investigation, therefore the control efficiency of equipment may 

not always be known. The Commission has determined that research and 

development facilities may base APEN reporting thresholds on actual instead of 

uncontrolled actual emissions. In addition, since owners and operators of such 

facilities do not always know in advance what projects will be undertaken, the 

Commission has allowed such sources to report emissions after the fact, in 

annual APEN updates to the inventory. 

Research and development activities are prime candidates for the types of 

operational flexibility allowed in this regulation (see discussion below). The 

Commission encourages research and development activities to use the 

operational flexibility provisions. 

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Regulation Number 3 

Adopted: October 20,2011 

Some of the activities were described in the Statement of Basis and Purpose for 

the Commission's May 1993 Regulation Number 3 hearing. Parties to this 

hearing have asked for clarification regarding some of the provisions. 

The emission levels for triggering APEN reporting requirements are based on 

uncontrolled actual emissions. The Commission recognizes that in some cases, 

"uncontrolled" emissions are not easily defined. For example, the uncontrolled 

emissions from a degreaser may be subject to interpretation. The emissions 

from this type of operation depend on how often it is used and how fast objects 

are cleaned in the unit. Uncontrolled emissions could possibly mean that a 

person is standing at the degreaser using the machine continually, and as rapidly 

as is humanly possible. The Commission recognizes that calculation of 

emissions for this and similar operations involves some judgment, and will take 

into consideration reasonable assumptions used in determining uncontrolled 

emissions. 

The exemption for land development (less than 25 acres in size and 6 months in 

duration) applies to all land clearing activities, such as preparation of land for 

housing development, or preparation of land for oil and gas activities to occur. 

As stated above, insignificant activity exemptions cannot be used if it, would 

result in an applicable requirements being avoided. The EPA requires all 

applicable requirements to be addressed in operating permits. Similarly, APEN 

and construction permit exemptions cannot be taken if an applicable requirement 

would be avoided. The Commission has given certain sources an exemption 

from the applicable requirement provisions, for APEN and construction permit 

purposes. For example, a source that is subject to Regulation Number 7, but not 

to a specific source category requirement of regulation Number 7 (i.e. the source 

is subject only to a case by case RACT determination), may take the APEN 

exemption based on the 1 ton per year de minimis level. The Commission has 

determined that RACT for such small sources is usually no control. For 

construction permits, a source may take an exemption if it is subject solely to a 

work practice standard of Regulation Number 7. For example, degreasers used 

in the ozone nonattainment area (metro-Denver) are subject to a specific Section 

of Regulation Number 7, which requires covers and proper operation. 

Degreasers in the nonattainment area are subject to a specific Section of the 

regulation, therefore they must file APENs, however since the Section only 

requires work practice standards, no permit is required if the emissions are below 

the permit de minimis levels. It should be noted that since an applicable 

requirement exists, the degreaser and associated work practices must be 

addressed in the operating permit. Degreasers in the rest of the State are 

exempt from APEN and permit requirements if they are below the de minimis 

levels. Note that the EPA is required to set Maximum Achievable Control 

Technology (MACT) limits for degreasers in 1994. When the Commission 

adopts the MACT standards for degreasers, all degreasers subject to the MACT 

standard will be required to file APENs and obtain permits. 

4. Inapplicability Determinations 

Operating permits must list all applicable requirements and must state how 

continuous compliance with the requirements will be demonstrated. The source 

is provided with protection from enforcement as long as each permit condition 

and compliance requirement is met (known as the permit shield). The source 

may wish to obtain enforcement protection for regulations, which do not apply. In 

such cases, the application must identify which regulations do not apply to the 

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Regulation Number 3 

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source. These regulations will then be identified in the permit, and the permit 

shield will apply. 

This protects the source in the event that a mistake is made and the regulation 

really does apply to the source. The source is protected from enforcement action 

until the permit can be reopened and the correct requirements inserted. 

5. Application Form and Checklist 

Operating permit applications must contain a lot of complex information, including 

identification of all applicable (and inapplicable, if the permit shield is to apply) 

requirements. This can be a daunting task for the applicant. The Commission 

has directed the Division to develop checklists for use by the applicant. One 

checklist will identify all data that must be included in an application. Another 

checklist will identify all air regulations. The applicant can use the latter checklist 

to identify which regulations apply to their source, and which don't. 

The State must submit an application form to the EPA along with the operating 

permit regulations. The Commission has directed the Division to develop an 

application form, taking into account suggestions and comments from the public. 

6. SIP Equivalency 

The Commission has determined that it is appropriate to allow sources to set 

forth procedures in their permit that will show that a SIP limit is being met through 

methods that are equivalent to, but do not exactly follow, procedures set forth in 

the SIP. 

For example, suppose a source is required to meet a volatile organic (VOC) 

compound limit by using a coating that does not contain more than a certain 

amount of VOC. The source could propose to meet the limit by some other 

means than using such a coating. Their application would set forth quantifiable, 

replicable, accountable procedures that would show that they could still meet the 

limit even though they would not be using the required coatings. Such procedure 

could consist of using control equipment, or using a combination of complying 

and non-complying coatings for which the average emissions would meet the 

VOC limit. Monitoring, recordkeeping and reporting procedures would be set 

forth in the permit. The procedures must be sufficient to show continuous 

compliance with the underlying applicable requirement. 

This procedure allows sources to show compliance through alternative methods 

without having to go through the Commission and the EPA for a case-by-case 

SIP revision. The EPA would review the process during its 45-day review period. 

The public would have opportunity for comment and hearing. 

NOTE: This procedure overrides the requirement in Regulation Number 7, which 

states that all such alternatives will undergo a case-by-case SIP revision. 

7. 112(r) (Accidental Release) Requirements 

Operating permits must address any requirements established under Title Ill 

(hazardous air pollutants) of the Federal Act, except that the accidental release 

plans required under Section 112(r) do not have to be incorporated into the 

permit. The permit must merely state that the source is required to submit a plan 

to the appropriate entity. The Commission can take enforcement action against 

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Regulation Number 3 

a source for failure to submit a plan. Enforcement action cannot be taken for 

failure of the source to meet any of the requirements contained in the plan. 

8. Compliance Monitoring 

Operating permits must contain monitoring sufficient to demonstrate compliance 

with the applicable requirements. Methods and procedures may be set forth in 

the applicable requirements. If methods and procedures in the applicable 

requirement are insufficient to demonstrate compliance, the operating permit 

must "fill the gap" by specifying appropriate methods. Compliance methods may 

be as simple as recordkeeping, or may require continuous monitoring equipment. 

The source must state in their application how they will demonstrate compliance. 

The Division reviews this proposal and agrees with it or recommends something 

else. The Common Provisions provides the Division with the authority to require 

monitors. The Division has used, and will continue to use, best engineering 

judgment to determine when monitors are necessary and feasible. The 

Commission has determined that in some instances it may be appropriate to 

require continuous emission monitors, even in cases where the applicable 

requirement does not specify monitors, and that sufficient opportunity for 

discussion and appeal are available to the source, therefore monitors can be 

required even if the applicable requirement does not specifically require monitors. 

The EPA is in process of developing and promulgating their enhanced monitoring 

rules. These rules may speak specifically to continuous monitoring. The 

Commission will take into account this new rule and determine if the operating 

permit monitoring requirements should be revisited once the EPA rule is 

promulgated. 

By January 1994, the EPA will publish a list of existing rules, which do not 

contain sufficient monitoring, or recordkeeping methods, and will develop criteria 

that could be used to determine what is sufficient. After the rules are identified, 

the EPA will proceed to revise the rules to make them sufficient. The need for 

"gap filling" will then decrease. 

9. Compliance Certifications 

Each operating permit application must be accompanied by a "compliance 

certification" indicating that all information presented is true and accurate. The 

certification must be signed by a "responsible official," usually a CEO, of the 

company. Likewise, compliance certifications must be submitted every six 

months, indicating the compliance status of the source. Such certifications must 

also be signed by the responsible official. The burden is on the source owner or 

operator to ensure that all permit conditions are addressed in the certification, 

and all information is complete and correct. 

The Commission's definition of "responsible official" allows delegation of 

responsible official authority to plant managers under certain conditions, 

including prior approval from the Division. 

10. Recordkeeping and Reports 

The operating permit must contain all recordkeeping necessary to ensure 

compliance with the applicable requirements. The Federal Act requires such 

data to be maintained for five years. The Commission has determined that 

sources need not keep a full five years of data on site for inspection review. 

Adopted: October 20, 2011 Page 263 
Regulation Number 3 

Adopted: October 20, 2011 

Instead, sources are required to make immediately available to the Commission 

or Division data for the past year, along with the compliance certifications for the 

past five years. The actual data for the remaining four years must be provided to 

the Commission or Division within 48 hours of request. 

Monitoring data must be reported at least every six months. 

The Commission will allow sources flexibility in determining what records are 

appropriate, and in determining the schedule for reporting, in order to allow 

coordination with other reporting requirements (such as Community Right To 

Know, etc.). Such flexibility is allowed provided the requirements of the Clean Air 

Act are met. 

Malfunctions and emergencies - The Commission has adopted the Federal 

provisions for emergency and malfunction protection, except that sources are 

required to provide oral notice within two hours of the next working day, and 

written notice with one month after the emergency occurs. Past experience 

indicates that sources will most likely not be able to meet the EPA's 

recommended two-day written notice. 

The Commission does not include continuous monitor malfunctions in the 

emergency provisions. The emergency provisions serve to provide an absolute 

defense if an applicable requirement is violated. Since the Commission cannot 

tell if a source is in or out of compliance with an applicable requirement when 

monitors malfunction, it is not appropriate to include monitor malfunctions in the 

emergency provisions. Monitor malfunctions which would violate provisions 

which set specific operating conditions and specifications for the monitor, 

however, could be granted the emergency protection for those specific 

performance conditions, if such malfunctions were due to unforeseen 

circumstances and reported as set forth in the emergency provisions. The 

Commission has determined that extra protection for monitor malfunctions is not 

warranted, as procedures and specifications for monitors include performance 

requirements which take into account the inherent operational fluctuations and 

abilities of the monitors. 

Sources must report any exceedances of standards, which are not due to 

malfunctions or emergencies "promptly." The Commission has determined that 

including such deviations in the six-month monitoring report is sufficient. This will 

not impair the Division or Commission's authority to assess penalties regarding 

the deviation. 

Public Availability of Reports: Copies of all reports and compliance certifications 

will be made available at the local health departments. As always, such 

information is available at the Division offices. 

11. State-Only Conditions 

Certain Commission regulations are not part of the State Implementation Plan, 

and therefore are not federally enforceable. The Commission has given sources 

the option of including state only conditions in operating permits, or of 

maintaining such conditions in a separate construction permit. This option is 

available for all state-only conditions except those pertaining to major Colorado 

HAP sources. Major Colorado HAP sources are required by statute to obtain an 

operating permit. "State-only" conditions will be listed separately from federal 

conditions in operating permit. (Sources that are major for federal HAPs must 

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obtain an operating permit, and provisions pertaining to the federal HAPs are 

federal, not state conditions.) 

Since the operating permit is meant to be used as an all-encompassing 

document for sources and the Division, the source may want to refer to only one 

document to determine what needs to be done to remain in compliance. If the 

conditions are included in an operating permit, the source may choose whether 

or not to have the permit shield, operational flexibility, and other operating permit 

allowances and requirements apply to the conditions. 

State-only conditions do not have to undergo the same procedural requirements 

as other operating permit conditions. Affected state and EPA review is not 

required. 

Currently, the following regulations are state-only requirements: odor Regulation 

Number 2, municipal waste combustor Regulation Number 6, Part B. Future 

Colorado MACT/GACT standards will be state-only requirements. 

12. Confidentiality 

Applicants are allowed to classify certain information as being confidential in 

terms of product or processes. In no case may emission information be kept 

confidential, and in no case may compliance certifications be kept confidential. 

Records and reports may be kept confidential, however, instances where this will 

be allowed will most likely be rare, since emissions data or information related to 

emissions data may not be kept confidential. 

The current confidentiality provisions and procedures remain in effect, however 

the Commission has directed the Division to examine the provisions and 

procedures and to recommend improvements. 

D. How Long Does It Take To Obtain the Permit? 

Regulation Number 3 

Adopted: October 20, 2011 

1. Completeness Review 

The Division has sixty days from receipt of an application to determine if all 

information necessary to process the application is included. If the application is 

incomplete, the Division must notify the source and request the additional 

information. Additional information must be submitted by the applicant within a 

reasonable amount of time. Once a complete application is received, the 

Division must act on the application within 18 months. The Division must analyze 

the application, prepare the permit, and ensure that all of the procedural steps as 

set out below are met. Once all requirements are met, the Division will send the 

source its fee letter, and will not issue the permit until all applicable processing 

fees are paid. The fee letter must be sent within 18 months of receipt of a 

complete application. 

2. Public Notice and Hearing 

Once the Division analyzes the application and prepares a draft permit, the 

permit and application must undergo a thirty-day public notice. If a hearing is 

requested during the public notice, thirty-day notice of the hearing must be 

provided, and the hearing must occur within sixty days of the notice. 

Page 265 
The Commission has provided an opportunity for sources to respond to any 

public comments received. This source response in no way affects the Division's 

time constraints for issuing the permit, nor does it affect the permit, which the 

Division ultimately issues. 

3. Affected State Review 

During the public notice, a copy of the draft permit will also be sent to any 

affected, nearby states, for their review. 

4. EPA Review 

Once public notice and hearing are completed, the Division will make any 

necessary revisions to the draft permit, and will submit a proposed permit to the 

EPA for their review. The EPA has 45 days to review the permit. The Division 

then has up to 90 days to make any necessary revisions to the permit to address 

EPA concerns, before the permit can be issued. 

5. Copies of Application 

The applicant must provide a sufficient number of copies of the application for 

submittal to the EPA, affected states and public notice, including copies for 

County Commissioners. 

E. Renewals 

Regulation Number 3 

Adopted: October 20, 2011 

1. Renewal Application Content 

Operating permits must be renewed every five years. Renewal applications must 

undergo all of the review procedures (public notice, EPA review) as the initial 

operating permit. 

Applicants may incorporate by reference any previous application material or 

permits for portions of the operation which will not change from the initial 

application. The renewal application may only address operations which will 

change and which will require new permit terms or conditions. Copies of all 

material incorporated by reference must be included with the renewal application. 

All material must be provided for public comment, affected state review, and EPA 

review. 

2. Renewal Application Due Date 

The federal rule states that permitting authorities should be able to process 

"90%" of renewal applications within six months. The federal rule does not 

mandate that states process renewals within six months. The rule gives states 

flexibility to require applications for renewals, and specifically states that other 

times may be approved, which are necessary to issue the permit before it lapses. 

The application can be due as soon as 18 months before expiration, and as late 

as six months. Renewed permits must be issued before the old permit expires. 

As described above, the public comment, hearing notice, hearing, EPA review, 

and revision periods required in the Federal rule take up 220 days, or 

approximately seven and a half months. ·The time allotted for these activities is 

fixed in the Acts and rules (except for the time allowed for States to revise draft 

permits, based on EPA review). The amount of time for actual review of the 

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Regulation Number 3 

application itself varies depending upon the type of application. A breakdown of 

the allotted times follows: 

Public Notice: 30 days 

Hearing: 60 days 

EPA Review: 45 days 

Division Response: 90 days 

TOTAL 220 days 

Two hundred and twenty (220) days is the minimum required. No time is allotted 

for revising the permit between each step as necessary, nor for transmitting the 

permit from one step to the next. The 220 days is required for public notice and 

EPA review only, it does not include any time for the Division to actually review 

the application and draft a permit. 

Sources are allowed to seek judicial review if a permit is not issued in time. This 

could potentially result in wasted Division and court resources dealing with an 

impossible situation. In addition, the EPA may determine that the program is not 

adequate if the Division continually fails to issue renewed permits before 

expiration. Finally, if permits are not issued in time, the EPA can revoke and 

reissue permits, or can terminate the permits, in which case the source's right to 

operate ceases. 

Given that the notice and review procedures alone take 220 days, and the 

allowed flexibility, and the requirement that renewed permits be issued before 

expiration, the Commission has determined that it is not reasonable to allow 

renewal applications to be submitted as late as six months before expiration. 

Nine months may be adequate if hearings are not requested for such renewals, 

however, no one can predict how many applications will or will not require public 

hearing. It would not make sense to accept applications only six or nine months 

before expiration, knowing that if a hearing is requested, the new permit will not 

be issued before expiration. The twelve months will give the Division sufficient 

time to review the application, and in addition, will give the source some time to 

ensure that they have submitted a complete application before the permit 

expires. Sources are allowed to update their applications up to the time a draft 

permit is issued for public notice. This will allow sources a chance to address 

any last minute market considerations or changes in their application. 

The Division will send written notice of the need to apply for a permit renewal to 

permittees six months prior to the date a renewal application is due. This notice 

is to aid permittees, and the failure of the Division to provide notice to any 

individual permittee is not contended to be used as a defense for the failure to 

apply for a permit renewal. 

As sources and the Division gain experience with the new operating permit 

program, the Commission and the Division will determine if the timeframe for 

renewals can be shortened. The first renewals will not be due until the year 

2000. 

F. Reopenings 

Adopted: October 20,2011 Page 267 
Operating permits must be "reopened" during the term of the permit if new regulations 

become applicable to the source, if a mistake is found in the permit, or if additional 

measures need to be incorporated to ensure compliance with applicable requirements. A 

permit is reopened to address only the new requirement or correction, not to address the 

entire permit. The Division must give the source 30 days notice before reopening the 

permit. Reopenings must undergo all of the same procedures and requirements as the 

original permit (notice, EPA review, etc.). The Commission will allow sources the option 

to reopen an entire permit instead of just the necessary portion. This would require, 

however, that a source be able to submit a complete application for renewal within 30 

days of notice, so that the Division can meet the 18-month deadline. 

G. Modifications 

States must adopt expeditious procedures for processing changes that require a 

modification to a permit. 

Regulation Number 3 

Adopted: October 20, 2011 

1. Administrative Modifications 

Administrative modifications are *minor changes to the permit, such as change in 

owner, more stringent monitoring requirements, or correction of typographical 

errors. The change at the source can be made upon submittal, and the Division 

must revise the permit within 60 days. No public notice or EPA review is 

required. The original expiration date does not change when administrative 

modifications are made. 

2. Minor Modifications 

The existing construction permit program requires sources to obtain construction 

permits before they construct or modify. Revisions to construction permits are 

required before any changes at the source are made. In contrast, the Federal 

rule allows changes to be made without revisions to the operating permit, 

provided no SIP requirements are violated. Sources are allowed to make "minor 

modifications" upon notice to the Division. The source must supply a draft 

permit, which is submitted for affected state and EPA review. The permit is 

revised within 90 days. No public notice is required at the time the modification is 

made. The Commission was faced with a dilemma. Since the construction 

permit program is a SIP requirement, sources would not be allowed to make 

minor modifications without first obtaining a construction permit. This in effect 

would negate the operational flexibility envisioned in the Federal Act. 

Only certain modifications at the source may qualify as "minor modifications" for 

operating permit purposes. The change cannot be a "Title 1" modification. Title I 

contains requirements applicable to new sources. Title I revisions include the 

following changes: 

1. Modification that triggers Prevention of Significant Deterioration and New 

Source Review (significant net emission increase) 

The significant levels (defined in Part A of this regulation) are based on 

the potential to emit of a source or modification. Since no construction 

permit is in place to limit the potential to emit of a minor modification, all 

minor modifications will be triggered based on potential emissions. not 

actual emissions. 

Page 268 
Regulation Number 3 

Adopted: October 20, 2011 

2. Modification which triggers New Source Performance Standards (NSPS) 

(Any change that increases the amount of any air pollutant) - This 

definition only applies to specific NSPS sources, unless it is referenced 

in an applicable requirement 

3. Modification that triggers Section 112 (hazardous pollutants). EPA will 

be adopting "de minimis" levels that will trigger a modification. 

Minor modifications cannot involve any significant change or relaxation in 

monitoring, recordkeeping, or reporting requirements. Minor modifications also 

cannot violate any permit condition, which the source has voluntarily obtained in 

order to limit potential emissions for avoidance of requirements (such as PSD 

requirements). 

The EPA expressed their concern regarding the construction permit SIP 

requirements and minor modifications. The Commission has determined that it is 

appropriate to submit a SIP revision for the construction permit program, in order 

to allow sources the flexibility allowed under minor modifications. The 

Commission will allow minor modifications under the operating permit procedure, 

and changes before obtaining a permit, however all substantial requirements 

needed for a construction permit must be met. These requirements include 

ambient modeling to assess the modification's impact on air quality in Colorado, 

as required in the SIP. As under the current construction permit program, minor 

modification procedures cannot be used to circumvent PSD or NSR requirements 

by making individual changes, which together would otherwise trigger PSD or 

NSR. The enforcement protection of the permit shield does not apply to these 

modifications. Sources should be confident that all applicable requirements 

would be met before submitting a change as a minor modification. If the source 

errs in its determination, the Division, the Commission, and the EPA can take 

enforcement action against the source and the source's right to operate under 

the modification is terminated (the source must revert back to the permit as it 

existed before the modification was requested). 

Upon permit renewal, the minor modification undergoes public notice along with 

the rest of the permit, and the permit shield can be extended to the minor 

modification provisions. 

3. Significant Modifications 

Significant modifications are changes at the source which are not administrative 

modifications, and which do not qualify as minor modifications. Such changes 

trigger PSD or NSPS, etc., or involve significant changes in or relaxation of 

monitoring, recordkeeping and reporting requirements. A revised permit must be 

obtained before the source is allowed to commence construction for the change. 

A source may choose to obtain a revision to its operating permit, or it may 

choose to obtain a construction permit before making the change. Significant 

modifications to operating permits must undergo all of the public notice and EPA 

review requirements, therefore a source should plan on submitting its application 

well in advance of making the change. If a construction permit is obtained first, 

the source should apply at least three to four and a half months in advance 

(except for PSD sources, which should plan 12 months in advance). Once the 

construction permit is obtained, the source may commence construction. The 

conditions of the construction permit do not need to be incorporated into the 

operating permit until renewal, unless more than three years remains in the term 

Page 269 
of the operating permit, in which case the operating permit must be reopened, 

and the significant modification provisions incorporated. 

H. Operational Flexibility 

The Federal rule requires a State's program to include operational flexibility provisions, 

which allow a source to make certain changes without having to obtain a modification to 

their operating permit. The changes are simply incorporated into the operating permit 

when it is renewed. The types of operational flexibility are described briefly below. 

Subcommittee papers and fact sheets, which explain the provisions in more detail, and 

give specific examples, are available at the Division and Commission offices. The 

Commission has directed the Division to devise simplified explanations of all of the 

provisions. 

"502(b)(1 0)" Changes (named after a Section of the Federal Act): A source is allowed to 

make a change, which would violate an express permit term, provided no applicable 

requirements are violated. The source can make the change after a seven-day advance 

notice to the Division. The permit shield does not apply. The Commission will allow 

sources to revert back to the original permit term, provided seven-day notice is given to 

the Division. The permit shield can then apply again to the provision, which is contained 

in the permit. 

Permit Caps: A source may ask for an upper limit in total facility emissions. Changes 

may occur within the facility, as long as the upper limit is not exceeded, and all applicable 

requirements are met. The permit shield applies to these changes. Seven-day notice is 

required before the change is made. This type of operational flexibility may be suitable 

for research and development facilities. 

Alternative Scenarios: The source can identify various operational scenarios in its 

application, along with the applicable requirements and compliance demonstrations. The 

source can then switch from one scenario to another without notification to the Division. 

The permit shield applies to these changes. 

Emission Trading Based on the Permit: The applicant can request that the trading 

provisions (for netting out) provided for in Part A of this regulation be incorporated into 

their operating permit. As long as all of the provisions are met, the source can use the 

provisions to make changes without notification to the Division. 

Off Permit Changes: These changes can be made at the source with seven-day notice to 

the Division. The changes involve activities that are not addressed in the operating 

permit. The same qualifications as those for minor modifications apply to these changes 

(cannot be Title I modifications, significant monitoring changes, etc.) Note that the same 

SIP concerns apply to these changes that are discussed above under minor 

modifications. A construction permit would be required before these changes could be 

made. The Commission has decided to submit a SIP revision to allow these changes. 

Emission trading based on the SIP: This is the only federally allowed operational flexibility 

provision that the Commission did not adopt. This provision would allow sources to use 

the emission trading provisions of Part A without specifically stating the procedures in the 

permit. The Commission does not currently have an approved SIP that would allow this, 

therefore the EPA would not approve this procedure at this time. The EPA is expected to 

develop guidelines for approvable SIPs within two years. The Commission will consider 

this provision once it is apparent what the EPA would approve. 

I. General Permits 

Regulation Number 3 

Adopted: October 20,2011 Page 270 
General permits are standard permits that apply to specific source categories. The 

sources in the category have similar applicable requirements and similar monitoring, 

record keeping and reporting requirements. The general permit will include criteria by 

which a source may qualify for the permit. Sources that are out of compliance may not 

qualify for a general permit, since a separate individual compliance plan would be 

required. The general permit undergoes one-time public notice and hearing and EPA 

review when it is initially developed. Qualifying sources can use standard, simplified 

applications and obtain the general permit without having to go through the entire 

application process (public notice and hearing) individually. A list of all sources that have 

been issued a general permit shall be maintained by the Division and made available 

upon request. 

The general permit (as originally developed) undergoes five-year renewal, including 

public notice and EPA review. 

General permits will also be developed for the construction permit program, and will 

usually be identical to the general operating permit for that source category. Existing 

sources that have not obtained a general construction permit through the construction 

permit program (probably because a general permit did not exist at the time a 

construction permit was obtained) may operate under the general operating permit within 

60 days of submitting a complete application for the permit, which corresponds with the 

amount of time allowed for a completeness determination. The application shield 

becomes effective upon submission of a complete application. The Division will issue the 

general permit to the source upon completion of the analysis. The permit shield becomes 

effective upon issuance of the operating permit. 

Sources which receive a general construction permit through the construction permit 

program may operate under the general permit as an operating permit 60 days after a 

complete operating permit application is submitted, provided the required compliance 

demonstration has been performed in the required time (180 days). Such source must 

apply for the operating permit within 12 months of commencing operation. Once such 

application is received and determined to be complete, the Division will issue a 

certification, which states that the construction permit now becomes the operating p~rmit. 

General permits will ideally be useful for minor sources that will be subject to operating 

permits at a later date. Minor sources are more likely to be subject to similar applicable 

requirements. The Commission has directed the Division to devote resources as they 

become available to identification of sources that would be suitable for general permits 

and to the development of general permits. Candidates for general operating permits 

include sources that become subject to new MACT/GACT standards (i.e. dry cleaners), 

or existing and new NSPS sources (i.e. asphalt plants). 

The Commission will allow major sources to have general permits as part of their overall 

operating permit. As general permits are developed, major sources may use them. The 

source would just reference in their initial or renewal application that they have a general 

permit. General permits, however, cannot be issued to major sources if the issuance of 

the general permit would cause a violation of any of the applicable requirements in any 

other operating permits they have, or if issuance of a general permit would trigger a Title I 

or Title Ill modification. The Commission will allow general permits to be used for an 

entire major source only in those instances where the use of general permits is 

appropriate (homogenous, straight-forward sources). 

J. Title Ill (Hazardous Air Pollutant Requirements) 

Regulation Number 3 

Adopted: October 20,2011 Page 271 
The provisions of Title Ill must be implemented through the operating permit program. As 

discussed above, all major sources of HAPs must obtain an operating permit. As the 

Commission adopts MACT standards, the permit must be reopened to include the new 

requirements. 

As the EPA promulgates new MACT standards, they will decide if minor sources as well 

as major sources affected by the standard must obtain operating permits. 

Once the EPA approves the State's operating permit program, the Division and 

Commission must begin making case by case MACT determinations for new major 

sources and modifications, if the EPA has not yet set a MACT standard for that category. 

The EPA will be setting emission levels at which modifications are triggered. 

Once the EPA approves the State's operating permit program, if the EPA fails to meet its 

mandated deadline for setting a particular MACT standard, the State must determine 

MACT for that source category within 18 months. Permits will be reopened to incorporate 

the State MACT standard. Once the EPA determines MACT for the category, permits 

may need to be reopened again, and sources may need to retrofit their units, depending 

upon the difference between the State and EPA MACT determinations. 

K. Title IV (Acid Rain Provisions) 

The Commission is required, and fully intends, to adopt the acid precipitation rules and 

requirements as promulgated by the EPA, and to implement the requirements through 

the Title V permits, as also required under the Federal Act. 

Title IV sources (power plants) are required to submit the Title IV portion of their 

operating permits by January 1, 1996. The permits must be issued by December 31, 

1997. The EPA is planning on having all of the requirements and forms finalized so that 

Title IV sources can apply for Title IV requirements at the same time they apply for their 

initial operating permit. This could help avoid re-opening of the permit. To facilitate this, 

the Commission has determined that Title IV sources should be included in the last group 

of existing sources required to apply for operating permits (due one year after EPA 

approves the program, see discussion above). 

The Commission also intends to adopt provisions related to the WEPCO rule 

promulgated by the EPA, which deals with Clean Coal Technology Projects and other 

modifications at utilities. The rule is currently slated for the spring of 1994 in the 

Commission's regulatory agenda. In the interim, the Commission and Division will 

continue the existing policy of treating such projects as allowed by the EPA. Also, the 

Commission wishes to encourage Clean Coal Technology Projects, which are used to 

develop and identify better methods of controlling and preventing air pollution. The 

Commission has directed the Division to consider research and development factors, and 

the importance of developing new technologies, if enforcement action may be necessary 

due to violations related to such projects. 

II. Construction Permit Program 

A. Synthetic Minors 

As discussed above, construction permits are the vehicles through which sources can 

obtain federally enforceable limits on their emissions in order to avoid the operating 

permit requirements. In some cases, sources may also choose to obtain limits to avoid 

PSD or NSR requirements. Such synthetic minor permits must undergo public notice in 

order to be federally enforceable. 

Regulation Number 3 

Adopted: October 20, 2011 Page 272 
B. SIP Equivalency 

The Commission has determined that it is appropriate to allow construction permit 

sources to use the SIP equivalency procedure that is provided for operating permits in 

the Federal Act. Current regulations, such as Regulation Number 7, require a case-bycase SIP revision for equivalent procedures, which involves public notice, a mandatory 

Commission hearing, and EPA approval. The new SIP equivalency provisions override 

Regulation Number 7 provisions. All SIP equivalency proposals require public notice, 

opportunity for hearing (but not mandated if not requested), and EPA review. The 

Commission will require such construction permits to follow the PSD track, which requires 

public notice and an opportunity for public hearing. The EPA will review the proposal 

during the public comment period. 

C. Minor Modifications and Operational Flexibility 

The Commission has extended most of the operational flexibility provisions directly to the 

construction permit program, since no modification to a permit is required. These 

provisions include Administrative Modifications, Alternative Scenarios, Emission Trading 

Based on the Permit, and Permit Caps. 

The remaining operational flexibility provisions, and the minor modification provisions are 

not available through the construction permit program, however sources may obtain 

these additional allowances by voluntarily applying for an operating permit. 

D. General Permits 

The Commission has determined that the general permit process will be allowed only for 

the operating permit program. The general application and permit forms, however, 

should be used for construction permits as they are developed. The Colorado Act 

requires new sources to obtain a construction permit before commencing construction, 

therefore the source must have their construction permit in hand before constructing. In 

addition, Regulation Number 3 requires certain sources to undergo public notice before 

construction. The Commission believes that notice should continue to be provided to the 

public where appropriate, before a source constructs near them. 

As discussed above under general operating permits, the Division will identify candidates 

for general construction permits as resources are available. The same sources identified 

in the discussion above are candidates for general construction permits. In addition, 

general permits may be suitable for sources wishing to obtain synthetic minor status, 

such as emergency and backup generators. 

Ill. Emission Fees 

Though it was not noticed for this hearing, some parties indicated they had concerns 

regarding the Division's policies for charging annual emission fees. A request was made 

to include the Division's policy in the regulation. The Commission believes the Division 

should be given the flexibility to determine the most efficient and reasonable procedures 

and policies for assessing fees, therefore the policy will not be included in the regulation. 

The Division will prepare a written policy for public distribution on the methods it will use 

to calculate and collect emission fees. 

IV. Where Can a Source Go For Assistance In Understanding the New Requirements? 

A. Small Business Assistance Program 

Regulation Number 3 

Adopted: October 20, 2011 Page 273 
Even though existing minor sources (small businesses) are exempt from the operating 

permit program, small businesses will need help understanding the construction permit 

program requirements. In addition small businesses need to understand the operational 

flexibility requirements, and need to understand if it would be advantageous for them to 

apply for an operating permit. The EPA may decide that some minor sources should be 

required to apply for operating permits as new MACT and NSPS standards are 

promulgated. 

Last September, the Commission approved a plan for developing a Small Business 

Assistance Program. The program is under development and is expected to be 

implemented and fully operational by November of 1994. In the interim, Division staff is 

available to answer any questions, which a small business may have regarding air quality 

regulations and requirements. 

Some information has already been developed regarding APEN requirements and 

simplified calculation procedures. 

B. Pre-application Meetings 

This regulation provides opportunity for any source to request a preapplication meeting 

with the Division, to discuss what requirements may be applicable to a source. 

C. Division Staff 

Division staff will remain available to all sources and the public, to answer questions 

regarding the operating permit and construction permit programs. 

I.M. Adopted March 17, 1994 

Revisions to Regulation Number 3 Part A, Section II.E. 

