STATE OF COLORADO
 

Bill Ritter, Jr., Governor 

James B. Marlin, Executive Director 

Dedicated to protecting and improving the health and environment of the people of Colorado 

4300 Cherry Creek Dr. S. Laboratory Services Division 

Denver, Colorado 80246-1530 8100 Lowry Blvd. 

Phone (303) 692-2000 Denver, Colorado 80230-6928 

TDD Line (303) 691-7700 (303) 692-3090 Colorado Department Located in Glendale, Colorado of Public Health 

http://www.cdphe.state.co.us	 and Environment 

AUG - 3 2007 

August 1, 2007 

RECEIVEI) Robert Roberts 

Regional Administrator AUG 03 L 

US EPA Region VIn 

999 18th Street, Suite 500 

Denver, Colorado 80202 USEPARNS OFFICE

Dear Mr. Roberts: 

The following actions are submitted to EPA for final approval and incorporation into the Colorado 

State Implementation Plan. Two copies of the materials needed for your review of each action are 

included with this letter. 

•	 Regulation Number 4: New Wood Stoves and the Use of Certain Woodburning Appliance 

During High Pollution Days regarding a testing protocol for masonry heaters, to add a 

definition for exempt devices, to clarify definitions in the regulation, and to correct 

grammatical and typographical errors. 

•	 Regulation Number 3: Stationary Source Permitting and Air Pollutant Emission Notice 

Requirements regarding 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 

organic compounds and the list of hazardous air pollutants consistent with federal actions, 

and to make technical corrections. 

•	 Common Provisions Regulation regarding issues that the United States Environmental
 

Protection Agency (EPA) has raised with the regulation; specifically whether or not the
 

regulation complies with EPA guidance requirements for determining that upsets and
 

breakdowns as violations ofthe federal program.
 
Air Quality Control Commission 

State Implementation Revisions August] , 2007 

Robert Roberts Page 2 

•	 Regulation Number 1: Emission Controls for Particulate Matter, Smoke, Carbon Monoxide, 

and Sulfur Oxides regarding changes to the federal program in recent months and for 

Regulation Number 1 to consider proposed revisions to the performance testing requirements 

for air curtain destructors. 

•	 Regulation Number 3: Stationary Source Permitting and Air Pollutant Emission Notice 

Requirements, Part A - Concerning the Increase of Stationary Source Emission Fees. 

•	 Common Provisions Regulation regarding issues that the US EPA has raised with the 

regulation; specifically, whether or not the regulation complies with EPA guidance on what 

is ap.upset,and/or malfunction and whether or not EPA and members ofthe public can pursue 

injtinctive relief for upsets as violations of the law. 

•	 Regulation Number 7: Emissions of Volatile Organic Compounds regarding increased 

control requirements for emissions of volatile organic compounds and oxides of nitrogen 

from oil and gas exploration and production activities in the nine county deferred ozone 

nonattainment area and on a statewide basis. 

We look forward to your timely review and approval ofthis request. The Office of the Colorado Air 

Quality Control Commission may submit any additional technical support documentation or 

information that you may need for review directly to the EPA. Should there be any questions 

regarding these materials, please contact me at the Commission Office at 303-692-3478. Thank you. 

Sincerely, 

Jam s B. Marti~· '#..~

cc.	 Martha Rudolph, CDPHE Environmental Programs Director 

Doug Lempke, Air Quality Control Commission Administrator 
.ADMINISTRATIVE MATERIALS 

Copies of the following administrative materials are included in this submittal of revisions to 

Regulation 6 & 1: New Source Performance Standards. Hearing held on September 21, 

2006. 

• Hearing Notice as published in the CCR 

• Agenda 

• Agenda Item Control Sheet (and attachments) 

• Parties, EPA and Public Comments if any. 

• Statement of Basis, Specific Statutory Authority and Purpose for each regulation. 

• Opinion of the Attorney General 

• Regulation as published in the CCR 

• Notice of final adoption 
Hearing Notice as Published in the CCR Agenda
 
~7'73

STATE OF COLORADO 

Bill Owens, Governor
 

Dennis E. Ellis. Execulive Director
 

Dedicated 10 protecting and improving the health and environment of the people of Colorado 

COLORADO AIR QUALITY CONTROL COM1~4:I§S~9Ni'\.7 F 0 

http://www.cdphe.stale.co.US ,_or. ,f"" .,1,i=- i l 

" ._.. '.... 1._ c > "'- _.
 

EDO-AQCC·A5
 

4300 Cherry Creek Drive South
 

Denver, Colorado 80246·1530
 \;) JUN 16 2006 

Phone (303) 692-3 100
 

Fax (303) 691-7702
 

TDD (303) 691-7700 :::.::(;·'lONS/LICENSING
 

~cCRETARY OF STATE 

NOTICE OF WRITTEN COMMENT ONLY 

RULEMAKING HEARING
 

BEFORE THE
 

COLORADO AIR QUALITY CONTROL COMMISSION
 

Regarding proposed revisions to:
 

Regulation Number 6
 

STANDARDS OF PERFORMANCE FOR NEW STATIONARY SOURCES
 

and
 

Regulation Number 1
 

EMISSION CONTROL FOR PARTICULATES, SMOKES, CARBON
 

MONOXIDE AND SULFUR OXIDES
 

SUBJECT:
 

The Air Quality Control Commission will hold a written comment only rulemaking hearing to
 

consider a request by the Division to set a public rulemaking hearing date to consider a proposal
 

for Regulation Number 6 to adopt by reference a set ofprovisions to incorporate changes to the
 

federal program in recent months and for Regulation Number 1 to consider proposed revisions to
 

the perfonnance testing requirements for air curtain destructors.
 

FEDERAL REQUIREMENTS:
 

The federal act does require the Commission to make the rule revisions that are the subject of
 

this Notice ofPublic Rulemaking Hearing. These revisions are required by the federal act and
 

are not more stringent than the requirements of the federal act.
 

HEARING SCHEDULE:
 

DATE: September 21,2006
 

TIME: 9:00 AM
 

PLACE Colorado Department of Public Health & Environment
 

4300 Cherry Creek Drive South, Sabin Room
 

Denver, CO 80246
 

The hearing may be continued at such places and time as the Commission may announce. 

Page 1 of3 CR 29-1461 
The Commission shall deliberate upon the evidence; testimony and written submissions 

presented at this hearing, as well as any related matters properly submitted before the hearing 

record is closed. 

PUBLIC COMMENT: 

This is a written comment only rule-making hearing. The Commission encourages all interested 

persons to provide their views in writing prior to the hearing. Written comments must be 

submitted by September 6, 2006. The Commission especially solicits comments and analyses 

from persons who will incur directly some cost or benefit from the proposed revisions. No 

testimony will be taken at the hearing except for good cause shown. Written submission should 

be mailed to the Commission Office at the address listed in the hearing schedule. 

PARTY STATUS: 

In order to obtain party status at the hearing compliance with several requirements as defined in 

the Commission's Procedural Rules is necessary. An original and three (3) copies of a written 

petition for party status must be filed with the Office of the Air Quality Control Commission no 

later than 5:00 p.m. July 20, 2006. The petition must: 1) identify the applicant; 2) provide the 

name, address, and telephone and facsimile numbers ofthe applicants representative; and 3) 

briefly summarize what, if any, policy, factual, and legal issues the applicant has with the 

proposal(s) as ofthe time of filing the application. Copies ofthe petition for party status must 

also be received, by this same date, by the Division staff person and the Assistant Attorneys 

General representing the Division and the Commission identified below. 

Individuals may also obtain party status through the submittal of an initial alternative rule to the 

proposed rule. The submittal of an alternative proposal must be accompanied by twenty (20) 

copies ofthe initial alternative proposed rule and all other associated documents by the date 

specified for party status requests. Initial alternative rules must also be filed with the Division 

staff person and with the Assistant Attorneys General. 

Air Quality Control Commission Air Pollution Control Division 

Theresa L. Martin Dena M. Wojtach 

EDO-AQCC-A5 APCD-Bl 

4300 Cherry Creek Drive South 4300 Cherry Creek Drive South 

Denver, CO 80246 Denver, CO 80246 

Steve Brown Mike Elliott 

Attorney for the Commission Attorney for the Division 

Attorney General's Office Attorney General's Office 

1525 Sherman St., 5th Floor 1525 Sherman St., 5th Floor 

Denver, CO 80203 Denver, CO 80203 

Requests received beyond the above stated deadline shall only be considered upon a written 

motion for good cause shown. The Commission reserves the right to deny party status to anyone 

that does not comply with the Commissions procedural rules. 

STATUS CONFERENCE: 

A status conference will be held if necessary to ascertain and discuss the issues involved, and to 

ensure that parties are making all necessary efforts to discuss and resolve such issues prior to the 

submission of prehearing statements. Attendance at this status conference is mandatory for 

anyone who has requested party status. 

Page 2 on CR 29-1462 
PREHEARING CONFERENCE/PREHEARING STATEMENTS:
 

A prehearing conference will be held if necessary to ascertain and discuss the issues involved,
 

and to ensure that parties are making all necessary efforts to discuss and resolve such issues prior
 

.to the hearing. Attendance at the prehearing conference is mandatory for anyone who has
 

requested party status.
 

PROCEDURAL MATTERS:
 

Written comments will be accepted prior to the hearing and at the hearing. The Commission
 

encourages the submission of written recommendations. Written comments received at the
 

Commission Office by September 6, 2006 will be distributed to the Commission for review
 

prior to the hearing. The Commission requests that twenty (15) copies of all written statements
 

be submitted.
 

STATUTORY AUTHORITY FOR THE COMMISSION'S ACTIONS:
 

The rule-making authority ofthe Commission can be found in sections 25-7-105-109 c.R.S. and
 

25-7-114 c.R.S. as amended. This list ofstatutory authority is not intended as an exhaustive list
 

ofthe Commission's statutory authority to act in this matter.
 

Dated this I)'~ay of J at Denver, Colorado 

C04Z QZZ"r"-4.1~~~~A" DOUgla~mPke, Administra or 

Page 3 of3 CR 29-1463 
Agenda
 
STATE OF COLORADO
 

Bill Owens, Governor 

Dennis Ellis, Executive Director 

COLORADO AIR QUALITY CONTROL COMMISSION 

http://Vl.-\vw.cdphe.staleco.us 

4300 Cherry Creek Dl"lve South 

OED-OLRA-A5 

Denver, Colorado 80246-1530 

Phone (303) 692-3100 Colorado Department 

Fax (303) 691-7702 of Public Health TOO (303) 691-7700 

and Environment 

Notice of Meeting and Agenda
 

Air Quality Control Commission
 

&
 

Board of Health
 

September 21, 2006 

Colorado Department of Public Health & Environment
 

Sabin Room
 

4300 Cherry Creek Drive South
 

Denver, Colorado
 

10:00 a.m. 

Note:	 Board of Health members shaH join the Commission to discuss 

the Commission's Annual Report to the Pubic in fulfillment of 

the requirements of 25-7-105(4)(a) 

Call to Order:	 Determination of a Quorum 

Approval of Minutes:	 Review/Approval of the August 17, 2006 meeting minutes of the 

Air Quality Control Commission. 

Public Comment:	 The public is invited to comment on any air pollution issue not on 

the agenda. The Commission will not take action on issues 

discussed under this agenda item today; however, items may be 

scheduled for further discussion or action. 
RULEMAKING HEARING 

1.	 Regulation Number 6 & 1: New Source Performance Standards 

(5 minutes presentation, 10 minutes discussion) 

The Division will present to the Commission a proposal to revise Part A of the regulation to 

incorporate by reference additions and changes the U.S. EPA has made to 40 CFR Part 60. 

The Division has also proposed that the Commission make corresponding changes to clarify 

provisions of Regulation Number I, Section lILB regarding the provisions for air curtain 

destructors to meet a grain loading standard. 

BRIEFINGS, REpORTS AND COMMISSION DISCUSSIONS 

2.	 Requirements for Stack Testing New Equipment 

(5 minutes presentation, 15 minutes discussion) 

The Division will respond to questions asked by a member ofthe public at the August 17th 

meeting regarding the requirements to conduct testing on stack emissions for new process 

equipment specifically a small incinerator charging less than 200 pounds per hour. 

3.	 Annual Report to the Public 

(10 minutes presentation, 15 minutes discussion) 

The Commission's Administrator will review the annual report to the public and discuss air 

quality in the various regions of the state. The Commission will provide an opportunity for 

public comment. 

4.	 Summertime Ozone Update 

(10 minutes presentation, 10 minutes discussion) 

The Division will review the sumniertime ozone monitoring data for the Denver 

metropolitan and Northern Front Range areas and report on any exceedences or violations of 

the ozone standards. The Division will also review the historical data and project future 

values that will be needed to remain below the national standard in next years summer 

season. 

5.	 Energy Development, Use, Renewable Energy and Energy Efficiency 

(40 minutes presentation, 20 minutes discussion) 

The Department's Sustainability Program and the Colorado Office of Energy Management 

and Conservation (OEMC) will discuss with the Commission the history and future of 

energy development in Colorado and those sources impacts to air quality across the State. 

The Sustainability Program & the OEMC will discuss how they are working together to 

identify and quantify opportunities for achieving air quality benefits in the development of 

renewable energy and energy efficiency projects and how they are working together to 

minimize environmental impacts from future energy development. 

6.	 Commissioner Informational Items 

Commissioners will discuss among themselves activities that they have participated in over 

the past month that they believe other Commissioners and/or members of the public may be 

interested in hearing about. 

7.	 Division Director's Report - Margie Perkins 

Monthly activities report 

2 
8.	 Attorney General's Report - Steve Brown 

Update of any recent court actions on air quality issues 

9.	 Administrator's Report - Doug Lempke 

October meeting agenda items review 

10.	 Regional Haze SIP Development Public Hearing 

(120 minutes presentation, 120 minutes discussion) 

The Commission will consider the presentations and discussions ofthe Division and 

interested members of the public regarding the determination of baseline and natural 

conditions for visibility in each of the Class I areas in Colorado that are impacted by the 

regional haze rule requirements. 

The Commission will consider the determination of the uniform rate of progress that is 

necessary for determining compliance with the provision ofthe regional haze rule and the 

amount of progress necessary to achieve for the first planning period ofthe program in 

2018. The Commission will also consider the monitoring network and how it will be relied 

upon to characterize visibility conditions in each ofthe Class I areas. 

The Commission solicits and encourages interested members ofthe public to participate and 

make comment at the meeting. The Commission intends to provide direction to the Division 

to use specific baseline and natural conditions and to set rates of progress for each of the 

class I areas as a result of this workshop. 

Adjourn 

3
 
Agenda Item Control Sheet (AICS) 

(and attachments) 

- Memorandum of Notice (MON) 

- Proposal of Rulemaking Language 

- Issue of Fact Sheet (normally attached to the AleS) 

- Economic Impact Analysis (EIA) - initial & final statutory requirement 
COLORADO AIR QUALITY CONTROL COMNIISSION 

AGENDA ITEM CONTROL SHEET 

Item Title: Revisions to Regulation No.6, Part A and Regulation No.1 

Meeting date: September 21,2006 

TYPES OF ACTION 

NON-HEARING ACTIONS 

_ Administrative 

_ Briefing 

_Policy 

_Area Designations 

REQUEST FOR HEARING 

_ Public Rulemaking 

Infonnational 

HEARING 

-..X- Public Rulemaking 

Infonnational 

-..X- Adoption 

RECOMMENDED ACTION 

_ Approval _ Denial 

X Required 

MOTION 

_ Attached _ Not applicable 

STATUTORY AUTHORITY 

General Specific ---.X 

EPA SUBMITTAL 

Is this issue considered a SIP revision? Yes. 

Which SIP? Regulation No. 1 portion of Colorado SIP 

EPA submission deadline: None 

Is this a delegated program? Yes. 

(Requires EPA approval and delegation ofauthority to Colorado to implement NSPS programs) 
ISSUE: The Colorado Department of Public Health and Environment, Air Pollution Control Division 

(Division) requests that the Colorado Air Quality Control Commission (AQCC) revise Regulation No. 

6, Part A to incorporate by reference additions and changes the U.S. Environmental Protection Agency 

(EPA) made to its New Source Performance Standards (NSPS) in 40 C.F.R. Part 60. Additionally, the 

Division requests that the AQCC make a corresponding, clarifying change to Regulation No.1. 

I. Incorporation by Reference of Federal Amendments to 40 C.F.R. Part 60 

Regulation No.6, Part A, Subpart Cb
 

40 C.F.R. Part 60, Subpart Cb
 

69 FR 42117 (July 14, 2004)
 

This action amends the large municipal waste combustor (MWC) emission guidelines to add a
 

carbon monoxide emission limit for one type ofMWC technology that was not previously
 

addressed.
 

There are no known sources in Colorado that may be affected by this rulemaking.
 

Regulation No.6, Part A, Subpart Da 

40 C.F.R. Part 60, Subpart Da 

70 FR 28605 (May 18, 2005) 

This action amends the standards for electric utility steam generating units to include mercury 

emission limits for units that commence construction or reconstruction after January 30, 2004. 