Pursuant to Section 112(n) of the federal Clean Air Act, the US Environmental Protection Agency (EPA) is 

required to conduct an extensive study to create a reliable estimate of the existence or quantity of 

hazardous air pollutants (HAPS) emissions from certain sources such as utility and non-utility industrial 

boilers. Another study under Section 112(n) relates to emissions from publicly owned treatment works 

(POTWs). Section 112(n) recognizes that technological limitations exist on the ability to reliably estimate 

these emissions. The required studies are complex and costly, and EPA has indicated that the utility and 

non-utility boiler study will not be concluded until the end of 1995. The original time frame contemplated 

by Congress anticipated that the study would be completed by November 15, 1993. Unlike the 

mandatory boiler study, the Clean Air Act merely authorized EPA to study POTW emissions and EPA has 

decided not to continue with the study. Thus, the emissions information that was originally expected will 

not be developed in time to facilitate APEN reporting by December 1994. Since the emissions from 

facilities that treat municipal-type wastewater are virtually identical to those from POTWs, the lack of 

POTW emissions data also affects this category of sources as well. 

During rulemaking in 1993, a deferral for HAP reporting from boilers and other listed sources was granted 

until six months from the date federal studies are complete or until December 31, 1994. This deferral 

appears in Part A, Section II. E. 

This was based in large part on the recognition that it would be unreasonable and infeasible to expect 

these sources to attempt to duplicate the EPA studies and to provide meaningful data earlier than EPA. 

The postponement was not intended to forgo reporting obligations (it applied to emissions points and 

processes only, not to entire facilities), but rather, to recognize technical limitations and to await (not 

duplicate) the results of the EPA studies. The Statement of Basis, Specific Statutory Authority and 

Purpose for the 1993 rulemaking session explained, "Due to ongoing studies aimed at quantifying their 

Regulation Number 3 

Adopted: October 20, 2011 Page274 
emissions of non-criteria pollutants, the Commission has deferred APEN reporting requirements for five 

source categories until six (6) months after the studies have been completed or December 31, 1994, 

whichever is earlier." 

It is now apparent that neither the EPA boiler study nor the POTW study will be timely completed for 

effective implementation of' II.E. The clear intent of the regulation is to postpone report of HAP 

emissions by sources such as utility and non-utility industrial boilers, POTWs and municipal-type 

wastewater treatment works, pending the results of the ongoing EPA studies. The rationale for this 

intention is that it is technologically infeasible for these sources to comply with this reporting requirement 

without the results and utilization of the EPA studies. The original intent and rationale for a postponement 

continue to pertain at this time and provide the basis for this rulemaking. 

Additionally, highly costly tests would be required if reporting is required prior to the results of the EPA 

studies. There is a serious question about the accuracy of any reporting prior to the conclusions of the 

EPA studies. Moreover, if sources attempt to formulate tests, inconsistencies with testing procedures, 

resulting data and interpretation thereof would result, thereby further complicating issues for impacted 

sources and administration by the state. It is believed that using the EPA studies results will allow 

avoidance of such costs and result in more accurate APENS, which, in turn, will facilitate easier 

administration by the state. 

During the Commission's prior deliberations on this matter, the Commission expressed intent to revisit 

this December 31, 1994 deadline if the EPA studies would not be timely completed. Impacted sources 

must be placed on notice as early as possible concerning any deadline because lead-time to conduct 

studies and extensive planning would be necessary. This rulemaking postpones to December 31, 1995, 

or six (6) months after the EPA studies are complete, whichever are earlier, for utility and non-utility 

industrial boilers, and POTWs and municipal-type wastewater treatment plants. This decision furthers the 

Commission's original intent concerning the underlying reporting. This issue may be revisited in the 

future if the information expected to be derived from the EPA studies continue to be delayed. 

The specific authority for this regulation is contained in the Colorado Air Pollution Prevention and Control 

Act, 1992 as amended. The Legislative Declaration,' 25-7-102, recognizes that an accurate emission 

inventory is needed to adequately manage air resources in Colorado. Section 25-7-109.3 provides 

authority for regulating HAPs. Section 25-7-114.1 provides authority for requiring APENS, and for 

allowing exemptions from the requirements. Section 25-7-109(4) requires the Commission to promulgate 

regulations pertaining to HAPs. 

I.N. Adopted May 19, 1994 

Findings Regarding the Basis for the Emergency Rule Revisions to Regulation Number 3, 

Concerning the Operating Permit Program 

The Air Quality Control Commission held this emergency rulemaking hearing on May 19, 1994, after such 

notice of rulemaking as practical, to postpone the November 15, 1994 deadline for submission of 

operating permit applications by those existing major stationary sources previously notified by the Division 

to submit applications by that deadline. The revisions to Regulation Number 3 would phase-in the 

required submission of operating permit applications by these sources over a three-month period 

beginning January 1, 1995. The Commission finds that the immediate adoption of this emergency 

regulation is imperatively necessary for the preservation of the public welfare and to ensure compliance 

with the federal law, and that compliance wit normal notice requirements for rulemaking would be contrary 

to the public interest. 

This emergency regulation is necessary for three reasons. First, the Environmental Protection Agency 

(EPA) has issued a formal letter to the State of Colorado advising the State that its Title V operating 

permit program submission, contained in the Commission's Regulation Number 3, must be revised in 

order to obtain federal approval of the State operating permit program in accordance with the mandates 

Regulation Number 3 

Adopted: October 20,2011 Page 275 
of the federal Clean Air Act. The earliest date by which the Commission is able, pursuant to law, to 

promulgate such revisions and make them effective is September 30, 1994. Sources that are subject to 

the operating permit application deadline of November 15, 1994 will not have sufficient time to complete 

their applications and submit them by that time after the promulgation of the revisions. 

Secondly, and more importantly, it was not until the 1994 Colorado legislative session that the legislature 

appropriated money for the necessary FTE's at the Division to process operating permit applications and 

to implement the program. The money will not be available for the Division's use until July 1994, and 

given the shortcomings of the State personnel system, the new Division employees will not, in all 

likelihood, begin their employment until on or around November 1, 1994. If the Commission did not act 

on an emergency basis to postpone the application deadline of November 15, 1994, persons subject to 

the application deadline will be required to apply to the Division prior to its ability to fully train the new 

employees or to provide sources any services necessary under the mandates of the federal Clean Air 

Act. This imposes an unnecessary burden on sources, as well as the Division. 

Finally, the federal Clean Air Act requires that the State have sufficient money to cover the direct and 

indirect costs of implementing the Title V program. These costs include those necessary for the Division 

to review permit applications and issue permits within certain established timeframes, as well as to 

perform inspections and other compliance monitoring actions. The EPA has indicated to the State, in a 

letter dated April 8, 1994, that if the State does not have sufficient money to cover these costs, the EPA 

cannot grant any type of approval, including interim program approval. In this event, EPA must take over 

the Title V program in Colorado, and has threatened to impose sanctions on the State. Therefore, the 

Commission must act on an emergency basis to postpone the operating permit application deadline in 

order to give sources sufficient advance notice of the changed deadline and in order to ensure that the 

Division will be able to review and process those applications within the timeframes set forth in the federal 

Clean Air act. 

In light of the evidence presented at the emergency hearing on the difficulty and cost to sources of 

completing operating permit applications, given the short timeframe between the Commission's ability to 

revise and make effective changes to Regulation Number 3 required by the EPA and the current 

deadline; on the difficulty and cost of evaluating operating permit applications filed with the Division and of 

the Division's inability to perform services required by the current Regulation Number 3 and deadline of 

November 15, 1994; and on the EPA's letter evidencing its concern that the Division will not be sufficiently 

financed to perform those federally-mandated services, the Commission finds that an emergency exists 

which warrants the passage of this emergency regulation. The Commission does not believe that this 

emergency regulation represents any risk to public health. 

1.0. Adopted August 18, 1994 

Revisions to Regulation Number 3 

This Statement of Basis, Specific Statutory Authority, and Purpose comply with the requirements of the 

Administrative Procedures Act, Section 24-4-103(4}, C.R.S. (1994) for adopted or modified regulations. 

The 1990 Amendments to the Federal Clean Air Act require states to implement an operating permit 

program. Failure of a state to implement the operating permit program will result in EPA sanctions. 

On July 15, 1993, the Air Quality Control Commission adopted revisions to Regulation Number 3 

necessary to implement the State's operating permit program. The Commission also adopted revisions to 

Regulation Number 3 that were necessary to integrate the operating permit program with the existing 

construction permit program, and that were necessary to extend certain provisions of the operating permit 

program to minor sources not otherwise subject to the program. 

Regulation Number 3 

Adopted: October 20, 2011 Page 276 
On November 5, 1993, the Governor submitted Colorado's operating permit program to the Region VIII, 

Environmental Protection Agency (EPA) for its approval. The EPA reviewed Colorado's submittal and on 

AprilS, 1994 responded to the State's submittal, noting certain deficiencies in the program. These 

deficiencies must be corrected and the revisions submitted to the EPA no later than October 1, 1994. 

The Commission promulgated these revisions to Regulation Number 3 in response to EPA's comments. 

EPA also noted certain legislative changes that are required in order for the State of Colorado to obtain 

full approval of its operating permit program. Therefore, at this time, the Commission contemplates that 

the State will receive interim approval of the operating permit program; within 18 months after receiving 

the interim approval from EPA, the State must submit legislation that will satisfy all of the federal 

requirements. 

The EPA in its April 8 letter required the Commission to revise in certain respects the Statement of Basis, 

Specific Statutory Authority, and Purpose for Revisions to Regulation Number 3 that was dated July 15, 

1993 and which was submitted to the EPA on November 5, 1993. The required revisions are reflected in 

this Statement of Basis, dated August 18, 1994. 

Specific Authority 

The specific authority for this regulation and its revisions is contained in the Colorado Air Quality Control 

Act, 25-7-101, et seq. (1989 & 1994 Supp.). Section 25-7-105(1)(A)(1) requires the Commission to adopt 

into the State Implementation Plan all requirements of the federal act. Sections 25-7-105(12) provide 

authority to implement the operating permit provisions of Title V of the federal act. Section 25-7-1 05.1 

sets forth the federal enforceability provisions. Section 25-7-106(6) provides authority for monitoring, 

recordkeeping and reporting requirements. Section 25-7-114.1 provides authority for APEN requirements 

and for allowing exemptions from the requirements. Section 25-7-114.2 through 114.5 set forth 

construction and operating permit requirements, and application and public participation requirements. 

Commission action in promulgating these revisions is taken pursuant to Sections 25-7-105 to 109 and 25-

7-114. 

Statement of Basis and Purposes of Changes to Regulation 

1. In Part A, I.B.9.e., the definition of "applicable requirement" concerning enhanced 

monitoring was changed to comply with the federal definition, incorporating all monitoring 

and enhanced monitoring requirements established pursuant to Sections 504(b) and 

114(a)(3) of the federal act. 

2. In Part A, I.B.22., the definition of "federally enforceable" was amended to mirror the 

definition found in Section 25-7-105.1 of the Colorado Air Pollution Prevention and 

Control Act. 

3. In Part A, I.B.35.D.e., the Commission exempted any modifications that are not "major 

modifications" from the definition of Title I modifications, for sources with operating 

permits that utilize the minor permit modification procedures set f6rth in Part C, Section 

X.A. This is because EPA cannot allow the minor permit modification procedures to be 

used for Title I modifications; therefore, for the minor permit modification procedures to 

have any use at all, this change was necessary. All modifications must still comply with 

the requirements of 40 CFR Part 51.165, as reflected in Regulation Number 3, Part B, 

IV.D.1.a.-h. In effect, this change merely allows an operating permit source to modify 

without going through the procedural requirements of obtaining a construction permit, but 

still requires the source to meet all substantive requirements. 

4. Part C, X.A.5., XII.A.1 and XII. B. were revised to reflect the change described in 

paragraph Number 3 above. 

Regulation Number 3 

Adopted: October 20, 2011 Page 277 
5. Part A, 1.8.62, a definition of "state-only condition" was added. This term is used 

throughout Regulation Number 3. 

6. In Part A, Section 11.0.1.aaa. (APEN exemptions), and in Part C, Section II.E.3.aaa. 

(insignificant activities for operating permits), the Commission exempted storage of 

lubricating oils from notice and permit requirements. Because new source performance 

standards apply to storage tanks of capacity> 40,000 gallons, the Commission revised 

these provisions to ensure that the exemptions would not allow a source to avoid new 

source performance standards. 

7. In Part A, 11.0.5., the Commission established an administrative procedure whereby the 

Division could process and grant requests for exemptions from permit and APEN 

requirements. However, this amounted to a SIP revision without allowing EPA the 

opportunity to review and approve the revisions. Therefore, the Commission amended 

this procedure to require that the Commission adopt the exemptions pursuant to 

rulemaking, on an annual basis, and submit the revisions to EPA prior to a source being 

able to take the exemptions. 

8. Part A, IV. B. contains operational flexibility provisions concerning "trading based on the 

permit." The federal rule allows a source to take advantage of any EPA-approved 

emissions trading program, without the need for a SIP revision. At this time, Colorado 

does not have an EPA-approved generic emissions trading program. To obtain EPA 

approval of the State's operating permit program, the Commission amended this 

provision to clarify that the trading based on the permit may be utilized only if the SIP 

contains an EPA approved trading program. 

9. At Part 8, III.A.6., the Commission clarified that the provisions of IV.D.1.a.-h. must be met 

in order for the source to utilize the minor permit modification procedures. Previously, the 

Commission had merely cross-referenced Section IV.D.1., which contained time periods 

for review that conflicted with the minor permit modification procedures. 

10. At Part 8, IV.D.1.i. and in Part C, V.C.1.c., the Commission had provided authority for a 

source to use an alternative emissions limitation that is as stringent as an applicable 

requirement so long as the permit contained provisions to ensure that the limitation is 

quantifiable, accountable, enforceable and based on replicable procedures. The 

preamble to the operating permit rule, 40 CFR Part 70 makes clear that it is the SIP, not 

the permit that must contain these replicable procedures. Therefore, in Part C, the 

Commission amended V.C.1.c. to clarify that the alternative emissions limitation may be 

taken only if it is allowed by the SIP; then in Part 8, IV.D.1.i., the Commission removed 

the alternative emissions limitation language because the SIP must itself contain the 

replicable procedures. EPA is expected to have guidance in the near future on 

alternative emissions limitation. 

11. In Part C, 111.8.7., the Commission clarified that a source applying for a combined 

construction/operating permit must first obtain the permit prior to commencing 

construction. 

12. In Part C, III.C.12., the Commission clarified that ambient air quality standard 

considerations in issuing permits apply .only to temporary sources (pursuant to the federal 

law), and to new and modified sources applying for a combined construction/operating 

permit (pursuant to state and federal law). Although this was always the case, the 

provision previously could have been read to allow consideration of these standards in 

issuing operating permits. 

Regulation Number 3 

Adopted: October 20, 2011 Page 278 
13. In Part C, V.B.3. & 5., the Commission allowed minor sources to voluntarily opt into the 

operating permit program in order to gain the operational flexibility of operating permits. 

These minor sources, however, could avoid the public participation, EPA and affected 

state review provisions. The EPA was concerned that synthetic minor sources would be 

able to opt into the program, and in so doing would lose their federally enforceable · 

limitation (imposed by the construction permit which would be lost), without going through 

the required public participation and EPA and affected state review. The Commission 

revised these provisions to clarify that synthetic minors opting into the program must go 

through all the necessary reviews. In addition, major sources of Colorado-only HAPs 

need not go through the public review process attendant to operating permits. The EPA 

was concerned that the provision could be read to allow federal HAP major sources to 

avoid public participation and review. The Commission clarified these provisions to 

ensure that such was not the case. 

14. In Part C.III.B., the Commission revised the schedule for submission of operating permit 

applications by the remaining two-thirds of sources in order to reflect the anticipated 

interim approval date of the operating permit program of January 1, 1995. This revision 

would also allow the Division to notify some sources of the need to submit an application 

before January 1, 1996, but on or after November 15, 1995, upon twelve months' notice. 

Changes to the Statement of Basis and Purpose dated July 15, 1993 

I.C.2. "Regulated HAPS" 

Revise this paragraph to read: 

Note that a HAP must be subject to a standard before the applicant is required to address it in the permit 

application. Once the EPA adopts a MACT standard for a particular HAP, all sources, even those not 

subject to the particular MACT standard, and even those not in the source category, must address that 

HAP in applications. In cases where the Commission or Division determines MACT on a case-by-case 

basis because the EPA has not timely promulgated a MACT standard for a source category or 

subcategory of sources, the MACT becomes applicable to all sources within that source category, 

pursuant to 112(g) of the federal act. In cases where the Commission or Division determines MACT on a 

case-by-case basis for an existing source that modifies prior to promulgation of an applicable MACT 

standard, the HAP becomes regulated only for a particular source subject to the case-by-case standard, 

pursuant to 112(g) of the federal act. Once the EPA promulgates the list of 112(r) (accidental release) 

pollutants, those pollutants will be considered to be "regulated" for all sources. 

I.G.2. Minor Modifications 

Revise the second paragraph under this heading to read: 

Only certain modifications at the source may qualify as "minor modifications" for operating permit 

purposes. The change cannot constitute a "major modification" as that term is defined in Part A, Section 

II.B.35.B. The change cannot otherwise be a "Title I" modification. Other Title I requirements are 

applicable to new sources. These Title revisions include the following changes: (same). 

I.H. Operational Flexibility 

Emission Trading Based on the Permit: Revise this paragraph to read: The federal rule allows a source 

to change its operations, using the emissions trading provisions of an EPA-approved SIP to net out and 

avoid the need to revise its permit. At this time, the emissions trading provisions of Part A, Section V, 

have not been approved by EPA as generic trading provisions. Therefore, until the Colorado SIP 

contains a generic emissions trading policy approved by EPA, each emissions trade request will require a 

Regulation Number 3 

Adopted: October 20, 2011 Page 279 
case-by-case SIP revision. EPA is intending to provide guidance for an emissions trading program in the 

near future. 

J.P. Adopted March 16, 1995 

Revisions to Regulation Number 3 Construction Permit Program 

Background 

At the request of the U.S. Environmental Protection Agency, Region 8, the Air Quality Control 

Commission adopted amendments to Regulation Number 3, Parts A and 8, in order to clarify how the 

provisions relate to each and the federal regulations. These changes were necessary in order to gain 

federal approval of the State Implementation Plan. 

Specific Statutory Authority 

The Specific authority for this regulation is found in the Colorado Air Quality Control Act. Section 25-7-

1 05(1) provides that the Commission shall promulgate such rules and regulations as are consistent with 

the legislative declaration and necessary for the proper implementation and administration of the 

Colorado Pollution Prevention and Control Act, including a comprehensive state implementation plan 

which shall meet all requirements of the federal act and shall be revised whenever necessary or 

appropriate. Section 25-7-109 provides that the Commission shall adopt, promulgate and from time to 

time modify or repeal emission control regulations that require the use of effective practical air pollution 

controls. Section 24-4-103 provides the rule making procedure followed during the promulgation of this 

rule. Section 25-7-110 provides the specific Commission procedures followed during the setting of 

standards and regulations. Commission action in promulgating these regulations is taken pursuant to the 

above statutory provisions. 

Purpose 

Most of the amendments to Regulation Number 3, Parts A and 8 are of a general housekeeping nature. 

However, three provisions require greater explanation: 

The Division originally proposed adding a definition of "construction" consistent with the federal definition 

for New Source Review and Prevention of Significant Deterioration. To eliminate the potential for 

confusion and conflict with the state statutory definition, the Division has removed that provision from the 

amendments. There is a definition for construction, which applies to Regulation Number 3, Parts A and 8, 

in the General Provisions Regulations; that definition matches the state statutory definition. 

The changes to the definition of "Net Emissions Increase" in Part A, Section 1.8.37 needs some 

explanation. In order for an increase or decrease to be creditable, the Division could not have relied on 

the increase or decrease in issuing a permit under Regulation Number 3. Also, the source has two 

choices for proving the extent of the emissions increase or decrease: ( 1) the source submits or has on file 

an APEN indicating the baseline emissions rate and then submits a revised APEN within one year after 

making the increase or decrease (the difference between the two APENs is the amount of creditable 

increase or decrease) or (2) the source provides credible, demonstrable evidence to the Division of actual 

emission rates both before and after making the increase or decrease (the source can make the before 

and after demonstration any time during the contemporaneous period). 

The general constructions permit provisions of Part 8, Section IV.J. were amended to provide greater 

detail of how the Division would actually implement the provisions. The Division retains the discretion to 

determine whether it will issue a general construction permit, although a source or group of sources can 

request that the Division do so. These provisions are meant only for minor sources, including sources 

wishing to obtain federally enforceable limits on their potential to emit, making them synthetic minors. The 

contents of a general construction permit will vary depending on the type of source involved. The Division 

Regulation Number 3 

Adopted: October 20,2011 Page 280 
will state in the general construction permit that goes out for public notice all the criteria a source must 

meet in order to qualify for coverage under the permit, the method of application (including specific 

application forms if different from a standard construction permit), the deadline for application, and other 

requirements as necessary and specified in the permit (i.e. monitoring, reporting, and recordkeeping 

requirements). After receiving an application to be covered by a general construction permit, the Division 

will determine whether the source fits within the intended coverage of the general construction permit, 

meets all applicable requirements, and satisfies all the criteria as laid out in the general construction 

permit. If the Division grants a source the right to construct and operate under a general construction 

permit, there are still some situations under which the Division may require the source to obtain an 

individual construction permit (i.e., the source makes changes that bring it out of compliance with the 

general construction permit or circumstances change such that the source is no longer appropriately 

controlled under the general construction permit). 

Overall, the amendments to Regulation Number 3, Parts A and B are meant to integrate with the existing 

rules and meet the federal requirements for the State Implementation Plan. 

I.Q. Adopted May 18, 1995 

Revisions to Regulation Numbers 8 and 3 Synthetic Minor Permit Program 

This Statement of Basis, Specific Statutory Authority, and Purpose comply with the requirements of the 

Administrative Procedures Act, Section 24-4-103(4), C.R.S. (1994) for adopted or modified regulations. 

Background 

At the request of the Division, the regulated community and the state legislature (HB94-1264), the Air 

Quality Control Commission adopted rules that would allow the Division to issue permits to limit a 

source's potential to emit hazardous air pollutants (HAP). Such a mechanism is necessary and important 

because it enables the Division to issue a permit to a source of HAP in order to limit the source's potential 

to emit below emission thresholds requested by the applicant, thus allowing the source to avoid a variety 

of requirements such as Title V operating permit requirements, Title Ill maximum achievable control 

technology (MACT) requirements promulgated by the U.S. Environmental Protection Agency (EPA), or 

Colorado MACT requirements. 

Specific Statutory Authority 

The specific authority for these revisions is contained in the Colorado Air Quality Control Act, 25-7-1 01, et 

seq. (1989 & 1994 Supp.). Section 25-7-109.3(2) provides the specific authority for the Commission to 

adopt provisions allowing the Division to create synthetic minor sources of hazardous air pollutants. 

Section 25-7-109 provides that the Commission shall adopt emission control regulations requiring the 

use of effective practical air pollution controls. Section 25-7-109.3(2) provides that in order to minimize 

additional regulatory and compliance costs to the state's economy, any program created by the 

Commission shall contain a provision, which exempts those sources or categories of sources, which it 

determines to be of minor significance from the requirements of the program. Section 24-4-103 provides 

the rule making procedure followed during the promulgation of this rule. Section 25-7-110 provides the 

specific Commission procedures followed during the setting of standards and regulations. Commission 

action in promulgating these regulations is taken pursuant to the above statutory provisions. 

Purpose 

The rulemaking includes the permanent addition of Regulation Number 8, PartE, Section IV and 

amendments to Regulation Number 3, Part B. Following is a description of the purpose of each Section 

within Regulation Number 8, Part E, Section IV: 

Regulation Number 3 

Adopted: October 20, 2011 Page281 

f 
Section A of the rule clarifies that Regulation Number 8, PartE, Section IV applies to sources that choose 

to voluntarily limit their potential to emit HAP. This Section clarifies that although the Division shall issue 

permits to qualified applicants, the Division will not include in the permit any indication of the source's 

exemption status for other requirements (i.e. Title V or Title Ill of the federal Act) unless the source asks 

the Division to include all relevant emissions units and pollutants in the permit review. Under this 

regulation, the applicant chooses which emission units to cover in the particular permit: that can be all 

HAP emission points, some or one HAP emission points, all criteria pollutant emission points, and/or 

some or one criteria pollutant emission points. Unless there is a need for a state-only or federally 

enforceable permit condition, the Division will not impose any additional applicable requirements on 

criteria pollutants or HAPs for the emission unit or a number of emission units. If the permit applicant 

wants a thorough review of the facility and a determination by the Division that the facility qualifies as a 

synthetic minor from Title V and/or Title Ill, or other specific provisions of the state or federal Act, then the 

applicant can choose to have a comprehensive Division review in the permit. Sources choose in the 

permit application the threshold level below which they want to limit the potential to emit hazardous or 

criteria pollutants. Sources may want to bring their emissions below Title V major source thresholds or 

may want to limit their emissions below affected source thresholds under specific MACT standards or 

enhanced monitoring thresholds when those rules are eventually enacted. When a source applies for a 

permit under Regulation Number 8, the Division uses the procedural provisions of Regulation Number 3 

to issue the permit. Finally, this Section clarifies that receiving a permit under this regulation will not 

relieve a source from possible future EPA requirements that apply to minor or area sources of HAP or 

state conditions; however, such sources may request a permit to further limit the potential to emit HAP 

below the trigger threshold. 

Section B describes the elements of a permit issued under this regulation. The permit needs to include 

practically enforceable permit conditions. The Division makes the final determination on what those 

conditions are on a case-by-case basis for each permit. The monitoring, recordkeeping, and reporting 

requirements will depend on the specific source, for instance, practical enforceability may require 

calculating mass balances, installing a continuous emission monitor, keeping track of consumption rates 

for various materials, etc. However, the permit conditions to limit a source's potential to emit shall be only 

as stringent as necessary to limit the source's potential to emit the pollutant of concern. For instance, the 

Division cannot require a source to add control equipment to reduce emissions significantly if the source 

can adequately reduce emissions without that control equipment. The applicant may consolidate reporting 

or monitoring requirements from this regulation and Regulation Number 3 for the emissions unit. Finally, if 

requested by the applicant, the permit may include alternative operating scenarios, approved by the 

Division. Such alternative operating scenarios shall include specific monitoring, recordkeeping, and 

reporting methods as needed. However, Section IV.B.4 for alternative operating scenarios is not intended 

to include modifications that trigger new source review unless such sources go through all the specific 

requirements of the construction permit program for modifications under new source review. 

Section C tells the source what information to turn in to the Division, increasing the efficiency of 

communications between the source and the Division and streamlining the application process. The 

application forms will reflect the intent for the Division to be flexible in its approach to permitting these 

sources. Although the Division would prefer a consistent approach (i.e., all applications filled out fully), the 

Division recognizes that often these sources will have unique circumstances that cannot be adequately 

addressed in a standard application form. The Division further intends that the application forms be 

flexible enough so that sources can choose to have the Division calculate emissions and determine the 

permit conditions for them. 

Section D, the public participation requirements, is a requirement of EPA. This Section makes mandatory 

what was previously discretionary for the Division. 

Section E clarifies that the Division can combine the requirements from this Regulation with those for 

limiting the potential to emit criteria pollutants under Regulation Number 3 into a single permit so that it is 

easier for both the Division and the source to keep track of the overall permit requirements. Also, this 

Section IV of Regulation Number 8 is not intended to restrict the ability of a source to apply for and the 

Regulation Number 3 

Adopted: October 20, 2011 Page 282 
Division to issue a construction permit under Regulation Number 3 with limits on the potential to emit 

criteria or hazardous air pollutants. 

Section F explains to the source that if a physical or operational change triggers another requirement, the 

permit issued under this Section will not relieve the source of the obligation to comply with that 

requirement. 

Section G informs the source that is must comply with the permit conditions at all times, i.e. on an 

ongoing basis. 

Section H serves as an interim mechanism for gaining federal enforceability of the permit and is based on 

EPA guidance on potential to emit; this Section does not apply once EPA has approved these rules for 

limiting the potential to emit HAP. In order for a permit to be federally enforceable, EPA must receive a 

certification of compliance from the source indicating the source will comply with the permit terms. The 

source should send a copy of the initial permit approval with the certification of compliance to EPA and a 

copy of the certification to the Division (to keep in the permit file). The responsible official, defined in 

Regulation Number 3, needs to sign the certification. 

The revisions to Regulation Number 3 are necessary to implement the provisions of Regulation Number 

8, Part E, Section IV through the construction permit program. Note, that the operating permit program 

already has the necessary provisions to integrate Regulation Number 8, Part E, Section IV. The 

amendment to Section III.A.4 is not intended to extend any new rights to the applicant in the event the 

applicant declines permit conditions set by the Division, this amendment just makes explicit that the 

permit is strictly voluntary and that a dissatisfied applicant has normal rights of appeal associated with 

construction permits issued under Regulation Number 3. The addition of Section III.A.7 is to clarify that if 

a source wants to request a limit on the potential to emit in a standard construction permit, the source 

may do so. This Section also gives the Division the authority to limit the potential to emit HAP in a 

construction permit. The amendments to Section IV.C implement the public participation requirements of 

Regulation Number 8, Part E, Section IV. The requirement that the Division submit a copy of the public 

notice to EPA for sources applying for a permit to limit the potential to emit criteria pollutants or federal 

HAP is meant to include criteria pollutants (already required under an agreement between the Division 

and EPA) and federal HAP listed in Appendix A of Regulation Number 8 (these are the HAP listed by 

EPA under Section 112(b) of the federal Act). Permits for sources limiting the potential to emit Colorado 

HAP do not need to be sent to EPA for comment. 

Overall, these rules are intended to meld with the existing permit provisions within Regulation Number 3 

while providing the added authority for the Division to issue permits to limit the potential to emit hazardous 

air pollutants and the opportunity for Colorado sources to get out of more rigorous permit requirements. 

I.R. Adopted May 18, 1995 

Revisions to Regulation Number 3 Part A, Section II.E.2 (As requested by Metro Wastewater 

Reclamation District) 

This Statement of Basis, Specific Statutory Authority and Purpose for revisions to Regulation Number 3 

complies with the requirements of the Administrative Procedures Act, C.R.S. '24-4-103(4) for adopted or 

modified regulations. 

The 1990 Clean Air Act Amendments required states to inventory air emissions. C.R.S. ' 25-7-114.1 

contains the requirements for this inventory. The Amendments also authorized EPA to conduct 

emissions studies for certain source categories, included publicly owned treatment works (POTWs). No 

adequate, reliable, and economically reasonable emissions estimations methods are currently widely 

available for these emissions. 

Regulation Number 3 

Adopted: October 20, 2011 Page 283 
Based on the expectation that publication of these studies would result in the creation and dissemination 

of practical emission estimation techniques, revisions to Regulation Number 3 were promulgated in March 

of 1994 which postponed reporting of non-criteria reportable pollutants for these sources until July 31, 

1995, or until six months after the completion of the national studies, whichever occurred first. The 

postponement also applied to facilities, which treat municipal-type wastewater, since such facilities' 

emissions are virtually identical to those from POTWs. 

EPA has eliminated funding for the federal POTW study. However, the Association of Metropolitan 

Sewerage Agencies (AMSA) has been assisting EPA in preparing its guidance document, and AMSA has 

also been preparing its own guidance. These documents are expected to be useful in estimating POTW 

air emissions. A final draft of AMSA's report is expected to be issued in the summer of 1995. EPA is also 

expected to issue its finding of presumptive MACT for POTWs for purposes of the Clean Air Act " 112U) 

and (g) at about this time. 

Authority 

The specific authority for this regulatory amendment is contained in C.R.S. '25-7-106(1), which 

authorizes the Air Quality Control Commission to promulgate such regulations as are necessary or 

desirable to carry out an effective air quality control program, and ' 25-7-114.1, which authorizes the 

Commission to promulgate the APEN inventory program. 

Purpose 

In order to give POTWs and facilities that treat municipal-type wastewater sufficient time to prepare 

reliable APENs, the Commission has extended the postponement of reporting for non-criteria reportable 

pollutants for these sources until December 31, 1995. The Commission finds that extending the APEN 

reporting deadline is in the public interest because the information to be published by EPA and AMSA will 

not become available to these sources in time to allow for sufficiently reliable APEN reporting. 

1.5. Adopted August 17, 1995 

Revisions to Regulation Number 3 to Change TSP to PM-10 for PSD Increments and 

Housekeeping 

This Statement of Basis, Specific Statutory Authority and Purpose complies with the requirements of the 

Administrative Procedure Act, C.R.S. 1973, Section 24-4-103(4) for adopted or modified regulations. 

On June 3, 1993 the U.S. EPA promulgated changes to the Prevention of Significant Deterioration (PSD) 

rules replacing the Total Suspended Particulate (TSP) increment with particles with an aerodynamic 

diameter of less than or equal to a nominal10 micrometers (PM-10) increments. TSP continues to have 

a significance level for new sources but no longer influences the PSD increments. 

Additionally the Division has identified several mistakes in the publishing of Regulation Number 3. 

Specific Authority 

The specific authority for this regulation is contained in the Colorado Air Pollution Prevention And Control 

Act, 1992 as amended. Section 25-7-105 (1) (a) (I) requires the Commission to promulgate a 

comprehensive state implementation plan that meets all requirements of the federal Clean Air Act. 

Section 25-7-105(1) (c) requires the Commission to promulgate a prevention of significant deterioration 

program. 

Purpose 

Regulation Number 3 

Adopted: October 20,2011 Page 284 
The Regulation Number 3 PSD rules implement the Federal PSD rules in Colorado. Under the PSD 

program areas that are in compliance with the National Ambient Air Quality Standards (NAAQS) are 

required to adopt a permit program for the preconstruction review of new stationary sources and 

modifications of existing stationary sources to prevent significant deterioration of existing air quality levels. 

The implementation of the new PM-1 0 increments will utilize the existing baseline dates and baseline 

areas for PM. The PM increments measured, and PM-1 0 already consumed since the original baseline 

dates established for TSP will continue to be accounted for, but all future calculations of the amount of 

increments consumed will be based on PM-1 0 emissions. 

The Division is also proposing some minor housekeeping while revising this regulation. There were 

several Sections where the language published in the Colorado Register was either repeated or the 

changed paragraph and the original paragraph were both printed. There was also an outside request that 

submitted an outdated version of the regulation that was inadvertently published. 

I.T. Adopted December 21, 1995 

Part A, Sections 1.8.37 & 67; Part B, Section IV.D.4 

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. 

Regulations 3, 7 and the Common Provisions establish lists of Negligibly Reactive Volatile Organic 

Compounds (NRVOCs). The revisions adopted consolidate the list of NRVOCs into the Common 

Provisions, assuring that the same list of NRVOCs apply to all the Colorado Regulations. This provides 

more consistency in those chemicals regulated as VOCs. 

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 Regulations pertaining to organic solvents and photochemical 

substances. Section 25-7-109(2)(f) and 25-7-109(2)(g), C.R.S., grant the Commission the authority to 

promulgate regulations pertaining to Organic solvents and photochemical substances. 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 

Of the EPA list of non-photochemically VOCs), and adopting the EPA definition by reference, a single list 

of negligibly reactive VOCs will apply uniformly to all These revisions to Regulations Number 3, 7, and 

the Common Provisions are intended to clarify substances that are negligibly reactive VOCs, which are 

reflected in the EPA list of non-photochemically reactive VOCs. By consolidating the list (which consists 

Colorado Air Quality Control Commission Regulations. 

This revision will also include EPA's recent addition of acetone to the negligibly reactive VOC list. The 

addition of acetone to the list of negligibly reactive VOC's provides additional flexibility to sources looking 

for an alternative to more photochemically reactive VOCs. Because the EPA has added acetone to their 

list of non-photochemically reactive VOCs many industries, which make and supply products to Colorado 

industries, are planning to substitute acetone for more reactive VOCs. This change in the content of 

products purchased by industry for use in Colorado would adversely affect industries in Colorado if 

acetone remains a regulated VOC in Colorado. By adopting acetone as a negligibly reactive VOC 

industries will be able to take advantage of and benefit from this possible shift in product contents. 

Regulation Number 3 

Adopted: October 20, 2011 Page 285 
I.U. Adopted February 15, 1996 

Revision to Part A, Section II.E.1 APEN Deferral for Utility and Non-Utility Boilers 

This Statement of Basis, Specific Statutory Authority and Purpose complies with the requirements of the 

Administrative Procedures Act, CRS 1793, Section 24-4-103(4) for adopted or modified regulations. 

The current provisions of Regulation Number 3, Part A, Section II.E.1., were designed to postpone 

reporting of non criteria reportable pollutants by sources such as utility and non-utility industrial boilers 

and small municipal generators pending the results of ongoing studies being conducted by EPA pursuant 

to Section 112(n) of the federal Clean Air Act. EPA was directed by Congress to complete those studies 

within three years after enactment of the federal act, i.e., by November 15, 1993; however, EPA has yet 

to do so. 

During the Commission's last deliberations on this subject, it was stated that if EPA could not meet its 

deadline, then the Commission would revisit this deadline. Both the Commission and the regulated 

community were hopeful that EPA would be able to finish its work by the fall of 1995 so sufficient time 

was available for utilities to meet the December 31, 1995 deadline. 

Specific Authority 

Section 25-7-114.1 provides authority to the Commission to identify APEN reporting requirements. There 

currently are no federal reporting requirements concerning emissions of non-criteria reportable pollutants 

(NCRPs) or hazardous air pollutants (HAPs) from boilers. The current state regulations exceed federal 

regulatory requirements with respect to APEN reporting of emissions. 

Purpose 

A short postponement of the original deadline serves a significant dual purpose and both the state and 

the regulated community benefit from a deferral in this instance. The postponement avoids forcing an 

uneconomic and non-beneficial compliance requirement at this time on the regulated community. Since 

there are no compliance obligations respecting HAP emissions from boilers, either in effect or proposed, 

EPA and Division interpretations provide that an applicant for a Title V operating permit need only listnot estimate quantities of emission of- an application for an operating permit. This revision is 

administrative in nature, and is not intended to affect air emissions. 

I.V. Adopted March 21, 1996 

Revisions to Parts A, B & C for Insignificant Activities (Parties: Air Pollution Control Division, 

Colorado Association of Commerce & Industry and the Colorado Utilities Coalition for 

Clean Air Division- Part A, Section I.B.9.a; Section II.D.1.kk, 4.a, b.(iii) & (vi); Part C, 

II.E.3.kk 

The Division reviews the addition of any requested insignificant activities to Regulation Number 3 once 

each year. The additions requested included small remote reservoir degreasers and torch cutting 

activities. Both of these items were reviewed by EPA Region VIII prior to the hearing date and given 

verbal approval. 

The degreaser exemption provides that degreasers not using any chemicals covered by a Maximum 

achievable Control Technology (MACT) standard and meeting the definition of small remote reservoir are 

Regulation Number 3 

Adopted: October 20, 2011 Page 286 
not required to submit an APEN to the Division. The torch cutting exemption clarifies the status of torch 

cutting as an exempt activity. 

Authority 

The specific authority for this regulatory amendment is contained in §25-7-114.1(2), C.R.S., which 

requires the Commission to exempt those sources or categories of sources, which it determines to be of 

minor significance from the requirement than an air pollutant emission notice is filed. Section 25-7-

114.6(1 ), C.R.S., requires that the Commission designate those classes of minor or insignificant sources 

of air pollution which are exempt from the requirement for an emission notice or the payment of an 

emission notice filing fee because of their negligible impact upon air quality. 

Purpose 

This rule change provides some clarification and additions to the APEN exemption list for those sources 

that the Division believes to be of minor significance. 

Colorado Association of Commerce and Industry- Part A, Section II.D.1.ttt; Part C, Section II.E.3.nnn. 

The Division reviews the addition of any requested insignificant activities to Regulation Number 3 once 

each year. The Colorado Association of Commerce and Industry (CACI) requested the addition of 

emergency power generators with limitations based on the size or hours of operation. The revisions rely 

on EPA guidance regarding emergency power generators. 

Authority 

The specific authority for this regulatory amendment is contained in C.R.S §25-7-114.1 (2), which requires 

the Commission to exempt those sources or categories of sources, which it determines to be of minor 

significance from the requirement that an air pollutant emission notice be filed. C.R.S. §25-7-114.6(1) 

requires that the Commission designate those classes of minor or insignificant sources of air pollution that 

are exempt from the requirement for an emission notice or the payment of an emission notice filing fee 

because of their negligible impact on air quality. 

Purpose 

This rule change provides an addition to the APEN exemption list and clarification of the insignificant 

activities list for emergency power generators that are of minor significance base on size and/or hours of 

operation. 

Colorado Utilities Coalition for Clean Air- Part A, Section II.D.1.aaa.(i), (ii); sss.(1 ).iv to vii; uuu; vvv; www; 

xxx; yyy; zzz; aaaa.(i), (ii); Part C, II.E.3.aaa.(i), (ii), xxx.(1 ).iv to vii; yyy; zzz; aaaa; bbbb; ecce; dddd; 

eeee 

This Statement of Basis, Specific Statutory Authority and Purpose complies with the requirements of the 

Administrative Procedure Act, C.R.S. 1973, Section 24-4-103(4) for adopted or modified regulations. 

The current provisions of Regulation Number 3., Part A and Part C both contain lists of activities and 

sources considered to be "insignificant" or exempt from reporting requirements. On December 29, 1995, 

the Commission proposed revisions to its existing Regulation Number 3, Parts A and C. Alternative 

proposals were submitted by members of the public, and after consultation, were endorsed by the 

Division. 

Regulation Number 3 

Adopted: October 20,2011 Page287 
Specific Authority 

Section 25-7-114.1 provides authority to the Commission to identify APEN reporting requirements. 

Further, the rulemaking authority of the Commission is found in Sections 25-7-105 to 109 CRS, as 

amended. The regulations of the Commission currently contain lists of activities and sources exempt 

from APEN and reporting requirements. On July 10, 1995, the U.S. EPA issued a White Paper designed 

to streamline and simplify the development of Part 70, Title V permit applications. The White Paper 

explains that Part 70 provides permitting authorities considerable flexibility in defining certain activities or 

sources as "insignificant" upon proper showing of such. The White Paper itself contains substantial lists 

of activities or sources that are insignificant for reporting purposes. 

Purpose 

The addition of the following sources or activities to existing APEN exemption and reporting requirements 

serves a significant dual purpose and both the state and regulated community benefit from the alternate 

proposals. The revision of existing regulation avoids forcing an uneconomic and non-beneficial 

compliance requirement on the regulated community. Several of the following activities or sources are on 

federal lists as "insignificant," as well as those of neighboring states. These revisions are administrative 

in nature, and are not intended to affect air emissions. 

Non-road Internal Combustion Engines: 

Machinery utilized by the construction and service industries such as various types of pumps, light plants, 

compressors, and generators are powered by various sizes of internal combustion engines. Most are 

relatively small. Some emergency equipment such as fire pumps are powered by larger engines, but are 

operated infrequently. The exemptions listed above identify those within this category that have 

insignificant emissions. This exemption is consistent with other exemptions in the regulation (see, for 

example, Subsections k. and 1.). As a practical matter, APENS have not been required from most of 

these machines in the past. The sizes of most of these engines are comparable to the thousands of light 

and heavy trucks (gasoline and diesel powered), which travel the roads in this state without any reporting 

requirements. 

The EPA proposal of May 17, 1990 (58 Fed. Reg. 28809) and the EPA study it references contains useful 

findings. It exempts all spark-ignition (gasoline, propane and natural gas powered) engines. On page 

28816 of the Federal Register notice, EPA finds that it did not propose manufacturing standards for 

spark-ignition engines because little to no emission benefit would be achieved for testing, record keeping 

and reporting requirements on these engines. Cost burdens industry would have to bear would not be 

reasonable. It also found that test procedures have not been demonstrated to be capable of accurately 

predicting the levels of hydrocarbons, carbon monoxide and particulate matter emissions generated by 

these engines in actual use. In addition, the economics and failure problems associated with gasolinepowered engines dictate that relatively small sizes of gasoline engines are used for the light commercial 

equipment described above. As a result, all spark-ignition engines should be exempt from APEN 

reporting and classified as an insignificant activity. 

The EPA study found that it could also exempt engines located on a trailer or truck bed. These engines 

are relatively small (dictated by trailer size and carrying capacity limitations) and power light commercial 

equipment, such as welders, compressors and generators, see page 28815 of the Federal Register 

notice. 

Larger machines are typically powered by diesel engines of varying sizes. A review of emission factor 

data from AP-42 supports a Division of diesel-powered engines into three categories for APEN exemption 

purposes. Using emission factors from AP-42, expected emissions from a 175 horsepower diesel engine 

operating 24 hours per day, 7 days per week, 52 weeks per year at a load factor of 0.5 would present a 

"worst case" estimate under the 8760 hours per year "potential to emit" methodology. The following 

emissions are calculated: 

Regulation Number 3 

Adopted: October 20,2011 Page 288 
-0.5 ton per year of carbon monoxide 

-0.2 ton per year of hydrocarbons 

-0.2 ton per year of particular matter 

-2.5 ton per year of nitrogen oxides 

-0.2 ton per year of sulfur oxides 

A 300 horsepower engine could operate up to 3 hours per day, or 1095 hours per year, and have the 

same emissions as the 176 horsepower engines. Similarly, an engine up to 750 horsepower could 

operate 1 hour per day, or 365 hours per year and have the same emissions as the 175 horsepower 

engine class. 

This approach is consistent with the approach taken by the EPA in its Guidance Document for 

"Calculating Potential To Emit for Emergency Generators," issued September 6, 1995. There, the EPA 

agreed that the use of 8, 760 hours per year for calculating the potential to emit for emergency generators 

did not control. Instead, EPA recommended that the potential to emit be based upon an estimate of the 

maximum amount of hours the generators could operate based on a case-by-case basis where justified 

by the source owner or permitting authority. Surface water storage impoundment of non-potable water 

and storm water evaporation ponds: Chemical analysis and observation of these sources has 

consistently demonstrated that they are a negligible emission source of any regulated air pollutant. 

Non-potable water pipeline vents: 

Proper flow through of non-potable water maintains these sources as insignificant. Proper flow keeps the 

water in line from becoming septic and therefore a negligible source of any regulated air pollutant. 

1. Steam vents and safety release valves: 

Safety release valve vents enable immediate reduction of pressure in steam lines. Emissions out 

of the safety valves consist only of pure water vapor. 

2. Deaerator/vacuum pump exhausts: 

These are negligible sources of emission of any regulated air pollutant. 

3. Seal and lubricating oil systems for steam turbine electric generators: 

Atmospheric vents exist in coal-fired utility turbine lube oil systems enable removal of water vapor 

from lube oil return lines from the turbine and generator bearings. This enables atmospheric 

pressure operation of lube oil storage tanks. These are not storage systems, but actual service 

operations. Calculations reveal that these activities would emit less than one ton of VOC's a 

year, per facility. 

4. Venting of natural gas lines for safety purposes: 

To enable the safe delivery of fuel gas to the utility boilers, and provide the ability to safely purge 

natural gas from fuel lines within a generation building, vent lines exist to allow the intermittent 

discharge of natural gas to safe areas away from personnel and ignition sources. 

The intermittent discharge of natural gas would occur during start-up and shutdown of the natural 

gas supply to generating unit burners to purge air or natural gas from the piping system within the 

generation building. These activities are not expected to emit more than one ton of VOC's or 

more than 11 0 pounds of hexane a year. 

Sulfuric acid storage tanks not to exceed 10,500 gallons capacity and sodium hydroxide tanks: 

Regulation Number 3 

Adopted: October 20, 2011 Page 289 
Sulfuric acid and sodium hydroxide, used to control pH, are stored in tank systems vented to the 

atmosphere. These vents will exhaust vapor from a tank system through vapor extraction and 

contraction because of changes in temperature and barometric pressure. These losses, which 

are referred to as breathing losses, occur without any significant change in liquid level in the tank, 

and are negligible. 

Waste lubricating oil storage tanks not larger than 40,000 gallons and lubricating oil-conditioning 

systems: 

Low volatility waste turbine and motor lube oil generated by utility plant machinery and mobile 

heavy equipment is stored in tanks. These tanks are equipped with atmospheric vents on the 

tops of the tanks. Emissions through these vents are expected to occur during the filling and 

emptying of the tanks. These emissions contain trace amounts of VOC's, with no other reportable 

emissions expected. Based on the low annual throughput of these tanks, emissions are 

insignificant, assuming that the tanks are emptied approximately five times per year or less. 

Colorado Utilities Coalition for Clean Air - Part A, Section II. E.1 

This Statement of Basis, Specific Statutory Authority and Purpose complies 24-4- with the requirements 

of the Administrative Procedure Act, C.R.S. 1973, Section 103(4) for adopted or modified regulations. 

The current provisions of Regulation Number 3, Part A, Section II.E.1, were designed to postpone 

reporting of non-criteria reportable pollutants by sources such as utility and non-utility industrial boilers 

and small municipal generators pending the results of ongoing studies being conducted by EPA pursuant 

to Section 112(n) of the federal Clean Air Act. EPA was directed by Congress to complete those studies 

within three years after enactment of the federal act, i.e., by November 15, 1993; however, EPA has yet 

to do so. 

Both the Commission and the regulated community were hopeful that EPA would be able to finish its work 

by the fall of 1995 so sufficient time was available for utilities to meet the original December 31, 1995 

deadline. The EPA did not meet that deadline, and the Commission granted a deferral until June 30, 

1996. The EPA study is now the subject of further delay due to one of the individual constituent 

hazardous air pollutant studies and the extensive federal government furloughs in both late 1995 and 

early 1996 that substantially contributed to further delay the study's progress. 

Specific Authority 

Section 25-7-114.1 provides authority to the Commission to identify APEN reporting requirements. There 

currently are no federal reporting requirements concerning emissions of non-criteria reportable pollutants 

(NCRPs) or hazardous air pollutants (HAPs) from boilers. The current state regulations exceed federal 

regulatory requirements with respect to APEN reporting of emissions. 

Purpose 

A short postponement of the amended deadline serves a significant dual purpose and both the state and 

the regulated community benefit from a deferral in this instance. The postponement avoids forcing an 

uneconomic and non-beneficial compliance requirement at this time on the regulated community. Since 

there are no compliance obligations respecting HAP emissions from boilers, either in effect or proposed, 

EPA and Division interpretations provide that an applicant for a Title V operating permit need only listnot estimate quantities of emissions of- HAPs reasonable believed to be contained in the boiler 

emissions in an application for an operating permit. This revision is administrative in nature, and is not 

intended to affect air emissions. 

Regulation Number 3 

Adopted: October 20, 2011 Page 290 
I.W. Adopted March 21, 1996 

Revisions to Part 8, Section III.D.1.f, Section IV.C.1.e, Section IV.C.1.f, and Section IV.C. 

The changes to Regulation Number 3 were adopted in order to make it clear that the redesignation of the 

Denver metropolitan area as an attainment maintenance area for ozone does not change the requirement 

for gasoline stations in the Denver metropolitan area are to obtain a construction permit. 

Section III.D.1.f appears to imply that, upon such redesignation, gasoline stations in the Denver area 

would not be required to obtain a permit because that area would become an attainment area. However, 

Section III.D.5 goes on to provide that such exemptions do not apply because gasoline stations are 

subject to the RACT requirements of Regulation Number 7, Section VI.B.3.b. The purpose of the 

revisions is simply to make it clear from the text of Regulation Number 3, Part B, Section III.D.1.f alone 

that gasoline stations in the Denver area are still required to obtain a construction permit. The revisions 

to Sections IV.C.1 and IV.C.4 were necessary to ensure that permits for de minimis exemptions from, and 

alternative means of compliance with, the requirements of Regulation Number? are subject to review and 

comment by the public and by EPA Such comment and review is necessary because the Sections I.A. 

and II.D of Regulation Number 7 provide the agency with the authority to revise the requirements that 

apply to a source without revising the SIP. The SIP requirements were developed and adopted following 

review and comment by EPA and the public. It follows that any change in those requirements with 

respect to any source or category of sources should also be subject to such public comment and review. 

The specific statutory authority to amend this regulation pertaining to exemptions from permit 

requirements is set out at§ 25-7-114.2. Further statutory authority can be found in the Commission's 

authority to redesignate the area because such redesignation must include an approvable maintenance 

plan. The specific statutory authority to promulgate the rules necessary for redesignation is set out in§§ 

25-7-105(1)(a)(l) and (2); -106(1)(a); -107 (1) and (2.5); and -301. 

This revision to Regulation Number 3 is not intended to reduce air pollution and will have no regulatory 

effect on any person, facility or activity. 

For clarification, the Commission adopted these re_g_ulat1on revisions as fo lows: 

Regulation Revision Ozone SIP and Maintenance Plan 

Part B, Section III.D.1.f Exists in Appendix C of the Ozone Maintenance 

Plan to be come a part of that document approved 

March 21, 1996 

Part B, Section IV.C.1.e and f; Section IV.C.4 Adopted as subsequent regulation revisions to be 

submitted to the Governor and EPA Separately and 

concurrently as a revision to the SIP (and 

Maintenance Plan). 

I.X. Adopted June 20, 1996 

Revisions to Part A, Section V.C.1.f (Fees Correction) 

This revision corrects an erroneous regulation change requested by the Division in response to an EPA 

letter of September 19, 1994, which provided comments on the revisions to Regulation Number 3 for the 

operating permit program. The comment made by EPA was for clarification, not a requirement that the 

State should not charge for fugitive emissions. The change requested by the Division in 1995 included 

the term fugitive emissions in the paragraph of exclusions from the definition of regulated pollutant. 

Because of this change, the Division's authority under the statute to charge annual fees for fugitive 

Regulation Number 3 

Adopted: October 20, 2011 Page 291 
emissions became confused which affected the Division's ability to cover its operating costs through fees. 

The regulation text also no longer conformed to Section 25-7-114.7, as revised in the 1996 legislative 

session. 

Authority 

Section 25-7-114.6.(3), C.R.S., requires that the revenues from fees collected by the Division 

approximate the annual appropriations to the Division to carry out its duties with respect to stationary 

sources. Section 25-7-114.7, C.R.S., requires imposition of an annual emission fee on stationary 

sources, and defines what is a regulated pollutant for purposes of these fees. 

Purpose 

These changes address an erroneous March 1995 revision made with respect to the charging of fees for 

fugitive emissions. The revision specifically exempted fugitive emissions and would significantly reduce 

the Division's ability to collect fees sufficient to cover duties with respect to stationary sources. In 1992 

the General Assembly prohibited imposition of annual fees for fugitive dust or fugitive emissions as those 

terms were defined at the time in "Commission rule 1.8.1 of regulation number 3, 5 CCR 1001-5." That 

rule defined only fugitive dust and the March 1995 regulatory revision inadvertently addressed fees on 

fugitive emissions as well. This rule conforms the regulation to statute, and eliminates any ambiguity 

between the two. Moreover, during the 1996 legislative session, the legislature in HB1271 amended 

Section 25-7-114.7(1) to clarify the authority of the Commission to assess fees for fugitive emissions. 

The Commission intends that all forms of "fugitive dust," regardless of whether the dust is of a size or 

substance to adversely affect public health or welfare, is excluded from the definition of "regulated 

pollutant", for purposes of annual fees. 

The Commission determines that these revisions are administrative in nature and are not intended to 

reduce air pollution. 

I.Y. Adopted June 20, 1996 

Revisions to Part A, Section 1.8.9, 59, Section V.C.12; Part 8, Section 111.0.2; Part C, Section 

II.A.1.b, Section VI.A, E, H.3 and Section XII.A.1;Appendices 8, C and D for Hydrogen 

Sulfide 

Background 

The Division requests that the Commission adopt changes to Parts A and C and the Appendices within 

Regulation Number 3 to better reflect current EPA implementation of the Title V operating permit 

program. These changes include: (1) noting that a source major only for Total Suspended Particulate 

(TSP) is not required to obtain an Operating Permit in Part C; (2) deleting the Hazardous Air Pollutant 

reference beside the pollutant Hydrogen Sulfide (H2S) in Appendices 8, C, and D of Regulation Number 

3 to reflect the federal delisting of this pollutant, and; (3) expanding the definition of "applicable 

requirement" in Part A to clarify that EPA-issued PSD permits are applicable requirements of the 

Operating Permit Program. A discussion of each of these changes follows. 

The current notation under Regulation Number 3, Part C Section II.A, General Considerations, lists all 

major sources as being required to obtain Operating Permits. The EPA has issued a written guidance 

document indicating that the definition of regulated air pollutant for purposes of Title V applies only to 

emissions of PM-10, and not TSP. The current requirements reflected in Part C, Section II.A.1.b does not 

reflect the federal program requirements. 

Currently, H2S is reflected as a Hazardous Air Pollutant in Appendices 8, C, and D. The EPA stated that 

the inclusion of H2S on the federal list was a typographical error and removed the pollutant from the 

federal list. As a result of the reference to H2S as a hazardous air pollutant in the Appendices, sources 

Regulation Number 3 

Adopted: October 20, 2011 Page 292 
emitting H2S have been charged annual fees for HAPs and sources major for H2S emissions could be 

required to get an Operating Permit. 

The current definition of applicable requirement in Part A, Section I.B.9.a does not provide authority for 

EPA-issued PSD permits to be incorporated into Operating Permits. The definition of "applicable 

requirement" in Part 70 of the federal program includes permits issued by EPA. The State needs this 

regulatory change to make the rules consistent with the federal law. Currently, regulated entities subject 

to these requirements can obtain a permit from EPA or can voluntarily have the requirement placed in 

their Title V permits, but this situation does not support the intent behind the Title V program. 

Specific Authority 

The specific authority for changes to this regulation is found in the Colorado Pollution Prevention and 

Control Act. Section 25-7-105(12) provides authority to promulgate regulations, which are necessary to 

implement the minimum elements of Title V. Section 25-7-103(1.5) allows the Commission to define air 

pollutant consistent with the federal act. Section 25-7-114.4(1 )(I) and Section 25-7-114.4(3)(a) provide 

authority for promulgating regulations for the effective administration of construction and operating 

permits, and complying with all applicable requirements for operating permits. Section 25-7-114.5 

provides authority for evaluating permit applications to determine whether operation and emissions 

comply with all applicable emission control regulations. Relevant federal law includes 42 U.S.C. Section 

7661a(b)(5)(A), and 40 C.F.R. Sections 70.1(b), 70.3, and 70.6(a)(1) regarding applicable requirements. 

Commission action in making changes to Regulation Number 3 is taken pursuant to the above statutory 

provisions. 

Purpose 

The amendments adopted by the Commission add language in Regulation Number 3, Part C, Section 

II.A.1.b indicating that a source that is major only for TSP is not required to receive an Operating Permit. 

This amendment ensures conformity with the federal law. 

The amendments delete the reference to Hazardous Air Pollutant noted next to hydrogen sulfide in 

Appendices B, C, and D. This ensures consistency with the Federal delisting and eliminates the potential 

confusion for sources that will be major only based on emissions of hydrogen sulfide as a Hazardous Air 

Pollutant to obtain an Operating Permit. The amendments expand the definition of applicable 

requirement in Part A to include those permits issued by EPA under Part C and Part D of the federal act. 

This ensures conformity with the federal law. 

The amendments correct a few typographical errors that existed in Regulation Number 3, Parts A, B, and 

c. 

Finally, the amendment to Part C, Section II.A.1.b, regarding TSP, is administrative in nature and is 

intended to reflect current EPA policy; it is not intended to reduce air pollution. The amendment to Part A, 

Section I.B.9.a, regarding the definition of applicable requirement, is administrative in nature and reflects 

the requirements of Part 70. This action regarding the definition of applicable requirement maximizes air 

quality benefits in the most cost effective manner by enabling sources to incorporate federally issued PSD 

permit into their Operating Permit. Thereby, these sources will only be reporting to one enforcement 

authority. These revisions applicable to Part C are not to be submitted as part of the State 

Implementation Plan. 

I.Z. Adopted October 24, 1996 

Revisions to Generic Part A, Section V, (with Regulation Number 5, Emissions Trading and 

Banking 

Regulation Number 3 

Adopted: October 20, 2011 Page293 
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, 25-7-110.5 and 25-7-110.8, C.R.S. 

The Division has worked with the emissions trading and banking subcommittee to develop Regulation 

Number 5 and revisions to Regulation Number 3 for the purpose of implementing an EPA-approvable 

emissions trading program. 

The subcommittee has developed a trading rule combining elements from the existing EPA guidance and 

the prior Commission rule. The subcommittee spent a great deal of time discussing the issues around 

the possible uses for credits, how credits could be certified, and how they should be traded and tracked. 

Emission reduction credits are intended to be granted only for reductions beyond compliance levels that 

are actual, quantifiable, surplus and enforceable. This rule is not intended to impose additional control 

limitations on sources. The rule does impose requirements to ensure that these basic criteria are met in 

order to guarantee that the source flexibility afforded by this program does not occur at the expense of air 

quality. 

This rule is a revision to the SIP done only under the Commission's general authority. Thus, the trading 

and banking rule will not be state enforceable until after legislative review. Section 25-7-133(2), C.R.S. 

Additionally, because EPA must approve this change into the SIP, the Commission finds it appropriate to 

delay the effective date of these revisions until EPA approval as a SIP revision. This will provide the 

sources that might wish to participate the assurance that the rule is approved and that the credits are 

useable prior to the implementation of the program. The existing trading provisions in Regulation Number 

3 will remain in effect until the new trading rules are approved by EPA. These constraints on the effective 

date of these revisions are reflected in the rule text approved by the Commission. In addition, in order to 

avoid confusion about what portions of the regulations are effective until EPA approval of the SIP change, 

the parts of Regulation Number 3 that will be repealed are printed in italics. 

State implementation plans are to include, among other things, enforceable emissions limitations and 

other control measures, means or techniques to meet the requirements of the Clean Air Act. These are 

to include economic incentives such as fees, marketable permits, and auctions of emissions rights. 42 

U.S.C. 7410(a)(2)(A). These regulation revisions are being submitted as a SIP revision pursuant to the 

foregoing Clean Air Act requirements. 

The following issues were identified by the subcommittee and noticed by the Commission for further 

consideration. The Commission discussed and resolved these issues in the course of this rulemaking 

proceeding and makes the following findings regarding these issues. 

Issue: Once used, does a permanent emission reduction credit (ERC) ever expire? Some believe that 

an ERC once used, even if from a permanent reduction, should expire after some period (e.g., 20 years). 

Conclusion: The Commission, based on the experience in the previous trading rules, decided that the 

permanent credits should not expire after they are put into use. 

5. Issue: Should a decrease in electrical demand be usable to generate emission reduction 

credits? 

Conclusion: Because of the existence and operation of the national electrical grid system, the 

Commission believes that it would be far too difficult to verify that there had been a decrease in demand 

(a decrease in actual emissions) and not a variation in the grid structure, and therefore at this time finds it 

is inappropriate to allow a decrease in demand to generate ERCs. 

Regulation Number 3 

Adopted: October 20,2011 Page 294 
6. Issue: As the proposed rule is written, inter-pollutant trading is allowed on a case-bycase basis subject to Division approval. The subcommittee and the Division recognized 

that a universal or standard protocol for approving such trades would be desirable, but 

that no officially approved protocols for any inter-pollutant trades exist. 

Conclusion: The Commission agrees that there is currently insufficient scientific information available to 

support inter-pollutant trades in most cases. In order to ensure that the Division staff is not placed in the 

position of having to develop information and protocol to support an inter-pollutant trade proposal, the 

Commission finds that the burden of proving the acceptability of an inter-pollutant trade shall be placed on 

the source. 

Because of concerns expressed by the EPA that the protocol for inter-pollutant trades has not yet been 

developed, the language of VI. B. was amended to allow proponents of such trades the opportunity to 

make their case to the Division and EPA for approval. This amendment attempts to address the EPA 

concern. 

7. Issue: The proposed rule states that temporary credits must be credited and traded 

within the same "season" for seasonal pollutants. Should temporary credits be allowed to 

be traded from a season of lower concern to a season of higher concern? 

Conclusion: The Commission finds that the use of temporary credits should be restricted to the same 

season in which they were generated, or a season of lower concern. This will help mitigate any significant 

increases in seasons that may cause a violation of the NAAQS. 

Issue: At this time no internal provisions exist for program development and implementation. How should 

the cost of the program implementation and development be addressed? 

Conclusion: The Commission acknowledges that the Division will monitor the activity in the trading 

program and, if needed, legislative fee authority will be sought. Fees for permit changes required by this 

rule will be charged pursuant to Regulation Number 3. Nevertheless, the Commission acknowledges that 

resources are not currently available and funding may be needed for this program. 

8. Issue: Should the rule contain procedures or criteria specific to trading Hazardous Air 

Pollutants (HAPs)? The subcommittee and the Division agreed not to address this issue 

of HAPs in the proposed rule. 

Conclusion: The Commission is concerned that use of ERCs for criteria pollutants that contain or consist 

of HAPs could unduly increase the risks to communities and the environment in the vicinity of the creditusing source. Assessing relative risk is difficult, time-consuming and highly fact-specific to a particular 

source and trade. In order to address this concern, the Commission adopted Section VI.G.8 that requires 

that the HAPs reduced to generate the ERC must be of equal or greater toxicity than the HAPs contained 

in the emissions for which the ERC will be used in lieu of satisfying an applicable requirement. Section 

VI.G.8 does not operate as an emissions control regulation on any HAPs, but is simply a limitation on 

participation in the trading program. 

9. Issue: How is the base emission rate set? In order to show the level of actual emissions 

at a source before reductions for which credits are claimed, a period representative of 

normal operating conditions must be used. 

Conclusion: The Commission adopts provisions that require using the last twelve months' actual 

emission rate unless the last twelve months are not representative. The source may propose to the 

Division to use any consecutive twelve months in the last ten years as more representative of normal unit 

operations. This allows most sources to use a period, which the Commission believes is likely to be 

representative of normal operating conditions. Where the source can show that the period is not 

representative, the rule allows source flexibility in determining their pre-reduction actual emissions. 

Regulation Number 3 

Adopted: October 20,2011 Page 295 
10. Issue: Should the Commission give authority to the Division to allow discounts from the 

ten percent contribution of emission reductions for air quality benefits for generators that 

participate in a voluntary pollution prevention program or other voluntary "beyondcompliance" programs? Should a generator be allowed to contribute only five percent of 

its their emissions reductions for air quality benefits as an incentive for participation in 

pollution prevention programs? 

Conclusion: The Commission agreed to provide such flexibility to the Division for generators that have 

voluntarily adopted comprehensive and facility-wide environmental programs such as a Pollution 

Prevention Program or other similar voluntary "beyond-compliance" programs. 

11. Issue: Should ERCs be used to satisfy Best Available Control Technology (BACT) or 

Lowest Achievable Emission Rate (LAER) requirements where a source triggers PSD or 

nonattainment New Source Review and must install BACT or LAER control technologies? 

Recent reports in the national press have indicated that EPA is giving serious 

consideration to allowing ERC use for BACT as it attempts to move away from commandand-control approaches to more contemporary market approaches. 

Conclusion: The Commission believes that ERCs may appropriately be used in lieu of the emissions 

reductions which would otherwise be achieved by application of the BACT technology requirements in 

situations where such technology requirements are not cost-effective or exacerbate other pollutant 

emissions, and the use of an ERC would achieve the same purposes more efficiently. In such instances, 

it will be incumbent on the source to demonstrate that such a situation exists. In any case, however, the 

other PSD provisions and required analyses would apply to the source. PSD requirements are performed 

on future allowable emission rates. Because of concerns about the use of ERCs for BACT requirements, 

although the Commission has allowed ERCs to be used to meet BACT requirements in limited instances, 

it believes that this provision should only be applied prospectively for new BACT requirements and not to 

allow a source to remove BACT where it has already been installed. The Commission concludes that use 

of ERCs in lieu of emissions reductions from LAER is not appropriate because of the potential impacts on 

nonattainment areas. 