This amendment to 40 CFR Part 60, Subpart Da was promulgated as one piece of a broader 

rulemaking to address mercury emissions from coal-fired electric utility steam generating units. 

The AQCC has historically incorporated New Source Performance Standards in 40 CFR Part 

60, such as this action, by reference into Regulation No.6, Part A. Other portions of the 

federal rulemaking require policy decisions to be made by the AQCC and, therefore, are being 

presented to the AQCC in a separate rulemaking package. 

AND 

40 C.F.R. Part 60, Subpart Da
 

70 FR 51266 (August 30,2005)
 

This action corrects section designations within the subpart. It does not affect the substance of
 

the regulation.
 

AND
 

40 C.F.R. Part 60, Subpart Da
 

71 FR 9867 (February 27,2006)
 

This action revises the existing standards for particulate matter, nitrogen oxide, and sulfur
 

oxide emissions. This action also adds technical clarifications and compliance alternatives to
 

the existing requirements.
 

There are three sources in Colorado that may be affected by this rulemaking.
 
Regulation No.6, Part A, Subpart Db
 

40 C.F.R. Part 60, Subpart Db
 

71 FR 9867 (February 27,2006)
 

This action revises the existing standards for particulate matter, nitrogen oxide, and sulfur
 

oxide emissions. This action also adds technical clarifications and compliance alternatives to
 

the existing requirements.
 

There are seven sources in Colorado that may be affected by this rulemaking.
 

Regulation No.6, Part A, Subpart Dc
 

40 C.F.R. Part 60, Subpart Dc
 

70 FR 74679 (December 16, 2005)
 

This action corrects the definition of "annual capacity factor" and expands the definition to
 

address steam generating units that are rented or leased.
 

AND 

40 C.F.R. Part 60, Subpart Dc
 

71 FR 9867 (February 27,2006)
 

This action revises the existing standards for particulate matter, nitrogen oxide, and sulfur
 

oxide emissions. This action also adds technical clarifications and compliance alternatives to
 

the existing requirements.
 

There are 78 sources in Colorado that may be affected by this rulemaking.
 

Regulation No.6, Part A, Subpart AA and AAa
 

40 C.F.R. Part 60, Subpart AA and AAa
 

70 FR 8523 (February 22, 2005)
 

This action adds alternative requirements for monitoring emissions from furnace exhausts and
 

makes minor editorial corrections.
 

There is one source in Colorado that may be affected by this rulemaking.
 

Regulation No, 6, Part A, Subpart GG
 

40 C.F.R. Part 60, Subpart GG
 

69 FR 41346 (July 8,2004)
 

This action codifies several alternative testing and monitoring procedures that have routinely
 

been approved by EPA and reflects changes in nitrogen oxides emission control technologies
 

and turbine design since the standards were promulgated.
 

AND 
40 C.F.R. Part 60, Subpart GG 

71 FR 9453 (February 24,2006) 

This action establishes and clarifies compliance monitoring options, including clarification that 

continuous emission monitors are not required for turbines that do not use steam or water 

injection to control nitrogen oxide emissions. This also includes minor revisions to biannual 

reporting requirements. 

There are 28 sources in Colorado that may be affected by this rulemaking. 

Regulation No.6, Part A, Appendix B 

40 C.F.R. Part 60, Appendix B 

70 FR 28605 (May 18, 2005) 

This action adds a new Performance Specification l2A for mercury emission measurement 

from coal-fired electric steam generating units. 

This amendment to 40 CFR Part 60, Appendix B was promulgated as one piece of a broader 

rulemaking to address mercury emissions from coal-fired electric utility steam generating units. 

The AQCC has historically incorporated New Source Performance Standards in 40 CFR Part 

60, such as this action, by reference into Regulation No.6, Part A. Other portions ofthe 

federal rulemaking require policy decisions to be made by the AQCC and, therefore, are being 

presented to the AQCC in a separate rulemaking package. 

There are 13 sources in Colorado that may be affected by this rulemaking. 

II. Incorporation by Reference of New Federal Standards in 40 C.F.R. Part 60 

Regulation No.6, Part A, Subpart EEEE 

40 C.F.R. Part 60, Subpart EEEE 

70 FR 74870 (December 16,2005) 

This action promulgates standards ofperformance for new other solid waste incineration units 

(OSWI).
 

There are no known sources in Colorado affected by this rulemaking.
 

III. Revision to Regulation No.1, Section III.B. 

This action ensures that air curtain destructors that are subject to 40 C.F.R. Part 60, Subparts 

CCCC and EEEE are not subjected to inconsistent and infeasible state requirements. This 

proposed change does not differ from federal requirements. 

Regulation No.1 Section III.B. currently provides that all incinerators except biomedical waste 

incinerators meet certain particulate matter grain-loading standards. To establish compliance 

with these standards the regulation provides for performance testing. Under the definition set 

forth in the AQCC's Common Provisions Regulation, air curtain destructors that are subject to 

a federal NSPS are considered incinerators. 

At the time Section III.B was enacted there were no federal NSPS governing air curtain 

destructors. On December 1, 2000, however, EPA promulgated New Source Performance 
Standards (NSPS) for Commercial and Industrial Solid Waste Incineration Units at 40 C.F.R. 

Part 60, Subpart CCCe. On December 16, 2005, EPA promulgated NSPS for Other Solid 

Waste Incineration Units at 40 e.F.R. Part 60, Subpart EEEE (see Section II. of this document). 

Both standards apply to air curtain destructors meeting limited applicability criteria and 

establish opacity standards and appropriate performance testing requirements for those units. 

Neither standard establishes particulate matter grain-loading requirements. 

As currently worded, Regulation No.1, Section III.B. requires that air curtain destructors 

subject to Subparts CCCC and EEEE meet the state grain-loading standards and conduct 

performance testing to demonstrate compliance with these standards. It is not feasible, 

however, to conduct such performance tests on air curtain destructors due to their lack of a 

distinct stack. Therefore, the Division requests that the AQCC revise Section III.B. to exclude 

air curtain destructors subject to 40 e.F.R. Part 60. This revision would result in the 

requirement for air curtain destructors subject to a NSPS to meet standards and conduct 

performance testing as provided in the NSPS, which is more appropriate for those units. 

This revision would be a change to Colorado's State Implementation Plan. EPA has indicated 

that it would not consider this change "backsliding" because EPA did not consider air curtain 

destructors to be "incinerators" at the time Section III.B. was approved into the SIP. EPA has 

provided· a letter to the Division setting forth this determination prior to the hearing, and the 

letter is included in this final hearing package. 

ATTACHMENTS: 

1.	 Memorandum ofNotice 

2.	 Regulation No.6, Part A - Proposed Rule (including the Statement of Basis and Specific 

Statutory Authority and Purpose) 

3.	 Regulation No. 1 - Proposed Rule (including the Statement of Basis and Specific Statutory 

Authority and Purpose) 

4.	 Initial Economic Impact Analysis 

5.	 Negative Declaration Letter for 40 e.P.R. Part 60, Subpart FPFP 
SIGNATURES: 

1. ~O-A-~ G~""",",~=-- ~'b_-----:...\1-~-O=--..::~_

Preparer ~~\S Date 

2. 

Supervisor Date 

3. 

Pt~rana~erc (. T '., \."~ ,,,,,i ".,\,'t c \. ( ,. 

Date 

. '1.(.. 1£ I 1.( " 1\.. ~!) I Itt. 4. ---.:.:.....-....:::...:..-..:....l,,-----!b.Lf---I-------!-----!'------'--~~_I,....l..--~..:....-~-.=...-" 1 

Division Director Date 
Proposed Language for Regulation No.1
 

Request for Hearing
 

June 15,2006
 

1&8. Incinerators 

III.B.2. Standard of Performance for all incinerators other than biomedical waste 

incinerators AND AIR CURTAIN DESTRUCTORS SUBJECT TO 40 CFR 60. 

CR 29-1473
 
STATE OF COLORADO
 

Bill Owens, Governor 

Dennis E. Ellis, Executive Director 

Dedicated to protecting and improving the health and environment of the people of Colorado 

4300 Cherry Creek Dr. S. Laboratory SeNices Division 

Denver, Colorado 80246-1530 8100 Lowry Blvd. 

Phone (303) 692-2000 Denver, Colorado 80230-6928 

TDD Line (303) 691-7700 (303) 692-3090 Colorado Department Located in Glendale, Colorado of Public Health 

http://www.cdphe.state.co.us and Environment 

MEMORANDUM of NOTICE 

Date: September 21, 2006 

To: Colorado Air Quality Control Commission 

Subject: Revisions to Regulation No.6, Part A and Regulation No. 1 

The Colorado Department of Public Health and Environment, Air Pollution Control Division (Division) 

requests that the Colorado Air Quality Control Commission (AQCC) revise Regulation No.6, Part A to 

incorporate by reference additions and changes the U.S. Environmental Protection Agency (EPA) made to its 

New Source Performance Standards (NSPS) in 40 C.F.R. Part 60. The Division requests that the AQCC 

make a corresponding, clarifying change to Regulation No.1. 

What's in this Package? 

This package includes the language of the proposed changes to Regulation Nos. 1 and 6 (including the 

Statements of Basis and Specific Statutory Authority and Purpose), EPA's non-backsliding determination for 

the Regulation No.1 changes, and the Negative Declaration Letter for 40 C.F.R. Part 60, Subpart FFFF. 

Explanation of the Proposed Rule 

The Division proposes to incorporate by reference into Regulation No.6, Part A the most recent publication 

of 40 C.F.R. Part 60 (July 1,2005) and any amendments published in the Federal Register after that date. 

The Division also proposes to revise the applicability provisions for incinerator performance testing 

requirements in Regulation No.1. 

Materials Contained in the Proposed Rule 

These proposed rule changes incorporate by reference federal amendments to existing standards and new federal 

standards in 40 C.F.R. Part 60 into Regulation No.6, Part A by incorporating by reference the most recent 

publication of 40 C.F.R. Part 60 (July 1,2005) and any amendments published in the Federal Register after that 

date. 
INITIAL 

ECONOMIC IMPACT ANALYSIS 

for 

AQCC Regulation No.6, Part A 

Standards of Performance for New Stationary Sources 

and 

AQCC Regulation No.1 

Particulate Matter, Smoke, Carbon Monoxide and Sulfur Oxides 

June 15,2006 

I. Requirements for EIA 

Section 25-7-110.5 (4)(a), c.R.S. sets forth the requirements for initial and final Economic 

Impact Analysis, as stated below: 

"Before any permanent rule is proposed pursuant to this section, an initial economic 

impact analysis shall be conducted in compliance with this subsection (4) ofthe proposed 

rule or alternative proposed rules. Such economic impact analysis shall be in writing, 

developed by the proponent, or the Division in cooperation with the proponent and made 

available to the public at the time any request for hearing on a proposed rule is heard by the 

commission. A final economic impact analysis shall be in writing and delivered to the 

technical secretary and to all parties ofrecord five working days prior to the prehearing 

conference. If no prehearing conference is scheduled, the economic impact analysis shall 

be submitted at least ten working days before the date ofthe rule-making hearing. The 

proponent of an alternative proposal will provide, in conjunction with the Division, a final 

economic impact analysis five working days prior to the prehearing conference. The 

economic impact analyses shall be based upon reasonably available data. Except where 

data is not reasonably available, or as otherwise provided in this section, the failure to 

provide an economic impact analysis of any noticed proposed rule or any alternative 

proposed rule will preclude such proposed rule or alternative proposed rule from being 

considered by the Commission. Nothing in this section shall be construed to restrict the 

Commission's authority to consider alternative proposals and alternative economic impact 

analyses that have not been submitted prior to the prehearing conference for good cause 

and so long as parties have adequate time to review them." 

Further, the statute lists those situations when no Economic Impact Analysis is needed. These 

can be found in CRS, section 25-7-110.5 (2), which states: 

"The requirements of sections (1) (c) to (1) (f), (3) (g), and (4) ofthis section shall not 

apply to any rule-making packet for any Commission rule, and the requirements of 

subsections (3) (g) and (4) of this section shall not apply to any Commission rule, which 

adopts by reference applicable federal rules or which rule is adopted to implement 

prescriptive state statutory requirements, where the Commission is allowed no significant 

policy-making options, or which rule will have no regulatory impact on any person, 

facility, or activity." 
2 

II. Discussion 

The Air Pollution Control Division ("the Division") is requesting that the Colorado Air Quality 

Control Commission (AQCC) set a hearing to consider revisions to Regulation Nos. 1 and 6. 

The Division is proposing to adopt by reference amendments to and new federal standards in 40 

CFR Part 60. 

In December 2000, the U.S. Environmental Protection Agency (EPA) promulgated a New 

Source Performance Standard (NSPS) for Commercial and Industrial Solid Waste Incinerators at 

40 CFR Part 60, Subpart CCCC that applies to new air curtain incinerators in limited 

circumstances. The AQCC adopted the standard by reference in February 2002. In December 

2005, the EPA promulgated a NSPS at 40 CFR Part 60, Subpart EEEE for Other Solid Waste 

Incinerators that also applies to new air curtain incinerators in limited circumstances. Both 

standards contain performance testing requirements for affected air curtain incinerators. 

During the process of developing a rule proposal for the AQCC to adopt this new standard, the 

Division identified an issue regarding the performance testing requirements for incinerators in 

Regulation No.1, Section IH.B. Based on the definition of an incinerator in the AQCC's 

Common Provisions regulation, air curtain incinerators subject to a NSPS in 40 CFR Part 60 

would also be subject to additional performance testing requirements in Regulation No.1, 

Section IH.B. It is not feasible, however, to conduct a performance test as required by Section 

TILB. on an air curtain incinerator. Retention of this requirement would result in an impossible 

compliance requirement for owners and operators of air curtain incinerators subject to 40 CFR 

Part 60, Subparts CCCC and EEEE. 

The Division is proposing to revise Regulation No.1, Section 1II.B. to specify that the 

performance testing requirements in that section do not apply to air curtain incinerators subject to 

a standard in 40 CFR Part 60. This proposed revision will make requirements for air curtain 

incinerators consistent with federal provisions and will, therefore, have no economic impact 

beyond that of the federal requirements. 
Parties, EPA and Public Comments
 
Statement of Basis,
 

Specific Statutory Authority and Purpose
 
Statement of Basis, Specific Statutory Authority, and Purpose 

Revision to Regulation No.1 

September 21, 2006 

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 COLORADO AIR POLLUTION PREVENTION AND CONTROL ACT, SECTION 25-7-109, 

C.R.S., PROVIDES THE COMMISSION THE AUTHORITY TO ADOPT AND REVISE RULES AND 

REGULATIONS THAT ARE CONSISTENT WITH STATE POLICY REGARDING AIR POLLUTION AND 

WITH FEDERAL RECOMMENDATIONS AND REQUIREMENTS. 

BASIS AND PURPOSE 

THE U.S. ENVIRONMENTAL PROTECTION AGENCY (EPA) PROMULGATED A NEW SOURCE 

PERFORMANCE STANDARD FOR COMMERCIAL AND INDUSTRIAL SOLID WASTE 

INCINERATORS (CISWI) AT 40 CFR PART 60, SUBPART CCCC ON DECEMBER 1, 2000. 

THE COMMISSION INCORPORATED THE NEW STANDARD BY REFERENCE INTO REGULATION 

No.6, PART A IN FEBRUARY 2002. AT THAT TIME, THERE WERE NO SOURCES IN 

COLORADO SUBJECT TO SUBPART CCCC. IN SEPTEMBER 2005 A NEW UNIT SUBJECT TO 

SUBPART CCCC COMMENCED CONSTRUCTION, WHICH RAISED AN ISSUE REGARDING 

PERFORMANCE TESTING REQUIREMENTS FOR THAT UNIT. 

SUBPART CCCC OF 40 CFR PART 60 APPLIES TO AIR CURTAIN DESTRUCTORS THAT 

COMBUST WOOD OR YARD WASTES AT A COMMERCIAL OR INDUSTRIAL FACILITY. SUBPART 

CCCC INCLUDES PERFORMANCE TESTING REQUIREMENTS FOR SUCH UNITS. THE 

COMMISSION'S COMMON PROVISIONS REGULATION DEFINES AIR CURTAIN DESTRUCTORS 

SUBJECT TO 40 CFR PART 60 AS INCINERATORS, WHICH ALSO SUBJECTS THEM TO GRAIN 

LOADING STANDARDS AND PERFORMANCE TESTING REQUIREMENTS UNDER REGULATION 

No.1, SECTION III.B. IT IS NOT FEASIBLE, HOWEVER, TO CONDUCT PERFORMANCE 

TESTING ON AIR CURTAIN DESTRUCTORS FOR GRAIN LOADING EMISSIONS AS SPECIFIED IN 

SECTION III.B. DUE TO THEIR LACK OF A STACK. 

IN ORDER TO ENSURE THAT APPROPRIATE AND REASONABLE EMISSION STANDARDS AND 

PERFORMANCE TESTING REQUIREMENTS ARE APPLIED TO AIR CURTAIN INCINERATORS, THE 

COMMISSION HAS ADOPTED REVISIONS TO REGULATION No.1, SECTION III.B. CLARIFYING 

THAT AIR CURTAIN INCINERATORS SUBJECT TO 40 CFR PART 60 ARE NOT SUBJECT TO 

SECTION III.B. 
Opinion of the Attorney General
 
JOHN W. SUTHERS 

Attorney General 

CYNTHIA H. COFFMAN 

STATE OF COLORADO 

DEPARTMENT OF LAW 

STATE SERVICES BUILDING 

1525 Sherman Street - 5th Floor 

Chief Deputy Attorney General Denver, Colorado 80203 

DANIEL D. DOMENICO OFFICE OF THE ATTORNEY GENERAL Phone (303) 866-4500 

Solicitor General Fax (303) 866-5691 

Tracking Number: 2006-00264 

OPINION OF THE ATTORNEY GENERAL RENDERED IN
 

CONNECTION WITH THE RULES ADOPTED BY THE
 

Air Quality Control Commission
 

ON 09/21/2006
 

5 CCR 1001-8 

REGULATION No.6 STANDARDS OF PERFORMANCE FOR NEW STATlONARY SOURCES 

The above-referenced rules were submitted to this office on 09/22/2006 as required by section 24-4-103, CR.S. This 

office has reviewed them and finds no apparent constitutional or legal deficiency in their form or substance. 

October 10, 2006 08:15:23 MST 

JOHN W. SUTHERS 

Attorney General 

by DANIEL D. DOMENICO 

Solicitor General 

29 AG Nov 1001-8 
Regulation as Published in the CCR
 
DEPARTMENT OF PUBLIC HEALTH AND ENVIRONMENT 

Air Quality Control Commission 

REGULATION NO.1
 

EMISSION CONTROL FOR PARTICULATE MATTER, SMOKE, CARBON
 

MONOXIDE, AND SULFUR OXIDES
 

5 CCR 1001·3
 

Regulation No.1 

EPA test methods 1, 2, 3,4, 5, 6, 6a, 6b, 6c, 8 and method 9 (40 CFR 60.275, Appendix A, Part 60) are 

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

Air Quality Control Commission Regulations. Materials incorporated by reference are those in existence 

as of the date of this regulation 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. 

Definitions 

American Society for Testing and Materials 

United States Environmental Protection Agency 

Fugitive Emissions 

Emissions that cannot be reasonably collected and passed through a stack, chimney, vent or 

other equivalent opening. 

Grains per dry standard cubic foot 

Haul Roads 

Roads which are used for commercial, industrial or governmental hauling of materials and which 

the general public does not have a right to use. 

Intermittent Sources 

Those stationary sources of air pollution which do not operate on a continuous basis for a period 

of time sufficient to allow for opacity observations in accordance with EPA Method 9. 
Particulate Matter 

Roadways 

Roads, other than haul roads, used for motorized vehicular traffic. 

Welfare 

As used in these regulations, effects on public welfare include, but are not limited to, effects on 

soils, water, crops, vegetation, manmade materials, animals, wildlife, weather, visibility, and 

climate, damage to and deterioration of property, and hazards to transportation, as well as effects 

on economic values and on personal comfort and well being. 

REGULATION NO.1 Emission Control Regulations for Particulate Matter, Smoke, Carbon 

Monoxide, and Sulfur Oxides for the State of Colorado. 

I. APPLICABILITY: REFERENCED FEDERAL REGULATIONS 

LA. The provisions of this Regulation NO.1 are applicable to both new and existing sources and 

without regard to whether a source has been issued an emission permit. Except where 

specifically made applicable to attainment, attainmenUmaintenance or non-attainment areas, the 

requirements set forth herein apply statewide. (Areas designated as unclassifiable shall be 

treated as attainment). The provisions of this regulation apply to a source even though it may also 

be subject to other regulations of the commission; and in the event the requirements of this 

regulation conflict or are inconsistent with the requirements of any other regulation of the 

commission, the more stringent emission limitations shall apply except that a specific emission 

limitation for a particular source shall take precedence over a general emission limitation which is 

inconsistent. 

LB. At several places in this regulation various federal regulations, performance standards, and 

procedures that have been previously pUblished in the Federal Register and/or the Code of 

Federal Regulations have been incorporated by reference. This regulation provides appropriate 

citations to such materials and incorporates them as they are published. Amendments to such 

regulations, standards and procedures made after the effective date of this regulation are not 

incorporated herein. Copies of said materials may be obtained for a nominal copying fee from the 

Technical Secretary to the commission at the Air Quality Control Commission office at 4300 

Cherry Creek Drive South, B-1, Denver, CO 80246. Copies are also available at the commission 

office for public inspection at no cost. 

II. SMOKE AND OPACITY 

II.A. Stationary Sources 

11.A.1. Except as provided in paragraphs 2 through 6 below, no owner or operator of a source shall allow 

or cause the emission into the atmosphere of any air pollutant that is in excess of 20% opacity. 

This standard is based on 24 consecutive opacity readings taken at 15-second intervals for six 

minutes. The approved reference test method for visible emissions measurement is EPA Method 

9 (40 CFR, Part 60, Appendix A (july, 1992)) in all subsections of Section II. A and B of this 

regulation. 

II.A.2. Intermittent Sources 

Except as provided in paragraphs 3 through 6 below, no owner or operator of an intermittent 

source shall allow or cause the emission into the atmosphere of any pollutant that is in excess of 

20% opacity. If EPA Method 9 (40 CFR, Part 60, Appendix A (july, 1992)), a continuous 
emissions monitor, or other credible method is used and 24 consecutive opacity readings taken at 

15-second intervals cannot be taken because such a source does not operate continuously for six 

minutes, the readings shall be taken at 15-second intervals during periods of operation until 24 

readings have been made or for a period of thirty minutes, whichever is sooner, and the source 

shall be deemed in violation if the average opacity of such readings exceed 20%. 

1l.A.3.	 Pilot Plants and Experimental Operations 

No owner or operator of a process unit of a pilot plant or experimental operation shall emit or 

cause to be emitted into the atmosphere from any such process unit particulate matter for a 

period or periods aggregating more than six minutes in any sixty consecutive minutes which is in 

excess of 30% opacity. 

Except as otherwise provided in this paragraph this emission standard for pilot plants and 

experimental operations shall be applicable for a period not to exceed 180-operating days 

cumulative total from the date operation of such a process unit commences; thereafter the 20% 

opacity limitation provided in Section ILA.1 or 2 of these regulations shall apply to emissions from 

such a process unit of a pilot plant or experimental operation. For the purpose of this Section 

1I.A3 "Operating Days" shall mean any calendar day during which the process unit is operated 

and air pollutants are emitted (without regard to the length of period of time operated or amount of 

pollutants emitted). For good cause shown, the division may extend the period of relaxed 

operation beyond 180 operating days for the operation of a process unit, but in no event to 

greater than 365 operating days without the concurrence of the commission. 

ILAA.	 Fire Building, Cleaning of Fire Boxes, Soot Blowing, Start-up, Process Modification or Adjustment 

of Control Equipment Except as provided in Sections 1I.A.6, no owner or operator of a source 

shall allow or cause to be emitted into the atmosphere any air pollutant resulting from the building 

of a new fire, cleaning of fire boxes, soot blowing, start-up, any process modification, or 

adjustment or occasional cleaning of control equipment, which is in excess of 30% opacity for a 

period or periods aggregating more than six minutes in any sixty consecutive minutes. 

1l.A.5.	 Smokeless Flare or Flares for the Combustion of Waste Gases 

No owner or operator of a smokeless flare or other flare for the combustion of waste gases shall 

allow or cause emissions into the atmosphere of any air pollutant which is in excess of 30% 

opacity for a period or periods aggregating more than six minutes in any sixty consecutive 

minutes. 

ILA.B.	 Exemptions 

The requirements of Section ILA.1 and 2 of this regulation shall not apply to the following sources 

or types of emissions: 

ILA.B.a.	 Emissions from fireplaces, fireplace inserts and stoves, provided such devices 

are burning only clean dry wood or wood products and are used for 

noncommercial or recreational purposes. 

II.AB.b.	 Fugitive dust: As used in this Regulation No.1, "fugitive dust" means airborne 

particulate matter, which is not a direct or proximate result of man's activities. 

II.A.B.c.	 Fugitive particulate emissions: As used in this Regulation No.1, "fugitive 

particulate emissions" mean fugitive emissions of particulate matter that are the 

direct or proximate result of man's activities, (e.g., Materials left by man exposed 

to the wind or later acted upon by another force as the wind or automobile traffic, 
or particulate matter being thrown into the atmosphere by the operation of a 

bulldozer.) 

II.B.	 Diesel Powered Locomotives 

II.B.1.	 Except as provided in paragraph 2 below, no owner or operator shall emit or cause to be emitted 

into the atmosphere from any diesel-powered locomotive any air pollutant which is in excess of 

20% opacity while being operated below 6,000 feet (mean sea level) and 30% opacity while being 

operated above 6,000 feet (mean sea level). 

II.B.2.	 Exceptions 

II.B.2.a.	 Emissions that exceed the opacity limits of Section II.B.1. as a result of a cold 

engine start-up, not to exceed thirty consecutive minutes and provided the 

locomotive is in a stationary position. 

II.B.2.b.	 Emissions for nonconsecutive periods of three minutes with an aggregate of not 

more than ten minutes in any consecutive sixty minutes when a locomotive 

engine is being tested, adjusted, rebuilt, or repaired in the maintenance yards. 

II.B.2.c.	 Emissions for periods of up to four minutes when a locomotive is accelerated 

after standing still. 

II.B.3.	 The owner or operator of any diesel-powered locomotive that has been cited for violation of 

Section II.B.1. of this regulation, but which is not available for compliance inspection shall submit 

to the division an affidavit attesting to those abatement measures which have been completed 

and shall state in that affidavit that the vehicles cited have achieved compliance with this 

regulation. 

II.C.	 Open Burning 

II.C.1.	 Except as provided in paragraph 2 below, no person shall burn or allow the burning of rubbish, 

wastepaper, wood or other flammable material on any open premises, or on any public street, 

alley, or other land adjacent to such premises, unless an open burning permit is first obtained 

from the division. In granting or denying such permits the division shall base its decision on the 

location and proximity of such burning to any building or other structure, the potential contribution 

of such burning to air pollution in the area, climactic conditions on the day or days of such 

burning, and compliance by the applicant for the permit with applicable fire protection and safety 

requirements of the local authority. The division may consider: (A) Whether there is any practical 

alternative method for the disposal of the material to by burn and (B) Whether burning will be 

conducted so as to minimize emissions. Methods for minimizing emissions may include, but are 

not necessarily limited to, the use of permitted incinerators or air curtain destructors, the use of 

clean auxiliary fuel, drying the material prior to ignition and separating out for alternative disposal: 

Rubber, tires, plastic, insulated wire, insulation, and other materials which produce more smoke 

than clean combustible materials. Sources subject to the open burning provisions in this 

regulation NO.1 may also be subject to state only Regulation NO.9. 

II.C.1.A.Whether there is any practical alternative method for the disposal of the material to be burned. 

II.C.2.	 Sources Exempted from obtaining open burning permits 

II.C.2.a.	 The non-commercial burning of private household trash in PM attainment areas 

unless local ordinances or rules prohibit such burning. 
II.C.2.b.	 Fires used for non-commercial cooking of food for human beings, for instructional 

purposes, or recreational purposes. 

II.C.2.c.	 Flares used to indicate some danger to the public. 

II.C.2.d.	 Agricultural open burning - The open burning of cover vegetation for the purpose 

of preparing the soil for crop production, weed control, and other agricultural 

cultivation purposes. The open burning of animal parts or carcasses is not 

included in the exemption. Except that, if the State Agricultural commission 

declares a public health emergency or a contagious or infectious disease 

outbreak that imperils the livestock of the state that requires the burning of 

diseased animal carcasses after providing telephone notice to the division and 

the relevant local health department office by leaving a voice mail message. All 

necessary safeguards shall be utilized during such non-permitted open burning 

to minimize any public health or welfare impacts. In addition, the owner or 

operator shall take steps to ensure that all surrounding and potentially impacted 

residents, businesses, schools and churches are notified prior to beginning the 

open burn. 

II.C.2.e.	 Noncommercial burning of trash in the unincorporated areas of counties of less 

than 25,000 population according to the latest federal census provided such 

open burning is subject to regulations of the board of county commissioners for 

such county adopted by resolution and such regulations include, among other 

things, permit provisions and prohibit any such burning that would result in the 

exceedence of any NMQS. 

II.C.3.	 Nothing herein shall be construed as relieving any person conducting open burning from meeting 

the requirements of any applicable federal, state or local requirements concerning disposal of 

waste materials. 

11.0.	 Smoke and Obscurants for Military Training Exercises Emissions associated with the generation 

of smoke or obscurants on Fort Carson and Pinon Canyon maneuver site (hereafter, referred 

together as Fort Carson) by United States military forces, or allied forces in a combined training 

exercise with the United States, shall be exempt from the opacity limits specified in Regulation 

No.1, sections II. and III. provided that all of the following conditions are met: 

11.0.1.	 All participants in the training shall follow all applicable Department of Defense training manuals 

and guidance regarding Department of Defense-approved smokes and obscurants. 

11.0.2.	 No off-property transport of visible emissions from any smoke or obscurants used on Fort Carson 

shall occur. 

111.0.3.	 Smoke or obscurants generation shall cease immediately in the event that any such visible 

emissions cross or has a reasonable probability of crossing the installation property boundary. 

11.0.4.	 The commander in charge of any training involving smoke or obscurants will ensure the following 

precautionary measures are implemented. 

II.D.4.a.	 When planning and conducting training, prevailing meteorological conditions will 

be analyzed, both before and on the day of training, to determine if they meet 

established training criteria for the use of smoke or obscurants and to allow 

compliance with the requirements of paragraph 3 above. If the meteorological 

conditions do not meet those criteria, then smoke or obscurants will not be 

employed. 
IIDA.b. Prior to using smoke or obscurants, inspect and validate the training site and the 

training mission. 

IIDA.c. Upon initiation of smoke or obscurant generation, observe the initial smoke or 

obscurant plume to verify that it conforms to established training criteria and to 

allow compliance with the requirements of paragraph 3 above. If the wind 

direction and speed is not favorable for the exercise, then the location will be 

adjusted or the smoke mission will be postponed or canceled. 

IIDA.d. Post one or more trained smoke observers to provide direct observation of the 

smoke/obscurant plume at all times while smoke or obscurants are used during 

the training. Smoke observers will remain alert for visible smoke that has a 

reasonable probability of drifting across the installation property boundary, in 

which case the smoke observer shall have the authority to immediately halt 

smoke generation operations. The smoke observer(s) must maintain capability 

for immediate communication with the officer commanding the use of smoke or 

obscurants used in the training exercise. 

IIDA.e. Units conducting training using smoke or obscurants on Fort Carson must 

perform necessary checks with Fort Carson range division to assure immediate 

communication capability, including capability to request or obtain meteorological 

updates. In the event of failure to maintain such capability, the training exercise 

will be halted. 

11.0.5. In the event visible emissions from smoke or obscurant use drift across the installation property 

boundary, Fort Carson shall implement necessary response measures to minimize impacts and 

shall inform the state as soon as possible, but no later than 24 hours or the next business day 

after the event. A written notice shall follow this notification within 48 hours to the state detailing 

the circumstances of the occurrence and stating whether additional measures will be adopted to 

prevent such visible emissions from drifting across the boundary in the future. 

II.D.6. Installation commander, Fort Carson, shall be responsible to ensure compliance with this section 

by all personnel employing smoke or obscurants at Fort Carson. 

III. PARTICULATE MATTER 

liLA. Fuel Burning Equipment 

1I1.A.1. No owner or operator shall cause or permit to be emitted into the atmosphere from any fuelburning equipment, particulate matter in the flue gases which exceeds the following: 

1I1.A.1.a. O.S Ibs. per 106 BTU heat input for fuel burning equipment of less than or equal to 

1x1 06BTU/hr total heat input design capacity. 

11I.A.1.b. For fuel burning equipment with designed heat inputs greater than 1x1 06 BTU per 

hour, but less than or equal to SOOx1 06 BTU per hour, the following equation will 

be used to determine the allowable particulate emission limitation. 

PE=0.S(FI)-Q26 

Where: 

PE = Particulate Emission in Pounds per million BTU heat input. 

FI = Fuel Input in Million BTU per hour. 
III.A.1.c.	 0.1 lbs. fer 105 BTU heat input for fuel burning equipment of greater than 

500x10 BTU per hour or more. 

III.A.1.d.	 If two (2) or more fuel burning units connect to any opening, the maximum 

allowable emission rate shall be calculated on a lb/ hour basis as calculated from 

a weighted average of the individual allowable limits for each unit ducting to the 

common stack. 