12. Issue: How will the local effect of "hot spot" pollutant trades be analyzed to prevent a 

local criteria pollutant exceedance due to emission credit transactions? Should the rule 

require modeling of criteria, pollutants to assure there are no exceedances of the 

National Ambient Air Quality Standards? Conclusion: The Commission adopts the 

language in Section VI.G.7 of Regulation Number 5 requiring modeling for all trades in 

order to ensure that trades do not cause or contribute to a NAAQS exceedance, an 

increment exceedance, or any violation of a required SIP provision. As that Section 

reflects, the source may request that the Division waive the modeling requirement if the 

source can document to the Division's satisfaction that the trade has a negligible impact. 

13. Issue: How and who modifies the conformity budget for intersector trading? With mobile 

to stationary source trades, does the emission budget increase after the life of the credit 

has expired, and how is this accomplished? 

Conclusion: The Commission has provided for ERCs to be available to satisfy conformity requirements in 

accordance with the federal rules. The Transportation Conformity requirements (40 CFR Parts 51 and 

93) presently allow for trades among emissions budgets where either a SIP revision or a SIP establishes 

mechanisms for such trades. 40 CFR §93.124{c). The Colorado emissions trading rule is intended to be 

a SIP revision establishing such a "mechanism" to allow for such trades. 

The Commission recognizes that, if mobile source emissions rise above the mobile source emissions 

budget in the state implementation plan, a plan revision may be necessary as otherwise required by state 

and federal law. 

Regulation Number 3 

Adopted: October 20,2011 Page 296 
14. Issue: What becomes of the "buffer" between a credit-generating source's potential to 

emit and its actual emissions before the reduction for which the credit is claimed? Does 

the generator get to keep a portion, all, or none of it? 

Conclusion: The Commission finds that methods exist to allow a source to retain the operating flexibility 

from a pre-reduction "buffer." When a source wants such flexibility, it may claim credits for less than the 

entire reduction in emissions accomplished; the difference constitutes a new "buffer." A source may use 

temporary credits to meet short-term operating needs. 

These methods retain flexibility for the source without relying on "paper reductions." The Commission 

concludes that it is imperative that reductions for which credits are granted must be actual reductions. 

Allowing a source to retain a buffer from within the credits granted, as proposed by the Colorado 

Association of Commerce and Industry, would result in credits for "reductions" which did not actually 

occur. This result is unacceptable, particularly because sources determine their own permitted emissions 

levels when they file their Air Pollution Emission Notices. 

For example, a source with a ninety-five ton per year permitted level that actually emits fifty tons reduces 

its emissions to forty tons. The source should take a new permit with a level between forty and fifty tons 

(e.g., forty-five tons) so that the source has a five-ton buffer. The source may then fluctuate its emissions 

between forty and forty-five tons without violating the permit, and generate temporary credits for any 

emissions reductions below forty-five tons. 

In order to ensure that reductions are actual, an ERG-generating source will not be able to increase its 

permitted emissions in the absence of a process or control modification. The source cannot, for example, 

simply file an APEN with higher emissions estimates and thereby increase its permitted emissions. The 

effect would be to allow emissions for which credits were already granted, resulting in "paper reductions." 

This consequence is unacceptable. 

15. Issue: Should a closer relationship be established between emission trades and the 

various pollutant-specific SIP elements? With regard to the spatial distribution of 

emissions, the rule as proposed did not acknowledge any sub-regional emission budgets, 

dispersion modeling requirements, or other spatial considerations contained in attainment 

and maintenance demonstrations for specific SIP elements. 

Conclusion: The original proposed regulation did not have a modeling requirement for ERC use. The 

Division subsequently proposed that modeling be required prior to an ERC use unless the source 

requests that such modeling be waived and the source can show that the ERC use would have a 

"negligible" impact. The Colorado Association of Commerce and Industry expressed a concern that the 

Division would require costly or unnecessary modeling in most cases. This concern stems from the lack 

of definition of what is "negligible" in the judgment of the Division. The Commission believes that 

modeling should only be required where the location or circumstances of the ERC use would reasonably 

be expected to cause or contribute to a NAAQS violation, an increment exceedance, or violation of a SIP 

provision such as near a "hot spot" in a nonattainment area or where ambient conditions are within 5% of 

any applicable standard. The Commission, based on the explanation offered by the Division, believes 

that the modeling required by the rule as adopted will adequately address this issue. 

16. Issue: Should the emission trading rule clarify whether trades can take place among 

different air sheds/Air Quality Control Regions. 

Conclusion: The Commission adopts two levels of limitations on the geographic scope of trading. First, 

trades are limited to sources within the same nonattainment area or from a source in a nonattainment 

area to one in an attainment area. Second, all trades must be between sources within the same PM-10 

PSD areas. These limitations are intended to avoid excessive impacts on local communities and Class I 

areas from long-distance trades. 

Regulation Number 3 

Adopted: October 20,2011 Page 297 
In addition to the issues discussed above, the Commission also considered concerns about granting 

ERCs for emission reductions that occurred in the past. This rule allows a source to use credits 

generated under the old rule and to seek credit certification for reductions, which occurred prior to 

adoption of this rule. However, the Commission wants to emphasize that past emission reductions, which 

have been used to demonstrate attainment or reasonable further progress for SIP purposes are not 

eligible to qualify as ERCs. 

The Commission recognizes that use of ERCs in lieu of compliance with an emission limitation may raise 

public concerns in the vicinity of the credit-using source. For this reason, the rule anticipates that notice 

to the Division will be required prior to use of ERCs. Permanent ERC use must be accomplished through 

a permit change. Temporary ERC use may occur only after an APEN is filed with the Division. Each of 

these documents is available to the public. Notices of ERC use will be published on the ERC Trading 

Network by the Division. The provisions of Regulation Number 3 requiring and allowing public notice and 

comment of proposed permits and modifications will also apply to permit actions to approve use of ERCs. 

The Commission believes that use of the Division's discretion to seek public comment needs to be 

supplemented in order to provide sufficient information to the public regarding proposed uses of ERCs. 

Accordingly, the Commission has included a requirement that the Division notify local governments in the 

affected area when the trade will result in the use of ERCs, which would exceed the threshold for, or 

otherwise trigger, public notice and comment pursuant to Section IV.C.1 of Part B, Regulation Number 3. 

The Commission anticipates that local governments will be able to use this notice to schedule 

informational meetings for citizens, which Commission members and appropriate Division staff will be 

able to attend. The Commission also emphasizes that the Division should exercise appropriate discretion 

to provide public notice and comment for trades that involve HAPs, which would be implemented by 

notifying the local government pursuant to the process described above. 

The Commission elected to preclude trading of elemental lead because of that pollutant's particular· 

characteristics and modified the definition of criteria pollutant for the purposes of this regulation. 

The Commission included Section IV.A.1.d. in this regulation to ensure that ERCs are granted only for 

real overall reductions in emissions. This provision ensures that reductions will be creditable only if the 

emissions are not replaced in the airshed by another generator in a business of like kind. In order to 

assure that this program does not grant credit for "paper'' reductions, the rule prohibits generating ERCs 

where this business shift will replace emissions within the same airshed. This determination will be made 

on a case-by-case, fact-specific basis. 

Specific Statutory Authority 

These regulation revisions are adopted under the general authority of the Commission found in Section 

25-7-105(1), C.R.S. and are consistent with 42 U.S.C. 7410(a)(2)(A). 

Purpose 

This rule was proposed in order to provide the maximum flexibility for sources in meeting the state and 

federal requirements outlined under the possible uses for credits. The Commission makes the following 

findings in regards to the adoption of this regulation: 

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. 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 through the retirement of 10% of the 

achieved reduction in emissions. 

Regulation Number 3 

Adopted: October 20, 2011 Page 298 
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 requirement for increased emissions modeling may impose 

additional costs, the Commission believes this requirement is necessary to 

ensure that no violations of air standards will occur as a result of using ERGs. 

I.AA. Adopted November 21, 1996 

Revisions to Appendices 8, C 

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. 

Regulations 3, 7 and the Common Provisions establish lists of Negligibly Reactive Volatile Organic 

Compounds (NRVOCs). The revisions adopted update the list of NRVOCs so that the state list remains 

consistent with the federal list. Additionally because perchloroethylene will no longer be listed as a VOC 

in Regulation Number 7, Section XII, Control of VOC Emissions from Dry Cleaning Facilities using 

Perchloroethylene as a Solvent, is being deleted. 

Regulation Number 8 and 3 list the federal Hazardous Air Pollutants (HAPs). In the June 8, 1996 Federal 

Register the EPA removed Caprolactam (CAS 1 05-60-2) from the federal list of Hazardous Air Pollutants. 

The conforming changes in Regulation Number 3 Appendices B, C and D have been made to keep the 

list of federal HAPs in Regulation Number 3 consistent with the federal list. The list of HAPs in Regulation 

Number 8 has been removed and a reference to the list in Regulation Number 3 has been added. 

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 Regulations pertaining to organic solvents and photochemical 

substances. Section 25-7-109(2)(f) and 25-7-109(2)(g}, C.R.S., grant the Commission the authority to 

promulgate regulations pertaining to organic solvents and photochemical substances. Sections 25-7-

105(1)(l)(b) and 25-7-109(2)(h) provide authority to adopt emission control regulations and emission 

control regulations relating to HAPs respectively. 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 

. These revisions to Regulations Number 3, 7, 8 and the Common Provisions are intended to update the 

state lists of NRVOCs, the Ozone SIP, and HAPs for consistency with the federal lists. 

1.88. Adopted November 18, 1999 

Revisions to Part C Incorporation by Reference of New and Revised Federal Regulations 

Concerning Compliance Assurance Monitoring (40 C.F.R. Parts 64, 70, and 71) into 

Colorado Air Quality Control Commission Regulation Number 3, Part C, Addition of 

Section XIV. 

Background 

Regulation Number 3 

Adopted: October 20,2011 Page 299 
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. 

Pursuant to Section 114 of the 1990 Clean Air Act Amendments ("CAAA"), the U.S. Environmental 

Protection Agency ("EPA") promulgated new regulations in 40 C.F.R. Part 64 and revised regulations to 

40 C.F.R. Parts 70 and 71 to implement compliance assurance monitoring ("CAM") for pollutant specific 

emission units at major stationary sources of air pollution that are required to obtain Title V operating 

permits. The requirements imposed by the CAM rule are separate from the requirements of EPA's 

"periodic monitoring" rule found at 40 C.F.R. Section 70.6(a)(3)(i). The periodic monitoring rule requires 

that each operating permit contain any emissions monitoring or test methods already required by an 

applicable requirement including any "periodic monitoring sufficient to yield reliable data from the relevant 

time period that are representative of the source's compliance with the permit ... such monitoring shall 

assure use of terms, test methods, units, averaging periods, and other statistical conventions consistent 

with the applicable requirement." See 40 C.F.R. Section 70.6(a)(3)(i)(B) (emphasis added). 

Subject to certain exemptions, the new CAM regulations require owners or operators of such sources to 

conduct monitoring that satisfies particular criteria established in the rule to provide a reasonable 

assurance of compliance with applicable requirements of the Act. Monitoring requirements contained in 

the rules focus on emissions units that rely on pollution control equipment to achieve compliance with 

applicable standards. The CAM regulations also provide procedures for coordinating these new 

requirements with the Operating Permits Program regulations. 

The CAM regulation generally will not require implementation of its requirements for most units subject to 

CAM until the first round of Title V permit renewals, which will generally be five years after initial Title V 

permit issuance. 

The following table reflects the schedule by which CAM plans must be submitted by owners and 

opera t ors o a f ff ecte d emiSSIOnS Unl "t s: 

Pollutant Specific CAM Plan Due as part CAM Plan Due as part CAM Plan Due as part 

Emission Unit (PSEU) of the Operating Permit of the Operating Permit of the Operating Permit 

Size INITIAL ApQiication REVISION Application RENEWAL Application 

"Large" PSEU (see 40 If Title V permit If a significant permit If Title V permit 

C.F.R. Section 64.5(a)) application is not revision 1 at an existing application was 

complete by 4/20/98 OR Title V source complete before 4/20/98 

if PSEU part of a 

greenfield permit 

application after 4/20/98 

"Other" PSEU (see 40 Never Never Always 

C.F.R. Section 64.5(b_l}_ 

1. "significant permit revision" is defined as "significant permit modification" in Colorado Air Quality Control Commission Regulation 

Number 3, Part A, Section I.B.36.h. This definition is subject to change when the federal Part 70 revisions are promulgated and 

adopted by the Colorado Air Quality Control Commission. 

In the event of a significant proposed operating permit modification that may trigger the earlier application 

of the CAM rule, the rule's provisions only become applicable with respect to those pollutant specific 

emission units for which the proposed operating permit revision is applicable. See 40 C.F.R. Section 

64.5(a)(2). 

Regulation Number 3 

Adopted: October 20, 2011 Page 300 
Regulations to implement these CAAA mandates were originally proposed in 1993 as the "enhanced 

monitoring" program. The enhanced monitoring proposal focused on monitoring air emissions as a 

means of ensuring source compliance with CAAA emission limitations and operating permit conditions. 

The EPA received approximately 2,000 comment letters to the enhanced monitoring proposal. In 

response to these comments and through a series of stakeholder meetings, the agency decided to 

redesign the Part 64 program. In 1995, the EPA promulgated a revised draft Part 64 rule, which is now 

known as the CAM rule. The final CAM rule was promulgated on October 22, 1997. 

The Commission heard testimony from members of the public who were concerned that the 

implementation of the rule would have the effect of making existing applicable requirements more 

stringent. It is the Commission's understanding however that this is not the purpose nor should be the 

result of implementation of the CAM rule. In adopting the CAM rule by reference, the Commission does 

not intend that existing applicable requirements become more stringent. 

Authority 

Section 25-7-105(12), C.R.S. (1997) provides authority to promulgate regulations that are necessary to 

implement the minimum elements of Title V of the Clean Air Act. Section 25-7-106(6), C.R.S. (1997) 

provides the Commission with the authority to require testing, monitoring and record keeping. 

Commission action in promulgating these regulations is taken pursuant to the above statutory provisions. 

The Commission is not adopting the CAM rule in this incorporation by reference as part of the Colorado 

State Implementation Plan. For that reason, the provisions of Section 25-7-105.1 C.R.S. (1999) 

regarding federal enforceability do not apply. 

Purpose 

Adoption by reference of the Federal CAM regulations contained in 40 C.F.R. Part 64, and the revisions 

to 40 C.F.R. Parts 70 and 71 make the regulations enforceable under Colorado law. Adoption of the 

regulations 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. 

I.CC. Adopted November 15, 2001 

Revisions to Regulation Number 3, Part 8: Concerning Construction Permits, Including 

Regulations for the Prevention of Significant Deterioration 

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., and implements Sections 25-7-

105(17) and 25-7-212, C.R.S. 

The rule revisions adopted implement the provisions of House Bill 99-1351. Regulation Number 3 

contains permitting, monitoring, reporting, visibility protection, and fee requirements. 

Specific Statutory Authority 

The Colorado Air Pollution Prevention and Control Act, Section 25-7-105(17), C.R.S., provides the 

authority for the Commission to hold hearings to approve emission inventories related to state and federal 

lands. That subsection also directs the Air Pollution Control Division to prepare inventories for all state 

land management agencies with jurisdiction over state lands. Section 25-7-212, C.R.S., requires federal 

land managers to develop a plan for evaluating visibility in mandatory class I federal areas and to provide 

to the state an emission inventory for pollutants that affect any mandatory federal class I area within 

Colorado. This Section also directs the Commission to use the inventories to develop control strategies 

Regulation Number 3 

Adopted: October 20, 2011 Page 301 
for reducing emissions within the state of Colorado as a primary component of the visibility long-term 

strategies. 

The Commission's action is taken pursuant to procedures set forth in Sections 25-7-105, 25-7-110 and 

25-7-110.5, C.R.S. 

Purpose 

In general, HB 99-1351 was intended to provide mechanisms for the state to develop information 

important to its efforts to protect and enhance visibility, particularly in mandatory federal class I areas. 

This bill specifies the types of information that must be reported, collected and approved for use in the 

state implementation plan. 

Federal agencies own and administer approximately 36% of the land in Colorado. Accordingly, the 

federal government has jurisdiction over many sources of emissions within the state. The inventory 

information developed under this regulation will provide additional information needed regarding these 

emissions, as well as those from similar state lands. 

The rule requires that all federal and state lands have emission inventories approved by the Commission 

by December 31, 2002 and at least every five years thereafter. The emission inventories must include 

emissions in both Colorado and other states that may affect visibility in mandatory federal Class I areas in 

Colorado. 

House Bill 99-1351 requires the first submittal of inventory information by the federal land management 

agencies by December 31, 2001. The Commission anticipates that the affected federal land managers 

may rely upon regional inventory information to satisfy in part the requirements of this rule. The regional 

inventory development process is in its early stages. In addition, this hearing has been continued once 

and accordingly this rule may not become effective before the statutory deadline for the initial federal 

public lands emission inventory submittal. The Commission recognizes that this created uncertainty for 

the federal land managers. Nevertheless, the General Assembly established the deadline for submittal of 

the federal public lands inventory in 1999 and the federal agencies have known about this requirement for 

more than two years. 

The Commission anticipates that submittal of the regional emission inventory will provide enough 

information to reasonably meet the December 31, 2001 deadline. In order to ensure that inventories 

reflect the best information available, however, the Commission allowed the federal agencies an 

additional six months to provide supplemental information to fully meet the requirements of this rule. Any 

such additional information must be submitted to the Commission by July 1, 2002. The Commission is to 

hold a public hearing on the inventories and approve them by December 31, 2002. This schedule will still 

allow sufficient time for the Commission to consider and approve, if appropriate, the inventory information 

submitted. 

The Commission believes that the emissions subject to the reporting requirements of this rule are in the 

order of hundreds of tons per day of criteria pollutants and that this level of emissions justifies application 

to federal and state land managers of reporting requirements similar to those that apply to owners and 

operators of other large emissions sources. 

The Commission has the authority to exempt from the inventory requirements any sources or categories 

of sources that it determines to be of minor significance. This rule does not contain such an exemption 

because little is known about several of the source categories (e.g., biogenic sources). The Commission 

may consider at a later time whether such an exemption is appropriate based on additional information 

that may be gathered. 

The Commission elected for the purposes of this regulation to define federal land management agencies 

as those agencies that own and manage at least 50,000 acres of land in Colorado. The Commission 

Regulation Number 3 

Adopted: October 20, 2011 Page 302 
intended to exempt agencies with relatively small amounts of land (e.g., Department of Commerce, 

Bureau of Reclamation) from having to prepare inventories. In the Commission's view, the benefit of 

developing information relative to emissions from lands managed by smaller agencies did not justify the 

administrative burden and costs of preparing such emission inventories. 

The Division is required by the bill's provisions to provide an inventory of emissions from activities of all 

state of Colorado land management agencies on state of Colorado lands that may affect visibility in 

Colorado's Class I areas. The inventory is to be delivered to the Commission by July 31, 2002 and at 

least every five years thereafter. 

There are several requirements in the statute that have not been included in the regulation as they are 

largely policy directives to the Commission and Division from the General Assembly 

The rule revisions adopted address the procedural mechanisms for accomplishing the mandatory 

requirements of House Bill 99-1351. The Commission concludes that these rule revisions are adopted to 

implement prescriptive state statutory requirements, where the Commission is allowed no significant 

policy-making options, for the purposes of§ 25-7-110.5, C.R.S. The Commission also concludes that it 

has no discretion under state law to adopt alternative rules that differ significantly from these revisions, for 

the purposes of§ 25-7-11 0.8(1 }, C.R.S. Accordingly, the Commission did not include in the record some 

of the portions of the rulemaking prerequisites addressed in§ 25-7-110.5, C.R.S. and did not make 

specific determinations regarding the factors listed in§ 25-7-110.8(1}, C.R.S. 

The Commission took into consideration the appropriate items enumerated in Section 25-7-109(1)(b}, 

C.R.S. 

I.DD. Adopted July 18,2002 

Revisions to Regulation Number 3 

This Statement of Basis, Specific Statutory Authority and Purpose comply with the requirements of the 

Colorado Administrative Procedure Act Sections 24-4-103(4) and (12.5}, C.R.S. for new and revised 

regulations. 

Regulation Number 3 sets forth the Air Quality Control Commission's permitting and air pollutant emission 

notice programs for stationary sources. The regulation is organized into four parts: Part A contains 

general provisions and the Air Pollution Emission Notice (APEN) program; Part B deals with major and 

minor source Construction Permits; Part C sets forth the Operating Permit program; and, Part D provides 

the statements of basis, specific statutory authority and purpose for revisions to the regulation. Changes 

have been made to each of these parts to clarify ambiguous language, eliminate duplicative or 

unnecessary provisions and to make the requirements more understandable and easier to read. 

Additionally, some substantive changes have been made to address inconsistencies between the 

regulation and state and federal law, to improve the permit program from an air quality protection 

perspective and to eliminate unnecessary burdens on the regulated community. Appendices B and C to 

the regulation were deleted because they were duplicative of Appendix D. The majority of the revisions 

were proposed by the Air Pollution Control Division based on internal review and extensive discussions 

with interested parties. The Division's initial proposals were addressed at length during a subcommittee 

process involving the Commission, the Division, stakeholders and other interested parties. During this 

process, participants commented on the initial proposal and offered additional suggestions. The proposal 

presented to the Commission is a collaborative effort of the Division and interested stakeholders. 

Specific Statutory Authority 

Regulation Number 3 

Adopted: October 20, 2011 Page 303 
The specific statutory authority for these revisions is set forth in various Sections of the Colorado Air 

Pollution Prevention and Control Act ("Act"). Section, 25-7-105(1), C.R.S., gives the Air Quality Control 

Commission authority to promulgate rules and regulations necessary for the proper implementation of the 

Act, including regulations to assure attainment and maintenance of national ambient air quality standards, 

emission control regulations and a prevention of significant deterioration program. Section, 25-7-105(12), 

C.R.S., provides specific authority to establish, emission notice, construction permit and operating permit 

programs. Some of the statutory parameters for these programs are set forth in Sections 25-7-114, 

through 25-7-114.7 of the Act, and these Sections in turn, provide statutory authority for the current 

revisions. Additional authority for these revisions is set forth in Section 25-7-106, C.R.S., in Section 25-7-

119, C.R.S., and in Section 25-7-132, C.R.S. 

Purpose 

A review of the previous Regulation Number 3 revealed numerous stylistic, grammatical and formatting 

problems, language ambiguities and obsolete or duplicative provisions. These revisions are intended to 

update, clarify and streamline this regulation. Additionally, changes have been made to address 

developments in state and federal law, to eliminate inconsistencies between the regulation and state and 

federal law, and to improve the programs set forth in the regulation from an air quality perspective while 

eliminating or minimizing undue and unnecessary burdens on the regulated community. 

I. Part A Revisions 

Part A of Regulation Number 3 contains a definitional Section and provisions that set forth the Air 

Pollution Emission Notice program and other general provisions relevant to the notice and permit 

programs. 

A. Definition Changes 

Numerous changes to the definition Section were made. Primarily, these changes were designed to fix 

ambiguous language, to make the definitions more readable or to delete obsolete or duplicative 

definitions. For example, the definition of applicable requirement was modified to clarify that it included 

construction permit requirements that may have been modified during the operating permit process. This 

definition was always intended to include such modifications, but the old language failed to clearly explain 

that intent. Similarly, a change to the definition of major modification was necessary to clarify that the 

term included both physical changes and changes in the method of operation. The prior version omitted 

language resulting in an ambiguity regarding this intended meaning. Changes were made to the 

definition of net emissions increase to clarify that in calculating an increase or decrease of emissions, 

sources are not committed to use the emission numbers contained in an APEN. For example, when 

credible demonstrable evidence indicates a different amount of actual emissions exists, this information 

can be used to demonstrate a net emissions decrease. The definition of significant was also changed to 

clarify that the Prevention of Significant Deterioration (PSD) and New Source Review (NSR)-

nonattainment area (NAA) programs do not apply to certain hazardous air pollutants. Specifically, the 

state PSD and NSR/NAA programs exempt those hazardous air pollutants that are exempt from the 

federal PSD and NSR/NAA programs pursuant to Section 112(b)(6) of the Federal Act. 

In addition to the clarifications, formatting and readability changes made to the definition Section, a 

number of definitions were added or modified to reflect developments in federal law. For example, the 

Commission revised the definitions of actual emissions and major modification to include special 

provisions governing physical or operational changes at electric utility steam generating units. These 

changes were necessitated by changes in the federal regulations arising out of the decision in the 

Wisconsin Electric Power Company ("WEPCO") case. The changes are applicable only to coal-fired 

electric utility steam generating units. Colorado law has required that NSR provisions be interpreted 

consistent with federal requirements since 1994 when the Colorado General Assembly enacted HB94-

1264, Section 25-7-109, C.R.S. The WEPCO definitions have been added, consistent with EPA's 

regulations, in order to clarify the meaning and scope of the changes to the definitions of actual emissions 

Regulation Number 3 

Adopted: October 20,2011 Page 304 
and major modification. Units need not have obtained a formal applicability determination from the 

Division before proceeding with the physical or operational change, although doing so is at the risk of the 

source. Actual emissions levels may be determined from the information found in periodic APENs which 

sources file pursuant to Regulation Number 3, Part A, or from other credible information, such as data 

from continuous monitoring systems. The filings by sources in the past, such as APENs, have enabled 

the Division to track sources' emission increases and decreases in a manner consistent with the 

provisions in the WEPCO rule, therefore, the Commission believes this formal adoption should not 

impose a greater burden on sources in Colorado than they have historically experienced. The 

Commission notes that, consistent with the legislature's intent, the WEPCO provisions have been 

implemented by the Division in recent years. One example is the flexibility provided a change qualifying 

as a pollution control project. 

The definition of major modification was further changed to restrict what constituted a temporary activity. 

Under both the old and new regulations, temporary activities are not considered to be part of a major 

stationary source. The old definition could be read, however, to exclude activities that constituted 

temporary sources under the PSD program. Such sources are subject to certain limited PSD 

requirements, and could be classified as an exempt temporary activity resulting in an exemption from 

those limited requirements. The new version clarifies that only temporary construction or exploration 

activities are exempt, thus preserving the applicability of the PSD temporary source requirements. 

Under the definitions for major modification and major source, while emissions from temporary 

construction are not included in determining whether there is a major modification or source, emissions 

from ongoing construction are included. Several parties requested clarification as to what constitutes 

ongoing construction. Such a determination must be made on a case-by-case basis, but generally, 

construction lasting more than two years will be considered ongoing. 

At the suggestion of the regulated community, the definition of commenced construction was 

supplemented to identify the entire range of pre-construction activities that may be undertaken without 

obtaining a construction permit. 

Provisions governing regulation of non-road engines have undergone a complete overhaul. In addition, 

the definition of non-road engines was moved from the APEN exemption provisions in Part A, Section 

II.D.1.sss., to the definition Section of Part A The prior regulation (Section II.D.1.sss.) exempted certain 

non-road engines from APEN and permitting requirements, provided these exemptions did not apply 

where the engines would otherwise trigger PSD, NSR-NAA review or other applicable requirements. 

Since the promulgation of that regulation, Congress amended the federal Clean Air Act. These 

amendments, as interpreted by the D.C. Circuit Court of Appeals, precluded the states from enacting 

emission control regulations for non-road engines except under very restricted circumstances. The Court 

of Appeals held, however, that states could enact use restrictions such as restrictions on the hours of 

operation or amount of fuel usage. To address this situation, the regulated community requested that 

non-road engines be specifically identified as non-stationary sources, thus exempting them from most, if 

not all, of the requirements of Regulation Number 3. While agreeing that non-road engines should not be 

treated as stationary sources, the Division expressed a concern that a large aggregation of these engines 

might result in a violation of ambient air quality standards. To reconcile these conflicting concerns the 

regulatory revisions create a new state-only non-road engine program for certain non-road engines. 

The Commission's authority to establish a non-road engine program and to regulate the operation of nonroad engines is set forth in 27-7-106(1) C.R.S., and through the legislative declaration in 25-7-102 C.R.S. 

Non-road engines subject to the program must submit an APEN and pay appropriate APEN fees. If 

specified emission levels are tripped in the APEN, the program further requires that the source obtain a 

temporary permit and pay applicable permit fees. The permit will include such use restrictions as are 

necessary to prevent an exceedance of ambient air quality standards. Non-road engines that are mobile 

or self-propelled equipment such as bulldozers, haul trucks, water trucks, loaders, shovels, backhoes, 

road graders, cranes or similar mobile equipment are not subject to the state-only permit program and are 

not required to obtain an APEN. 

Regulation Number 3 

Adopted: October 20,2011 Page 305 
Whether an engine qualifies as a non-road engine as opposed to a stationary source will depend on the 

facts of a particular case. To qualify as a non-road engine under Regulation Number 3, Part A, Section 

I.B.40.a.iii., the engine must be portable. What constitutes portable will be determined on a case-by-case 

basis. Additionally, such portable engines lose their status as non-road engines if they remain at a 

location for more than twelve consecutive months. The regulation narrowly defines location such that use 

of a portable engine at multiple sites at a given source does not constitute use at a single location. This 

provision, however, is not intended to allow a source to circumvent the regulation by moving a given 

engine for the purpose of avoiding expiration of the twelve-month period. 

For sources that have voluntarily obtained permits for a non-road engine(s) as defined in Regulation 

Number 3, Part A, Section 1.8.40., prior to the effective date of this rule revision, a source may continue to 

operate under the existing permit. A modification or re-opening of the existing permit will effectively 

subject a source to the requirements set forth in the non-road engine state-only permit program (Part A, 

Sections I.B.40.c. and I.B.40.d.) 

During the public hearing on this rulemaking, the Commission raised concerns regarding the flexibility and 

responsiveness of the new state-only non-road engine permit program in emergency or other unforeseen 

situations. In these situations, it is an operator's obligation to file an APEN and obtain a state-only nonroad engine permit under Sections I.B.40.c., and I.B.40.d., prior to the exceedance of any trigger level 

(i.e., hours of operation and/or emission limitation). This clarification is intended to increase program 

flexibility by ensuring that operators, including local and state government, will not be penalized when 

responding to emergencies and business planning conditions when such conditions subsequently trigger 

APEN and permit application requirements under the program. 

To enhance and foster program responsiveness, the Commission expects that the Division shall act to 

complete state-only non-road engine permit applications as expeditiously as possible. In addition, under 

the authority set forth in Section 25-7-114.5(5), C.R.S., the Commission has determined that state-only 

non-road engine permit applications shall not be designated as permit actions subject to public notice 

requirements. 

B. Changes to APEN Program 

The Division proposed to add record keeping requirements to a number of APEN exemptions. The 

Commission did not adopt the specific record keeping language in Part A of the regulation. The intent of 

the Commission, however, is that sources should have records or other information sufficient to verify that 

an exemption from APEN requirements can be taken in accordance with the regulatory requirements. 

The Commission revised Section II.D.4.a.(vi), deleting the solvent return opening size requirement for 

small remote reservoir cold solvent degreasers contained in Section II.D.4.a.(vi)(A). The Commission also 

revised the emissions limit in Section II.D.4.a.(vi)(C) from 350 pounds of volatile organic compounds per 

year to one ton of emissions per year. These changes were requested by industry based on the argument 

that the existing provision was specifically designed for one particular source and is not useful for the 

broader industry. While sources are no longer required to meet the solvent return opening provision in 

order to claim the exemption, they are subject to the requirements contained in Regulation Number 7, 

Section X.B. 

Measurement of the throughput threshold for the fuel storage and dispensing equipment APEN 

Exemption in Section II. D.1.ccc., was changed from a 30-day average to an annual average. In addition, 

language was added to clarify that sources in the Denver ozone attainment-maintenance area must still 

utilize Stage 1 vapor recovery on all tanks with a capacity greater than 550 gallons, as required by 

Regulation Number 7. While ordinarily sources subject to other applicable requirements would be 

precluded from taking the exemption under the APEN and constructions permit exemption catchall 

provisions, in this particular instance, it is the Commission's intent that sources may take this exemption 

providing that the Regulation Number 7 vapor recovery requirements are met. 

Regulation Number 3 

Adopted: October 20,2011 Page 306 
An APEN exemption for wet screening operations was added at Section I.D.1.cccc. Certain wet 

screening operations are subject to New Source Performance Standard ("NSPS") Subpart 000. This 

federal requirement requires that such facilities comply with a zero visible emissions standard. Ordinarily, 

a source that is subject to a New Source Performance standard precludes the source from taking an 

APEN exemption pursuant to the catchall provision in Section II.D.4. It is the Commission's intent that in 

this particular case, application of NSPS Subpart 000 shall not prevent a wet screening operation from 

taking the exemption. 

A substantive change was made to the applicable de minimis levels for APEN exemptions in attainment 

and nonattainment areas. Under the prior regulation, if an area was nonattainment for any pollutant the 

lower nonattainment de minimis levels applied for all pollutants. This has been revised so that the lower 

levels will only apply to the pollutants for which the area is not in attainment. 

The exemption for agricultural operations was changed to provide greater clarity and to be consistent with 

the requirements of the State Act. Conforming changes were also made to the agricultural exemption set 

forth in Part C. 

Because Regulation Number 3 and the Common Provisions Regulation under went contemporaneous 

review, the primary focus with respect to duplicative provisions was to eliminate duplications between the 

two regulations. Duplicative provisions that were only applicable to Regulation Number 3 were deleted 

from the Common Provisions Regulation. Provisions applicable to multiple regulations remain in the 

Common Provisions and were deleted from Regulation Number 3. Certain non-Regulation Number 3 

duplications were also addressed. A full review of all the Commission's regulations was not undertaken 

at this time. It is expected that there are additional duplications that should be addressed as other 

regulations are opened for revision. 

C. Fee Schedule Revisions 

The language governing the fee schedule for APENs and permit processing was simplified to provide that 

fees will be charged in accordance with the procedures and amounts set forth in the Act. This change 

alleviates the requirement of revising the regulation every time the statutory fee schedules change. 

D. Confidentiality Provisions 

The rules governing confidentiality of documents submitted in connection with APENs and permit 

applications were changed to be consistent with the Act, and to clarify ambiguities in the prior regulation. 

In addition, more specific provisions were added regarding the process involved in asserting 

confidentiality and determining whether documents are in fact confidential. Under the prior regulation, the 

evaluation of confidentiality claims was very ambiguous making it difficult for the Division to determine 

whether a document was confidential, and providing sources no guidance as to the steps they should 

take to ensure confidential treatment of documents. The new provisions clearly set forth the rules for 

claiming confidentiality and for evaluating such claims. This should benefit the Division and the regulated 

community by providing a clear understanding of confidentiality protections. 

Pursuant to the State Act, information submitted as part of an air pollutant emission notice, Permit 

Application or Operating Permit reports is confidential only if it relates to secret processes or methods of 

manufacture or production. This limitation is reflected in the revised regulation. In contrast, Section 25-7-

111 (4), C.R.S. provides that information obtained by the Division in connection with an enforcement 

action may be entitled to confidential treatment if it constitutes a trade secret. The current regulatory 

revision is not intended to alter or affect the protections offered under Section 25-7-111 (4), C.R.S. 

In cases where the Division determines that certain information is not subject to confidential treatment the 

revisions shorten the notification period from fifteen to three days. This change was made based on the 

statutory mandate in the Colorado Open Records Act requiring release of public records within three days 

after a request for such records. The notification period is intended to allow the source the opportunity to 

Regulation Number 3 

Adopted: October 20,2011 Page 307 
obtain judicial relief from the Division's determination under the State Administrative Procedures Act prior 

to release of the information. While it is recognized that the three-day notification period may make it 

difficult for a source to institute a timely action, the requirements of CORA preclude a longer period. It is 

expected that the Division will take the steps necessary to provide actual notice to the source as soon as 

a determination is made, so that the source will have adequate time to protect its rights. 

II. Part B Revisions 

The majority of revisions to Part B involve stylistic changes intended to improve the readability of the 

regulation. A small number of substantive revisions were made as described below. 

The provisions in Section IV. H., were changed to clarify the requirements for obtaining a final approval 

construction permit. The previous regulation required the source to demonstrate compliance with the 

initial approval construction permit. The Division was then required to conduct an inspection to determine 

compliance. Because an inspection during the initial approval period is not required by law, the new 

regulation makes the inspection discretionary. This provides necessary protections in those instances 

where an inspection may be needed. The provision was further modified to give the Division discretion as 

to whether to issue a final approval permit when there is a pending operating permit application. 

Requiring the issuance of a final approval permit was often an unnecessary step in situations where an 

operating permit would be issued shortly thereafter. To avoid confusion among sources when the 

Division elects not to issue a final approval construction permit, a notice will be provided to the source in 

writing. Similar flexibility was added to Section III.D.6., in cases where a previously permit exempt source 

loses its exemption based on addition of new emission points. 

The prior regulation required submission of an operation, maintenance, and record keeping plan with the 

construction permit application. This provision ignored the reality that such plans are difficult to provide 

until after the source has been constructed. The new regulation provides that these plans must be 

submitted prior to obtaining final approval. 

Significant changes were made to the post construction monitoring requirements for the PSD program. 

The changes were made to be consistent with the federal PSD regulations. The revisions provide 

flexibility to either require or waive post-construction monitoring. 

The revisions expand the provisions governing appeals of construction permits. The prior regulation 

provided that a source could appeal the Division's decision to the Commission, but failed to identify the 

process for such an appeal. The revision provides that the appeal must be made within thirty days after 

the issuance of the permit, denial or revocation, and will be held in accordance with the general rules for 

adjudicatory hearings. A similar provision was also added in Part Cat Section V.E. 

Section V.B. has been changed to reflect that the Black Canyon of the Gunnison has been reclassified as 

a National Park. The boundaries of this area remain the same, and there is no change in the 

classification of this area as Class I or Class II. 

Revisions have been made throughout the regulation to address changes in areas from the 

nonattainment classification to the attainment/maintenance classification. A search of the regulation was 

conducted to identify those provisions that depended on the area being classified as nonattainment. 

When a requirement remains in place after the reclassification of an area, the word nonattainment was 

changed to attainment/maintenance. Otherwise, no change was made. A substantive change was made 

to the applicable de minimis levels for permit exemptions in attainment and nonattainment areas. Under 

the prior regulation, if an area was nonattainment for any pollutant the lower nonattainment de minimis 

levels applied for all pollutants. This has been revised so that the lower levels will only apply to the 

pollutants for which the area is not in attainment to be consistent with a similar revision in Part A. 

Ill. Part C Revisions 

Regulation Number 3 

Adopted: October 20, 2011 Page 308 
As with Parts A and B, the majority of revisions to Part C include changes to improve readability and to 

clarify ambiguous provisions. Revisions were made to Section II. E., to fix poorly worded language. The 

new provision more clearly explains when an insignificant activity exemption can be taken. In addition, 

changes in II.E., and to either Sections regarding exemptions included in Part C were made to conform to 

exemptions in Part A and B. 

Provisions regarding the phase-in of the operating permit program were deleted since these provisions 

are now obsolete. 

Section III.B.2., sets forth certain timing requirements with respect to submitting operating permit 

applications. The prior regulation was unclear as to the new legal requirements for sources subject to the 

operating permit requirement after start-up by operation of law. The revised provision clarifies that 

sources shall submit an application within twelve months of the effective date of the new requirements or 

at such other time specified in those requirements. The revisions also clarify that when a source subject 

to an operating permit is modified, an application to revise the permit must be submitted within twelve 

months of the modification. 

In the past, significant confusion has arisen when a source seeks an operating permit prior to obtaining a 

final approval construction permit under Part B. Revisions to Sections VA, and IV.B.3., clarify the rules 

governing these situations. These revisions also conform to the changes made in Part B, Section IV. H. 

The flexibility given to the Division to issue an operating permit absent a final approval construction permit 

under Section VA, is intended to apply regardless of whether the source has commenced operation of 

the emission unit(s) at issue. 

IV. Appendices 

Prior to this rulemaking, Regulation Number 3 included four appendices: Appendix A, Method for 

Determining De Minimis Levels for Non-Criteria Reportable Pollutants; Appendix B, 1993 Non-Criteria 

Reportable Pollutants; Appendix C, 1994 and Subsequent Years Non-Criteria Reportable Pollutants; and 

Appendix D, Non-Criteria Reportable Pollutants. This rulemaking deletes the original Appendix B and 

Appendix C because they are duplicative of Appendix D. Appendix D has been revised to Appendix B in 

order to maintain continuity in the regulation. 

I.EE. Adopted October 17, 2002 

Revisions to Regulation Number 3 

This Statement of Basis, Specific Statutory Authority and Purpose comply with the requirements of the 

Colorado Administrative Procedure Act Sections 24-4-103(4) and (12.5), C.R.S. for new and revised 

regulations. 

Regulation Number 3 sets forth the Air Quality Control Commission's permitting and air pollutant emission 

notice programs for stationary sources. Pursuant to its statutory authority, the Commission may exempt 

certain stationary sources from permitting and APEN requirements where emissions from such sources 

are deemed to be insignificant. The Commission is revising the exemptions for condensate and crude oil 

tanks and condensate and crude oil loading equipment to ensure that the exemptions apply only where 

the emissions are truly insignificant. Additionally, the Commission is revising the provisions designed to 

ensure that in exempting certain sources from APEN and permit requirements, the regulation does not 

allow sources to avoid other state and federal requirements. This revision clarifies when application of 

other requirements prohibit sources from claiming exemptions. 

Specific Statutory Authority 

Regulation Number 3 

Adopted: October 20, 2011 Page 309 
The specific statutory authority for these revisions is set forth in various Sections of the Colorado Air 

Pollution Prevention and Control Act ("Act"). Section, 25-7-105(1), C.R.S., gives the Air Quality Control 

Commission authority to promulgate rules and regulations necessary for the proper implementation of the 

Act, including regulations to assure attainment and maintenance of national ambient air quality standards, 

emission control regulations and a prevention of significant deterioration program. Section, 25-7-105(12), 

C.R.S., provides specific authority to establish, emission notice, construction permit and operating permit 

programs. Some of the statutory parameters for these programs are set forth in Sections 25-7-114.1, and 

25-7-114.2 of the Act, including the authority to exempt certain sources from APEN and Permitting 

requirements. These Sections in turn, provide additional statutory authority for the current revisions. 

Purpose 

I. Condensate Tanks and Truck Loading Equipment 

Revisions to the crude oil and condensate storage tank exemption in Part A, Section II.D.1.ddd.and crude 

oil and condensate truck loading equipment exemption in Part A, Section II.D.1.ee., were proposed to 

address the issue of flashing emissions in condensate tanks. The exemptions, and a corresponding 

exemption in Part C, Section II.E.3.ee. and ddd., did not take flash emissions into account when the 

Commission initially adopted the exemption. The large quantity of volatile organic emissions that can be 

released during a flash event led to changes in the exemptions. Additionally, separate exemptions have 

been established for crude oil tanks and equipment and condensate tanks and equipment in recognition 

of the fact that flashing emissions from crude oil and condensate are significantly different. 

The Commission recognizes that in changing these exemptions a number of tanks and equipment that 

were previously exempt from APEN reporting, and therefore exempt from construction permitting 

requirements, will now be required to file APENs. The Commission does not believe, however, that these 

existing sources will now be required to obtain state construction permits, since such a requirement is 

triggered by construction or modification of a source, and not by a change in a previously applicable 

exemption. If, however, the tanks or equipment is modified after December 30, 2002, a construction 

permit will be required for the modification unless the tanks or equipment qualifies under the revised 

APEN exemption or constructions permit exemption. During the revision process there was some 

discussion about what might constitute a modification that would trigger construction permit requirements. 

Based on the information provided to date, the Division and Commission do not currently believe that 

reworking of an existing well would constitute a modification under the regulations. Additionally, sources 

subject to PSD, NSR-NAA and Title V permitting requirements are required to have such permits 

regardless of their exemption status. The Commission notes to permit applicants that this change 

becomes effective on the effective date of this regulation. 

In connection with these revisions, the Commission has also looked at the timing requirements set forth in 

Part A, Section II.D.1.111., for submitting APENs and obtaining construction permits for tanks at crude oil 

and natural gas exploration and production sites. The Commission enacted this provision in 1993 to 

allow sources sufficient time to determine production levels before being required to submit APENs or 

construction permit applications. To affect this, Section II.D.1.111. provided that APENs for oil and gas 

exploration and production operations were not required until 30 days after filing the well completion or 

recompletion report with the appropriate state or federal agency. Additionally, Part B, Section III.D.8. 

provided that applications for construction permits for such operations were due at the same time as the 

APEN filing. Based on discussions during the regulation revision process the Commission discovered 

that the well completion report must be filed before production levels can be determined and that the 

provision should have referenced the report of first production. Therefore, the Commission has revised 

Section II. D.1.111. to clarify and effectuate the intent of the 1993 revisions. 

The Commission also recognizes the definition of condensate that appears in the Common Provisions 

Regulation does not include reference to an API gravity and therefore could be read to include crude oil. 

It is the Commission's intent that for the purposes of these exemptions, as well as APEN reporting, 

condensate should only include hydrocarbon liquids that fit within the Common Provisions definition and 

Regulation Number 3 

Adopted: October 20, 2011 Page310 
that have an API gravity of 40 degrees or above. The Commission anticipates revising the Common 

Provisions definition to more clearly reflect this intent the next time the Common Provisions regulation is 

opened for revision. 

II. APEN Catchall 

Changes to the APEN catchall in Part A, Section II. 0.4. and the construction permit catchalls in Part 8, 

Section 111.0.5., were significantly reworked to add clarity. The prior versions were somewhat unclear as 

to both the effect of APEN and permitting exemptions on other applicable requirements and when 

otherwise exempt sources would be required to file APENs. While the revisions minimally change the 

substantive requirements of the two catchall provisions the new language is intended to more clearly 

express these requirements. The new language clarifies that sources that are exempt from APEN and/or 

construction-permitting requirements are not, by virtue of that exemption, exempt from any other 

applicable requirements. Thus, for example, a source that is exempt from APEN or permitting 

requirements, must still comply with the Regulation Number 1 20% opacity standard. Likewise, an APEN 

exempt emission point at a major source is excused from paying APEN fees but may still need to be 

listed as an insignificant activity under the requirements of the Title V program. Additionally, where the 

emissions from a particular emission point would cause a source to avoid PSD, NSR-NAA or Title V 

information regarding that emission point cannot be omitted from any permit application, notwithstanding 

the fact that the emission point standing alone might be exempt from APEN or Construction Permit 

requirements. 

The Commission also requires that if the potential to emit, taking into account full design rate and 

continuous operation, triggers PSD or NSR requirements, the source must submit an Air Pollutant 

Emission Notice and apply for the appropriate permit, or must apply for a permit to limit the physical or 

operational capacity of the source such that the source is not considered to be a major source as defined 

in Section I. 8.59 of Part A of this regulation. This language previously appeared in the catchalls, but was 

relocated to this statement of basis. 

Finally, the revised catchall provisions subject certain emission points and sources to APEN and 

Construction Permit requirements notwithstanding the fact that such points and sources would otherwise 

be exempt. Sources specifically identified in the applicability Section of any subpart of Part A of 

Regulation Number 6 (New Source Performance Standards), or Regulation Number 8 (Hazardous Air 

Pollutants), Parts A, C, D, and E. This provision allows the Division to keep track of these points and 

sources, and ensure that the requirements of these programs are being properly followed. It must be 

noted, however, that wet screening operations subject to the exemption set forth at Part A, Section 

II.D.1.cccc may claim exemptions notwithstanding the fact that such sources are subject to New Source 

Performance Standard 000. 

I.FF. Adopted Apri116, 2004 

Revisions to Colorado Air Quality Control Commission Regulation Number 3 Stationary Source 

Permitting and Air Pollutant Emissions Notice Requirements 

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. 

Regulation Number 3 sets forth the Air Quality Control Commission's ("Commission") permitting and air 

pollutant emission notice programs for stationary sources. The rule revisions adopted reorganize and 

clarify the permitting, monitoring, reporting and fee requirements of Regulation Number 3. In addition, 

new provisions were added to conform the state program to the federal rules. 

Regulation Number 3 

Adopted: October 20, 2011 Page 311 
The existing regulation was composed of four parts. Part A contained general provisions and the Air 

Pollution Emission Notice [APEN] program; Part B addressed major and minor source construction 

permits; Part C set forth the Operating Permit Program; and Part D included the statements of basis, 

specific statutory authority and purpose for historical revisions to the regulation. 

The Commission reorganized the rule in order to make it easier for sources to find and comply with 

applicable requirements. Part A now contains general provisions applicable to reporting and permitting, 

including the Air Pollution Emission Notice requirements; Part B addresses construction permits; Part C 

includes the operating permit program; and Part D deals with the Nonattainment New Source Review and 

Prevention of Significant Deterioration ["New Source Review" or "NSR"] programs for major stationary 

sources. Minor sources will only be subject to Parts A and B; major sources (as defined for the Operating 

Permit program) are governed by Parts A, B and C. Major stationary sources must comply with Parts A, 

B, C and D. In particular, this reorganization separated the major stationary source NSR provisions from 

the construction permit requirements applicable to all sources. This will make it easier for minor sources 

to comply with the regulation. The Commission also made changes to each part in order to clarify 

ambiguous language, eliminate duplicative or unnecessary provisions, increase the level of certainty for 

the regulated community and make the regulation more understandable. Part E is now reserved for 

Environmental Management Systems and Part G contains the historical and current Statements of Basis, 

Specific Statutory Authority and Purpose for Commission rulemaking actions. 

In addition, the changes incorporate modifications to the nonattainment new source review and 

prevention of significant deterioration programs. Changes to these programs were necessary to comply 

with federal rule revisions that must be incorporated into the Colorado State Implementation Plan ("SIP"). 

The Commission tailored the federal requirements to Colorado's air quality program to ensure efficient 

and flexible operation and administration of the program while eliminating or minimizing undue and 

unnecessary burdens on the regulated community. 

Specific Statutory Authority 

The Colorado Air Pollution Prevention and Control Act, Section 25-7-105(17), C.R.S., gives the 

Commission authority to promulgate regulations necessary for the proper implementation of the Act, 

including rules to assure attainment and maintenance of national ambient air quality standards and a 

prevention of significant deterioration program. Section 25-7-105(12), C.R.S, provides specific authority 

to establish emission notice, construction permit and operating permit programs. Some of the statutory 

parameters for these programs are set forth in Sections 25-7-114 through 25-7-114.7 of the Act and these 

Sections, in turn, provide statutory authority for the current revisions. Additional authority for these 

revisions is set forth in Sections 25-7-106,25-7-119 and 25-7-132, C.R.S. 

The Commission's adoption of this rule is taken pursuant to procedures set forth in Sections 25-7-105, 

25-7-110 and 25-7-110.5, C.R.S. 

Purpose 

The Commission took into consideration the appropriate items enumerated in Section 25-7-109(1)(b), 

C.R.S. 

General Revisions to Regulation Number 3 

The Commission's reorganization of this rule separates the provisions applicable to all sources (Part A), 

the construction permit program (Part B) and the operating permit program (Part C). The NSR provisions 

for major stationary sources are now contained in Part D. In the past, these various components of the 

rule were intermingled to an extent that caused confusion and unnecessary work for both sources and for 

the Air Pollution Control Division ("Division"). By separating the major components of Regulation Number 

3, the Commission intends to make the provisions more readily usable, particularly for minor sources. 

Regulation Number 3 

Adopted: October 20,2011 Page 312 
As part of the reorganization, the Commission relocated some definitions. If a definition relates only to 

one part, it can be found at the beginning of that part. Definitions that are used in more than one part are 

placed in Part A. This approach will allow minor sources to identify applicable provisions without having 

to address the differences between construction permit, operating permit and major NSR requirements. 

The Commission in this rulemaking did not amend Section V. of Part A of the existing rule. That Section 

addresses emissions trading and changes to it are beyond the scope of this proceeding. Likewise, the 

Commission specifically concluded that this rulemaking should not extend to changes to the constructionpermitting program for minor sources unrelated to the federal NSR revisions; this restriction appeared in 

the notice of rulemaking. The Commission understands that discussions between the Division and 

stakeholders prompted by this proceeding may lead to policy and implementation changes. 

The Commission established the effective date for the NSR revisions as the date of EPA approval of the 

changes as part of the Colorado SIP. An earlier effective date would have created differences between 

federal and state rules that could expose the regulated community to inconsistent requirements. For the 

remainder of the rule, the Commission concluded that the effective date need not await EPA action. 

Those provisions will become effective following publication in the Colorado Register. 

Finally, an issue arose regarding the use of the term "attainmenUmaintenance" areas. Although this 

terminology is used in Colorado's State Implementation Plan, its relationship to these rule changes is 

unclear. The Commission decided to address this question at a later time. 

Finally, the Commission concluded that the revisions to Regulation Number 3 do not change the 

procedural, administrative nature of the regulation and are not specifically intended to reduce air pollution. 

Accordingly, the Commission did not make the determinations addressed in Section 25-7-110.8, C.R.S., 

although this Statement of Basis and Purpose includes discussion to inform interested parties of the 

Commission's intent. 

Part A Changes 

Changes to Part A largely clarify or correct existing provisions. Where EPA changed specific language 

used in this part, the Commission adopted identical phrasing absent an identified reason for a distinction. 

The term "annual actual emissions" in Section 1.8.9. replaces "actual emissions" throughout Part A in 

references to Air Pollutant Emissions Notices ("APENs") so that a source's reported emissions are those 

actually emitted during a single calendar year. This will distinguish reported emissions from the two-year 

average of "actual emissions" used for major NSR purposes. 

Section II.D.1.g. has been modified to refer to a "major source" rather than a "major stationary source," a 

term that is specific to the major NSR program. This conforms to Section 25-7-109, C.R.S. 

The Commission changed Section VI.C.3 to permit sources sixty days from issuance of an invoice to pay 

annual emissions fees. This approach will allow sources additional time to process fee payments. In 

addition, the Division is required to forward any bills more than thirty days overdue to the collections office 

for the state. This extended payment period will reduce the number of instances in which delays in 

payment result in a fee bill being sent to collections. 

The Commission adopted a change to the definition of "stationary source" reflected in Section Part A, 

Section 1.8.41 to conform it to federal and state law. 

Changes to Parts B and C 

The Commission made only conforming changes in Parts B and C after moving the provisions applying to 

major NSR to Part D. 

Regulation Number 3 

Adopted: October 20, 2011 Page 313 
Part D Changes 

Nonattainment New Source Review and Prevention of Significant Deterioration Provisions 

On December 31, 2002, the Environmental Protection Agency ("EPA") promulgated a final rule 

addressing the major NSR programs mandated by Parts C and D of Title I of the federal Clean Air Act. 

The Agency changed the requirements applicable to Colorado's SIP. The Commission adopted these 

revisions in order to comport Colorado's air quality program to the EPA rules. The revised regulation 

references to "NSR requirements" include both the nonattainment new source review and prevention of 

significant deterioration programs. 

EPA's major NSR changes modified the method for determining whether a proposed facility modification 

results in a significant emissions increase, thus triggering major NSR evaluation and technology 

requirements. In addition, EPA added new applicability options, Plant-wide Applicability Limitations and 

Clean Units, and an exclusion from major modification provisions for Pollution Control Projects. 

On October 27, 2003, EPA adopted further revisions to the major NSR program. In that rule, EPA 

provided a category of equipment replacement activities that would not be subject to the major NSR 

requirements under the routine maintenance, repair and replacement ("RMRR") exclusion. That rule has 

been challenged in U.S. Court of Appeals in Washington, D.C. The Court issued a stay, because of 

which the rule was not yet effective at the time of the hearing in this proceeding. The Commission 

elected to address RMRR issues in the future and not consider RMRR rule changes at this time. 

In general, the Commission changed Part D of Regulation Number 3 to mirror the EPA major NSR rules. 

There are instances in which the Commission's rule differs from the federal provisions. These cases are 

specifically identified in this Statement of Basis and Purpose, as required by Section 25-7-110.5, C.R.S. 

General 

The Commission required Division review and/or approval of certain actions in instances in which the 

federal rule was either silent or contained no similar specific requirement. The EPA rule preamble 

anticipates that state minor source permit programs will continue and the Commission agreed. 

Colorado's Air Pollution Prevention and Control Act ("the State Act") specifically requires permits for 

construction and modification of air pollution sources. The Commission has historically used permits as 

the basic administrative structure for its stationary source programs. Exceptions to permit requirements 

exist in the rule for sources or activities with small emissions that have a minimal impact on air quality. In 

Section I.B.5., the Commission imposed a requirement that owners or operators using the actual-toprojected-actual applicability test for a project that requires a minor source permit or modification 

[pursuant to Part A, Section I.B.26., Part C, Section I.A.4. or Part C, Section X., or any minor source 

permit under any provisions of Part B), to submit an otherwise-required permit application and include 

documentation adequate to substantiate calculations made for the test. The federal rule requires that the 

owner or operator retain, but not report to the permitting authority, this information. However, the 

information listed in this Section would necessarily be generated by the owner or operator to satisfy the 

federal requirements and need only be submitted with an otherwise-necessary construction permit 

application. Accordingly, the Commission concluded that this requirement does not exceed federal 

requirements for the purposes of the Colorado Air Pollution Prevention and Control Act. 

The Commission also concluded that the emissions calculated for the actual-to-projected actual test did 

not need to be the subject of a permit limitation. Accordingly, the information submitted will only be 

placed in an appendix to the major stationary source's Title V and/or in a construction permit note. This 

provision will assist the Division in evaluating the results of the applicability test before the relevant project 

is begun. Both the Division and the owner or operator will benefit from early identification of any 

disagreements about the applicability test. 

Regulation Number 3 

Adopted: October 20,2011 Page 314 
The Commission noted discrepancies in the use in the federal rule of the terms "regulated NSR pollutant" 

and "regulated air pollutant." The latter includes Hazardous Air Pollutants by definition. In order to 

conform all of the Sections using these terms, the Commission used "regulated NSR pollutant" throughout 

Part D. 

The federal rule allows a reviewing authority to establish a "reasonable period" for determining what 

constitutes a "contemporaneous" net emissions increase. Part A, Section I.B.37.b. of the old rule 

specified a period of five years. The Commission retained that five-year period in the revisions adopted. 

This period remains reasonable, just as it was under the prior version, serves to increase certainty and 

should assure that any net emission increase calculations are more accurate. 

For calculation of Baseline Actual Emissions levels in Part D, Section II.A.4., the Commission concluded 

that emissions during periods of startup, shutdown and malfunction must be quantified based on the rate 

of operation during that period. For example, during a control equipment malfunction the calculation must 

assume that no controls were used to reduce emissions during that period unless the source can 

demonstrate the actual level of control provided during the malfunction. The Commission will allow a 

source to use estimation methods based on best engineering judgment, subject to approval by the 

Division; however, sources utilizing Continuous Emissions Monitors should be able to quantify these 

emissions with relative ease. In any event, the Baseline Actual Emissions calculations must be approved 

by the Division for use in the applicability test. 

In calculating Baseline Actual Emissions, Part D, Section II.A.3., the emissions from malfunctions/upsets 

that exceed any enforceable limitations effective at the time of the event must be excluded. Allowing 

inclusion of these emissions in the calculation could reward a source for failing to limit, as much as 

possible, emissions during these events. Existing rules relating to these periods and "upsets" are not 

otherwise changed by the revisions. 

The federal rule requires that emissions from "demand growth" be excluded from the Projected Actual 

Emissions calculation. Demand growth is any increased utilization that could have been accommodated 

by the source prior to any change. In no case, however, may demand growth emissions exceed an 

enforceable limitation existing prior to the change or modification. 

The Commission elected not to elaborate on or further define some issues in the rule, instead relying on 

policy and practice that will be developed as necessary by the Division and/or EPA. These inClude what 

"could" increase emissions and what constitutes "regular operations" in Section VI.B.5.c. as well as the 

approach for evaluating "design capacity" in Section II.A.38.a. In another provision, Section VI.B.5., the 

Commission intends that the Division will implement the wording "reasonable possibility" consistent with, 

though not necessarily identical to, EPA's rule preamble and the Notice of Reconsideration issued by 

EPA regarding this issue. Likewise, when an owner or operator uses emission factors to monitor PAL 

pollutant emissions [Section V.A.?.c.(iii)], it and the Division will adjust, as appropriate, those factors to 

account for uncertainties or limitations inherent in the factor. The federal preamble may be consulted for 

guidance on such issues, including the option for the Division to exempt a source from having to validate 

the factors. 

Sections II.A.4.a. and VI. B. S.c. include the concept of a period that is "more representative of normal 

source operations" in the definition of Baseline Actual Emissions. The Commission decided that such 

determinations will continue to be resolved on a case-by-case basis by the Division. 

Plant-wide Applicability Limitations ("PAL") 

For the purpose of setting a PAL, a unit planned but not yet constructed as of the date of PAL 

determination has Baseline Actual Emissions of 0 tons per year, as it does not have actual emissions as 

of that date. These units do not differ in practice from those later planned but not yet constructed under 

the PAL. Both types of units must meet the emissions limitations and other conditions assessed in the 

PAL. Emissions units constructed at the time the PAL is set, but that have not yet operated for more than 

Regulation Number 3 

Adopted: October 20,2011 Page 315 
two years are new units. The Division, after consultation with EPA, recommended that the Commission 

not allow PALs for major stationary sources that have not been in operation for at least two years. The 

Commission agreed. These sources would not have "actual emissions" for this purpose because they 

would not yet have operated during a representative period. Allowing PALs for these sources would 

effectively create an "allowable PAL." EPA clearly indicated in the December 31, 2002 preamble that it 

did not intend to create provisions for allowable PALs in that promulgation. The phrasing here comports 

with EPA's intent. 

Process and control equipment changes under PALs require application and approval of a permit under 

existing provisions of Colorado law. PALs, since they establish a new emissions limitation for an entire 

facility, will necessitate a revision to the Operating Permit held by the owner or operator. The Division will 

act on any such permit application during the period otherwise provided in Part C. Once a source has 

obtained a PAL, the PAL emission limits and conditions must remain in place for the entire ten-year 

effective period of the PAL. Allowing a source to obtain and renounce a PAL at a shorter interval would 

create confusion and potentially allow manipulation of the PAL option to avoid major NSR. 

The Commission adopted language differing in minor respects from the federal rule in Sections XVII.B.2. 

and XVI1.1.2. The federal language used to construct Section XVII.B.2. was incomplete and unclear in 

that it did not specify that baseline actual emissions calculations must be provided for each emissions unit 

as parts of a PAL permit application. The phrase added creates no additional burden for sources that 

would have to evaluate emissions from these units in any event. In Section XVII.I.2., the Commission 

added the phrase "including any additional information requested by the Division." Although the 

Division's authority to request information in order to confirm an owner or operator's calculations is well 

accepted, this addition places the PAL applicant on notice that a request may be made. 

The Commission also departed from the federal wording in Section XVII.N.1. that addressed the semiannual report to be provided by PAL sources. The Commission concluded that requiring submittal with 

the report of all data relied upon imposed an unnecessary and undue burden on sources. Instead, the 

rule allows the Division to request these data if it finds it necessary to implement its administration of the 

PAL permit. 

Clean Units 

The CU provisions of this regulation address only the emissions from a specific unit. If a unit is 

designated as a Clean Unit, the source does not need to go through the major source NSR program if it 

makes certain types of changes in the future. This allows greater flexibility to a source. The source must 

accept the changes to its Title V permit that are required by the rule. Additionally, an owner or operator 

must apply for and obtain either a Construction Permit or Operating Permit for future changes at the CU 

that meet the definition of modification for Part B or C purposes even though it need not evaluate the 

project for major source NSR applicability. The Division will act on a permit application during the period 

otherwise provided in Part B or C of this regulation. 

Section XV.A.3. requires an owner or operator to submit a request for designation as a Clean Unit ("CU"), 

although this requirement does not affect automatic qualification as a CU. This provision ensures that the 

Division may conduct an initial, cursory review to confirm the qualification. Absent this provision, sources 

mistakenly using the CU option might operate for years in the belief that the designation protects 

operation of the unit. One principal concern for the Commission in adopting any regulation is to provide a 

high level of certainty for sources to avoid delayed compliance issues. By allowing the Division to review 

the information the source used to qualify as a CU, the Commission is providing that certainty for sources. 

In addition, this provision simplifies field and other inspections by assuring that the Division has an 

accurate record of the operations and equipment at the source. 

Pollution Control Projects 

Regulation Number 3 

Adopted: October 20, 2011 Page 316 
The Commission believes that the Pollution Control Project ("PCP") exclusion will only be used for 

projects that result in a significant emissions increase in a "collateral" pollutant. If the project does not 

cause increases in any regulated pollutant, it would not need an exclusion from major modification 

requirements. Therefore, Section XVI.A. requires that a source intending to use the PCP exclusion must 

submit an APEN and a permit application, whether the PCP is listed or unlisted, as a significant emissions 

increase is likely to occur. Under the federal rule, unlisted PCPs are required to obtain permits or permit 

modifications. The Commission omitted the provision in the federal rule requiring a written notice for 

listed projects to streamline duplicative requirements in the federal PCP provisions and Parts B and C of 

the regulation. However, recognizing the nature of PCPs, the Commission has retained the list of the 

information that must be submitted to the Division. This list differs in some respects from the information 

required in the permit provisions of Regulation Number 3. 

The Commission also adopted a provision requiring owners or operators of PCPs to retain records for a 

minimum of five years, consistent with the Operating Permit recordkeeping timeframe. The federal rule 

does not specify a retention period. This Commission action was appropriate to assure that sources and 

the Division have a common understanding about the retention period. Finally, in order to comply with 

the federal rule, the Commission included a public notice and comment opportunity for PCPs. 

I.GG. Adopted December 16, 2004 

Revisions to Regulation Number 3 

The primary purpose of this rule revision is to clarify the applicability of various permitting and APEN 

provisions to sources within areas designated as attainmenUmaintenance. Such clarification merely 

makes express the rule that applied by interpretation. In most cases, the revision makes the 

requirements applicable to attainment areas applicable to attainmenUmaintenance areas. One notable 

exception is the requirement for construction permits for gasoline stations within the Denver 1-hour ozone 

attainmenUmaintenance area, which requirement is specified in the SIP. 40 CFR 52.320(c)(94). This rule 

revision also includes other minor revisions, including reporting requirements for condensate storage 

tanks subject to Regulation Number 3, Section XII., and corrections for accuracy. This rule revision 

makes no significant, substantive changes to the regulation. Nothing in this rule change exceeds the 

requirements of federal law. This rule change is administrative in nature, is not intended to cause 

reductions in air pollution, and therefore is exempt from the requirement for findings pursuant to Section 

25-7-110.8, C.R.S. 

I.HH. Adopted July 21, 2005 

Revisions to Regulation Number 3 

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. 

Regulation Number 3 sets forth the Air Quality Control Commission's permitting and air pollutant emission 

notice programs for stationary sources. The Commission amended Regulation Number 3, Part A, Section 

V. to make it consistent with the repeal of the Emissions Trading Rule in Regulation Number 5 in 

December 2004. It was originally anticipated that Regulation Number 5 would replace Part A, Section V. 

in Regulation Number 3 as the Commission's trading program, essentially identical to EPA's. The text of 

Part A, Section V. was italicized to represent provisions that would remain effective until EPA approved 

the program in Regulation Number 5. EPA decided not to finalize its trading program; therefore, it would 

never approve Regulation Number 5 as a SIP component. The Commission deleted Section V.A.3., Part 

A that contained the outmoded effective date. The Commission also replaced the italicized text with 

normal font in all of Part A, Section V. to conform the text to these circumstances. In addition, one 

Regulation Number 3 

Adopted: October 20, 2011 Page 317 
hazardous air pollutant (2-butoxyethanol) was deleted to conform the State's list (in appendix b) to the 

Federal list of hazardous air pollutants. 

The Common Provisions Regulation sets forth requirements and definitions that pertain or may pertain to 

all of the other Commission regulations. EPA added four compounds to its list of compounds (known as 

non reactive volatile organic compounds) to be excluded from the definition of volatile organic compound 

on the basis that these compounds make a negligible contribution to tropospheric ozone formation. The 

Commission adopted a conforming change to the definition of non-reactive volatile organic compounds in 

the Common Provisions Regulation, Section I.G. 