III.A.2.	 Performance Tests 

Prior to granting of a final approval permit or amending a permit, when an emission source or 

control equipment is altered, or at any time when there is reason to believe that emission 

standards are being violated, the division may require the owner or operator of any fuel burning 

equipment to conduct performance tests, as measured by EPA Methods 1-4 and the front half of 

EPA Method 5 (40 CFR 60.275, Appendix A, Part 60), or other credible method approved by the 

division, to determine compliance with this subsection of this regulation. The particulate emission 

standards contained in this subsection do not include condensable particulate matter, or the back 

half emissions of EPA Method 5. 

III.B.	 Incinerators 

III.B.1.	 No owner or operator of an incinerator shall operate any incinerator without a permit from the 

division. 

III.B.2.	 Standard of Performance for all incinerators other than biomedical waste incinerators;C;nd air 

curtain destructors subject to 40 CFR 60J v 

III.B.2.a.	 In areas designated as non-attainment or attainment/maintenance for particulate 

matter, no owner or operator of an incinerator shall cause or permit emissions of 

more than 0.10 grain of particulate matter per standard cubic foot. (Dry flue gas 

corrected to 12 percent carbon dioxide.) 

III.B.2.b.	 In areas designated as attainment for particulate matter, no owner or operator of 

an incinerator shall cause or permit emissions of more than 0.15 grain of 

particulate matter per standard cubic foot. (Dry Flue gas corrected to 12 percent 

carbon dioxide.) 

III.B.3.	 Performance Tests 

Prior to granting a final approval permit or amending a permit, when an emission source or 

control equipment is altered, or at any time when there is reason to believe that emission 

standards are being violated, the division may require the owner or operator of an incinerator to 

conduct performance test(s) in accordance with 40 CFR 60 Appendix A. 

III.B.4.	 Standard of Performance for Biomedical Waste Incinerators. 

The owner or operator of an existing incinerator used for the disposal of biomedical waste shall 

comply with Part B, Section V of Regulation NO.6. Standard of Performance For New Biomedical 

Waste Incinerators as follows: 

III.B.4.a.	 All incinerators, existing as of the effective date of Part B, Section V of 

Regulation No.6, with a design rate of four hundred pounds per hour and greater 

must comply with the requirements of this regulation. 
III.B.4.b.	 All incinerators, existing as of the effective date of Part B, Section V of 

Regulation No.6, with a design capacity of less than four hundred pounds per 

hour must comply with the requirements of this regulation as applicable; except 

incinerators with a design capacity of less than 200 pounds per hour shall be 

permitted and allowed to operate only so long as the units continue to meet the 

particulate and visible emission standards existing prior to the effective date of 

Part B, Section V of Regulation No.6, the manufacturer's design specifications 

and any other applicable safety standards. (The standards existing prior to the 

effective date of this regulation are: a) For sources existing prior to January 30, 

1979: 20% opacity and 0.10 grains per dry standard cubic foot (gr/dscf) of PM for 

PM non-attainment areas and 0.15 gr/dscf of PM for PM attainment areas; b) 

20% opacity and 0.10 gr/dscf of PM for sources constructed after January 30, 

1979.) 

III.C.	 Manufacturing Processes 

III.C.1.	 Except as provided in paragraphs 2 of this subsection C., no owner or operator of a 

manufacturing process unit shall cause or permit emission of any particulate matter into the 

atmosphere during any consecutive sixty minute period which is in excess of the following. 

III.C.1.a.	 For process equipment having design rates of 30 tons per hour or less, the 

allowable emission rate shall be determined by the use of the equation: 

PE = 3.59(P)062 

Where: 

PE = Particulate Emission in lbs. per hour 

P = Process weight rate in tons per hour 

III.C.1.b.	 For process equipment having design rates of greater than 30 tons per hour, the 

allowable emission rate shall be determined by use of the equation: 

PE = 17.31(P)016 

Where: 

PE = Particulate Emission rate in Ibs. per hour 

P = Process weight rate in tons per hour 

III.C.1.c.	 If two or more process units are connected to the same opening, the maximum 

allowable emission rate shall be computed by summing the allowable emissions for 

the units being operated. 

III.C.2.	 Exceptions 

Fugitive dust and fugitive particulate emissions as defined in Section II.A.6 of this Regulation. 

III.C.3.	 Performance Tests 

Prior to granting of a final approval permit or amending a permit, when an emission source or 

control equipment is altered, or at any time when there is reason to believe that emission 

standards are being violated, the division may require the owner or operator of any manufacturing 
process to conduct performance tests, as measured by EPA Methods 1-4 and the front half of 

EPA Method 5 (40 CFR 60.275, Appendix A, Part 60), or other credible method approved by the 

division, to determine compliance with this subsection of this regulation. The particulate emission 

standards contained in this subsection do not include condensable particulate matter, or the back 

half emissions of EPA Method 5 (40 CFR 60.275, Appendix A, Part 60). 

1/1.0. Fugitive Particulate Emissions 

I11.0.1. General Requirements 

1II.D.1.a.	 Existing Sources 

III.D.1.a.(i).	 Every owner or operator of a source or activity that is subject to this 

Section 111.0. shall employ such control measures and operating 

procedures as are necessary to minimize fugitive particulate emissions 

into the atmosphere through the use of all available practical methods 

which are technologically feasible and economically reasonable and 

which reduce, prevent and control emissions so as to facilitate the 

achievement of the maximum practical degree of air purity in every 

portion of the State. 

III.D.1.a.(ii).	 In determining what control methods are available, practical, 

economically reasonable and technologically feasible, the following 

factors shall be considered: effects on the health, welfare (as defined in 

Section I.G. of the Common Provisions regUlation), convenience, and 

comfort of the inhabitants of the State of Colorado; effects on the 

enjoyment and use of the scenic and natural resources of the State; the 

impact on normal operating procedures; altitude, topography, climate, 

and anticipated meteorological conditions (inclUding wind and 

precipitation); soil conditions; the degree to which a type of emission to 

be controlled is significant; the continuous, intermittent, or seasonal 

nature of the emission, the economic, environmental, and energy 

impacts and other costs of compliance; the proximity of the source or 

activity to populated areas; and the nature, scope and duration of the 

source or activity. 

III.D.1.a.(iii).	 This Section 111.0. shall be enforceable only through the procedures 

specified below in Section 1II.D.1.b. through 1I1.0.1.e. 

1II.D.1.b.	 New Sources 

Every owner or operator of a new source or activity that is subject to this 

Section 111.0. and which is required to obtain an emission permit under 

Regulation No.3 shall submit a fugitive particulate emission control plan 

meeting the requirements of this Section 111.0. at such time as, and as 

part of, the required permit application. Such plan shall be approved or 

disapproved by the division in the course of acting to approve or 

disapprove the permit application and no emission permit shall be issued 

until a fugitive particulate emission control plan has been approved. 

1II.D.1.c.	 Emission Limitation Guidelines for Submission of Control Plan. 

If the division determines that a source of activity which is subject to this 

Section 111.0. (whether new or eXisting) is operating with emissions in 

excess of 20% opacity and such source is subject to the 20% emission 
limitation guideline; or if it determines that the source or activity which is 

subject to this Section 111.0. is operating with visible emissions that are 

being transported off the property on which the source is located and 

such source is subject is to the no off property transport emission 

limitation guideline; or if it determines that any source or activity which is 

subject to this Section 111.0. is operating with emissions that create a 

nuisance; it shall require the owner or operator of that source or activity 

to submit a written plan to the division for the control of fugitive 

particulate emissions within the time period specified in Section 111.0. 

Provided, however, that in the case of a source or activity which already 

has a control plan, the division shall review said control plan and if it 

determines the plan does not meet the requirements of this Section 

111.0., it shall require the submission of a revised control plan. (As used 

herein, "nuisance" shall mean the emission of fugitive particulates that 

constitutes a private or public nuisance as defined in common law, the 

essence of which is that such emissions are unreasonable interfering 

with another person's use and enjoyment of his property. Such 

interference must be "substantial" in its nature as measured by a 

standard that it would be of definite offensiveness, inconvenience, or 

annoyance to a normal person in the community.) 

[Cross Reference: Appendices A and B] 

IIID.1.d.	 Control Plans 

IIID.1.d.(i). 

With respect to operations or activities that have more than one source 

of fugitive particulate emissions, submissions of control plans or plan 

revisions pursuant to Section 111.0. shall be required only with respect to 

those individual sources for which there does not exist a currently 

approvable control plan and which are not being operated in accordance 

with the requirements of this Section III.D., provided, however, that 

control plans required by Section III.D:I.b for new sources and activities 

shall contain provisions for control of fugitive particulate emissions from 

all significant sources of such emissions. 

III.D.1.d.(ii).	 Sources required to submit control plans for revisions to the division shall 

do so within sixty days of the date such plan or revision is requested; 

provided, however, that the division, in its discretion, may where 

appropriate establish a different time period for submittal, taking into 

consideration such factors as the duration of the operation of the source 

or activity, the significance and nature of the emissions, and the relative 

complexity of the operation and applicable control methods. 

III.D.1.d.(iii).	 Each control plan shall include all available practical methods which are 

technologically feasible and economically reasonable and which reduce, 

prevent and control fugitive particulate emissions from the source or 

activity into the atmosphere. For those materials, equipment, services or 

other resources (such as water for abatement and control purposes), 

which are likely to be scarce at any given time, an alternative control 

method must be included in the control plan. Any source required to 

submit a control plan may ask for a "control plan conference" with the 

division, and if so requested the division shall hold such a conference for 

the purpose of advising what types of control measures and/or operating 

procedures will meet the requirements of this section. 
[Cross Reference: Sections 111.0.2.a. through 1I1.0.2.k.] 

IIID.1.d.(iv).	 The division shall approve any plan submitted under this Section 111.0., 

unless the division determines that the plan does not meet the 

requirements of Section 111.0. If a control plan is not approvable in its 

entirety, the division shall approve those portions, which meet the 

requirements of this section and disapprove those portions, which fail to 

meet the requirements of this section. 

1I1.0.1.e.	 Enforcement 

IIID.1.e.(i).	 It shall be a violation of this regulation and the division may take 

enforcement action pursuant to C.R.S. 1973.25-7-115, as amended, if 

the owner or operator: 

111.0.1.e.(ii).(A). Fails to submit a control plan (or revision of an existing plan) 

within sixty days (or other time period specified by the division) after 

being notified by the division that such submittal is required unless 

operation of such source is discontinued so as to permanently eliminate 

the cause of fugitive particulate emissions there from; or 

IIID.1.e.(ii).(B). Owns or operates a source or activity for which the division has 

disapproved a control plan or a revised control plan unless operation of 

such source is discontinued so as to permanently eliminate the cause of 

fugitive particulate emissions there from; or 

IIID.1.e.(ii).(C). Fails to comply with the provisions of an approved control plan. 

111.0.1.e.(iii).	 The 20% opacity, no off-property transport, and nuisance emission 

limitation guidelines of this Section 111.0. are not enforceable standards 

and no person shall be cited for violation thereof pursuant to C.R.S. 

1973,25-7-115 as amended. 

111.0.2. Sources Subject to Section 111.0. 

The control measures and operating procedures listed in Sections IIID.2.a. through 1I1.0.2.k. are 

generally considered appropriate for the specific types of sources under which they are listed - at 

least as applied individually. Whether they remain appropriate when used in combination with 

other measures and procedures, must be determined on a case-by-case basis. 

1I1.0.2.a.	 Roadways 

1I1.0.2.a.(i).	 Unpaved 

f11.0.2.a.(i).(A).	 Applicability - Attainment and Non-attainment Areas 

1I1.0.2.a.(i).(B).	 General Requirement 

Any owner or operator responsible for construction or maintenance of 

any (existing or new) unpaved roadway which has vehicle traffic 

exceeding 200 vehicles per day in attainment areas or 150 vehicles per 

day in non-attainment areas (averaged over any consecutive 3-day 

period) from which fugitive particulate emissions will be emitted shall be 

required to use all available, practical methods which are technologically 

feasible and economically reasonable in order to minimize emissions 
resulting from the use of such roadway in accordance with the 

requirements of Section 111.0. of this regulation. 

III.D.2.a.(i).(C). Applicable Emission Limitation Guideline 

The nuisance emission limitation guideline shall apply to unpaved 

roadways. Abatement and control plans submitted for unpaved roadways 

shall be evaluated for compliance with the requirements of Section 111.0. 

of this regulation. 

III.D.2.a.(i).(D). Control Measures and Operating Procedures 

Control measures or operations procedures to be employed may include 

but are not necessarily limited to, watering, chemical stabilization, road 

carpeting, paving, suggested speed restrictions and other methods or 

techniques approved by the division. 

IIID.2.a.(i).(E). If the division receives a complaint that any new or existing 

unpaved roadway is creating a nuisance, it may require persons owning 

or operating or maintaining such roadways to supply vehicle traffic count 

information by any reasonable available means for the purpose of 

determining if they have sufficient traffic to subject them to the 

requirements of this Section 111.0. 

III.D.2.a.(ii). Paved 

III.D.2.a.(ii).(A). Applicability - Attainment and Non-attainment Areas 

III.D.2.a.(ii).(B). General Requirement 

Any person who through operations or activities repeatedly deposits 

materials which may create fugitive particulate emissions on a public or 

private paved roadway is required to submit a control and abatement 

plan upon request by the division which provides for the removal of such 

deposits and appropriate measures to prevent future deposits such that 

fugitive particulate emissions which may result are minimized; except 

that sand, salt or other materials may be dropped on snow or ice covered 

roadways for the purpose of safety and such deposits shall not be 

required to be removed on a more frequent basis than the community's 

normal street cleaning schedule except as otherwise provided in an 

applicable SIP provision. 

III.D.2.a.(ii).(C). Applicable Emission Limitation Guideline 

The nuisance emission limitation guideline shall apply to paved 

roadways. Abatement and control plans submitted for paved roadways 

shall be evaluated for compliance with the requirements of section III.D. 

of this regulation. 

III.D.2.a.(ii).(D). Control Measures and Operating Procedures 

Control measures or operational procedures to be employed may include 

but are not necessarily limited to, covering the loaded haul truck, 

washing or otherwise treating the exterior of the vehicle, limiting the size 

of the load and the vehicle speed, watering or treating the load with 
chemical suppressants, keeping the roadway access point free of 

materials that may be carried onto the roadway, removal of materials 

from the roadway and other methods or techniques approved by the 

division. 

III.D.2.b. Construction Activities 

111.0.2.b.(i). Applicability - Attainment and Non-attainment Areas 

1I1.0.2.b.(ii). General Requirement 

Any owner or operator engaged in clearing or leveling of land or owner or 

operator of land that has been cleared of greater than five acres in attainment 

areas or one (1) acre in non-attainment areas from which fugitive particulate 

emissions will be emitted shall be required to use all available and practical 

methods which are technologically feasible and economically reasonable in order 

to minimize such emissions in accordance with the requirements of Section 111.0. 

of this regulation. 

1I1.0.2.b.(iii). Applicable Emission Limitation Guideline 

Both the 20% opacity and the no off-property transport emission limitation 

guidelines shall apply to construction activities; except that with respect to 

sources or activities associated with construction for which there are separate 

requirements set forth in this regulation, the emission limitation guidelines there 

specified as applicable to such sources and activities shall apply. Abatement and 

control plans submitted for construction activities shall be evaluated for 

compliance with the requirements of Section 111.0. of this regulation. 

[Cross Reference: Subsections e. and f. of Section 111.0.2. of this regulation.] 

1I1.0.2.b.(iv). Control Measures and Operating Procedures 

Control measures or operational procedures to be employed may include, but are 

not necessarily limited to, planting vegetation cover, providing synthetic cover, 

watering, chemical stabilization, furrows, compacting, minimizing disturbed area 

in the winter, wind breaks and other methods or techniques approved by the 

division. 

1I1.0.2.c. Storage and Handling of Materials 

1I1.0.2.c.(i). Applicability - Attainment and Non-attainment Areas 

1II.D.2.c.(ii). General Requirement 

Any owner or operator or any new or existing materials storage and handling 

operation from which fugitive particulate emissions will be emitted shall be 

required to use all available practical methods which are technologically feasible 

and economically reasonable in order to minimize such emissions in accordance 

with the requirements of Section 111.0. of this regulation. 

1I1.0.2.c.(iii). Applicable Emission Limitation Guideline 

Both the 20% opacity and the no off-property transport emission limitation 

guidelines shall apply to storage and handling operations. Abatement and control 
plans submitted for storage and handling operations shall be evaluated for 

compliance with the requirements of Section 111.0. of this regulation. 

1II.D.2.c.(iv). Control Measures And Operating Procedures 

Control measures or operational procedures to be employed may include, but are
 

not necessarily limited to, the use of enclosures, covers, stabilization,
 

compacting, watering, limitation of fines and other methods or techniques
 

approved by the division.
 

111.0.2.d. Mining Activities 

1II.D.2.d.(i). Applicability - Attainment and Non-attainment Areas 

1I1.0.2.d.(ii). General Requirements 

Any owner or operator of any new or existing mining operation from which 

fugitive particulate emissions will be emitted shall be required to use all available 

practical methods which are technologically feasible and economically 

reasonable in order to minimize such emissions in accordance with the 

requirements of Section 111.0. of this regulation. 