Specific Statutory Authority 

The Colorado Air Pollution Prevention and Control Act give the Commission authority to promulgate 

regulations necessary for the proper implementation of the act. Section 25-7-1 05( 12), C. R. S, provides 

specific authority to establish emission notice, construction permit and operating permit programs. Some 

of the statutory parameters for these programs are set forth in Sections 25-7-114 through 25-7-114.7 of 

the act and these Sections, in turn, provide statutory authority for the current revisions. Additional 

authority for these revisions is set forth in Sections 25-7-106, 25-7-119 and 25-7-132, C. R. S. 

The Commission's adoption of this rule is taken pursuant to procedures set forth in Sections 25-7-1 05, 

25-7-110 and 25-7-110.5, C.R.S. 

Purpose 

The Commission took into consideration the appropriate items enumerated in Section 25-7-109(1)(b}, 

C.R.S. 

The purpose of removing the italicized text from Regulation Number3, Part 'A, Section V. was to prevent 

any ambiguity about the applicability of those provisions. Changing the font of the text does not have any 

regulatory impact since the provisions were already in effect and will remain in effect. Section V.A.3. was 

deleted because it was an outmoded provision that was only necessary if Section V. was to be replaced 

by Regulation Number 5. The Commission's repeal of Regulation Number 5 made that provision 

unnecessary. Removing the italics from Section V. also will eliminate confusion with the italicized text in 

Part D of Regulation Number 3. 

The purpose of the deletion of one hazardous air pollutant in appendix b of Regulation Number 3 and the 

addition of four non-reactive volatile organic compounds to the list in Section I. G. of the Common 

Provisions Regulation is to conform the Commission's rules to Federal regulations. The Federal rule 

changes were published on November 29, 2004. If the Commission did not make these revisions, the 

State rules would be more restrictive than the Federal rules because these revisions serve to exempt the 

compounds from emission standards, monitoring, reporting and record keeping requirements. 

1.11. Adopted December 15, 2005 

Revisions to Regulation Number 3 

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. 

Specific Statutory Authority 

The Colorado Air Pollution Prevention and Control Act, Section 25-7-105, C.R.S., gives the Commission 

authority to promulgate regulations necessary for the proper implementation of the Act, including rules to 

assure attainment and maintenance of national Ambient Air Quality Standards and a prevention of 

Regulation Number 3 

Adopted: October 20, 2011 Page 318 
significant deterioration program. Section 25-7-105(12), C.R.S. provides specific authority to establish 

emission notice, construction permit and operating permit programs. Some of the statutory parameters 

for these programs are set forth in Sections 25-7-114 through 25-7-114.7 of the Act and these Sections, 

in turn, provide statutory authority for the current revisions. Additional authority for these revisions is set 

forth in Sections 25-7-106,25-7-119 and 25-7-132, C.R.S. 

The Commission's adoption of this rule is taken pursuant to procedures and requirements set forth in 

Sections 25-7-105, 25-7-110 and 25-7-110.5, C.R.S. 

Purpose 

On December 31, 2002, the Environmental Protection Agency ("EPA") promulgated a final rule revising 

the Major New Source Review ["NSR"] programs mandated by Parts C and D of Title I of the Federal 

Clean Air Act. EPA changed the several Federal provisions that were reflected in Colorado's SIP and in 

2004 the Commission made revisions to match the new Federal Rule. 

In the 2002 Rule, EPA provided several new applicability options for stationary sources. Among those 

options is treatment of some sources as clean units. To qualify, the source operators must employ stateof-the-art pollution control technology as a result of a major NSR determination within the last ten years, 

or demonstrate that control technology being employed is comparable to the best available control 

technology or lowest achievable emission rate. A source that qualifies as a clean unit would not have to 

go through a traditional NSR applicability determination if it makes certain types of changes in the future. 

The Commission's 2004 Rule adopted the clean unit exemption virtually without change. 

The 2002 Rule also expanded the exemption from major modifications for pollution control projects 

(PCPS), originally provided only to electric utility steam generating units in the 1992 WEPCO Rule. Under 

the 2002 Rule, collateral emissions increases resulting from a PCP at an existing unit would not be 

included in calculations to determine if a project involving that unit would trigger NSR. 

As part of the 2002 rule, EPA allowed sources to calculate their actual and projected actual emissions to 

determine whether a modification will trigger NSR. If a source concludes that there is no "reasonable 

possibility" that emissions from a project will trigger NSR, the source is not required to keep records 

substantiating that calculation. However, the data and records would necessarily be generated by the 

owner or operator to calculate its emissions. 

The Commission did not follow the Federal Rule in this regard. In Section I.B.5., the Commission 

imposed a requirement that owners or operators using the actual-to-projected-actual applicability test for 

a project that requires a minor source permit or modification [pursuant to Part A, Section I.B.26.; Part C, 

Section I.A.3.; or Part C, Section X.; or any minor source permit under any provisions of Part B), submit 

an otherwise-required permit application and include documentation adequate to substantiate calculations 

made for the test. 

On June 24, 2005, the United States Court of Appeals for the District of Columbia Circuit issued its 

decision and opinion in the case of State of New York v. U.S. Environmental Protection Agency,----F.3D--

-- 2005 WL 1489698, 35 Envtl. L. Rep. 20,135, D.C.Cir., June 24, 2005. The court concluded that, 

regarding the clean unit exemption from NSR, the plain language of the Clean Air Act indicated that 

Congress intended to apply NSR to changes that increase actual emissions instead of potential or 

allowable emissions. As a result, the court vacated the clean units portions of the Federal Rule. The 

court also concluded that EPA lacks the authority to create pollution control project exemptions from NSR 

and vacated the PCP portions of both the 1992 Wepco Rule and the 2002 rule. By vacating those 

portions of the Federal NSR rule, the court terminated those exemptions to new source review. 

In view of the court's decision, the Commission concluded that there was no basis to retain the clean unit 

and pollution control project provisions in Regulation no. 3. The federal rule no longer allows operators to 

Regulation Number 3 

Adopted: October 20, 2011 Page 319 
use those provisions to determine applicability of NSR to the source and Colorado law and the Colorado 

State Implementation Plan should be conformed to federal law in this instance. 

The D.C. Circuit court also addressed the recordkeeping and reporting requirements of the federal rule. 

The 2002 rule excused a source from maintaining records of the information and calculations used in the 

actual-to-projected actual applicability test if the source determined that there was no "reasonable 

possibility" that the modification would trigger NSR. These are the same records necessary to 

substantiate calculations made for the applicability test. The court concluded that lack of evidence, in the 

form of data and records, could inhibit enforceability of the NSR program in this context. The court 

remanded this part of the rule. 

By remanding this portion of the 2002 rule, the court allowed EPA to further consider its position and 

return to the court at some time in the future for more proceedings in support of the rule. In this case, 

EPA has the opportunity to explain how it can ensure NSR compliance without the relevant data. There 

is no deadline, or requirement, for EPA to take further action. 

The Commission, in its 2004 rulemaking, elected to require that sources retain records that, among other 

things, are essential to substantiate sources' calculations using the actual-to-projected-actual applicability 

test. The Commission also chose to require that a source submit its data and calculations along with a 

permit application that would otherwise be required for the physical or operational change. The Division 

reviews the data and calculations only to confirm a source's conclusions whether it triggers NSR. The 

information submitted is then included in a non-enforceable appendix to a source's Title V Permit or as a 

permit note in the source's construction permit 

The recordkeeping requirement adopted by the Commission has benefits to both sources and the 

Division, one of which is to avoid later uncertainty whether a project triggered NSR. Accordingly, the 

Commission elected not to modify this part of Regulation Number 3. 

The recordkeeping requirement adopted by the Commission has benefits to both sources and the 

Division, one of which is to avoid later uncertainty whether a project triggered NSR. Accordingly, the 

Commission elected not to modify Part D, Section I.B.5. and to modify Part D, Sections V.A.7.c. and 

VI.B.5. in a manner, that maintains consistency with Section I.B.5. 

I.JJ. Adopted March 16, 2006 

Revisions to Regulation Number 3, Part F, Best Available Retrofit Technology 

This Statement of Basis, Specific Statutory Authority and Purpose complies with the requirements of the 

Colorado Administrative Procedures Act,§ 24-4-103, C.R.S., and the Colorado Air Pollution Prevention 

and Control Act,§§ 25-7-110 and 25-7-110.5, C.R.S ("the Act"). 

Specific Statutory Authority 

The Commission promulgates this regulation pursuant to the authority granted in C.R.S., Sections 25-7-

105 (general authorities and duties of the Commission for air quality control); 25-7-1 05(1 )(c), (authority to 

adopt a prevention of significant deterioration program); 25-7-106 (additional authorities of the 

Commission for air quality control); 25-7-106(1) (authority to exercise flexibility in developing effective air 

quality control program); 25-7-106(2) (authority to hold public hearings); 25-7-109(1)(a) (authority to 

require the use of air pollution controls); 25-7-109(2)(a) (authority to adopt emission control regulations 

pertaining to visible pollutants); 25-7 -114.4( 1) (authority to adopt rules for the administration of permits); 

25-5-114.5 (authority to require permit applications and make determinations, and to provide for public 

participation), and 25-7- 1002 (authority to maintain a program that complies with the requirements of the 

Federal act for prevention and remediation of significant deterioration of visibility in class I Federal areas). 

Basis and Purpose 

Regulation Number 3 

Adopted: October 20, 2011 Page 320 
On July 1, 1999, the U.S. Environmental Protection Agency promulgated final regulations that require 

each state to submit a State Implementation Plan (SIP) to address regional haze. Those regulations 

require the State to establish a mechanism to identify sources that must analyze installation of Best 

Available Retrofit Technology (BART) and to require those analyses and implementation of resulting 

determinations. 

The process begins with defining air pollution facilities that are "BART-eligible." Among the BART-eligible 

sources, some sources are "subject to BART." Sources that are subject to BART must complete an 

analysis and submit a proposal for determination by the State of the Best Available Retrofit Technology 

applicable to that source. This regulation establishes the mechanisms for this process. In many instances, 

the regulation matches the Federal BART rule, including provision for a BART -Alternative approach that 

would yield "better than BART" results. 

The Commission elected to assume that all BART-eligible sources are subject to BART, but require the 

Division to perform modeling to determine whether BART eligible sources will cause or contribute to 

visibility impairment in any class I area. BART-eligible sources that do not cause or contribute to visibility 

impairment in any class I area would not be subject to BART. Individual sources would also have the 

opportunity to demonstrate that they are not eligible or not subject to BART. This approach will provide 

information necessary to develop the regional haze SIP on the schedule required by Federal law and 

allows for challenges to decisions on whether individual sources must complete BART analyses and to 

BART determinations by the State. 

Sources subject to BART must evaluate all technologies through a five step case-by-case BART analysis. 

The five steps require sources to: 1) Identify All Available Retrofit Control Technologies; 2) Eliminate 

Technically Infeasible Options; 3) Evaluate Control Effectiveness of Remaining Control Technologies, 4) 

Evaluate Impacts and Document the Results and 5) Evaluate Visibility Impacts. The Commission intends 

that sources conducting a case-by-case analysis will follow EPA's Appendix Y to 40 CFR, Part 51 -

Guidelines for BART Determinations under the Regional Haze Rule. Sources must evaluate the visibility 

impacts of each technology option using CALPUFF and/or Division-approved modeling protocols. 

This rule requires a source subject to BART to file an application for a construction permit as the 

mechanism for submitting its BART analysis and proposal, and for seeking a Division determination of 

BART for the source. The Commission concluded that using the existing permitting mechanism was the 

most expedient way to present the analysis for Division determination. The Commission further 

determined that applications for BART determinations should be subject to the public comment process 

applicable to construction permit applications for new or modified major sources. 

When identifying the available retrofit control technologies, sources must include appropriate BACT, 

LAER, NSPS, Pollution Prevention (P2) and other controls used by similar sources. This can include new 

control technologies that are in the development stages of licensing and commercial demonstration or 

commercial sales. Where EPA has already conducted extensive analyses for a source category (e.g., 

EGUs) in relation to the Federal BART Rule and determined that certain control technology would not be 

required under the pertinent BART analyses, the Commission intends that a Colorado source subject to 

BART may adequately demonstrate that the same technology excluded under the EPA analyses would 

not be appropriate for the Colorado source by showing sufficient similarity between the source evaluated 

by EPA and the Colorado source. 

Sources that identify specific options as technically infeasible must show to the Division's satisfaction that 

the technology is not commercially available or that specific physical or chemical characteristics of the 

unit(s) or emission(s) involved will not allow the technology to operate effectively. 

The control effectiveness of any technology must be evaluated based on the highest removal efficiency 

available for the technology. Sources may also look at lower efficiencies in addition, but must include 

consideration of the best removal efficiency. If a source has existing controls in place, improvements to 

Regulation Number 3 

Adopted: October 20, 2011 Page 321 
the existing controls or running the existing controls at a higher efficiency must be included in the 

analysis. 

The Commission realizes that emission controls often have secondary impacts. Sources must evaluate 

the costs of compliance including the average cost effectiveness and the incremental cost effectiveness 

of each technology that is feasible for the source. Energy impacts including the direct energy 

consumption for each technology and any locally scarce fuels must be evaluated. Many control options 

have secondary impacts on other media. Sources must evaluate any increases in hazardous waste, 

wastewater, or other waste products, including increased usage of scarce resources such as water. In 

cases where a facility has a limited remaining operating life, the source can place a federally enforceable 

shutdown date in its operating permit. 

The Commission intends that the Division use EPA's presumptive limits as guidelines when evaluating 

the BART analyses, with the understanding that there is a strong presumption that power plants capable 

of generating 750 megawatts or greater will meet these limits or do better, while the coal-fired electric 

generating units at smaller plants need to consider the presumptive limits as part of the BART analysis. 

Further, if a source submits an analysis demonstrating that it will meet the presumptive limits, then the 

source will be presumed to have met the BART-analysis requirements, absent an adequate showing to 

the contrary. If a source proposes a BART limit that exceeds EPA's presumptive limits, the Division would 

determine whether the BART analysis sufficiently supports the higher limit or whether other controls or 

increased control efficiencies are feasible. The Commission intends that the Division would establish a 

BART .limit higher than the presumptive limit if supported by the BART analysis. 

The Federal rules require the State to submit a SIP that identifies BART-eligible sources in the State, and 

requires the State to either adopt BART controls or adopt a BART Alternative. In some respects, the 

approach in the proposed State rule to applying the requirements of the Federal Act is not specifically 

mandated by the Federal rule, but left to the discretion of the State. The Federal Act does not specify the 

administrative decision-making process that will be used to make the relevant BART determinations. The 

State rule establishes such a procedure, relying on existing permitting procedures to the extent possible 

and appropriate. The procedure established by the State rule affords sources an opportunity for a hearing 

on the relevant BART decisions. This process is consistent with permitting practices and otherwise not 

more stringent than Federal requirements. 

NOx emissions from coal-fired power plants vary considerably depending on the design of the boiler, the 

type of combustion controls and the type of coal used. Each of these factors has an impact on the BART 

analysis. In setting presumptive BART limits for NOx, EPA took into account available types of 

combustion control equipment, the differences between boiler types, and ranks of coal (bituminous, subbituminous and lignite), thereby indicating these factors should be a part of BART analyses-not solely 

for large power plants subject to the presumptive levels for NOx, but for all coal-fired power plants. These 

NOx-related characteristics should be taken into account in setting BART limits. The BART guidelines 

allow states to take these characteristics into account and it is the intent of the Commission that the 

Division should evaluate this issue as part of BART analyses. Consistent with the Federal BART 

Guidelines, BART determinations should take into account possible local economic disruption and 

unemployment that might result from adverse impacts on coal sales related to BART determinations. 

In consideration of the unusual number of significant and complex permit determinations under the BART 

rule that will be become open to public comment about the same time, the Commission intends that the 

Division consider reasonable flexibility in applying procedures and time periods for public comment. The 

Commission also intends that all agreements and BART alternatives be noticed together with the 

construction permit for public comment purposes. 

The Air Quality Control Commission expects that the Division will provide the information required by 40 

CFR 51.308.(d)(1) and (2) for the July 20,2006 regular monthly meeting of the Commission. 

I.KK. Adopted August 17, 2006 

Regulation Number 3 

Adopted: October 20, 2011 Page 322 
Revisions to Regulation Number 3 

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. 

In accordance with the 1990 Amendments to the Federal Clean Air Act, the U.S. Environmental 

Protection Agency (EPA) has approved incorporation of the provisions for the New Source Review and 

Prevention of Significant Deterioration programs (collectively referred to as "NSR") into Colorado's state 

implementation plan (SIP). In June 2005, the Governor submitted revisions to Colorado's NSR program 

to EPA Region VIII for review and approval. During review of the submittal, Region VIII identified minor 

issues with provisions in Regulation Number 3 that the Commission is correcting to ensure continuing 

federal approval of Colorado's NSR program. The Commission is also adopting language to treat 

nitrogen oxides as an ozone precursor, consistent with EPA's promulgation of corresponding language on 

November 29, 2005. 

Section 112 of the Clean Air Act requires EPA to maintain a list of hazardous air pollutants (HAPs) 

subject to regulation under that Section. EPA occasionally revises the list by adding or removing 

pollutants based on updated scientific evidence of health impacts. EPA removed methyl ethyl ketone 

(MEK) from the list on December 19, 2005. Therefore, the Commission is removing MEK from the list of 

HAPs in Regulation Number 3, Part A, Appendix B. 

On November 29, 2004, EPA revised the federal definition of volatile organic compounds (VOCs) to 

specifically treat tertiary butyl (t-butyl) acetate as a VOC only for certain purposes, including reporting and 

photochemical dispersion modeling. The Commission is making corresponding changes to the definition 

of VOCs in the Common Provisions Regulation, and is adding t-butyl acetate as a non-criteria reportable 

pollutant in Regulation Number 3, Part A, Appendix B. Sources oft-butyl acetate will be required to report 

the pollutant separately from their VOC emissions on an Air Pollutant Emission Notice, and should not 

count their t-butyl acetate emissions when evaluating compliance with applicable VOC emission 

limitations. The Division should combine VOC emissions and reported t-butyl acetate emissions when 

conducting dispersion modeling for sources oft-butyl acetate. 

The Commission is also correcting several regulatory reference errors in Parts A, C, and D. 

Specific Statutory Authority 

The Colorado Air Pollution Prevention and Control Act, Section 25-7-105, C.R.S., gives the Commission 

authority to promulgate regulations necessary for the proper implementation of the Act, including rules to 

assure attainment and maintenance of national Ambient Air Quality Standards and a prevention of 

significant deterioration program. Section 25-7-105(12), C.R.S. provides specific authority to establish 

emission notice, construction permit and operating permit programs. Some of the statutory parameters for 

these programs are set forth in Sections 25-7-114 through 25-7-114.7 of the Act and these Sections, in 

turn, provide statutory authority for the current revisions. Additional authority for these revisions is set 

forth in Sections 25-7-106, 25-7-119 and 25-7-132, C.R.S. 

The Commission's adoption of this rule is taken pursuant to procedures and requirements set forth in 

Sections 25-7-105, 25-7-110 and 25-7-110.5, C.R.S. 

Purpose 

The Commission is revising Regulation Number 3 to address issues identified by the U.S. Environmental 

Protection Agency (EPA) during review of Colorado's state implementation plan (SIP) in 2005, to 

incorporate federal changes to the New Source Review program, to revise the definition of volatile 

Regulation Number 3 

Adopted: October 20, 2011 Page 323 
organic compounds and the list of hazardous air pollutants consistent with federal actions, and to make 

miscellaneous technical corrections. These changes will help to ensure continued approval by EPA of 

Colorado's New Source Review program and will provide consistent treatment by EPA and the Division of 

hazardous air pollutants and volatile organic compounds. These changes will also correct regulatory 

cross-references within Regulation Number 3, which will make the regulation easier to understand. 

Further, these revisions include any typographical errors within the regulation. 

I.LL. Adopted December 15, 2006 

Revisions to Regulation Number 3, Part A, Section VI.D.1. 

This Statement of Basis, Specific Statutory Authority and Purpose complies with the requirements of the 

Colorado Administrative Procedure Act Sections 24-4-103(4}, C.R.S. for new and revised regulations. 

The Air Quality Control Commission has adopted revisions to Part A, Section VI.D.1. in order to increase 

the annual emission fees charged to air pollution sources in Colorado commencing in 2007. The revised 

fees are within the statutory limit set by Section 25-7-114.7, C.R.S. The increase is necessary to address 

decreasing fee revenues used to fund existing programs, as well as to provide additional funding for 

requested additional permitting and inspection personnel. The proposed increase was addressed at 

length during a subcommittee process involving the Commission, the Division, stakeholders and other 

interested parties. The revision is a collaborative effort of the Division and interested stakeholders. 

Specific Statutory Authority 

The specific statutory authority for these revisions is set forth in Sections 25-7-114.7 of the Colorado Air 

Pollution Prevention and Control Act ("Act"), which allows the Commission to set annual emission fees for 

regulated and hazardous air pollutants. 

Purpose 

The revisions to Part A, Section VI.D.1. were adopted to cover anticipated revenue shortfalls and fund 

requested additional FTE that will be used to address the Division's permitting backlog and the increased 

workload arising from the rapid growth of oil and gas sources in Colorado. 

I.MM. Adopted October 18,2007 

Revisions to Regulation Number 3, Part A, Section VI.D.1. 

This Statement of Basis, Specific Statutory Authority and Purpose complies with the requirements of the 

Colorado Administrative Procedure Act Sections 24-4-103(4), C.R.S. for new and revised regulations. 

The Air Quality Control Commission has adopted revisions to Part A, Section VI. D.1. in order to increase 

the annual emission fees charged to air pollution sources in Colorado commencing in 2007. The revised 

fees are at the statutory limit set by Section 25-7-114.7, C.R.S. The increase is necessary to address 

decreasing fee revenues used to fund existing programs. These revisions are concurrent with other 

recent fee adjustments to ensure appropriate funding for the program. 

Specific Statutory Authority 

Regulation Number 3 

Adopted: October 20, 2011 Page 324 
The specific statutory authority for these revisions is set forth in Sections 25-7-114.7 of the Colorado Air 

Pollution Prevention and Control Act ("Act"), which allows the Commission to set annual emission fees for 

regulated and hazardous air pollutants. 

Purpose 

The revisions to Part A, Section VI.D.1. were adopted to cover anticipated revenue shortfalls and fund 

requested additional FTE that will be used to address the Division's permitting backlog and the increased 

workload arising from the rapid growth of oil and gas sources in Colorado. 

I.NN. Adopted December 21, 2007 

Revisions to Regulation Number 3, Part E, Best Available Retrofit Technology 

This Statement of Basis, Specific Statutory Authority and Purpose complies with the requirements of the 

Colorado Administrative Procedures Act,§ 24-4-103, C.R.S., and the Colorado Air Pollution Prevention 

and Control Act,§§ 25-7-110 and 25-7-110.5, C.R.S ("the Act"). 

Specific Statutory Authority 

The Commission promulgates this regulation pursuant to the authority granted in Sections 25-7-105(1)(c), 

C.R.S. (authority to adopt a prevention of significant deterioration program); 25-7-1 09(1 )(a) (authority to 

require the use of air pollution controls); 25-7-1 09(2)(a) (authority to adopt emission control regulations 

pertaining to visible pollutants); 25-7-114.4(1) (authority to adopt rules for the administration of permits); 

and 25-7-1002 (authority to maintain a program that complies with the requirements of the federal act for 

prevention and remediation of significant deterioration of visibility in class I federal areas). 

Basis and Purpose 

This regulatory change places the Division's BART determinations and associated requirements in a new 

section of Regulation Number 3, Part E - Section VI. 

EPA has raised concerns regarding the practical enforceability of the Colorado's BART determinations. 

The emission limits and averaging times for each of Colorado's BART sources will be included in each 

Title V permit, and included in the proposed SIP. The Title V permits and the SIP are each federally 

enforceable when approved by EPA. Nonetheless, EPA believes that more is needed to ensure the 

practical enforceability of these BART limits. 

To address EPA's concerns the BART emission limits and related provisions concerning the installation, 

operation and maintenance of BART controls have also been added to Regulation Number3, and new 

Section VI will become part of Colorado's SIP. 

The foregoing approach is largely similar to the approach taken on the state's PM-1 0 SIP in 2001, where 

the state agreed to include certain emission limits in Regulation Number 1. 

1.00. Adopted February 21, 2008 

Revisions to Regulation Number 3 

This Statement of Basis, Specific Statutory Authority and Purpose complies with the requirements of the 

Colorado Administrative Procedure Act Sections 24-4-103(4), C.R.S. for new and revised regulations. 

Basis and Purpose 

Regulation Number 3 

Adopted: October 20, 2011 Page 325 
The Colorado Air Quality Control Commission ("Commission") intends to revise the provisions of 

Regulation Number 3, Part A and 8 to include PM2.5 as a Colorado regulated pollutant, to address 

inadvertent removals of rule revisions previously adopted by the Commission, and finally to correct 

typographical, grammatical and formatting errors found throughout Regulation Number 3. 

Regarding PM2.5 emissions, the EPA promulgated a revised national ambient air quality standard 

("NAAQS") for PM2.5 emissions on October 17, 2006. The effective date for the new standard was 

December 18, 2006. The Commission intends to apply the Regulation Number 3 requirements to PM2.5 

emissions. 

Additionally, the Commission intends to reinstate several previously adopted revisions and to correct 

several typographical errors in Regulation Number 3. 

Note that the Commission intends to defer any decision to exclude ethanol production facilities from the 

major stationary source definition of "chemical process plant" as proposed in the Federal Register on May 

1, 2007 (see 72FR24060] until all relevant pending matters at the federal level are resolved. 

PM2.5 Emissions 

The Commission intends to apply the Regulation Number 3, Part A and 8 requirements to PM2.5 

emissions by 1) including PM2.5 emissions under the "air pollutant" and "criteria pollutant" definitions 

found in Part A, Sections 1.8.6 and 1.8.16, and 2) setting permitting thresholds as the same level as PM10 

emissions (revise Part 8, Sections II.D.2 and li.D.3). Note that the EPA has not yet promulgated the 

PM2.5 New Source Review ("NSR") Implementation Rule, which will specify how PM2.5 emissions should 

be treated for Prevention of Significant Deterioration ("PSD") and major source NSR sources. Upon 

promulgation, the Commission intends to incorporate those changes into Regulation Number 3, Part D as 

well. 

Inadvertent Removals of Rule Revisions 

Several previously adopted rule revisions were discovered as having been inadvertently removed from 

Regulation Number 3. The Commission intends to reinstate these previously adopted revisions. 

Specifically, the Commission intends to: 

Re-identify volatile organic compounds ("VOCs") as being subject to the Reasonably Available Control 

Technology ("RACT") requirements. During the December 16, 2004 Regulation Number 3 rulemaking, 

VOCs were inadvertently removed from the RACT requirements. Since the minor source RACT 

requirement for VOC emissions were part of the State Implementation Plan, EPA considers removal of 

VOCs from minor source RACT requirements as backsliding. Therefore this revision should be reinserted 

into Regulation Number 3, Part 8, Section III.D.2. 

Re-insert the inadvertent removal of the following text previously adopted by the Commission on 

December 16, 2004: 

Reference to "attainment/maintenance" areas in Part 8, Sections li.D.1.c.(iii)(8), 111.8.5.d., and III.C.1.a., 

and 

Remove exemption reference to Denver Metropolitan PM1 0 attainment/maintenance area and change 

reference to "Denver Metropolitan PM10 and ozone attainment/maintenance area" to "Denver 1-hour 

ozone attainment/maintenance area" in Part 8, Section II.D.1.f. 

Typographical, Grammatical and Formatting Errors 

The Commission intends to correct several specific typographical errors in Regulation Number 3. 

Regulation Number 3 

Adopted: October 20,2011 Page 326 
Specifically, the Commission intends to: 

Revise "citric acid plants" to "nitric acid plants" in Part A, Section I.B.23.b.(ix), and 

Revise incorrect citation in Part B, Section I.A. 

In addition, the Commission intends to correct grammatical and formatting errors in Regulation Number 3. 

Specific Statutory Authority 

The Colorado Air Pollution Prevention and Control Act, Section 25-7-105, C.R.S., gives the Commission 

authority to promulgate regulations necessary for the proper implementation of the Act, including rules to 

assure attainment and maintenance of the NAAQS and a PSD program. Section 25-7-105(12), C.R.S. 

provides specific authority to establish emission notice, construction permit and operating permit 

programs. Key statutory parameters for these programs are set forth in Sections 25-7-114 through 25-7-

114.7 of the Act and provide statutory authority for the current revisions. Additional authority for these 

revisions is set forth in Sections 25-7-106, 25-7-119 and 25-7-132, C.R.S. 

The Commission's adoption of this rule is taken pursuant to procedures and requirements set forth in 

Sections 25-7-105, 25-7-110 and 25-7-110.5, C.R.S. 

I.PP. Adopted May 14, 2008 

Revisions to Regulation Number 3, Part F 

This Statement of Basis, Specific Statutory Authority and Purpose complies with the requirements of the 

Colorado Administrative Procedures Act,§ 24-4-103, C.R.S., and the Colorado Air Pollution Prevention 

and Control Act,§§ 25-7-110 and 25-7-110.5, C.R.S ("the Act"). 

Specific Statutory Authority 

The Commission promulgates this regulation pursuant to the authority granted in Sections 25-7-105(1)(c), 

C.R.S. (authority to adopt a prevention of significant deterioration program); 25-7-1 09(1 )(a) (authority to 

require the use of air pollution controls); 25-7-109(2)(a) (authority to adopt emission control regulations 

pertaining to visible pollutants); 25-7 -114.4(1) (authority to adopt rules for the administration of permits); 

and 25-7-1002 (authority to maintain a program that complies with the requirements of the federal act for 

prevention and remediation of significant deterioration of visibility in Class I federal areas). 

Basis and Purpose 

The original language in Section IV. B established that the Division could not require post combustion NOx 

controls for any BART source. The Division has reviewed the data available on post combustion NOx 

controls in the EPA BART regulation and requested that the Commission narrowly modify the exclusion of 

post combustion NOx control. The EPA BART regulation investigated post combustion NOx control for 

Electric Utility Generators (EGUs) and generally determined that post combustion NOx control was only 

necessary in limited cases. The Commission believes that this analysis should be extended to boilers, as 

they are similar types of equipment. The Commission does not believe that the analysis done by EPA in 

the BART rule can be extended to cement production because of the dissimilar nature of the overall 

process of operation between boilers and cement kilns. The Commission narrowly modifies the 

provisions regarding the analysis of post combustion NOx controls as it relates to non-EGUs and nonboilers. The Commission believes this narrow amendment to Regulation Number 3 is appropriate and 

supported by the evidence in the hearing record. 

I.QQ. Adopted September 18, 2008 

Regulation Number 3 

Adopted: October 20, 2011 Page 327 
Revisions to Regulation Number 3, Part A 

This Statement of Basis, Specific Statutory Authority and Purpose complies with the requirements of the 

Colorado Administrative Procedures Act,§ 24-4-103(4), C.R.S., for new and revised regulations. 

The Air Quality Control Commission has adopted revisions to Part A, Section VI.D.1. in order to increase 

the annual emission fees charged to air pollution sources in Colorado commencing in 2008. The revised 

fees are at the statutory limit set by Section 25-7-114.7, C.R.S. The proposal increases the fees to the 

levels enacted by the General Assembly, and signed by the Governor, in SB08-055, reflected in Section 

25-7-114.7, C.R.S. as amended. 

Specific Statutory Authority 

The specific statutory authority for these revisions is set forth in Sections 25-7-114.7 of the Colorado Air 

Pollution Prevention and Control Act ("Act"), which allows the Commission to set annual emission fees for 

regulated and hazardous air pollutants. 

Purpose 

The revisions to Part A, Section VI.D.1. were adopted to provide necessary revenue for existing and 

anticipated revenue shortfalls, and fund additional legislatively-authorized FTE and legislatively-directed 

air quality monitoring. 

I.RR. Adopted December 12, 2008 

Revisions to Regulation Number 3, Part A, B and C 

This Statement of Basis, Specific Statutory Authority and Purpose complies with the requirements of the 

Colorado Administrative Procedure Act Sections 24-4-103(4), C.R.S. for new and revised regulations. 

As of November 20, 2007, the EPA's deferral of a nonattainment designation for the 8-Hour Ozone 

Nonattainment Area expired, signifying that the area is now considered nonattainment, or in violation of 

the 1997 8-Hour Ozone NAAQS of 0.08 parts per million (ppm) for ground level ozone. This area is now 

known as the Denver Metro Area/North Front Range Nonattainment (DMNNFR) Nonattainment Area. 

The DMNNRF Nonattainment Area includes all of Adams, Arapahoe, Boulder, Broomfield, Denver, 

Douglas, and Jefferson Counties as well as portions of Larimer and Weld Counties. 

Pursuant to the Federal Clean Air Act, Colorado must prepare and submit a State Implementation Plan 

(SIP) to the EPA no later than by June 30, 2009. This plan must propose measures designed to reduce 

ground level ozone precursor pollutants. The plan must provide for reductions in these precursor 

pollutants sufficient to ensure that ozone is reduced to below the 8-Hour Ozone NAAQS no later than 

2010. If Colorado fails to submit a sufficient SIP by the aforementioned deadline, the Clean Air Act 

mandates that the U.S.E.P.A. prepare and implement a Federal Implementation Plan in Colorado. 

Pursuant to C.R.S. § 25-7-105(1)(a)(l), the Commission must adopt such measures as are necessary to 

ensure compliance with the NAAQS. The Commission has adopted these rules to carry out this mandate. 

Specifically, the Commission has adopted revisions to Regulation Number 3, Parts A, B and C to address 

ozone formation in the DMNNFR Nonattainment Area. Specifically, the Commission has adopted 

revisions to reduce an ozone precursor, volatile organic compound (VOC) emissions, and thus reduce 

ozone formation. These revisions are necessary to ensure attainment of the current 8-Hour Ozone 

NAAQS set at 0.08 ppm. Also, these revisions help Colorado make progress toward eventual 

Regulation Number 3 

Adopted: October 20,2011 Page 328 
compliance with the new ozone NAAQS set at 0.075 ppm as well as the Governor's directive to 

proactively and pragmatically reduce ozone levels. 