III.0.2.d.(iii). Applicable Emission Limitation Guideline 

Both the 20% opacity and the no off-property transport emission limitation 

guidelines shall apply to mining activities' except that with respect to sources or 

activities associated with mining for which there are separate requirements set 

forth in this regUlation, the emission limitation guidelines there specified as 

applicable to such sources and activities shall apply. Abatement and control 

plans submitted for mining activities shall be evaluated for compliance with the 

requirements of Section 111.0. of this regUlation. 

1I1.0.2.(iv). Control Measures and Operating Procedures 

Control measures or operating procedures to be employed may include, but are 

not necessarily limited to: 

1I1.0.2.d.(iv).(A). watering or chemical stabilization of unpaved roads as often as 

necessary to minimize re-entrainment of fugitive particulate matter from 

the road surface, or paving of roads; 

111.0.2.d.(iv).(B). prompt removal of coal, rock minerals, soil, and other dustforming debris from paved roads and scraping and compaction of 

unpaved roads to stabilize the road surface as often as necessary to 

minimize re-entrainment of fugitive particulate matter from the road 

surface; 

1I1.0.2.d.(iv).(C). restric~ing the speed of vehicles in and around the mining 

operation; 

111.0.2.d.(iv).(O). revegetating, mulching, or otherwise stabilizing the surface of all 

areas adjoining roads that are a source of fugitive particulate emissions; 

1I1.0.2.d.(iv).(E). to the extent practicable restricting vehicular travel vehicles to 

established roads; 
IIID.2.d.(iv).(F). enclosing, covering, watering, or otherwise treating loaded haul 

trucks and railroad cars, or limiting size of load, to minimize loss of 

material to wind and spillage; 

111.0.2.d.(iv).(G).substitution of conveyor systems for haul trucks; 

1I1.0.2.d.(iv).(H).minimizing the area of disturbed land; 

IIID.2.d.(iv).(I). prompt revegetation of disturbed surface areas; 

1I1.0.2.d.(iv).(J). planting of special windbreak vegetation at critical points; 

IIID.2.d.(iv).(K). restricting the areas to be blasted at anyone time; 

11I.0.2.d.(iv).(L). reducing the period of time between initially disturbing the soil 

and revegetating or other surface stabilization; 

111.0.2.d.(iv).(M).control of fugitive particulate emissions from storage piles 

through use of enclosures, covers, or stabilization, minimizing the slope 

of the upwind face of the pile, confining as much pile activity as possible 

to the downwind side of the pile and other methods or techniques as 

approved by the division. 

[Cross Reference: Subsections a., b., c., e., f., g., and L of Section 

111.0.2. of this regulation.] 

III.D.2.e. Haul Roads 

III.D.2.e.(i). Applicability - Attainment and Non-attainment Areas 

III.D.2.e.(ii). General Requirement 

Any owner or operator of any new or existing haul road which has vehicle traffic 

exceeding 40 haul vehicles or 200 total vehicles per day (averaged over any 

consecutive 3-day period) from which fugitive particulate emissions will be 

emitted shall be required to use all available practical methods which are 

technologically feasible and economically reasonable in order to minimize such 

emissions in accordance with the requirements of Section III.D. of this regulation. 

III.D.2.e.(iii). Applicable Emission Limitation Guideline 

The no off-property transport emission limitation guideline shall apply to on-site 

haul roads (Le., those located on and abutted by the property owned or under 

control of the owner or operator of the haul road) and the nuisance guideline 

shall apply to off-site haul roads (i.e., those abutted on both sides by property not 

owned or under the control of the owner or operator of the haul road). Abatement 

and control plans submitted for haul roads shall be evaluated for compliance with 

the requirements of Section III.D. of this regulation. 

III.D.2.e.(iv). Control Measures and Operating Procedures 

Control measures and operational procedures to be employed may include, but 

are not necessarily limited to, the use of vehicular speed reduction, watering, 

chemical stabilization. road carpeting and other methods of techniques approved 

by the division. 
IIID.2.e.(v). The division may require persons owning or operating or maintaining any 

new or existing haul roads to supply vehicle traffic count information by any 

reasonable available means for the purpose of determining if they have sufficient 

traffic to subject them to the requirements of this Section 111.0. 

III.D.2.f. Haul Trucks 

IIID.2.f.(i) Applicability - Attainment and Non-attainment Areas 

III.D.2.f.(ii). General Requirement 

Any owner or operator of any new or existing haul trucks from which fugitive 

particulate emissions will be emitted shall be required to use all available 

practical methods which are technologically feasible and economically 

reasonable in order to minimize such emissions in accordance with the 

requirements of Section 111.0. of this regulation. 

III.D.2.f.(iii). Applicable Emission Limitation Guideline 

The no off-property transport emission limitation guideline shall apply to haul 

trucks; except that when operating off the property of the owner or operator, the 

applicable guideline shall be no off-vehicle transport of visible emissions. 

Abatement and control plans submitted for haul trucks shall be evaluated for 

compliance with the requirements of Section 111.0. of this regulation. 

111.0.2.f.(iv). Control Measures and Operating Procedures 

Control measures or operation procedures to be employed may include but are 

not necessarily limited to, covering the materials, washing or otherwise treating 

loaded haul trucks to remove materials from the exterior of the vehicle prior to 

transporting materials, limiting load size, wetting the load and other methods or 

techniques approved by the division. 

[Cross Reference: C.R.S. 1973, Section 42-4-1208] 

111.0.2.g. Tailings Piles and Ponds 

III.D.2.g.(i). Applicability - Attainment and Non-attainment Areas 

III.D.2.g.(ii). General Requirement 

Any owner or operator of any new or existing tailings piles and ponds from which 

fugitive particulate emissions will be emitted shall be required to use all available 

practical methods which are technologically feasible and economically 

reasonable in order to minimize such emissions in accordance with the 

requirements of Section III.D. of this regulation. 

III.D.2.g.(iii). Applicable Emission Limitation Guideline 

Both the 20% opacity and the no off-property transport emission limitation 

guidelines shall apply to tailings piles and ponds. Abatement and control plans 

submitted for tailings piles and ponds shall be evaluated for compliance with the 

requirements of Section 111.0. of this regulation. 
111.0.2.g.(iv). Control Measures and Operating Procedures 

Control measures or operational procedures to be employed may include, but are 

not necessarily limited to: 

III.D.2.g.(iv).(A). watering and/or chemical stabilization, 

IIID.2.g.(iv).(B). synthetic and/or revegetative covers, 

III.D.2.g.(iv).(C). windbreaks, 

III.D.2.g.(iv).(D) minimizing the area of disturbed tailings, 

IIID.2.g.(iv).(E). restricting the speed of vehicles in and around the tailings 

operation, and/or, 

III.D.2.g.(iv).(F). other equivalent methods or techniques approved by the 

division. 

III.D.2.h. Demolition Activities 

III.D.2.h.(i). Applicability - Non-attainment Areas 

III.D.2.h.(ii) General Requirements 

Any owner or operator of any new demolition activities from which fugitive 

particulate emissions will be emitted shall be required to use all available 

practical methods which are technologically feasible and economically 

reasonable in order to minimize such emissions in accordance with the 

requirements of Section 111.0. of this regulation. 

III.0 .2.h.(iii). Applicable Emission Limitation Guideline 

Only the no off-property transport emission limitation guideline shall apply to 

demolition activities. Abatement and control plans submitted for demolition 

activities shall be evaluated for compliance with the requirements of Section 111.0. 

of this regulation. 

III.D.2.h.(iv). Control Measures and Operating Procedures 

Control measures or operational procedures to be employed may include, but are 

not limited to: 

III.D.2.h.(iv).(A). wetting down, including pre-watering of work surface, 

1I/.D.2.h.(iv).(B). removal of dirt and mud deposited on improved streets and 

roads, 

III.D.2.h.(iv).(C).wetting down, washing, or covering haulage equipment when 

necessary to minimize fugitive dust emissions during loading and transit. 

III.D.2.h.(v)	 Any demolition or renovation activity that has materials insulated or 

fireproofed with friable asbestos will also be subject to the provisions of the Air 

Quality Control commission's Regulation No.8, Part B. 
III.D.2.i. Blasting Activities 

III.D.2.i.(i). Applicability - Attainment and Non-attainment Areas 

III.D.2.i.(ii). General Requirement 

Any owner or operator of any new or existing blasting activities from which 

fugitive particulate emissions will be emitted shall be required to use all available 

practical methods which are technically feasible and economically reasonable in 

order to minimize such emissions in accordance with the requirements of Section 

II/D. of this regulation. 

III. D.2. i.(iii). Applicable Emission Limitation Guideline 

Only the no off-property transport emission limitation guideline shall apply to 

blasting activities. Abatement and control plans submitted for blasting activities 

shall be evaluated for compliance with the requirements of Section III.D. of this 

regulation. 

III.D.2.i.(iv). Control Measures and Operating Procedures 

Control measures or operational procedures to be employed may include, but are 

not limited to, the use of: 

I/I.D.2.i.(iv).(A). the removal of overburden prior to blasting, 

III.D.2.i.(iv).(B). watering down the blasted area as soon as practicable after 

blasting, 

IIID.2.j.(iv).(C). other equivalent methods or techniques approved by the 

division. 

III.D.2.j. Sandblasting Operations 

III.D.2.j.(i). Applicability - Attainment and Non-attainment Areas 

III.D.2.j.(ii). General Requirement 

Any owner or operator of any new or eXisting sandblasting activities from which 

fugitive particulate emissions will be emitted shall be required to use all available 

practical methods which are technologically feasible and economically 

reasonable in order to minimize such emissions in accordance with the 

requirements of Section 111.0. of this regulation. 

1II.D.2.j.(iii). Applicable Emission Limitation Guideline 

Only the 20% opacity emission limitation guideline shall apply to sandblasting 

operations. Abatement and control plans submitted for sandblasting operations 

shall be evaluated for compliance with the requirements of Section III.D. of this 

regulation. 

III.D.2.j.(iv). Control Measures and Operating Procedures 

Control measures and operating procedures to be employed may include, but are 

not limited to the use of enclosures with necessary dust collecting equipment, 
using wet sandblasting methods, and other methods or techniques approved by 

the division. 

III.D.2.k.	 Livestock Confinement Operations 

III.D.2.k.(i).	 Applicability - Attainment and Non-attainment Areas 

III.D.2.k.(ii).	 General Requirement 

Any owner or operator of any new or existing livestock confinement operations 

from which fugitive particulate emissions will be emitted shall be required to use 

all available practical methods which are technologically feasible and 

economically reasonable in order to minimize such emissions in accordance with 

the requirements of Section 111.0. of this regulation. 

III.D.2.k.(iii).	 Applicable Emission Limitation Guideline 

Only the no off-property transport guideline shall apply to livestock confinement 

operations. Abatement and control plans submitted for livestock confinement 

operations shall be evaluated for compliance with the requirements of Section 

111.0. of this regulation. 

IIID.2.k.(iv).	 Control Measures and Operating Procedures 

Control measures or operating procedures to be employed may include, but are 

not limited to the use of sprinkler systems and/or other equivalent methods or 

techniques as approved by the division. 

IV.	 CONTINUOUS EMISSION MONITORING REQUIREMENTS FOR NEW OR EXISTING 

SOURCES 

IVA	 Sources which are required to install, calibrate, certify and maintain continuous emission 

monitoring (CEM) systems for opacity, and/or sulfur dioxide and/or carbon monoxide (listed in 

Sections B, C, and 0, of this Section IV and in Section VII.) shall have such equipment installed in 

a location which in accord with sound engineering practice will provide for accurate opacity and/or 

sulfur dioxide, and/or carbon monoxide emission readings. The averaging times for these 

monitors shall correspond to the averaging times for the appropriate emission standard. 

IV.B.	 Fossil Fuel-fired Steam Generators 

IV.B.1.	 A continuous emission monitoring system for the measurement of opacity shall be 

installed, calibrated, maintained and operated by the owner or operator of any steam 

generator of a total rated capacity of or greater than 250 million BTU per hour heat input 

except where: 

IV.B.1.a.	 Gaseous fuel is the only fuel burned or, 

IV.B.1.b.	 Oil or a mixture of gas and oil are the only fuels burned and the source is 

able to comply with the applicable particulate matter and opacity 

regulation without utilization of particulate matter collection eqUipment, 

IV.B.1.c.	 The source demonstrates that a continuous monitoring system would not 

provide accurate determinations of the opacity of emissions (e.g., 

condensed, uncombined water vapor in the emissions would prevent 
accurate readings) and an alternative method of determining opacity 

approved by the division is employed. 

IV.B.2.	 Either a continuous emission monitoring system for the measurement of sulfur dioxide 

shall be installed, calibrated, maintained and operated or a division approved sampling 

plan shall be developed and implemented for determining the amount of sulfur in the fuel 

in order to calculate sulfur oxide emissions on any fossil fuel fired steam generator of a 

total rated capacity of or greater than 250 million BTU per hour heat input. 

IV.B.3.	 If an owner or operator is required to install a continuous monitoring system for sulfur 

oxides, a continuous monitoring system for measuring either oxygen or carbon dioxide is 

also required. 

IV.C.	 Sulfuric Acid Plant 

IV.C 1. The owner or operator of each sulfuric acid plant of or greater than 300 tons per day 

production capacity (the production capacity being expressed as 100 percent acid) shall 

install, calibrate, maintain and operate a continuous emission monitoring system for the 

measurement of sulfur dioxide for each sulfuric acid producing unit within such plant. 

IV.D.	 Fluid Bed Catalytic Cracking Unit at Petroleum Refineries 

IV.D.1.	 The owner or operator of each catalyst regenerator for fluid bed catalytic cracking units of 

or greater than 20,000 barrels per day fresh feed capacity shall install, calibrate. maintain 

and operate a continuous emission monitoring system for the measurement of opacity. 

IV.D.2. The owner or operator of each fluid bed catalytic cracking unit of 5,000 barrels per day or 

greater fresh feed capacity, located in a carbon monoxide (CO) non-attainment area shall 

install, calibrate, maintain, and operate a continuous emission monitoring system for the 

measurement of carbon monoxide. 

IV.D.3.	 Exemptions: 

IVD.3.a. The owner or operator of a fluid bed catalytic cracking unit described in 

IVD.2. may apply to the division for an exemption from continuous emission 

monitoring requirements listed in subsection IV.D.2. In order for an exemption to 

be granted, the following requirements must be met: 

IV.D.3.a.(i). The owner or operator of a source must conduct a flue gas 

emission test for carbon monoxide concentration. The test protocol must 

be approved at least 30 days in advance by the division and emissions 

during the test must not exceed 250 ppm by volume on a one hour 

average; and 

IVD.3.a.(ii). Source owners or operators must establish a consistent 

relationship between carbon monoxide flue gas concentration and 

indicator parameter(s) such as flue gas oxygen content, or flue gas 

temperature, through a division approved test program; and 

IVD.3.a.(iii). Source owners or operators must maintain records of CO 

indicator parameter(s), as described above, for a period of at least two 

years which shall be made available for division review upon request. 
IV.E.	 Performance Specifications 

The performance specifications used to determine the acceptability of monitoring equipment 

installed pursuant to Section IVD.2. shall conform to those referenced in Appendix B of Part 60, 

Title 40, Code of Federal Regulations, or other specifications approved by the division. 

IV.F.	 Calibration of Equipment 

Owners or operators of all continuous monitoring systems subject to Section IV. of this regulation 

shall check the zero and span drift of the system at least once per day and at such other times as 

designated by the division, according to procedures approved by the division. The division may 

also make such determinations in order to assure proper quality assurance. 

IV.G.	 Notification and Recordkeeping 

The owner or operator of a facility required to install, maintain, and calibrate continuous 

monitoring equipment shall submit to the division within 30 days following the end of each 

calendar quarter, a report of excess emissions for all pollutants monitored for that quarter. This 

report shall consist of the following information and/or other reporting requirements as specified 

by the division. 

IV.G.1. The magnitude of excess emissions computed in accordance with division guidelines, 

any conversion factor(s) used, and the date and time of commencement and completion 

of each time period of excess emissions. 

IV.G.2. The nature and cause of the excess emissions, if known. 

IV.G.3. The date and time identifying each period of equipment malfunction and the nature of the 

system repairs or adjustments, if any, made to correct the malfunction. 

IV.GA. A schedule of the calibration and maintenance of the continuous monitoring system. 

IV.G.5. Compliance with the reporting requirements of this Section IV.G. shall not relieve the 

owner or operator of the reporting requirements of Section II.E. of the Common 

Provisions Regulation concerning upset conditions and breakdowns. 

IV.H.	 A file of all data collected relating to the preceding two- year period shall be maintained by the 

owner or operator of an affected source. The format in which the required information is 

submitted shall be determined by the division. 

IV.1.	 The owner or operator of a facility utilizing fuel sampling as an alternative to continuous emission 

monitoring shall report fuel analysis data as specified in the sampling plan to the division within 

30 days following the end of each calendar half in a format prescribed by the division. The 

purpose of such report shall be to disclose emissions that would exceed S02 emission standards. 

V.	 EMISSION STANDARDS FOR EXISTING IRON AND STEEL PLANT OPERATIONS 

VA	 Electric Arc Furnaces 

VA1.	 Visible emissions from the gas-cleaning device or from uncaptured emissions escaping 

the Electric Arc Furnace shop, shall not exceed twenty percent (20%) opacity at any time. 

The approved reference test method for visible emissions measurement on which these 

standards are based is EPA Method 9 (40 CFR, Part 60, Appendix A (July, 1992)). 
V.A.2.	 Emissions from the gas-cleaning device shall not exceed a mass emission rate of 

0.00520 gr/dscf of filterable particulates maximum two-hour average, as measured by 

EPA Methods 1-4 and the front half of Method 5 (40 CFR 60.275, and Appendix A, Part 

60), or by other credible method approved by the division. This particulate emissions 

standard does not include condensable emissions, or the back-half emissions of Method 

5. 

V.B.	 Sources of particulate emissions at iron and steel plants not subject to specific emission 

limitations set forth in Section V shall comply with applicable emission limitations set forth 

elsewhere in this regulation. 

V.B.1.	 Smoke Emissions and Opacity Requirements 

[Cross-reference: Section II, subsections A.1., A.2 and A.6.i and A.6.iii] 

V.B.2.	 Particulate Emission Requirements 

[Cross-reference: Section III, subsection A.1, A.2, C.1 and C.3] 

V.C.	 A statement of the basis and purpose for the revisions to this Section adopted March 11, 1982 is 

hereby incorporated by reference, and a copy of the statement is available from the Air Quality 

Control commission office. 

VI.	 SULFUR DIOXIDE EMISSION REGULATIONS 

VIA	 Sources constructed or modified prior to August 11, 1977 shall be considered an existing source. 

All existing sources of sulfur dioxide emissions, except for sources listed in Section VII, shall 

comply with the following: 

VIA1.	 Averaging time - Unless otherwise specified in other sections of this regulation, the 

averaging time for all sulfur dioxide emissions standards shall be a three-hour rolling 

average. 

VI.A.2.	 If the sum of sulfur dioxide emission rates for all sources located on a contiguous site is 

less than three tons per day potential uncontrolled S02 emissions, and if all federal and 

state ambient air quality standards are met no process based S02 emission standard 

shall apply. 

VI.A.3.	 Existing sources of sulfur dioxide shall not emit sulfur dioxide in excess of the following 

process-specific limitations. (Heat input rates shall be the manufacturer's guaranteed 

maximum heat input rates). 

VI.A.3.a. Coal-fired operations including coal-fired steam generation: 

(These standards are also applicable to the use of coal-based by-product fuels.) 

VI.A.3.a.(i). Units with a heat input from coal or coal-based by-product fuels 

of less than 300 million BTU per hour: 

1.8 pounds of sulfur dioxide per million BTU of heat input. 

VI.A.3.a.(ii). Units with a heat input from coal or coal-based by-product fuels 

equal to or greater than 300 million BTU per hour: 

1.2 pounds of sulfur dioxide per million BTU of heat input. 
VI.A.3.b. Oil-fired Operations Including Oil-Fired Steam Generation 

VI.A.3.b.(i) Units with a heat input from oil of less than 300 million BTU per 

hour: 

1.5 pounds of sulfur dioxide per million BTU of heating input. 

VI.A.3.b.(ii). Units with a heat input from oil equal to or greater than 300 

million BTU per hour: 

0.8 pounds of sulfur dioxide per million BTU of heating input. 

VI.A.3.c. Combustion Turbines 

VI.A.3.c.(i). Combustion Turbines with a heat input of less than 300 million 

BTU per hour: 

1.2 pounds of sulfur dioxide per million BTU of heating input. 

VI.A.3.c.(ii) Combustion Turbines with a heat input equal to or greater than 

300 million BTU per hour: 

0.8 pounds of sulfur dioxide per million BTU of heating input. 

VI.A.3.d. Natural Gas Desulfurization 

Desulfurization Plants emitting more than five tons of sulfur dioxide per day: 

2 pounds of sulfur dioxide per 1,000 cubic feet of (actual) delivered gas. 

VI.A.3.e. Petroleum Refining 

0.7 pounds sulfur dioxide for the sum of all S02 emissions from a given Refinery, 

per barrel of oil processed, per day. This emission limit shall be calculated over 

each 24-hour period that commences at midnight. If the refinery does not operate 

for the entire 24-hour period, the actual hours of operation shall be used as the 

averaging time. At no time shall the averaging time be greater than 24 hours. 

Refineries in operation on or before August 1, 1995, which are covered by this 

regulation, shall submit a plan for division approval no later than February 1, 

1996. Sources constructed after August 1, 1995 shall submit a plan for division 

approval along with construction permit applications. The plan shall define how 

compliance with this limitation will be demonstrated. This plan shall address both 

how the S02 value is calculated, Le. mass balance, monitors, and how the 

barrels of oil processed value is derived, taking into account intermediate 

storage. The division shall not limit the determination of barrels processed per 

day to a 24-hour period. 

All data used to show compliance with this emission standard shall be 

maintained by the owner or operator of the affected source for a period of two 

years for sources that are not subject to the operating permit program, and five 

years for sources that are subject to the operating permit program. This data 

shall be available for inspection by the division upon request. 

VI.A.3.f.Cement Manufacture 
Seven pounds of sulfur dioxide per ton of material (including fuel) processed. 

This emission limit shall be calculated over each 24-hour period that commences 

at midnight. If the source does not operate for the entire 24-hour period, the 

actual hours of operation shall be used as the averaging time. At no time shall 

the averaging time be greater than 24 hours. 

All data used to show compliance with this emission standard shall be 

maintained by the owner or operator of the affected source for a period of two 

years for sources not subject to the operating permit program and five years for 

sources subject to the operating permit program. This data shall be available for 

inspection by the division upon request. 

VI.A.3.g. Sources Not Specifically Listed Above 

Application of all available practical methods of control, which are technologically 

feasible and economically reasonable. This is to be determined by the division. 

VI.AA.	 Recordkeeping and Reporting - All sources that have record keeping and reporting 

requirements shall comply with Sections IV.G. and IV.I of this regulation. 

VIA5.	 Data Retention - All sources that have recordkeeping and reporting requirements shall 

retain emission data for the preceding two-year period as referenced in Section IV.H. of 

this regulation or for a longer period if required under other applicable regulations. 

VI.B.	 All new sources of sulfur dioxide emissions shall comply with emission limitations as specifically 

provided by this subsection B. 

VI.B.1.	 For purposes of this Section VI.B. a new source is defined as a newly constructed or 

modified source of sulfur dioxide emissions that has not been issued an Emission Permit 

(in accord with Regulation NO.3 of this commission) prior to the August 11, 1977 

effective date of this amended regulation. 

VI.B.2.	 The averaging time for all new source emissions standards for sulfur dioxide shall be 

three hours. and any three-hour rolling average of emission rates which exceeds these 

standards is a violation of this regulation. 

VI.B.3.	 The term "modification" is as defined in the Common Provisions Regulation, Section I.G. 

except that any source of sulfur dioxide subject to an emission standard which measures 

the sum of all sulfur dioxide emissions from a given facility shall not be considered 

"modified" for the purposes of this regulation unless the alteration may cause an increase 

in the sum of all sulfur dioxide emissions from such facility. 

VI.BA.	 New sources of sulfur dioxide shall not emit or cause to be emitted sulfur dioxide in 

excess of the following process-specific limitations (Heat input rates shall be the 

manufacturer's guaranteed maximum heat input rates.) 

VI.BA.a. All Coal-Fired Operations, Including Coal-Fired Steam Generators 

VI.BA.a.(i). Units converted from other fuels to coal: 

1.2 Ibs. S02/million BTU of coal heat input. 

VI.BA.a.(ii). Units with a coal heat input of less than 250 million BTU per 

hour: 
1.2 Ibs. S02/million BTU coal heat input. 

VI.BA.a.(iii). Units with a coal heat input of 250 million BTU per hour or 

greater: 

OA Ibs. S02/million BTU coal heat input. 

VI.BA.b.	 All Oil-fired Operations, Including Oil-Fired Steam Generation. 

VI.B.4.b.(i). Units with an oil heat input of less than 250 million BTU per hour: 

0.8 pounds of sulfur dioxide per million BTU of oil heat input. 

VI.BA.b.(ii).	 Units with an oil heat input of 250 million BTU per hour or 

greater: 

0.3 Ibs. S02/million BTU of oil heat input. 

VI.B.4.c. Combustion Turbines 

VI.BA.c.(i).	 Combustion Turbines with a heat input of less than 250 million 

BTU per hour: 

0.8 pounds of sulfur dioxide per million BTU of heat input. 

VI.B.4.c.(ii).	 Combustion Turbines with heat input of 250 million BTU per hour 

or greater: 

0.35 Ibs. S02/million BTU of heat input. 

IV.BA.d. Natural Gas Desulfurization 

(As employed in this section, the term "delivered" means (a quantity of gas)
 

delivered to the transmission pipeline).
 

VI.B.4.d.(i). Desulfurization Plants emitting less than three tons per day of
 

S02: 

2.0 lbs. S02/1000 cubic feet of (actual) delivered natural gas. 

VI.B.4.d .(ii). Sources emitting three or more tons per day of S02: 

0.8 Ibs. S02/1000 cubic feet of (actual) delivered natural gas. 

VI.B.4.e. Petroleum Refining 

0.3 Ibs. sulfur dioxide, for the sum of all S02 emissions from a given refinery per 

barrel of oil processed. (Averaged over a daily 24-hour period, I.E. Midnight 

through 23:59.) 

VI.B.4.f. Production of Oil from Shale 

Production of oil from shale shall be subject to the emission limitations provided 

in Colorado Air Quality Control commission Regulation No.6, SUbpart B (Nonfederal New Source Performance Standards (NSPS), Section IV.C.3.) 
VI.B.4.g.	 Refining of Oil Produced from Shale 

VI.B.4.g.(i). Refineries processing less than 1,000 barrels per day: No 

process emission standard. 

VI.BA.g.(ii).	 Refineries processing 1,000 or more barrels per day: 

0.3 Ibs. sulfur dioxide, for the sum of all Sulfur dioxide emissions from a 

given refinery, per barrel of oil processed. 

VI.BA.h.	 Sulfuric Acid Production 

4.0 Ibs. sulfur dioxide/ton of acid produced and 0.15 Ibs. H2S04 mist/ton of acid 

produced. 

VI.B.5.	 Any new source of sulfur dioxide not specifically regulated above shall: 

VI.B.5.a.	 Limit emissions to not more than two (2) tons per day of sulfur dioxide, or 

VI.B.5.b.	 Utilize best available control technology as determined by the division 

subject to review by the commission. 

VI.B.6.	 Recordkeeping and Reporting - All sources that have recordkeeping and reporting 

requirements shall comply with Sections IV.G. and IV.I of this regulation. 

V.I.B.7. Data Retention - All sources that have recordkeeping and reporting requirements shall 

retain emission data for the preceding two-year period as referenced in Section IV.H. of 

this regulation or for a longer period if required under other applicable regulations. 

V.1.B.8.A written statement of the basis and purpose of this new source emission control 

regulation, which includes a detailed analytical evaluation of the scientific and technical 

rationale justifying this regulation has been prepared and adopted by the commission on 

August 11, 1977. This written statement entitled, "Rationale for the Promulgation of a 

New Source Emission Control Regulation and Ambient Air Quality Standards for Sulfur 

Dioxide", is hereby incorporated in this regulation by reference, in accord with C.R.S. 

1973,24-4-103 as amended. 

VI.C.	 Fuel Sampling 

The division must approve all fuel sampling plans. The appropriate ASTM test methods or other 

equivalent method approved by the division shall be used for all fuel sampling plans. 

VI.D.	 Performance Tests 

Prior to granting of a final approval permit or amending a permit, when an emission source or 

control equipment is altered, or at any time when there is reason to believe that emission 

standards are being violated, the division may require the owner or operator of any facility subject 

to the emission standards under Section VI to conduct performance tests, as measured by EPA 

Methods 1-4 Methods 6, 6a, 6b, 6c and Method 8 (40 CFR 60.275, Appendix A, Part 60), or any 

other method which the division finds appropriate to determine compliance with this subsection of 

this regulation. 

VI.D.1. The owner or operator of an existing source of sulfur dioxide shall, upon request of the 

division, conduct performance test(s) and furnish the division a written report of the 

results of such performance test(s) to determine compliance with this regulation. 
VI.D.2.	 Performance test(s) shall be conducted and data reduced and recorded in accordance 

with the test methods and procedures specified above unless the division: 

VID.2.a. Approves the use of an alternative method the results of which the 

division has determined to be adequate for indicating whether a specific source is in 

compliance, or 

VID.2.b.	 Waives the requirement for performance test(s) because the owner or operator of 

a source has demonstrated by other means to the division's satisfaction that the 

affected facility is in compliance with the standard. Nothing in this paragraph C. 

shall be construed to abrogate the commission's or division's authority to require 

testing under Article 7 of Title 25, Colorado Revised Statute 1973, and 

regulations of the commission promulgated there under. 

VID.3.	 The owner or operator of an affected facility shall provide the division thirty days prior 

notice of the performance test to afford the division the opportunity to have an observer 

present. 

VI.E.	 Related Compounds Containing Sulfur in Oxidized States: 

VI.E.1.	 For the purposes of this regulation, all oxidized forms of sulfur (including, but not 

restricted to sulfur trioxide (S03), trionyl chloride (SOCI 2 ), and sulfuric acid mist (H2S04 )) 

shall be considered as sulfur dioxide. 

VI.E.2.	 Quantities of such oxidized sulfur compounds shall be converted on a molar basis to an 

equivalent quantity of sulfur dioxide. The total of all such quantities, (expressed in parts 

per million by volume sulfur-dioxide-equivalents of other oxidized forms) shall be 

interpreted as "parts per million by volume sulfur dioxide" as used in Section B. above. 

VI.F.	 Alternative Compliance Procedures 

VI.F.1.	 Any person may apply to the division Director for approval of an alternative: 

VI.F.1.a.	 Test method, 

VI.F.1.b.	 Method of control, 

VI.F.1.c.	 Compliance period, 

VI.F.1.d.	 Emission limit, or 

VI.F.1.e.	 Monitoring schedule. 

VI.F.2. The application shall include a demonstration that the proposed alternative produces: 

VI.F.1.a.	 An equal or greater air quality benefit than that required in this 

subsection VI, or 

VI.F.2.b.	 The alternative test method is equivalent to that required by these 

regulations. 

VI.F.3.	 The division Director shall obtain concurrence from EPA prior to approving an alternative. 

VII.	 EMISSION REGULATIONS FOR CERTAIN ELECTRIC GENERATING STATIONS OWNED 

AND OPERATED BY THE PUBLIC SERVICE COMPANY OF COLORADO 
VI/A	 The electric generating stations owned and operated by the Public Service Company of Colorado 

listed below shall not emit or cause to be emitted nitrogen oxides (NOx) or sulfur dioxide (S02) in 

excess of the following limits. The emission rates for NOx and S02 are measured in terms of 

pounds of pollutant per million British Thermal Units of fuel fired in the unit (lb/mmBTU). 

VIIA1. Cherokee Electric Generating Station, 6198 North Franklin Street, Denver, CO 

VI/A1.a. NOx and S02limits: 

NOx (lb/mmBTU) S02 (lb/mmBTU) 

Unit 1 - 1.1 

Unit 2 - 1.1 

Unit 3 0.60 1.1 

Unit 4 0.45 1.1 

The NOx limit will be calculated based on a 30-day rolling average, and is 

effective November 1,1994. 

The S02 limit will be calculated as a three-hour rolling average, and is effective 

November 1, 1994. 

Public Service Company of Colorado shall install, certify and operate continuous 

emission monitoring equipment in accordance with 40 CFR Part 60.13, for 

measuring opacity, S02, NOx, and either O2 or CO2on Units 1, 2, 3 and 4. 

VI/Ab. Effective January 1,2005, the NOx limit for Unit 1 shall be 0.60 Ib/mm BTU, 

provided EPA approves the designation of the Denver area as a PM-10 

attainmenUmaintenance area. Such limit shall be calculated based on a 30-day 

rolling average. 

VII.A.c. Upon EPA approval of the designation of the Denver area as a PM-10 

attainmenUmaintenance area, the S02 emission rate from units 1 and 4 shall not 

exceed 0.88 Ib/mm BTU, calculated separately for each unit, based on a 30-day 

rolling average. Such emission limit shall apply seasonally from November 1 

through March 1. The additional S02 limit set out in this subsection VIIA1.c. 

shall not apply unless EPA repeals the incorporation of S02 permit limits into the 

SIP at 40 CFR 52.320(c)(82)(i)(E). 