Photochemical grid dispersion modeling indicates that without further emission controls, Colorado will 

attain the 8-hour standard by 2010. The dispersion modeling reflects that Colorado would attain the 

standard by a narrow margin -within 0.001 ppm on a standard of 0.08 ppm. Photochemical dispersion 

modeling analysis is the primary tool used to assess present and future qir qulaity trends, and is requried 

for EPA to approve the state attainment demonstration in the SIP. Dispersion modeling results have an 

inherent level of uncertainty, as recognized in EPA guidance, and it is appropriate for a state to use other 

tools at its disposal, including further control measures, to address and mitigate any uncertainties that can 

be present in dispersion modeling. It is appropriate for the state to use such tools to increase the 

confidence in and otherwise ensure that the predicted modeling results are accurate and borne-out in 

future air qulaity monitoring demonstrating attainent with the 8-Hour Ozone NAAQS. 

In addition, pursuant to EPA guidance, if modeling results indicate that the highest ozone levels will fall 

between 0.082 and 0.087 ppm, Colorado must conduct a "weight of the evidence" analysis and other 

supplemental analysis in order to corroborate the modeling results. Colorado's model results are within 

this range, and thus the state has conducted this analysis. The analysis supports the conclusion that 

Colorado will attain the standard by 2010, although by a narrow margin. To encrease the certainty of the 

model results and the weight of evidence demonstration, the Commission concludes that these additional 

control measures are necessary to carry out its mandate to adopt a SIP that contains those elements that 

are necessary to assure attainment of the 8-Hour Ozone NAAQS. 

In order to maintain consistancy between state regulations and federally enforceable regulations 

contained in the SIP, specifically changes to the exemptions, the Commission intends these revisions be 

adopted into the SIP. 

Statutory Authority 

The statutory authority for these revisions is set forth in the Colorado Air Pollution Prevention and Control 

Act ("Act"), C.R.S. § 25-7-101, et seq., specifically, C.R.S. §25-7-1 05(1 )(a) (authorizing a comprehensive 

state implementation plan which will assure attainment and maintenance of the NAAQS), 1 05(12) 

(authorizing rules necessary to implement the provisions of the emission notice and construction permit 

programs and the minimum elements of the operating permit program), 1 09(1 )(a), (2) and (3) (authorizing 

rules requiring effective practical air pollution controls for significant sources and categories of sources, 

including rules pertaining to nitrogen oxides and hydrocarbons, photochemical substances, as well as rule 

s pertaining to the storage and transfer of petroleum products and any other VOCs) and§ 25-7-301 

(authorizing the development of a program for the attainment and maintenance of the NAAQS). 

Purpose 

These revisions to Regulation Number 3 are part of an overall ozone reduction strategy to be 

incorporated into Colorado's SIP for ozone. The Commission intends that this overall ozone reduction 

strategy accomplishes five objectives: A) reduce VOC and nitrogen oxides' (NOx) emissions from oil and 

gas operations in the ozone nonattainment area, B) revise the control requirements for condensate tanks 

by transitioning from a system-wide to an emissions threshold control strategy in the ozone nonattainment 

area, C) expand VOC RACT requirements such that all ozone nonattainment areas are subject to 

Regulation 7's RACT requirements, D) clarify how the RACT requirements in Regulations 3 and 7 interact 

in the ozone nonattainment area, E) improve the Division's inventory of specific source category 

emissions state-wide; and F) make typographical, grammatical and formatting changes for greater clarity 

and readability. 

The Commission is adopting revisions to Part A to eliminate exemptions for certain facilities from air 

pollution emission notice requirements. These facilities include: 

Regulation Number 3 

Adopted: October 20, 2011 Page 329 
• Petroleum industry flares less than 5 tons per year (tpy) emissions, 

• Specified crude oil truck loading equipment, 

• Oil/gas production wastewater 

• Crude oil storage tanks, 

• Surface water storage impoundment, and 

• Condensate tanks with production 730 BBUyear or less. 

The Commission is also adopting revisions to Part B to exempt the following facilities from construction 

permit requirements: 

• Petroleum industry flares less than 5 tons per year (tpy) emissions, 

• Specified crude oil truck loading equipment, 

• Oil/gas production wastewater, except for commercial wastewater processing facilities, and 

• Specified crude oil storage tanks. 

The Commission is adopting revisions to Part C to clarify that the chemical storage tank exemption and 

surface water storage impoundment exemptions do not apply to specified production wastewater. 

In support of objectives A and E above, the Commission adopts these revisions to Regulation Number 3, 

Parts A, B and C to revise APEN reporting exemptions for specific source categories (Regulation Number 

3, Part A, Section II.D., Part B, Section II.D., and Part C, Section II. E.). 

Improve Emissions Inventory 

The Commission is changing several categorical APEN reporting and/or permitting exemptions in 

Regulation Number 3, Parts A, B and C in order to improve the Division's emissions inventory and for the 

sake of equity. These changes fall in three categories: 1) specific APEN and permitting exemptions were 

removed altogether; 2) specific APEN exemptions were removed and permit exemptions were kept in 

place; and 3) specific APEN and permit exemptions were clarified, but kept in place. 

Remove APEN and Permitting Exemptions 

The Commission has eliminated the APEN exemption for condensate tanks because the exemption was 

based on an emission level used in attainment areas. The Division will now be able to develop a 

complete inventory of condensate tanks and their emissions. 

Condensate tanks are now subject to the same APEN requirements as other source categories in the 8-

Hour Ozone Nonattainment Area. Additionally, the condensate tank exemption is based on a 

standardized emission factor, 13.7 pounds of VOC emissions per barrel of production, which may not be 

representative of each natural gas field. Even though the exemption was removed sources may still make 

use of the generic APEN exemption, upon determining that actual annual uncontrolled emissions fall 

below the applicable de minimis levels identified in Regulation Number 3, Part A. If based on this generic 

exemption, a source is determined to be APEN exempt, the source is also permit exempt. 

Remove APEN Exemptions, Keep Permit Exemptions 

Regulation Number 3 

Adopted: October 20, 2011 Page 330 
The Commission has removed specific source category APEN exemptions for petroleum industry flares, 

crude oil truck loading, oil production wastewater and crude oil storage tanks to improve the inventory of 

actual uncontrolled emissions. Sources may still use the generic APEN exemption, upon determining that 

actual annual uncontrolled emissions fall below the applicable de minimis levels. The Commission is 

maintaining current permitting exemptions until such time that the APEN data justify the need for 

permitting activities. 

Revise APEN and/or Permitting Exemptions 

Similarly, based on the Division's experience, actual emissions from several source categories specific to 

oil and gas-related operations may be higher than previously believed. Thus the APEN and permitting 

exemptions for surface water impoundments (Regulation Number 3, Part A, Section II.D.1.uuu. and Part 

C, Section II.E.3.yyy.) were revised to exclude from the exemption, oil and gas production wastewater 

(similar to Regulation Number 3, Part A, Section II.D.1.uu.). Also, the APEN and permitting exemptions 

for chemical storage tanks (Regulation Number 3, Part C, Section II.E.3.n.) were revised to exclude oil 

and gas production wastewater or commercial facilities' operations (similar to Regulation Number 3, Part 

A, Section II.D.1.uuu. and Part C, Section ll.E.3.yyy.). 

Finally, the APEN and permitting exemptions for fuel storage dispensing (Regulation Number 3, Part A, 

Section II. D.1.cccc. and Part C, Section II. E.3.cccc.) were revised to expand the applicability of the 

current exemption from specifically the 1-Hour Ozone Nonattainment or Attainment/Maintenance Area to 

any ozone nonattainment area for the sake of equity. 

I.SS. Adopted December 19, 2008 

Revisions to Regulation Number 3, Part F 

This Statement of Basis, Specific Statutory Authority and Purpose complies with the requirements of the 

Colorado Administrative Procedure Act Sections 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. ("the Act"). 

Specific Statutory Authority 

The Commission promulgates this regulation pursuant to the authority granted in Sections 25-7-105(1)(c), 

C.R.S. (authority to adopt a prevention of significant deterioration program); 25-7-1 09(1 ){a) (authority to 

require the use of air pollution controls); 25-7-109(2)(a) (authority to adopt emission control regulations 

pertaining to visible pollutants); 25-7-114.4(1) (authority to adopt rules for the administration of permits); 

and 25-7-1002(authority to maintain a program that complies with the requirements of the federal act for 

prevention and remediation of sig~ificant deterioration of visibility in Class I federal areas. 

Basis and Purpose 

This regulatory change updates the Division's BART determinations by adding determinations for 

Colorado Springs Utilities Drake Units 5, 6, and 7 and CEMEX Portland cement facility regarding limits 

and averaging times for sulfur dioxide, nitrogen oxides and particulates. 

The proposed change provides state and federally enforceable limitations for the BART sources. States 

must ensure that "each source subject to BART maintain the control equipment required by this subpart 

and establish procedures to ensure such equipment is properly operated and maintained". 40 CFR 

51.308(e)(v). This is required for SIP approval. 

I.TT. Adopted October 21, 2010 

Revisions to Parts A, B, C and D to Address Greenhouse Gases or GHGs 

Regulation Number 3 

Adopted: October 20, 2011 Page 331 

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This Statement of Basis, Specific Statutory Authority and Purpose complies with the requirements of the 

Colorado Administrative Procedure Act Sections 24-4-103(4) and (12.5), C.R.S. for new and revised 

regulations. 

Regulation Number 3 is designed to implement substantive regulatory programs authorized under the 

Colorado Air Pollution Prevention and Control Act ("Act") including provisions of the State Implementation 

Plan addressed in C.R.S. Section 25-7-105(1)(a), emission control regulations addressed in C.R.S. 

Section 25-7-105(1)(b}, Prevention of Significant Deterioration requirements addressed in C.R.S. 

Section 25-7-1 05(1 )(c), regulations as may be necessary and proper for the orderly and effective 

administration of construction permits and renewable operating permits addressed in C.R.S. Section 25-

7-114.4(1), as well as other authorized programs under the Act. The current revisions have been 

promulgated in order to facilitate this goal. The revisions were proposed by the Air Pollution Control 

Division based on EPA's GHG Tailoring Rule. On June 3, 2010, EPA promulgated the "Prevention of 

Significant Deterioration and Title V Greenhouse Gas Tailoring Rule." See 75 Fed. Reg. 31514 (June 3, 

2010). EPA's Greenhouse Gas (GHG) Tailoring Rule was designed to tailor the applicability criteria that 

determine which stationary sources and modification projects become subject to permitting requirements 

for GHGs under the Prevention of Significant Deterioration (PSD) and Title V Permitting Programs of the 

Clean Air Act (CAA). 

Specific Statutory Authority 

The Act, under C.R.S. Section 25-7-105(1)(a) authorizes the Air Quality Control Commission 

(Commission) to adopt rules necessary to implement the Act, and to adopt and revise comprehensive 

State Implementation Plans (SIP) to assure attainment and maintenance of national ambient air quality 

standards. C.R.S. Section 25-7-109 authorizes the Commission to adopt rules that are consistent with 

state policy regarding air pollution and with federal recommendations and requirements. C.R.S. 

Section 25-7-109(2) authorizes the Commission to regulate oxides of carbon, oxides of nitrogen and other 

chemicals, which encompasses the pollutant GHG. Additionally, Colorado is authorized to regulate 

GHGs under PSD and Title V in C.R.S. Sections 25-7-103(1.5), 25-7-114(3}, 25-7-114.3, and 25-7-201. 

Additional authority for these revisions is set forth in C.R.S. Sections 25-7-106 and 25-7-109, and 25-7-

114. 

In order to maintain consistency between state regulations and federally enforceable regulations 

contained in Colorado SIP, the Commission intends these revisions be adopted into the SIP. 

Purpose 

The Commission has adopted revisions throughout Regulation Number 3 to address GHG regulation in 

Colorado. These revisions were made to incorporate EPA's GHG Tailoring Rule into Colorado's Title V 

and PSD Permitting Programs, and to extend synthetic minor permitting to Colorado's stationary sources 

seeking federally enforceable limits to avoid major source or major stationary source applicability 

thresholds specific to GHGs. 

EPA's GHG Tailoring Rule establishes a phased approach for applying the CAA's PSD and Title V 

Permitting Programs to the sum of six GHGs 1

. The GHG Tailoring Rule has several different components 

including permitting thresholds and timing, commitments to the next steps, implementation options, and 

information requests. 

On April2, 2007, the U.S. Supreme Court held that GHGs are included in the definition of "air pollutant" 

under CAA Section 302(g). Massachusetts v. EPA, 549 U.S. 497 (2007). As part of this decision, the 

1The GHG air pollutant consists of the aggregate sum of six GHG gases: carbon dioxide (C02), nitrous oxide (N20), methane 

(CH4), hydrofluorocarbons (HFCs), perfluorocarbons (PFCs), and sulfur hexafluoride (SF6). These species of each GHG class are 

treated in aggregate, based on the total carbon dioxide equivalent (C02e). 

Regulation Number 3 

Adopted: October 20, 2011 Page 332 
Court mandated EPA to determine under CAA Section 202(a) whether GHG emissions from new motor 

vehicles endanger public health or welfare, or if too much scientific uncertainty remains to make such a 

determination. 2 

On December 7, 2009, EPA issued the Endangerment Finding and the Cause or Contribute Finding, both 

addressing GHGs under CAA Section 202(a). See 74 Fed. Reg. 66496 (Dec. 15, 2009). EPA's 

Endangerment Finding found that GHGs endanger the public health and welfare of current and future 

generations. The Cause or Contribute Finding found that the combination of the six well-mixed GHGs 

from new motor vehicles contributes to the GHG pollution which threatens public health and welfare. 

EPA's findings were a prerequisite to establishing GHG standards for light-duty vehicles, but they did not 

in themselves impose any requirements on GHG stationary sources. 

On May 7, 2010, EPA published the Light-Duty Vehicle Rule (LDVR) jointly with the National Highway 

Traffic Safety Administration to reduce GHG emissions and improve fuel economy of new passenger 

cars, light-duty trucks, and medium-duty passenger vehicles. See 75 Fed. Reg. 25324 (May 7, 2010). 

The new GHG emissions standards under the LDVR first apply to model year 2012 vehicles and become 

increasingly more stringent through model year 2016. 

EPA addressed the implications of GHGs as a newly regulated pollutant under the LDVR through the 

Johnson Memo ("EPA's Interpretation of Regulations that Determine Pollutants Covered by Federal 

Prevention of Significant Deterioration (PSD) Permit Program"). See 75 Fed. Reg. 17004 (March 29, 

2010). EPA concluded that a previously unregulated pollutant is subject to regulation once it is subject to 

actual control of emissions under the CAA or EPA regulation, and that control requirement takes effect. 

Accordingly, EPA concluded that once the LDVR takes effect on January 2, 2011 (the earliest date that a 

model year 2012 vehicle could be put on the market), GHGs will become regulated pollutants under the 

PSD and Title V permitting programs. Absent the Tailoring Rule, GHGs would then be subject to 

regulation at the existing PSD and Title V thresholds of 100 1250 tons per year (tpy). 

The foregoing federal actions now require appropriate changes to Colorado's regulations. Colorado law 

already provides the Commission authority and an obligation to regulate GHGs under the state's PSD 

and Title V permitting programs. Colorado's definition of "air pollutant" mirrors EPA's definition under the 

CAA. See C.R.S. Section 25-7-103(1.5) and CAA Section 302(g).3 Following the U.S. Supreme Court's 

holding in Massachusetts v. EPA, GHGs are included in the definition of air pollutant under CAA Section 

302(g). Colorado's PSD program applies PSD permitting requirements to new major stationary sources 

and major modifications. C.R.S. Section 25-7-210. Similarly, Colorado defines a Title V "major source" 

as "any stationary source[ ... ] that directly emits, or has the potential to emit, one hundred tons per year 

or more of any air pollutant." C.R.S. Section 25-7-114(3)(b). Furthermore, a Title V permit is required for 

any major source. C.R.S. Section 25-7-114.3(1)(b). The Division's proposed changes to Regulation 

Number 3 align these key definitions to Colorado's statute (which in turn map to the CAA) and add a 

definition of "subject to regulation," as defined in the Tailoring Rule. 

The Commission's mandate includes promulgation of regulations to reduce air pollution, including the 

promulgation of a comprehensive state implementation plan which "shall meet all requirements of the 

federal act and shall be revised whenever necessary or appropriate." C.R.S. Section 25-7-105; see also 

C.R.S. Section 25-7-102 (legislative declaration). Furthermore, Colorado's statutes provide that "In the 

formulation of each emission control regulation, the commission shall take into consideration [ ... ] the state 

policy regarding air pollution, as set forth in section 25-7-102 [and] Federal recommendations and 

requirements." C.R.S. Section 25-7-109(1)(b). 

2 CAA Section 202(a) requires EPA to "prescribe (and from time to time revise) ... standards applicable to the emission of any air pollutant from 

any class or classes of new motor vehicles ... which ... cause, or contribute to, air pollution which may reasonably be anticipated to endanger 

public health or welfare." 

3. The CAA defines "air pollutant" as" ... any air pollution agent or combination of such agents, including any physical, chemical, biological, 

radioactive[ ... ] substance or matter which is emitted into or otherwise enters the ambient air." CAA Section 302(g). Colorado's statute defines 

"air pollutant" as" ... means any fume, smoke, particulate matter, vapor, or gas or any combination thereof which is emitted into or otherwise 

enters the atmosphere, including, but not limited to, any physical, chemical, biological, radioactive [ ... ] substance or matter ... " C.R.S. Section 

25-7-103(1.5). 

Regulation Number 3 

Adopted: October 20, 2011 Page 333 
In addition to Colorado's statutory authority, federal PSD and Title V provisions under the CAA also place 

requirements on states to maintain PSD and Title V Permitting Programs in compliance with federal 

requirements. The chain of events described above renders GHGs to be considered a regulated pollutant 

subject to the federal PSD and Title V permitting requirements. Under PSD, EPA mandates that "each 

applicable implementation plan shall contain emission limitations and such other measures as may be 

necessary, as determined under regulations promulgated under this part, to prevent significant 

deterioration of air quality ... " CAA Section 161. Under Title V, the CAA provides that "Whenever the 

Administrator makes a determination that a permitting authority is not adequately administering and 

enforcing a program, or portion thereof, in accordance with the requirements of this title, the Administrator 

shall provide notice to the State and may, prior to the expiration of the 18-month period referred to in 

paragraph (2), in the Administrator's discretion, apply any of the sanctions specified in section 179(b)." 

CAA Section 502(i)(1). 

In order to avoid both the possibility of sanctions for failure to comply with EPA's permitting programs, as 

well as the unsustainable workload of regulating GHGs at the existing permitting thresholds of 1 00 I 250 

tpy, the Division proposes regulatory revisions to comport with EPA's GHG Tailoring Rule. 

Permitting Thresholds and Timing 

Regarding permitting thresholds and timing, EPA's GHG Tailoring Rule identifies three steps- Steps 1, 2 

and 3 - to phase in GHG permitting requirements over time. This rulemaking addresses only Steps 1 

and 2, as discussed in EPA's GHG Tailoring Rule. While EPA's GHG Tailoring Rule generally discusses 

a Step 3, 4 it provides few details on any associated timing and thresholds; instead EPA's GHG Tailoring 

Rule establishes an enforceable commitment to complete another rulemaking no later than by July 1, 

2012 for Step 3 and beyond. The Commission intends to expressly address these future actions 

expeditiously as they arise. 

This rulemaking establishes key definitions and the authority to regulate GHGs as well as addresses 

Steps 1 and 2 as identified in EPA's GHG Tailoring Rule. Step 1 spans from January 2, 2011 through 

June 30, 2011, and applies PSD and Title V permitting requirements to GHG emissions at "anyway 

sources," or stationary sources that are already subject to these permitting requirements for non-GHG 

pollutants. During Step 1, no source shall be required to obtain a Title V operating permit or PSD permit 

solely due to GHG emissions. Step 2 spans from July 1, 2011 through June 30, 2013. In Step 2, in 

addition to the requirements of Step 1, PSD and Title V permitting requirements apply to stationary 

sources which may be major5 for GHG emissions and no other regulated pollutant. 

EPA's GHG Tailoring Rule sets a 100,000 tpy carbon dioxide equivalent (C02e) applicability threshold for 

stationary sources that are major for GHG and no other non-GHG NSR regulated pollutant for PSD, and 

re-affirms that a significant emissions increase and a significant net emissions increase must occur in 

order to trigger PSD review. PSD and Title V permitting applicability thresholds and significance levels 

have traditionally been determined on a mass-basis. However, the Tailoring Rule sets a PSD 

significance level for GHG at 75,000 tpy on a C02e basis. There are distinct units of measure used in 

identifying GHG applicability thresholds and significance levels. Some are mass-based and some are 

C02e-based. The distinction between the two focuses on whether or not the global warming potential 

(GWP) is applied to each individual GHG species before summing the total of GHG classes for 

comparison to the appropriate value. 

The Commission recognizes that the EPA is currently developing GHG permitting guidance. At its 

earliest convenience prior to January 2, 2011, the Division is instructed to provide permitting guidance to 

sources to minimize uncertainty. 

4. EPA proposes to promulgate a separate rule specific to Step 3 by July 1, 2012. It is anticipated that this Step 3 will span from July 1, 2013 

through April 30, 2016. EPA offers limited regulatory details, but states that no stationary sources having potential to emit GHG emissions of 

less than 50,000 tons per year C02e would trigger PSD or Title V Permitting Programs under the Tailoring Rule due to GHG emissions alone. 

No other details are provided. 

5. M1Yor source or ml)jor stationary source. 

Regulation Number 3 

Adopted: October 20, 2011 Page 334 
Permitting and Application Requirements 

The Commission recognizes the difficulties in developing a GHG inventory in short order, and directs the 

Division to request permit applicants which are required to provide a GHG inventory to submit one by a 

reasonable deadline set by the Division. 

See the citations below for further information. 

Complete Application 

In Regulation Number 3, Part C, Section III.C.3.a., the Commission requires that all information related to 

the "emissions of pollutants sufficient to verify which requirements are applicable to the source" (which 

includes GHG) must be included in a complete application. Similarly, 40 C.F.R. 70.5(c)(3)(i) requires that 

Title V applications must include emissions of all regulated air pollutants. 

Further, in Regulation Number 3, Part C, Section IV.B.4, the Commission requires that a source update 

its permit application to address any requirements that become applicable after the date the source has 

submitted its application, prior to issuance of the draft permit for public comment. 

Application Shield 

In Regulation Number 3, Part C, Section II.B., the Commission grants a defense to an enforcement action 

to sources which submit a timely and complete application under Part C until a final determination on the 

permit has been made. Per Regulation Number 3, Part C, Section IV. D., after an application is deemed 

complete, the Division may request additional information in writing and set a reasonable deadline for 

response. However, the application shield defense is not available if the source "fails to submit by the 

deadline specified in writing by the Division any additional information identified as necessary to process 

the application, or to otherwise supplement its application in accordance with the provisions of Regulation 

Number 3, Part C, Sectic>ns IV.B.3. and IV.B.4." 

Applicable Requirement 

In Regulation Number 3, Part A, Section I.B.9., the Commission defines applicable requirement 

consistently with that definition found in 40 C.F.R. Part 70, Section 70.2. Based on these definitions the 

mandatory GHG Reporting Rule requirements codified in 40 C.F.R. Part 98 do not meet the definitions of 

applicable requirements at this time; however, any GHG BACT requirement or other federally enforceable 

GHG requirements, including GHG synthetic minor permit conditions necessary to avoid major source or 

major stationary source thresholds are considered applicable requirements. 

Regulation Number 3, Part C, Section V.B.4. requires that any operating permit address "all applicable 

requirements," however existing Title V sources that do not undergo PSD review should not trigger any 

GHG applicable requirements. 

"Subject to Regulation or Requirement" 

Prior to this rulemaking the Title V operating permit requirements of Regulation Number 3, Part C, 

Sections II.A.1.g., II.E.1. and II.E.2. already contained the language "subject to regulation or requirement", 

followed by a specific reference to the Federal Act or another part of Regulation Number 3. The phrase 

"subject to regulation" was addressed in the Johnson Memo, "EPA's Interpretation of Regulations that 

Determine Pollutants Covered by the Federal Prevention of Significant Deterioration (PSD) Permit 

Program" and later codified in the GHG Tailoring Rule and Regulation Number 3, Part A, Section I.B.44. 

See 75 Fed. Reg. 17004 (March 29, 201 0). For the purpose of these sections, the definition of "subject to 

regulation" is not applicable and the full phrase "subject to regulation or requirement" relates to the 

reference at the end of those statements. 

Regulation Number 3 

Adopted: October 20, 2011 Page 335 
Rescission Clause 

The Commission recognizes the uncertainty facing GHG stationary sources, given the potential for future 

federal legislation and the extensive pending legal challenges to GHG regulation under the CAA. The 

Commission intends GHG regulation in Colorado be consistent with the Federal Act, and has inserted a 

rescission clause making the effectiveness of the term Subject To Regulation dependent upon federal 

enforceability. Should either federal legislation or Court rulings from the District of Columbia Circuit Court 

of Appeals or the U.S. Supreme Court limit or render ineffective the regulation of GHG emissions under 

the PSD or Title V provisions of the Federal Act, then GHGs shall only be subject to regulation under this 

Regulation Number 3 for the affected permitting program(s) to the same extent. Example 1: if the 

regulation of GHGs under both PSD and Title V is vacated in whole, then all GHG emissions limitations or 

requirements included in any construction or operating permit issued under this Regulation Number 3 

shall no longer be enforceable. Example 2: if the Court remands the regulation of GHG emissions to EPA 

such that GHG regulation under the Federal Act is temporarily ineffective, either in whole or in part, any 

GHG emissions limitation or requirement included in any permit issued under this Regulation Number 3 

shall be limited or rendered ineffective to the same extent. Sources may actively seek to maintain those 

permit conditions if they so choose pursuant to Regulation Number 3, Part A, Section I.A. These 

examples are not intended to address all potential outcomes, but rather to provide some degree of 

implementation guidance. The Commission intends that this rescission will be automatically and 

immediately effective final of applicable court action or legislation. When triggered, this clause prevents 

regulation of GHG under Regulation Number 3 to the same extent of the federal action or court ruling and 

may require a new rulemaking action by the Commission to regulate GHGs for the affected permitting 

program, including any new details of such future regulation. 

Synthetic Minor Permits for GHGs 

No minor source air pollution construction permits are required at this time for GHGs, except where 

stationary sources voluntarily seek federally enforceable limits for GHGs to avoid major source PSD and 

Title V permitting requirements. (Regulation Number 3, Part 8, Section ll.A.7.) An application for a 

voluntary synthetic minor construction permit must include GHG emissions reported on Division-approved 

forms. Construction permits shall be issued based on production/process rates requested in the 

application, and the emission limit requested shall be a permit condition. (Regulation Number 3, Part 8, 

Section II.A.4.) 

If the above-mentioned rescission clause is triggered, any federally enforceable GHG emission limits 

contained in synthetic minor permits are no longer enforceable. The stationary source is requested to 

submit a cancellation request to the Division to cancel GHG emissions points and permits. 

Regulation Number 3 Revisions: 

The revisions to Regulation Number 3 as approved by the Commission are summarized below. 

Part A 

Add Regulation Outline 

Add new definitions of Greenhouse Gas and Carbon Dioxide Equivalent. The C02e 

definition incorporates by reference EPA's GWP codified via the GHG Mandatory Reporting 

Rule (Sections 1.8.10., 1.8.23.) 

Revise Major Source definition so that it applied to regulated NSR pollutant (which 

includes GHG) as well as to air pollutants (which does not included GHG) so that GHG is 

addressed and the definition may be used to establish the mass based GHG threshold 

(Section 1.8.25.b.) 

Regulation Number 3 

Adopted: October 20,2011 Page 336 
Add new definition of Subject to Regulation consistent with EPA's GHG Tailoring Rule 

and include the rescission clause as discussed above (Section I.B.44.) 

Revise annual emission fees to exclude GHGs (Section VI. D.) 

Part B 

Revise general permitting requirements to authorize the Division to issue synthetic minor 

permits for GHGs where stationary sources voluntarily choose to seek federally enforceable 

limits for GHG if they would otherwise be subject to PSD or Title V Permitting Programs 

(Sections II.A.4., II.A.7.) 

Part C 

Clarify that complete Title V Operating Permit applications include the reporting of GHG 

emissions as they are pollutants which may be subject to requirements applicable to the 

source, but not air pollutants, under Regulation 3 definitions (Section III.C.3.a.). 

Part D 

Revise the Definitions (Section II.A.): 

Revise BACT, Major Modification and Major Stationary Source Definition to use the term 

Regulated .NSR Pollutant for consistency and remove italics consistent with EPA's GHG 

Tailoring Rule so that these definitions become effective by January 2, 2011 (Sections II.A.8., 

II.A.22., II.A.24.a., II.A.24.a.(ii) and II.A.24.b.) 

Revise Regulated NSR Pollutant definition and remove italics consistent with EPA's GHG 

Tailoring Rule so that it becomes effective by January 2, 2011 (Section li.A.38.) 

Additionally, the Commission approves typographical, grammatical and formatting changes, as 

necessary. 

I.UU. Adopted January 7, 2011 

Regulation Number 3, Part D (Concerning Major Stationary Source New Source Review and Prevention 

of Significant Deterioration) and Part F (Best Available Retrofit Technology (BART) and 

Reasonable Progress for Regional Haze) 

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 (the Act). 

Specific Statutory Authority 

The Colorado Air Quality Control Commission (Commission) promulgates this regulation pursuant to the 

authority granted under Colorado Revised Statutes, Sections 25-7-105(1)(c), (authority to adopt a 

prevention of significant deterioration program); 25-7-1 09(1 )(a) (authority to require the use of air pollution 

controls); 25-7-109(2)(a) (authority to adopt emission control regulations pertaining to visible pollutants); 

25-7-114.4(1) (authority to adopt rules for the administration ofpermits); and 40-3.2-208 (authority to 

incorporate emission reduction plans for rate-regulated utilities within the state's Regional Haze State 

Implementation Plan). 

Basis and Purpose 

Regulation Number 3 

Adopted: October 20, 2011 Page 337 
PARTD 

These revisions to Regulation Number 3, Part D change the review and revision period for the Regional 

Haze Long Term Strategy (LTS) from every three years to every five years. This change aligns the 

reporting periods for the Regional Haze L TS and the Regional Haze progress reports that are required 

every five years pursuant to 40 C.F.R. Section 51.308(g). 

PART F 

On July 1, 1999, the U.S. Environmental Protection Agency (EPA) promulgated the final Regional Haze 

Rule (Rule), which went into effect, on August 30, 1999, and which requires each state to submit a State 

Implementation Plan (SIP) to address regional haze. The Rule is intended to achieve the national 

visibility goals as expressed in Section 169(a) of the Clean Air Act, 42 U.S.C. Section 7491. Colorado 

must develop a SIP revision in coordination and consultation with other states, tribes, federal land 

managers, EPA and Regional Planning Organizations (RPOs) designated by EPA. In the west, the RPO 

is the Western Regional Air Partnership (WRAP). 

Regional Haze is a visibility impairment that is caused by multiple sources over a broad geographic 

region. EPA's Regional Haze Rule requires every state to submit a SIP designed to improve visibility in 

its mandatory Class I federal areas (Class I areas). Class I areas are areas of great scenic importance, 

such as national parks and wilderness areas. There are 12 Class I areas in Colorado, and 156 

nationwide. 

A key element of EPA's regional haze program is Best Available Retrofit Technology (BART) for certain 

emission sources. Section 169A(b)(2)(A) of the Clean Air Act requires BART for certain existing major 

facilities, placed into operation between August 7, 1962 and August 7, 1977, that have the potential to 

emit more than 250 tons of visibility-reducing pollution a year. EPA's Regional Haze Rule requires SIPs 

to include BART emission limits for each subject-to-BART source that may reasonably be anticipated to 

impair visibility in any Class I area, unless the state demonstrates that an emissions trading program or 

other alternative measures will achieve greater reasonable progress toward natural visibility conditions. 

See 40 CFR Part 51 Section 308(e). EPA promulgated a BART Rule separate from its Regional Haze 

Rule. EPA's BART Rule includes guidelines (Appendix Y) regarding how states should make BART 

determinations. See 70 Fed. Reg. 39104 (July 6, 2005). EPA also promulgated a "BART Alternative" 

Rule. See 71 Fed. Reg. 60612 (October 13, 2006). The BART Alternative Rule allows an alternative 

program to source-by-source BART, if the program results in greater reasonable progress than would 

occur pursuant to individual BART. 

States were required to submit their regional haze SIPs to EPA by December 17, 2007. The Regional 

Haze Rule establishes the year 2064 as the date by which a goal of visibility at natural background levels 

is desired in all Class I areas. The Rule divides the 2007-2064 time periods into numerous planning 

periods. States were required to submit their initial RH SIP by December 31, 2007, then a revised 

Regional Haze SIP to EPA by July 31, 2018, and every ten years thereafter. See 40 CFR 

Section 51.308(f). 

Colorado submitted much of its regional haze SIP (including most of its BART determinations) to EPA in 

early 2008 for review. Following additional revisions, the Commission approved the remainder of 

Colorado's BART determinations in December 2008, and submitted Colorado's Regional Haze SIP to 

EPA's Region 8 for review in 2009. 

Upon review, EPA Region 8 informed Colorado that its regional haze SIP submittal was not approvable 

and needed to be revised before EPA could reconsider it for inclusion in the State Implementation Plan. 

EPA has identified deficiencies with Colorado's Regional Haze Element of the SIP, including the basis for 

and enforceability of BART determinations and the lack of reasonable progress goals (RPGs) and RP 

source determinations. These alleged deficiencies must be addressed in order for EPA to approve the 

Regulation Number 3 

Adopted: October 20, 2011 Page 338 
Regional Haze element of the SIP. This regulation is the second part of a bifurcated rulemaking process 

in which the Commission adopted the remaining outstanding Regional Haze SIP elements. 