VII.A.2. Arapahoe Electric Generating Station, 2601 South Platte River Drive, Denver, CO 

VI/A2.a. Nox and S02 limits: 

NOx (lb/mmBTU) S02 (lb/mmBTU) 
NOx (lb/mmBTU) S02 (lb/mmBTU) 

Unit 1 - 1.1 

Unit 2 - 1.1 

Unit 3 - 1.1 

Unit 4 0.60 1.1 +20% annual tonnage 

reduction 

The NOx limit will be calculated based on a 30-day rolling average, and is 

effective November 1, 1994. 

The S02 limit will be calculated as a three-hour rolling average, and is 

effective January 1, 1995. 

The 20% S02limit from Unit 4 shall be calculated on a calendar year, 

total annual tonnage basis. - Public Service Company of Colorado shall 

install, certify and operate continuous emission monitoring equipment in 

accordance with 40 CFR Part 60.13, for measuring opacity, S02, NOx, 

and either O2or CO2on Units 1, 2, 3 and 4. 

VII.A.2.b.	 Upon EPA approval of the designation of the Denver area as a PM-10 

attainment/maintenance area, the S02 emission rate from unit 4 shall not 

exceed 0.88 Ib/mm BTU, calculated on a 30-day rolling average. Such 

emission limit shall apply seasonally from November 1 through March 1. 

VII.A.2.c.	 Retirement of units 1 and 2 

VII.A.2.c.(i).	 Units 1 and 2 shall be permanently retired by January 1, 2003. 

This section VII.A.2.c. shall become effective upon EPA approval 

of the designation of the Denver area as a PM-10 

attainment/maintenance area. 

VII.A.2.(ii).	 This section VII.A.2.c shall not be construed to prevent the 

construction or operation of a new source on the site of such 

units, provided any such new source complies with all laws and 

regulations applicable to new sources. 

VII.A.3. Valmont Electric Generating Station, 1800 North 63rd Street, Boulder, CO 

NOx (lb/mmBTU) S02 (lb/mmBTU) 

Unit 5 0.45 1.1 

The NOx limit will be calculated based on a 30-day rolling average, and is 

effective November 1, 1994. 

The S02 limit will be calculated as a three-hour rolling average, and is effective 

November 1, 1994. 
Public Service Company of Colorado shall install, certify and operate continuous 

emission monitoring equipment in accordance with 40 CFR Part 60.13, for 

measuring opacity, S02, NOx, and either O2or CO2on Unit 5. 

VIII. RESTRICTIONS ON THE USE OF OIL AS A BACKUP FUEL 

VillA Applicability 

The provisions of this section are applicable to all points at the following stationary sources in the 

Denver PM 10 Attainment/Maintenance area that use oil as a backup fuel for natural gas, which is 

the primary process fuel: 

VIII.A.1. Public Service Company of Colorado, Zuni Electric Generating Station; 

VIII.A.2.Public Service Company of Colorado, Valmont Electric Generating Station; 

VIII.A.3. Public Service Company of Colorado, Delgany Steam Generating Station; 

VIII.A.4. University of Colorado Health Science Center (Fitzsimmons); and 

VIIIA5.Trigen-Colorado Energy, Golden, CO. 

VIILB. Requirements 

Beginning November 1, 1993, natural gas shall be the only fuel used from November 1 to March 1 of 

each year, except under the following circumstances: 

VIII. B.1.The supplier or transporter of natural gas imposes a curtailment or an interruption of 

service; 

VIII.B.2.For necessary testing of equipment used to operate the unit on oil, testing of fuel and 

training of personnel; or 

VIII.B.3.When an equipment malfunction at the facility makes it impossible or unsafe for the unit 

to operate on natural gas. 

VIILC. Recordkeeping 

Each stationary source subject to these provisions shall maintain records for a period of two years, which 

include the following information: 

VIII.C.1.dates and number of hour's fuel oil are burned; 

VIII.C.2. percent sulfur analysis of the fuel oil that is burned; 

VIII.C.3. number of gallons burned each day; and 

VIII.CA. reason(s) for the use of the fuel oil. 

VIII.D. Reporting 

Beginning April 1, 1994 and by April 1 of each year thereafter, each stationary source subject to these 

provisions shall submit to the division a report containing the information listed in Section VIII.C. 

VilLE. Alternate Recordkeeping and Reporting 
Where the information required under subsections C and D above is otherwise made available to the 

division, for example in Air Pollution Emission Notice (APEN) reports submitted by the source or pursuant 

to operating permit requirements or analogous information is maintained by the source in a credible form 

approved by the division, the requirements of subsections C and D of this Section VIII are satisfied. 

IX.	 EMISSION REGULATIONS CONCERNING AREAS WHICH ARE NONATTAINMENT OR 

ATTAINMENT/MAINTENANCE FOR CARBON MONOXIDE - REFINERY FLUID BED 

CATALYTIC CRACKING UNITS: 

No later than nine months after the effective date of this revision (January 30, 1987) no source which has 

emitted 1,000 or more tons of carbon monoxide during any 12 month period, nor any source which can 

reasonably be expected to emit 1,000 or more tons of carbon monoxide during any future 12-month 

period, shall emit any gas in which carbon monoxide constitutes 0.050% (500 ppm) or more of the volume 

of the gas, based on a one hour average. 

X.	 STATEMENTS OF BASIS AND PURPOSE 

Sections I through IV and minor revisions to Section VI (Adopted April 8, 1982) 

Regulation NO.1 sets forth emission limitations, equipment requirements, and work practices (abatement 

and control measures) intended to control the emissions of particulates, smokes and sulfur oxides from 

new and existing stationary sources. Control measures specified in this regulation are designed to limit 

emissions into the atmosphere and thereby minimize the ambient concentrations of particulates and 

sulfur oxides. 

The regulation is primarily aimed at control of particulates of 1O-micron size and smaller (i.e. "inhalable" 

particles). However, in recognition of the fact that larger particles - especially which may settle on roads, 

be ground into smaller sizes and later reintroduced into the atmosphere - larger size particles have also 

been controlled where control seemed appropriate. 

Section 11.A.1 - Smoke and Opacity. 

The previous opacity regulations have made any exceedence of 20% opacity a violation. To conform to 

the method of opacity measurement used by the U.S. Environmental Protection Agency, the commission 

has switched to the 6-minute averaging method of measuring opacity contained in EPA Method 9 (40 

CFR, Part 60, Appendix A (July, 1992)). The testimony presented by division representatives indicated 

investigators in the field have in effect been averaging opacity. The commission encourages the division 

to continue its practice of allowing non-agency personnel to attend smoke school and receive certification. 

Section 1l.A.2 - Intermittent Sources. 

The switch in methods of measuring opacity (see comments on Section 1I.A.1 above) made it necessary 

to devise a modified method to measure opacity from those sources, which do not operate continuously 

for at least six minutes. EPA Method 9 (40 CFR, Part 60, Appendix A (July, 1992)) was amended to 

accommodate this situation. 

Section ll.A.3 - Pilot Plants and Experimental Operations. 

The previous regulation excerpted pilot plants and experimental operations from its 20% opacity standard 

to the extent of allowing emissions of up to 40% opacity for no more than 3 minutes in any 60-minute 

period (see previous Section 11.A.2.b.). Because of the switch in methods of measuring opacity (i.e., now 

averaging for six minutes) this exception has been changed to now allow up to 30% opacity (as measured 

by EPA Method 9 (40 CFR, Part 60, Appendix A (July, 1992)) for no more than 6 minutes in any 60­

minute period. This revised exception represents an equivalent relaxation. This relaxed opacity limitation 

applied only for 180 operating days, after which the 20% opacity limitation of Sections 11.A.1 and 2 again 
applied. The regulation, however, provides that the division may extend the maximum 180 -day period on 

good cause shown. For clarification, the phase "operating day" has now been defined and the exception 

made applicable to "process units" of a pilot plant or experimental operation to more accurately reflect the 

commission's intent. 

Section IIA4 - Fire Building, Cleaning of Fire Boxes, Soot Blowing, Start-Up, Process Malfunction or 

Adjustments of Control Equipment. 

On the same rationale that the limited exception for pilot plants was amended (see comments on IIA3. 

above), the limited exceptions for these sources has also been changed from up to three minutes in a 60­

minute period at no more than 40% opacity to up to six minutes at 30% opacity (averaged). 

Section IIA5 - Smokeless Flares. 

Smokeless flares were not previously exempted in any way from the 20% opacity standard. The 

commission has now allowed a limited exception of up to six minutes in a 60-minute period at 30% 

opacity (averaged) to reduce the burden of upset reporting on operations of smokeless flares. 

Section 11.A.6. - Alfalfa Dehydrating Plants. 

This section remains the same as the previous Regulation NO.1 and requires compliance with 20% 

opacity by January 1, 1985. 

Section IIA7 - Wigwam Burners. 

House Bill 1366 (1977) added Section 25-7-108(3)(e) to the Air Pollution Control Act of 1970. It provided: 

"that the provisions of any commission Regulation concerning Wigwam Burners shall not apply prior to 

July 1, 1982, to any such burner located within seventy-five air miles of the border of any state bordering 

on Colorado if the regulations concerning wigwam wood waste burners of the bordering state are less 

stringent that those of the commission. Said exemption shall not apply to wigwam wood waste burners 

located within a twenty mile radius of any city, town, or municipality having a population of fifty thousand 

persons as determined by the 1970 Federal Census." House Bill 1109 (1979) repealed the Air Pollution 

Control Act of 1970 including Section 25-7-108(3)(e). The Colorado Air Quality Control Act established by 

House Bill 1109 did not contain the above quoted exemption in the new Section 25-7-1 09(3)(e) which 

gave the authority to adopt emission regulations for Wigwam wood waste burners to the commission. The 

commission has therefore promulgated emission standards for new and existing wigwam burners in this 

Regulation NO.1. New wigwam burners are subject to 20% opacity at all times. Effective January 1, 1983, 

existing wigwam burners are subject to a 40% opacity ceiling (i.e., no emissions in excess of 40% are 

allowed) except for 1 hour of start-up (ignition of a new fire after a period of non-operation). Additionally, 

existing wigwam burners must submit a plan to control their emission by the same date. As was provided 

for in HB 1090 and HB 1109 (1979), the regulation recognizes exemption from state regulation for certain 

wigwam wood waste burners subject to county regulation. 

Section IIA8. - Exemptions. 

As with the previous regulation, certain sources have been exempted from the opacity limitations in 

Sections 11.A.1. and 11.A.2. In some instances the exemptions are based on a determination that control of 

opacity is not economically reasonable or technically feasible (e.g., "fugitive dust" and noncommercial 

fireplaces burning clean wood); in others because the sources are subject to more appropriate emission 

limitations elsewhere in the regulation (e.g., iron and steel plants and "fugitive particulate emissions") the 

commission realizes that woodburning in fireplaces, fireplace inserts and stoves may cause severe air 

pollution problems and has appointed a committee to evaluate the problems and plans, if necessary, to 

recommend changes to the regulation regarding smoke sources when adequate data is developed. 

Definitions of "Fugitive Dust" and "Fugitive Particulate Emissions." 
In connection with its decisions on exemptions from Section 11.A.1. and 11.A.2. and for the purposes of 

Regulation NO.1 only, the commission has developed new definitions for "fugitive dust" (which is not 

subject to regulation) and "fugitive particulate emissions" (subject to the provisions of Section 111.0.) to 

help distinguish between fugitive particulate pollution subjected to and exempted from regulation. 

Section 11.8. - Diesel Powered Locomotives. 

This section has provisions for Diesel Powered Locomotives only and they are the same as the previous 

Regulation NO.1. Provisions for other motor vehicles have been deleted primarily because of the 

amendment of C.RS. 1973, Section 18-13-110 in 1979. The previous restrictions on emissions from offhighway heavy duty diesel-powered vehicles was not carried forward to the current regulation because it 

was felt no significant reduction in emissions could be achieved in light of the exemption for such vehicles 

for nonconsecutive periods of 15 seconds (see former Section I.B.3.c-2). 

Section II.C. - Open Burning. 

This section was reorganized by the commission and contains few substantive changes. The exemption 

for burning in municipalities with less than 3,500 population has been replaced with an exemption created 

by HB1090 (1979) for the unincorporated areas of counties with less than 25,000 population where the 

Board of County commissioners has adopted regulations to control open burning. As was provided for in 

HB 1090 (1978), the regulation recognizes a limited exemption from state regulation for certain burning 

subject to county regulation. 

Section IliA - Fuel Burning Equipment. 

This section has been reorganized and contains the same provisions as the previous Regulation NO.1 

except that the periormance test method has been changed from the American Society of Mechanical 

Engineer's Power Test Codes-PTC-27 dated 1957 entitled "Determining Dust Concentrations in A Gas 

Stream" to EPA Methods 1-4 and the front half of EPA Method 5 (40 C.F.R 60.275, Appendix A. part 60). 

The change in test methods was made because of division testimony that the latter method is the more 

widely used and recognized test procedure. Sources subject to Section V (iron and steel plants) of this 

RegUlation NO.1 are exempt from this section. 

Section III.B. -Incinerators. 

This section was changed only with respect to the periormance test method. The new methods to be 

used are EPA Methods 1-4 and the front half of EPA Method 5 (C.F.R 60.275, Appendix A, Part 60). The 

change in test methods was made because of division testimony that the latter method is the more widely 

used and recognized test procedure. 

Section III.C. - Manufacturing Processes. 

This section is a reorganization of the previous Regulation NO.1 and also contains provisions for existing 

alfalfa dehydration plants (also found in Air Quality Control commission Regulation No.5). Specific 

exemptions for Section V and for fugitive particulate emissions have been included in this section. 

Section 111.0.1 - (Fugitive Particulate Emissions) General Requirements. 

In its 1981 opinion in CF&I Steel Corporation v. Colorado Air Pollution Control commission (Case No. 77­

804), the Colorado Court of Appeals expressed reservations about appropriateness of applying an 

opacity test to non-point sources, stating it saw "a significant number or problems" attributable to the fact 

the test was developed for application to stack or point sources. Although the court's reservations were 

expressed in dicta and the commission has found that the opacity test can be applied to area sources 

(and the State Supreme Court has agreed to review the Court of Appeals decision), the commission 

nonetheless realizes that opacity readings may be made on point sources more readily than on certain 
"area sources" Accordingly, the new regulation has shifted the use of opacity (and off property transport) 

observations from an enforceable standard for area sources to a guideline in determining when the 

adequacy of applied control methods should be reviewed. The "general requirements" provisions of 

Section 111.0. explain when control plans (or revisions to existing control plans) must be submitted and set 

forth the criteria for approvability of such plans. Under this new approach, enforcement action under 

C.R.S. 1973,25-7-115 will be taken only when an owner or operator (a) fails to comply with the approved 

emission control plan for its source, (b) the source fails to submit a plan within the time prescribed for 

submittal, or (c) continues to operate after a control plan (or portion thereof) has been disapproved. A 

source will not, however, be deemed in violation if operation of such source is discontinued so as to 

permanently eliminate the cause of fugitive particulate emissions there from. Pursuant to C.R.S. 1973, 

25-7-114(f) and 25-7-115(5), if a new source is denied a permit for failure to provide an adequate control 

plan or an existing source cited for operation in violation of the regulation, the owner/operator is afforded 

the opportunity to contest the division's action before the Air Quality Hearings Board. 

The lists of control and abatement measures contained in the regulation represent measures that are 

generally considered to be available, practical, economically reasonable and technically feasible. This 

determination is based on several factors, including the division's observation that the same measures 

contained in the previous version of the regUlation generally were both effective in controlling emissions 

of particulates and sulfur oxides and affordable. With few exceptions, (e.g., road carpeting), no new 

measures have been added to the list of suggested control and abatement measures beyond those which 

were listed in Section 2.0.9. of the previous Regulation NO.1. 

To the extent cost data could be obtained from affected sources1

, or by the commission, or its staff, a 

cost-benefit analysis was done for controls of fugitive particulate emissions on the basis of dollar cost of 

control per ton of emissions reduced. The commission also considered, but did not quantify in dollars, 

other benefits to public health and welfare from controlling fugitive particulates such as aesthetics (e.g., 

elimination of visible plumes which obstruct views), elimination of "nuisance" conditions which frequently 

result in citizen complaints (e.g., dust from feedlots, construction activities and roadways), and possible 

adverse effects on certain industries - such as ski and tourist industries which benefit from clean air. The 

regulation requires employment of "~ available practical methods that are technologically feasible and 

economically reasonable." This requirement does not necessarily mean a source must employ all control 

measures and practices listed. For example, it obviously would not be economically reasonable to employ 

paving, road carpeting, dust suppressants and watering to control fugitive particulate emissions from 

unpaved roadways. Although the commission has determined that the control and abatement measures 

listed in the regulation are generally economically reasonable for the types of sources to which they 

apply, it is recognized that in particular instances some of the listed measures are ineffective, redundant 

or otherwise inappropriate. On the other hand, there may be control measures or practices not listed in 

the regulation for a type of source which are available, practical, technologically feasible and 

By Order of August 7,1981, the commission ordered its staff and the parties to the rulemaking 

proceeding to conduct an "informal discovery process" for the purpose, among others, of securing 

information on the cost to owners and operators of fugitive particulate emission sources of implementing 

the various control and abatement measures specified in the regulation. Discovery was to proceed in two 

phases of written inquiries and responses. The results of the process were disappointing. Some of the 

parties fully cooperated and submitted requested cost data including adequate information to substantiate 

the claimed costs. Despite receipt of written inquiries from commission staff, requests made to parties 

during the hearings for additional information, and the commission's follow-up letters to parties (dated 

November 6 and December 10, 1981) again requesting submittal of requested data; several parties failed 

to respond, others submitted unsubstantiated cost data, and others only partially responded. The 

commission therefore, proceeded on the assumption that control and abatement measures that have 

been successfully employed in the past, continue to represent available, practical, economically 

reasonable and technologically feasible methods of control unless substantive evidence to the contrary 

was received. 