EPA made a finding on January 15, 2009 that 37 states, including Colorado, had failed to make all or part 

of the required Regional Haze SIP submissions. See 74 Fed. Reg. 2393 (January 15, 2009). This action 

started a clock by which states must have approved SIPs, or EPA must promulgate Federal 

Implementation Plans (FIPs) within two years (i.e., by January 15, 2011 ). EPA initiated actions in 

Colorado to begin preparing a FIP, and this action by the Commission is taken to complete the adoption 

of a regional haze element of the SIP, address the deficiencies that Region 8 EPA has identified, and to 

prevent such a federal action in Colorado, with its attendant consequences (e.g., federal determinations 

of BART, federal reasonable progress determinations, federal permits, and state loss of CAA grant 

monies so EPA can prepare a FIP). 

During the 2010 legislative session, the Colorado legislature passed House Bill 10-1365, the "Clean AirClean Jobs Act" (CACJA). The CACJA sets forth requirements applicable to investor owned utilities in 

Colorado (Public Service Company of Colorado (PSCo) and Black Hills Energy) and certain of their 

electric generating units. The CACJA requires the investor owned utilities to submit emission reduction 

plans to the Colorado Public Utilities Commission (PUC), and provides that the Commission shall 

consider the air quality provisions of the emission reduction plans for incorporation·into the regional haze 

element of Colorado's SIP. See Section 40-3.2-208, C.R.S. PSCo and Black Hills submitted their 

emission reduction plans to the PUC on August 13, 2010, and the PUC approved the plans on December 

15, 2010. 

The Commission adopted into Regulation Number 3 BART determinations for PSCo's Hayden and 

Comanche plants, two units at CENC's Golden plant, CEMEX's Lyons Portland cement plant, and 

Colorado Springs Utilities' Drake power plant. The Commission also adopted an Alternative to BART 

program for two units at Tri-State Generation and Transmission Association's Craig power plant. The 

Commission determined that, for nitrogen oxide (NOx) emissions, the appropriate BART control for Craig 

Units 1 and 2 would be emission rates associated with the assumed installation and operation of selective 

non-catalytic reduction (SNCR). As an alternative to BART, it was proposed and the Commission 

adopted, a more stringent NOx emissions control plan that consists of emission limits associated with the 

assumed operation of SNCR for Unit 1 and the assumed operation of SCR for Unit 2. The state has 

determined that the alternative program achieves greater reasonable progress than would be achieved 

through the installation and operation of source-by-source BART, and thus meets the requirements of the 

regional haze rule. 

The Commission also adopted into Regulation Number 3 a BART Alternative for a number of PSCo 

plants and incorporated it into the Regional Haze SIP. The BART Alternative is based on reductions 

achieved as a result of a combination of shutdowns and retrofit emissions controls at certain PSCo 

facilities planned as part of HB 10-1365. The BART Alternative includes ten units at four PSCo facilities. 

The facilities included in the BART Alternative include Arapahoe Units 3 and 4, Cherokee Units 1-4, 

Valmont and Pawnee. The BART Alternative includes both BART and non-BART sources. The nonBART sources are older than the BART timeframe, and in effect will all be controlled by 2017 and reduce 

their NOx and S02 emissions as a result of enforceable facility retirement dates and, for one unit, fuel 

switching to natural gas as a peaking unit. For the BART sources, Cherokee 4, Pawnee and Valmont, 

Valmont will be retired by 2018, Pawnee will be fully controlled by mid-2015, and Cherokee will operate 

on natural gas by 2018. The state has determined that the BART Alternative achieves greater 

reasonable progress than would be achieved through the installation and operation of source-by-source 

BART and RP determinations at the covered sources, and thus meets the requirements of the Regional 

Haze rule. PSCo has designed and proposed the BART Alternative to meet the state CACJA. The 

Commission determined that to the extent there is any inconsistency between the CACJA and older, 

more generic legal requirements, the more recent and specific CACJA controls. The state has used 

simplifying assumptions to compare the emission reductions and visibility impacts associated with the 

PSCo BART Alternative, and believes that the BART Alternative is clearly superior to, and will result in 

greater reasonable progress than, source-by-source BART. For example, the state has determined and 

Regulation Number 3 

Adopted: October 20, 2011 Page 339 

l 

I 

I 

f 

I 

! 

I 
demonstrated that PSCo's BART Alternative emissions reductions are greater than, and would provide 

greater reasonable progress than, the presumptive or source-by-source BART limits. The Commission 

also adopted retirement dates of "no later than" July 1, 2012 and December 31, 2016 for Cherokee Units 

1 and 3, respectively. In doing so, the Commission is no way rejecting any portion of PSCo's emission 

reduction plan as approved by the PUC on December 15, 2010 (Decision No. C10-1328). Rather, the 

Commission's action is intended to provide flexibility and consistency in light of PSCo's pending 

application for rehearing, reargument or reconsideration (RRR) before the PUC, in which PSCo states 

that the revised dates are important for providing sequencing of activities that will ensure electrical system 

reliability in the Denver Metropolitan area. These dates are also wholly consistent with the PUC's 

decision because PSCo can comply with the dates established by both the PUC and the Commission, 

regardless of how the PUC rules on PSCo's RRR application. The Commission also notes that Hayden, 

another PSCo BART source, is not part of the BART Alternative program. The PUC approved controls for 

Hayden as part of PSCo's emission reduction plan under HB 10-1365, consistent with the state's BART 

determination for that source. 

The Commission also established non-binding goals for each Class I area in Colorado (expressed in 

deciviews) that provide for Reasonable Progress (RP) towards achieving natural visibility conditions in 

2018 and to 2064. See 40 C.F.R. Section 51.308(d)(1 ). The reasonable progress goals (RPGs) provide 

for improvement in visibility for the most-impaired (20% worst) days over the period of the SIP and ensure 

no degradation in visibility for the least-impaired (20% best) days over the same period. The Commission 

adopted into Regulation Number 3 emission limits for "reasonable progress" sources that have a 

significant impact on visibility impairment in Class I areas, in order to help the state make reasonable 

progress towards improving visibility in this first planning period. These sources include Black Hills 

Energy Clark Station (a HB10-1365 facility), the Holcim Cement Plant, Tri-State Generation and 

Transmission Association's Craig Station Unit 3 and Nucla Station, Platte River Power Authority's 

Rawhide Station, Colorado Springs Utilities' Nixon Power Plant, PSCo's Cameo plant, and CENC's Unit 

3. 

For all BART and BART Alternative determinations made by the Commission in the November 2010-

January 2011 proceedings, a source that has installed BART or implemented a state-approved BART 

Alternative is exempted from the imposition of further regional haze controls during this first regional haze 

planning period (i.e., through December 31, 2017). This exemption applies only to regional haze, and 

does not apply to controls or emission reductions that may be required or otherwise imposed pursuant to 

other air pollution programs (including, but not limited to, ozone standards). 

The revisions to Regulation Number 3, Part F also apply Monitoring, Recordkeeping and Recording 

(MRR) Provisions to BART, BART Alternative and Reasonable Progress emission limits. 

In addition to the regulatory changes described above, the Commission adopted changes to Colorado's 

Regional Haze SIP. Many of the changes are non-substantive edits while other changes address 

comments from Federal Land Managers, incorporate the justification for the BART and reasonable 

progress determinations, and provide the justification for the reasonable progress goals. The following 

presents an overview of the content of Colorado's Regional Haze SIP document: 

Chapter 1 - Overview 

Chapter 2 - Plan Development and Consultation 

Chapter 3 - Monitoring Strategy 

Chapter 4- Baseline and Natural Visibility Conditions in Colorado, and Uniform Progress for 

Each Class I area 

Chapter 5- Sources of Impairment in Colorado 

Regulation Number 3 

Adopted: October 20, 2011 Page 340 
Chapter 6- Best Available Retrofit Technology 

Chapter 7- Visibility Modeling and Apportionment 

Chapter 8 - Reasonable Progress 

Chapter 9- Long Term Strategy 

Chapter 1 0 - Commitment to Consultation, Progress Reports, Periodic Evaluations of Plan 

Adequacy, and Future SIP Revisions 

Chapter 11 - Resource and Reference Documents 

Appendix A- Periodic Review of Colorado RAVI Long Term Strategy 

Appendix B- SIP Revision for RAVI Long Term Strategy 

Appendix C- Technical Support for the BART Determinations 

Appendix D- Technical Support for the Reasonable Progress Determinations 

The revised chapters are intended to fully replace previously adopted SIP chapters. 

Additional Considerations 

The Commission provides the following additional statement, consistent with Sections 25-7-110.5(5)(a) 

and 110.8, C.R.S. 

()Colorado's proposed Regional Haze regulations and SIP revisions are consistent with EPA's 

federal requirements under the Regional Haze rule. There is no binding requirement on how a 

State may "consider" the federal statutory and regulatory factors in determining BART and RP 

and establishing RPGs. The manner and method of consideration is left to the state's discretion. 

States are free to determine the weight and significance to be assigned to each factor. See 70 

Fed. Reg. 39104, 39170 (July 6, 2005). State discretion is a cornerstone of the regional haze 

rule. See id., at 39137 ("Congress evinced a special concern with insuring that States would be 

the decision makers."). States also have flexibility to consider any other factors that the state 

determines to be relevant. See U.S. EPA, "Guidance for Setting Reasonable Progress Goals 

Under the Regional Haze Program," p. 5-1 (June 2007). Federal law also allows states flexibility 

to adopt alternative programs that provide greater reasonable progress than BART. The 

Commission has adopted such alternatives for PSCo and Tri-State sources. The Commission 

finds that the revisions adopted in this hearing are wholly consistent with the discretion and 

expertise to be applied by state agencies under the federal act. Accordingly, the proposed 

revisions are no more stringent or different than federal law, and Sections 25-7-110.5 and 110.8 

do not appear to apply. 

Additionally, HB10-1365 provides, in part, that the Commission must vacate this rulemaking 

proceeding and must initiate a new proceeding for the consideration of alternative proposals for 

the appropriate controls for those units covered by the utility plans for inclusion in the regional 

haze element of the state implementation plan if, among other things, the Commission rejects any 

portion of the plans as approved by the PUC. Section 40-3.2-208(2)(b), C.R.S. If the 

Commission were to reject any portion of the utility plans, this proceeding would be vacated and a 

new proceeding initiated, making it impossible for Colorado to submit a timely and complete SIP 

revision to address Regional Haze, and resulting in a FIP. Under these circumstances, it is 

reasonable to conclude that the Commission rules regarding "1365" sources are being adopted to 

implement prescriptive state requirements, that the Commission has no significant policy-making 

Regulation Number 3 

Adopted: October 20,2011 Page 341 
options with respect to these sources, and that many provisions of Sections 25-7-110.5 and 11 0.8 

do not apply. See Section 25-7-110.5(2), C.R.S. 

Despite the foregoing, certain elements of this proceeding could be viewed (as certain parties 

have alleged) as exceeding the federal act or differing from the federal act. For example, the 

closure or repowering of PSCo facilities would not be required solely by EPA's Regional Haze 

Rule. Accordingly, the Commission is providing this additional statement, consistent with 

Sections 25-7-110.5(5)(a) and 110.8, C.R.S. 

(II) EPA's regional haze requirements are performance based, and the regional haze rule sets 

forth factors that states must consider when assessing controls and emission limits for sources 

emitting visibility impairing pollutants. Section 169A of the federal Clean Air Act (1977) sets forth 

the following national visibility goal: "Congress hereby declares as a national goal the prevention 

of any future, and the remedying of any existing, impairment of visibility in mandatory Class I 

Federal areas which impairment results from man-made air pollution." 42 U.S.C. Section 7491. 

To help facilitate this goal, EPA finalized the regional haze rule in 1999. The Rule requires States 

to adopt SIPs to address visibility impairment in the Class I areas. Critical components of such 

SIPs (particularly the SIP for the first planning period) are BART and RP. EPA provides flexibility 

to states regarding how to apply the relevant factors to BART and RP analyses. 

(Ill) Applicable federal requirements specifically address the issues regarding visibility impairment 

in Class I areas that are of concern to Colorado. Applicable federal requirements do not 

specifically address all of the issues that are of concern to Colorado. House Bill 1 0-1365 is 

intended to address Colorado's compliance with a number of federal Clean Air Act requirements 

in a comprehensive and more efficient fashion than in a step-by-step (or regulation by regulation) 

approach. The legislation specifically declares that it is intended to create "a coordinated plan of 

emissions reductions ... to meet the requirements of the federal act. .. at a lower cost than a 

piecemeal approach." Section 40-3.2-202(1), C.R.S. While regional haze is an important 

consideration in the context of HB10-1365, it is not the only one. HB10-1365 aims to address 

other air pollution issues as well, including national standards for ozone. See. e.g., Sections 40-

3.2-204(1 ), 204(2)(b)(II)(B) and 205(1 )(c), C.R.S. Data regarding visibility impairing emissions 

and control technologies was considered in the federal process leading up to the promulgation of 

the Regional Haze Rule. See. e.g., EPA's "Technical Support Document for BART S02 Limits for 

Electric Generating Units," Apri11, 2005, and "Technical Support Document for BART NOx Limits 

for Electric Generating Units and Technical Support Document for BART NOx Limits for Electric 

Generating Units Excel Spreadsheet," April15, 2005, Memoranda to Docket Number 2002-0076. 

These Memoranda reflect an analysis of all individual BART-eligible units in the country, including 

Colorado. See 70 Fed. Reg. at 39131-35. See also EPA's "Regulatory Impact Analysis for the 

Final Clean Air Visibility Rule or the Guidelines for Best Available Retrofit Technology (BART) 

Determinations Under the Regional Haze Regulations," U.S. EPA, June 2005. Additionally, the 

state determines that the regulatory requirements do not exceed the requirements of the federal 

act because the state is not imposing the BART alternative measures on an unwilling entity. 

Rather, the sources voluntarily proposed the packages as BART alternative measures and, in the 

case of PSCo, in order to comply with HB10-1365. 

(IV) The adopted rule will provide certainty to sources, by providing necessary monitoring, 

recordkeeping and reporting mechanisms and clear timing requirements to ensure the 

achievability of the specified closure or performance based standards. With respect to the "1365" 

sources in particular, the requirements improve the utilities' ability to comply in a cost-effective 

manner while preventing or reducing the need for costly retrofits to meet more stringent 

requirements later. 

(V) If the state does not take action by January 2011, EPA has indicated it will promulgate a FIP. 

The state and federal rules also have similar time frames for implementation. BART controls 

must be installed as soon as practicable but in no event later than five years after EPA approval 

Regulation Number 3 

Adopted: October 20, 2011 Page 342 
of the regional haze SIP, and all BART, BART alternatives and RP controls must be implemented 

within this first planning period (i.e., before January 1, 2018). 

(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. BART and RP determinations are very source 

specific; different controls and emission limits are to be expected and reflect the State's sourcespecific consideration of federal statutory and legal factors, and of the state's implementation of 

HB10-1365. 

(VIII) If the state rule were not adopted, EPA has indicated it will promulgate a FIP. This would 

likely result in more costly control requirements for sources which would be passed on to 

consumers. 

(IX) The Regional Haze Rule requires associated State procedural, reporting and monitoring and 

recordkeeping requirements. The procedural, reporting, monitoring and recordkeeping 

requirements provided in Colorado's rule do not differ from, and often incorporate by reference, 

federal requirements. 

(X) Demonstrated technology is available to control and monitor visibility impairing emissions. 

(XI) The adopted rule will contribute to the prevention of pollution by reducing visibility impairing 

emissions. 

(XII) A no action alternative would not address the required standard, and could result in EPA's 

promulgation of a FIP. 

(XIII) All regulatory changes in this proceeding are based on reasonably available, validated, 

reviewed, and sound scientific methodologies. All information made available by interested 

parties has been reviewed and considered by the Commission. 

(XIV) Evidence in the record supports the finding that the rule shall result in a demonstrable 

reduction of pollutants that contribute to regional haze. 

(XV) Evidence in the record supports the finding that the rule shall bring about reductions in risks 

to human health or environment, and provide other benefits (e.g., protection of visibility) that 

justify the cost to government, the regulated community, and to the public to implement and 

comply with the rule. 

(XVI) The Commission has chosen the alternative that is the most cost effective, provides the 

regulated community flexibility, and which achieves the necessary reductions in air pollution. The 

alternative will maximize the air quality benefits of regulation in the most cost effective manner. 

The Commission notes that no parties provided alternate proposals to the PSCo BART 

Alternative during this proceeding. The Commission also notes that in approving PSCo's 

emission reduction plan, the Colorado Public Utilities Commission thoroughly considered the 

economic impacts and concluded that that the approved plan comes at a lower cost to ratepayers 

than an all-controls option. Even if for some reason PSCo's BART Alternative were not 

determined to be the most cost effective option, the Commission finds that approval of the BART 

Alternative and incorporation of the alternative into the Regional Haze SIP is consistent with the 

legislature's intent in adopting the CACJA. 

PARTG STATEMENTS OF BASIS, SPECIFIC STATUTORY AUTHORITY AND PURPOSE 

Regulation Number 3 

Adopted: October 20,2011 Page 343 
I.W. Adopted October 20, 2011 

Regulation Number 3. Part A. B. C and D- addressing federal changes to the New Source Review (NSR) 

Program related to PM2.5 National Ambient Air Quality Standards (NAAQS), several recent 

Environmental Protection Agency (EPA) State Implementation Plan (SIP) actions in which EPA partially 

disapproved various SIP revisions. EPA's Deferral of Biogenic Sources of C02 Emissions. other 

miscellaneous revisions, and typographical, grammatical and formatting errors. 

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 (the Act). 

Specific Statutory Authority 

The Colorado Air Quality Control Commission (AQCC) promulgates this regulation pursuant to the 

authority granted under Colorado Revised Statutes. Sections 25-7-105(1){c), (authority to adopt a 

prevention of significant deterioration program); 25-7-109(1)(a) (authority to require the use of air pollution 

controls); 25-7-109(2)(a) (authority to adopt emission control regulations pertaining to visible pollutants); 

and 25-7-114.4(1) (authority to adopt rules for the administration of permits). 

Basis and Purpose 

EPA promulgated federal changes to the New Source Review (NSR) Program, which must be 

incorporated into Regulation Number 3 in order to maintain consistency with the federal NSR Program 

related to PM2.5 National Ambient Air Quality Standards (NAAQS). Subsequently, EPA disapproved and 

proposed to disapprove Air Pollutant Emission Notice (APENl exemption provisions in Regulation 

Number 3, associated with Colorado's September 1997. April 2003 June 2003, July 2005. August 2006, 

and August 2007 SIP submittals. Also, EPA proposed its Deferral of Biogenic Sources of C02 Emissions, 

deferring biogenic carbon dioxide (C02) from regulation under the federal Prevention of Significant 

Deterioration (PSD) and Title V Permitting Programs for three years. In addressing the above actions, 

several additional Regulation Number 3 provisions were identified in need of revision. 

Sources affected by this proposal include PM2.5 and C02 emission sources, as well as open burning 

sources. mobile sources, stationary internal combustion engines. emergency generators. oil and gas 

surface water impoundments, deaerator/vacuum pump exhaust, and air curtain destructors. 

PM2.5 Related Rules 

On February 21, 2008, the AQCC adopted revisions to Regulation Number 3, Parts A and B to identify 

PM2.5 as a criteria pollutant, triggering reporting and minor source permitting requirements. However. 

the AQCC did not make corresponding revisions to major stationary source permitting requirements under 

the New Source Review (NSR) Program as the EPA had not yet promulgated the associated PM2.5 

implementation rules. Since that time, EPA promulgated a series of rules regarding the regulation of 

PM2.5 under the NSR program. See "Implementation of the New Source Review (NSR) Program for 

Particulate Matter Less than 2.5 Micrometers (PM2.5)" (73 FR 28321, May 16. 2008). "Prevention of 

Significant Deterioration (PSD) for Particulate Matter Less Than 2.5 Micrometers (PM2.5l -Increments, 

Significant Impact Levels (SILs) and Significant Monitoring Concentration (SMC)" (75 FR 64864, October 

20. 2010), "Requirements for Preparation, Adoption, and Submittal of Implementation Plans" (76 FR 

18870, April6. 2011). and "Implementation of the New Source Review (NSR) Program for Particulate 

Matter Less Than 2.5 Micrometers (PM2.5l: Final Rule to Repeal Grandfather Provision" (76 FR 28646, 

May 18. 2011 ). The 2008 and 2010 rules, combined with the December 21, 2010 promulgation of the 

methodology to test for PM2.5, provide a complete framework establishing how to apply PM2.5 to the 

NSR Program. Prior to the promulgation of the December 2010 rules. application of PM2.5 to the NSR 

Program made little sense. See 75 FR 80118. Consequently, the AQCC chose to wait to adopt the suite 

Regulation Number 3 

Adopted: October 20, 2011 Page 344 
of PM2.5 implementation rules until after the last of the PM2.5 implementation rules and the 2010 PM2.5 

testing methodology were finalized. 

The May 16, 2008 rule provided flexibility in designating PM2.5 precursor pollutants. While sulfur oxides 

(S02) must be treated as a PM2.5 precursor in all areas of the state, more flexibility is afforded to 

nitrogen oxides (NOx), volatile organic compounds (VOCs) and ammonia (NH3). This rule requires that 

NOx be presumed a PM2.5 precursor state-wide unless a state demonstrates that NOx is not a 

"significant contributor" to PM2.5 concentrations within any area. See 73 FR 28328. However, VOCs 

and NH3 are not required to be treated as PM2.5 precursors, except that high molecular weight VOCs 

(equal to or greater than 25 carbon atoms and low vapor pressure) will be addressed as a condensable 

particulate. See 73 FR 28329-283330. 

At this time, the AQCC has identified S02 and NOx as PM2.5 precursors, state-wide. Based on the 

limited PM2.5 modeling and monitoring data available for Colorado, the AQCC determined that there is 

insufficient evidence to claim either way that NOx emissions do or do not contribute significantly to the 

concentration of PM2.5 in any area in Colorado. Without evidence to narrow the identification of NOx as 

a precursor to specific areas, Colorado must identify NOx as a PM2.5 precursor state-wide. Less is 

known about VOCs and NH3 and their contribution to PM2.5 in Colorado, and so Colorado has chosen to 

not identify them as PM2.5 precursors at this time. 

EPA Partial Disapproval Actions 

On October 3, 2011, EPA's action granting partial disapproval and partial approval of revised Air Pollution 

Emission Notice (APEN) and permitting exemptions that the Commission submitted to EPA as SIP 

revisions in September 1997, June 2003, July 2005, August 2006, and August 2007, was published in the 

Federal Register. See 76 FR 61054. EPA partially disapproved APEN exemptions for open burning, 

mobile sources, stationary internal combustion engines, emergency generators, oil and gas surface water 

impoundments, deaerator/vacuum pump exhaust. and air curtain destructors. The basis for EPA's 

disapproval of the subject provisions and the revisions intended to address each provision are as follows: 

Open burning APEN exemption was corrected to reference federally enforceable Regulation Number 1 

(Part A Section II.D.1.q.). EPA commented that the change in reference from Regulation Number 1, 

which is part of Colorado's SIP, to Regulation Number 9, which is not part of Colorado's SIP, was not 

approvable. 

Mobile sources APEN exemption was clarified (Part A Section II.D.1.ppp.) and associated revisions were 

made to the insignificant activities list (Part C, Section II.E.3.uuu.). EPA commented that these 

exemptions only apply to stationary sources, not non-road engines and not sources being used for 

transportation purposes. 

Stationary internal combustion engine APEN exemption was repealed (Part A Section II.D.1.sss.) and 

related revisions were made to the associated permitting exemption (Part B, Sections II.D.2.c., and 

II.D.2.c.(i)-(iii)) and insignificant activities list (Part C, Section II.E.3.nnn.). EPA commented that the APEN 

exemption should require recordkeeping and reporting. The AQCC repealed the APEN exemption and 

revised the permit exemption to be consistent with current SIP approved language instead of requiring 

additional recordkeeping and reporting. Note that while the categorical exemption is being repealed, 

sources may still utilize the general one and two ton APEN exemptions found in Part A, Section II.D.1.a. 

Emergency generator APEN exemption was repealed (Part A Section II.D.1.ttt.), and related revisions 

were made to the associated permitting exemption (Part 8, Sections II.D.2.c., and II.D.2.c.(i)-(iii)) and 

insignificant activities list (Part C, Section II.E.3.nnn.). EPA commented that the APEN exemption should 

require recordkeeping and reporting. The AQCC repealed the APEN exemption, and revised the permit 

exemption to be consistent with current SIP approved language instead of requiring additional 

recordkeeping and reporting. Note that while the categorical exemption is being repealed, sources may 

still utilize the general one and two ton APEN exemptions found in Part A Section II.D.1.a. 

Regulation Number 3 

Adopted: October 20, 2011 Page345 

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Surface water impoundment APEN exemption was clarified (Part A. Section II.D.1.uuu.) and related 

revisions were made to the associated permitting exemption (Part B. Section II.D.1.m.) and insignificant 

activities list (Part C. Section II.E.3.vvy.). EPA commented that the APEN exemption should be clarified 

to confirm that the exemption applied to oil and gas produced water. In addition to making this revision. 

the AQCC also clarified exceptions to these exemptions and insignificant activity. 

Deaerator/vacuum pump exhaust APEN exemption was repealed (Part A. Section II.D.1.xxx.) and 

associated revisions were made to the insignificant activities list {Part C. Section II.E.3.uuu.). EPA 

commented that it was unclear what these activities were. The AQCC is unaware of any source making 

use of this exemption. and thus has removed this exemption and associated insignificant activity. 

Air curtain destructor APEN exemption removal (Part A. Section II.D.1.ffff.}. EPA commented that 

because air curtain destructors meet the SIP approved definition of an incinerator and as such are 

required to submit APENs and obtain permits. that this exemption should be removed. 

On February 4. 2011. EPA's action granting partial approval and partial disapproval of SIP revisions 

submitted to EPA in April2003 and June 2003, was published in the Federal Register. See 76 FR 6331. 

Those 2003 SIP revisions to Regulation Number 3 revised APEN exemptions and permitting exemptions 

in Regulation Number 3. Parts A and B. respectively. To address EPA's concerns. the following 

provisions that EPA disapproved or on which EPA otherwise provided comment. were revised or removed 

as follows: 

Stationary internal combustion engines 10 ton per year permitting exemption in attainment areas (Part B. 

Sections II.D.1.c .. and li.D.1.c.(iii)). EPA commented that Colorado did not make the anti-backsliding 

demonstration necessary to increase the permitting exemption threshold from 5 tons per year to 1 0 tons 

per year. The AQCC opted to revert back to the 5 tons per year threshold that EPA previously approved 

instead of making the necessary demonstration at this time. Note that this revision does not prevent any 

source from making use of the facility-wide permit exemptions found in Part B. Sections II.D.2. or li.D.3. 

Non-road engine state-only requirements (Part A. Sections I.B.31.c. and I. B.31.d.}. EPA commented that 

it could not approve provisions which are identified as state-only provisions. The AQCC agrees and has 

further placed "{State-only Requirement)" at the beginning of these sections to clearly identify that they 

are state-only provisions. 

Biogenics Deferral Revisions: 

On June 3. 2010. EPA's "Prevention of Significant Deterioration and Title V Greenhouse Gas (GHG) 

Tailoring Rule," commonly called the GHG Tailoring Rule. was published in the Federal Register. See 75 

FR 31514. EPA's GHG Tailoring Rule was designed to tailor the applicability criteria that determine which 

stationary sources and modification projects become subject to permitting requirements for GHGs under 

the Prevention of Significant Deterioration {PSD} and Title V Permitting Programs of the Clean Air Act 

(CAA). 

On July 20. 2011. EPA's "Deferral for C02 Emissions from Bioenergy and Other Biogenic Sources Under 

the Prevention of Significant Deterioration (PSD} and Title V Programs." commonly called the Biogenic 

Deferral. was published in the Federal Register. See 76 FR 43490. Beginning July 1. 2011, EPA's 

Biogenic Deferral temporarily excludes biogenic C02 emissions from the definition of "subject to 

regulation" to allow biogenic sources of carbon dioxide (C02} emissions a three year deferral from the 

PSD and Title V permitting requirements; the three year deferral applies even if the source's GHG 

emissions exceed the threshold established in the Tailoring Rule. To maintain consistency with 

implementation of federal requirements associated with the Tailoring Rule and the associated Biogenic 

Deferral. the AQCC incorporated EPA's Biogenic Deferral into Colorado's PSD and Title V Permitting 

Programs, as follows: 

Regulation Number 3 

Adopted: October 20,2011 Page 346 
Revise the existing definition of Subject to Regulation consistent with EPA's proposed Biogenic Deferral 

(Part A Section I.B.44.b.). 

Other Revisions: 

In addressing the above actions, the AQCC made several additional Regulation Number 3 revisions that 

relate to: revising the time frame for reporting the Notice of Startup to the Division from thirty days prior to 

fifteen days after commencing operation, which is consistent with Colorado's House Bill 10-1042, as 

codified in 25-7-114.5(12)(a), C.R.S.; including NOx as a precursor to ozone in ozone significant 

monitoring concentration (SMC) and removing the total suspended solid SMC. both consistent with 

federal requirements; and making typographical, grammatical and formatting corrections. 

Additional Considerations 

These adopted rules are mandated by federal law and necessary to maintain EPA approval of Colorado's 

SIP. The revisions associated with the PM2.5 Implementation Rules and Biogenics Deferral mirror the 

federal requirements. While the PM2.5 Implementation Rules do allow States the opportunity to deviate 

from the specified PM2.5 precursor pollutants, Colorado does not have sufficient modeling and monitoring 

data available to support a decision to identify VOC and NH3 as PM2.5 precursors or narrow the area in 

which NOx is identified as a PM2.5 precursor in Colorado. The related revisions adhere to federal 

requirements [as required by Sections 25-7-105(1). 25-7-201(a) and 25-7-203. and 25-7-302. C.R.S.l 

and therefore the provisions of Sections 25-7-11 0.5(5) and 110.8. C.R.S. do not apply to these revisions. 

With respect to EPA's SIP disapproval actions, while the AQCC must address EPA's comments, 

Colorado has some flexibility in addressing those comments. Here, the provisions of Sections 25-7-

11 0.5(5) and 11 0.8. C.R.S. apply to this rulemaking. Thus. the AQCC makes the following 

determinations only as they pertain to the SIP disapproval actions, and only where the AQCC has 

flexibility in addressing EPA's comments. 

Pursuant to 25-7-110.5(5). C.R.S .. the AQCC makes the determination that: 

(I) EPA's SIP disapproval actions are federal requirements that may apply to this rulemaking. 

(II) The applicable federal requirements imposing emission reporting and permitting are 

performance based. While the AQCC must address EPA's comments. there is some flexibility in 

how best to address those comments. 

(Ill) Regarding EPA's comments on the APEN exemptions, accurate actual emissions data for 

open burning sources, mobile sources. stationary internal combustion engines. emergency 

generators. oil and gas surface water impoundments. deaerator/vacuum pump exhaust. and air 

curtain destructors is limited, although more is known about the engines. generators and air 

curtain destructors. The AQCC concluded that the adopted rule will clarify and generally improve 

Colorado's inventory of emissions from these sources in Colorado. and thus the reporting 

components are essential to this effort. 

(IV) With respect to APEN associated permitting exemption revisions, these revisions strike an 

appropriate balance between exempting small emission sources, ensuring that Colorado has a 

reasonably accurate inventory, as well as ensuring that reporting and permitting requirements are 

reasonably uniform and equitable. 

(V} The AQCC is not aware of any timing issue that could justify changing the timeframe in which 

these rules are implemented. There are deadlines by which states are expected to implement 

federally mandated changes. with potential sanctions for failing to meet these deadlines. 

Regulation Number 3 

Adopted: October 20,2011 Page 347 
(VI) The APEN and associated permitting exemption and insignificant activity requirements in 

question are not specifically designed with a margin for accommodation. but instead will rely on 

the opportunity for future revisions. as necessary, to adjust for uncertainty and future growth. 

(VII) The adopted revisions establish reasonable equity for sources subject to the revisions by 

providing the same requirements for similarly situated sources. 

(VIII) If revisions to the APEN and permitting exemptions and insignificant activities are not 

adopted. while there would be no change in cost to industry, Colorado's emissions inventory 

accuracy will not improve. Emissions inventories are essential tools in protecting public health 

and the environment. A less accurate emissions inventory may translate into a public health and 

welfare and environmental cost. by delaying the time necessary to improve the inventory when 

developing plans to address future NAAQS. 

(IX) The proposed revisions include no requirements that differ from applicable federal 

requirements. 

(X) Demonstrated technology is available to comply with the particulate matter permitting 

requirements. Sources are already using the control devices intended to be used to comply with 

this rule. 

(XI) The adopted rules will contribute to prevention of pollution. by having sources more 

accurately assess emissions to determine if APEN reporting or permitting requirements apply. 

Understanding emissions is essential in preventing pollution. 

(XII) Because these rules are federally mandated, no alternative rules would address the 

requirements in question. 

Further. pursuant to 25-7-11 0.8(1 ), C. R.S., the AQCC makes the determination that: 

(I) The rule is based upon reasonably available, validated, reviewed, and sound scientific 

methodologies. and the AQCC has considered all information submitted by interested parties. 

(II) These amendments are largely administrative in nature as they relate to APEN reporting, 

permitting exemptions and insignificant activities. 

(Ill) Evidence in this record supports the finding that the rule shall bring about reductions in risks 

to human health and the environment that justify the costs to implement and comply with the rule. 

(IV) The rule is the most cost effective. provides the regulated community flexibility, and achieves 

any necessary reduction in air pollution. 

(V) The selected regulatory alternative will maximize the air quality benefits of regulation in the 

most cost-effective manner. 

Regulation Number 3 

Adopted: October 20, 2011 Page 348