The regulation therefore requires submission and evaluation of emission control plans on a source-bysource basis to allow the division to evaluate the plan for each source in light of its particular 
circumstances. At such time, the owner or operator and the division may determine that some of the listed 

measures are not appropriate as applied to a particular source or that others not listed are. This approach 

of a separate control plan for each source allows maximum flexibility in developing an enforceable control 

plan which represents an appropriate approach to control - in some instances more, in other instances 

less stringent than the listed controls. As control technology advances and other relevant circumstances 

change, it is expected that control methods meeting the requirements of Section 111.0. will also change 

and that control plans previously approvable may have to be amended. 

Sections III.D.1.c. and d. (Amended October 28, 1982) 

Regulation No.1, sections IIlD.1.c. and d. were amended in response to the Attorney General's rule 

opinion of April 19, 1982 (disapproving, in part, section 111.0. of Regulation NO.1 as adopted on April 8, 

1982) and the objections of the Air Pollution Control division of the Colorado Department of Health that 

the regulation did not allow it to require fugitive particulate emission control plans in all appropriate 

situations. 

Evidence presented by the division at the hearing demonstrated that in many instances the emission 

limitation guidelines ("triggers") could be met by use of emission controls significantly less stringent than 

"all available practical methods of control that are technologically feasible and economically reasonable" 

(hereafter "all practical controls"). The attorney general's primary concern was that virtually identical 

sources could therefore be subjected to these differing "standards" - i.e., one required to apply "all 

practical controls"; the other only having to avoid exceeding a less stringent trigger with the division being 

unable to require a control plan. 

The division also testified that, in some instances, the 20% opacity and no-off-property-transport 

guidelines would be inadequate because use of those triggers to require submission of a control plan 

required an observation be made at the time the particulates were being emitted and also that the 

observations be made under specific circumstances. The division would therefore be unable to require a 

control plan, even though one may be appropriate, if an inspector did not actually observe the 

exceedence of the guideline or if all requirements for making the observation were not present (e.g., the 

winds exceeded 30 mph). 

First of all the regUlation does not necessarily require that a division inspector personally observes 

emissions exceeding one of the triggers. The division may require a control plan prOVided there is 

adequate, reliable evidence that a trigger has been exceeded. 

The revisions to the regulation further address the problems the division has raised. The nuisance trigger 

(which was preViously applicable only to unpaved roads and haul roads) has been made applicable to all 

regulated sources. This will allow the division to require a control plan from a source creating a nuisance 

even when an inspector is unable to use the 20% opacity or no off-property transport guideline (e.g., 

because of high winds). 

The language adopted is literally less comprehensive than that proposed in the rulemaking notice. The 

revised regulation, however, (a) at a minimum addresses those sources of fugitive particulate emissions 

where the need for specific control plans is clearest and (b) provides more concrete (less vague) 

guidance to persons subject to the regulation of what level of control is required absent a specific control 

plan. The commission expects that this will facilitate voluntary compliance by sources without plans. 

Although theoretically situations could still arise whereby similar sources are subjected to different 

standards, it is the determination of the commission that in practice, as revised, the regulation with its now 

broader nuisance trigger will subject virtually all significant sources of fugitive particulate emissions to the 

requirement of applying "all practical controls". In the event the regulation fails to achieve this intended 

objective, the regUlation will be viewed as a "first step" towards its achievement and further revisions will 

be made. 
Nothing in the regulation is intended as, nor should it be construed as, prohibiting the division from 

conducting inspections as required by C.R.S. 1973, 25-7-115 - whether on an annual or other periodic 

basis, in response to complaints, or otherwise. 

Section 1I1.0.2.a. - Roadways. 

This section provides a list of appropriate control measures for controlling dust from unpaved roadways. 

The commission initially had to determine which unpaved roadways warranted control based on the 

amount of fugitive particulate emissions resulting from their use. The amount of 25 tons per year (TPY) 

per mile was chosen as an appropriate figure based on the fact that 25 TPY is the figure in commission 

Regulation No.3 deemed "significant" for the purpose of triggering the special non-attainment area permit 

requirements (eg., offsets, LAER) for major modifications. Regulation No.3, Section IV.0.2.b.(v). 

(Emissions of 25 TPY or more is also one of the triggering factors that would require a new emission 

permit application be subjected to public comment. Regulation No.3, Section IV.C.1.) Using 25 TPY (per 

mile) as the point at which an unpaved road should be required to control emissions, it was calculated 

using representative figures for the other factors that unpaved roads with traffic counts of 150 vehicles in 

non-attainment areas and 200 vehicles in attainment areas would cause emissions requiring control. 

The commission included the traffic count of 150 vehicles per day (averaged over any consecutive 3-day 

period) for unpaved roadways in non-attainment areas as a result of the calculated emissions from an 

average weight passenger car (2800 Ibs.), traveling at a speed of 30 miles per hour, over a one mile 

stretch of unpaved road and with the assumption of 30% of those emissions remaining suspended. Using 

the following equations: 

EF= 5.9 (.§) (~) (Q) 

12 30 3 365 

EMISSIONS = .3(EF)x(Y) x 365 days/yr = 25 tons/yr. 

2000lbs./ton 

S =silt content 

v =vehicle speed 

W =weight of vehicle 

d =dry days per year 

EF =emission factor expressed in terms of Ibs. per vehicle miles traveled 

Y =Vehicle miles traveled per day 

The higher traffic count in attainment areas can be accounted for by examining the difference in the factor 

"number of dry days per year" between attainment and non-attainment areas (215 and 285 respectively). 

(Because the non-attainment areas are basically all east of the mountains "dry day" figures for Colorado 

eastern plains were used for non-attainment areas; and north-central mountain figures were used for 

attainment areas.) 
In response to the Colorado Court of Appeals' decision in CF&I Steel Corporation vs. AQCC (cited 

above), the regulation no longer has separate sections concerning publicly owned and privately owned 

unpaved roadways. The provisions for control of emissions from unpaved roadways apply to all unpaved 

roadways and reference to ownership has been eliminated. 

There was discussion at the rulemaking hearing about whether dust emissions from unpaved roadways 

were inhalable and therefore presented a hazard to public health. It is the commission's conclusion that 

65% of the emissions [expressed as a percentage of suspended particulate (i.e. less than 30 microns)] 

from unpaved roadways are less than 10 microns in size and less (improved emission factors for fugitive 

dust from western surface coal mining sources Vol. II) and that they therefore do warrant control for the 

protection of public health. 

Various persons, including local governments and the Colorado General Assembly, expressed concern 

about the cost of controlling emissions from unpaved roadways and urged that local officials are generally 

in a better position to determine and exercise appropriate control over roadways. Especially in light of the 

limited personnel resources of the division, the commission would therefore encourage the division to 

exercise its authority under C.R.S. 1973, Section 25-7-111 (2)(f) in designating local agencies willing and 

able to enforce the regulation as agents of the division in concurrently enforcing this regulation - and 

especially with respect to air pollution problems which can be evaluated by such local agencies. 

Neither the 20% opacity nor the no off-property transport emission limitations guidelines seemed 

appropriate for application to unpaved roadways. To focus the limited personnel resources on the more 

serious problems a "nuisance" emission limitation guideline has been employed. Investigations will be 

initiated in response to citizen's complaints of nuisances created by excess emissions from unpaved 

roadways. 

Section III.D.2.b. - Construction Activities. 

Large percentages (54% from dozers, 49% from scrapers, 48% from graders, 67% from exposed areas) 

of the fugitive particulate emissions from construction activities are inhalable (Improved Emission Factors 

for Fugitive Dust from Western Surface Coal Mining Sources, Vol. II) and therefore need controls. Thus 

the commission has established a list of potential control measures for this activity. The smallest size of 

disturbed acreage requiring control in non-attainment areas was reduced from 5 acres to 1 acre in size in 

order that those smaller sources - determined to be significant source of emissions in non-attainment 

areas because of the great amount of construction activities occurring on smaller sites - could be 

controlled. The 5 acres remains as the size cutoff in attainment areas. 

Section III D.2.c. - Storage and Handling of Materials. 

The commission established a list of potential control measures for this activity for inclusion in a 

requested control plan. The percentage of inhalable particulates from storage and handling activities is 

presented in Improved Emission Factors for Fugitive Dust from Western Coal Mining Sources. Vol. II 

(listed as 30% loading, 49% dozer, 61 % storage piles) are significant emissions and therefore the 

commission has concluded that such emissions should be controlled. 

Section III.D.2.d. - Mining Activities. 

A large percentage of fugitive particulate emissions from mining activities are inhalable. The information 

in Table 12-2 from Improved Emission Factors for Fugitive Dust from Western Coal Mining Sources. Vol. 

!!, shows inhalable particulates for several mining related activities in a range of 30% - 67%. The 

commission has concluded that these are significant emissions and should therefore be controlled. Thus 

the commission has established the list of potential control measures for this activity for inclusion in a 

control plan. Underground mining activities are exempt from the provisions of Section III.D.2.d. However, 

if emissions from underground mining activities are vented to the atmosphere, they are subject to the 

opacity provisions of Section II.A.1. 
Section III.D.2.e - Haul Roads. 

The commission determined that a substantial amount of fugitive particulate emissions come from haul 

roads. For example, the percentage of inhalable particulates created by haul trucks traveling on such 

roads is listed as 52% in a table from Improved Emission Factors for Fugitive Dust from Western Surface 

Coal Mining Sources Vol., II. The commission has concluded that these emissions are significant and 

should be controlled. Thus, the commission established the list of potential control measures for this 

activity. The commission included a traffic count of 40 haul vehicles or 200 total vehicles per day 

(averaged over any consecutive 3-day period) for haul roads as a result of the calculated emissions using 

the following formula: 

EF = SV 

60 365 4 

S =silt content (if unknown assume 15%) 

V =vehicle speed in mph (average) 

W =mean annual number of days with .01 inches or more rainfall 

N =number of wheels on vehicle 

Assumptions: 

40 mph (average speed) =V 

6 wheels on vehicles =N 

80 days (West Slope condition) =W 

EF = 15 x 40 365 -80 §= 11.71bNMT 

60 365 4 

Emissions = .3 (EF) x "Y" x 365 Days IYr 25 Tons/Year 

= 

2000 Ib Per Ton 

E= 25 x 2000 = 40 vehicle miles per 

day 

.3(11.7)(365) 
EF = Emission factor expressed
 

in terms of Ibs.
 

Per vehicle mile traveled 

"Y" = Vehicle miles traveled per
 

day
 

Recognizing that a haul road could have significant emissions even without hauling 40 haul vehicles per 

day because of other vehicular traffic, haul roads are subject to the regulation when their traffic count 

exceeds either 40 haul vehicles or 200 total vehicles per day (200 light weight vehicles representing 

emissions of 25 tons per year for unpaved roadways - see comments on Section 1II.o.2.a. above.) 

As with roadways and for the same reasons, a nuisance emission limitation gUideline has been adopted 

as an inspection "trigger" for "off-site" haul roads. The no off-property transport emission limitation 

guideline applies to "on-site" haul roads. 

Section III.D.2.f. - Haul Trucks. 

A list of alternative control measures has been established by the commission for this activity for inclusion 

in a requested control plan. There were no emission factors for determining the emissions from the load 

of a loaded haul truck. 

Section 1II.o.2.g. - Tailings Piles and Ponds. 

The commission established the list of abatement and control measures for this activity for inclusion in 

any requested control plan. "exposed areas" are listed in a table as being 67% inhalable particulates. This 

is found in Improved Emission Factors for Fugitive Dust from Western Surface Coal Mining Sources, Vol. 

11. The commission concluded that these emissions are significant and therefore should be controlled. 

Section III.D.2.h - Demolition Activities. 

A significant amount of this activity does occur in the non-attainment areas and necessitates control. The 

commission established the list of control measures for this activity for inclusion in a control plan 

submittal. Cross-reference is made to the requirements of Regulation NO.8 regarding asbestos materials. 

Section III.D.2.i - Blasting Activities. 

The commission provided a list of potential control measures for inclusion in any requested control plan. 

The percentage of inhalable particulates from blasting is listed as 44% in a table from Improved Emission 

Factors for Fugitive Dust from Western Surface Coal Mining Sources, Vol. II. The commission concluded 

that these emissions are significant and should therefore be controlled. 

Section III.D.2.j. - Sandblasting Operations. 

The commission established a list of potential control measures for inclusion in any requested control 

plan. 

Section III.D.2.k - Livestock Confinement Operations. 
· The commission established a list of potential control measures for inclusion in any requested control 

plan. These measures will provide an economic benefit to the operator of livestock confinement 

operations (i.e., there should be fewer incidents of dust pneumonia in livestock). 

Agriculture Activities: The commission determined that fugitive particulate emissions from agricultural 

activities (e.g., plowing, or dicing) cannot be controlled by methods that are economically reasonable and 

feasible - such as watering. The commission further determined that the great majority of emissions from 

agricultural activities were not from activities such as plowing, but from the action of the wind on exposed 

soil. The commission therefore reviewed the provisions of the Colorado Soil Erosion and Dust Blowing 

Act of 1954, C.R.S. 1973 Section 35-72-101, and determined that statute adequately addresses the 

problem of fugitive particulate emissions from agricultural activities. Agricultural activities are therefore not 

subject to the provisions of Section 111.0. Agricultural activities have been specifically exempted from the 

open burning requirements of Section II.C. The exemption is viewed as an economic necessity to 

commercial agricultural operations. 

Section IV. - Continuous Emission Monitoring Requirements for Existing Sources. 

The commission has included Continuous Emission Monitoring Requirements for four types of sources: 

Fossil Fuel-Fired Steam Generators; Sulfuric Acid Plants; Fluid Bed Catalyst Regenerators at Petroleum 

Refineries. However, CEM units for the measurement of NOx emissions from existing sources of NOx 

were considered unnecessary as there is no NOx standard for existing sources. As a substitute to CEM 

an approved coal-sampling program to determine the sulfur content of the coal being fired in the steam 

generators may be employed. With such data, S02 emissions can be calculated. Performance 

specifications, calibration requirements, notification and recordkeeping have been included for the 

evaluation of any such CEM system that is required by this section. This part meets and exceeds the 

requirements of 40 CFR, Part 51, Appendix P, Volume 40, No. 194 Fed. Reg. 46247 (October 6, 1975). 

The commission has determined that continuous emission monitoring for carbon monoxide (CO) is 

necessary for fluidized-bed catalytic cracking unit regenerators at petroleum refineries. Continuous 

Emission Monitoring will ensure the emission standard is being met at these sources that are the largest 

CO emitters in the state. (March 20, 1986) 

Section V. - (Adopted March 11, 1982) See below. 

Section VI. - Sulfur Dioxide Emission Regulations: 

The commission made no substantive changes to the provisions of the previous Regulation NO.1. 

The commission revised the regulation to make existing sources subject to meeting specific emission 

standards when their emissions exceed three tons per day of sulfur dioxide rather than the previous five 

tons per day. The new level is to ensure that major sources of sulfur dioxide in Colorado are well 

controlled such that ambient impacts and potential air quality related value impacts are reduced. (March 

20,1986) 

Section IX. Emission Regulations Concerning Areas that are Non-attainment for Carbon Monoxide. 

Carbon Monoxide Emission Regulation: The Denver Metro Area has a serious Carbon Monoxide Air 

Pollution Problem. Air quality monitoring conducted in 1980 indicated that the Denver Metro Area 

exceeded the standard by almost 58% (for the second worst case). Air quality modeling performed in 

support of the 1982 State Implementation Plan (SIP) shows that the predicted maximum concentration of 

CO in 1987 will still exceed the national Air Quality Standard by 25%. If Denver does not come into 

compliance by 1987 it faces possible economic sanctions or imposed measures, which will decrease 

carbon monoxide levels sufficiently so that the standard will be met. 
EPA reviewed Colorado's 1982 SIP submittal and expressed concern regarding the CO problem and the 

division's plans to deal with it. One strategy EPA has stated Colorado must employ is the requirement that 

all major stationary sources of CO (greater than 1,000 TPY) in non-attainment areas use "Reasonably 

Available Control Technology" (RACT) to reduce emissions. Though EPA has not specifically defined 

what RACT is for major CO sources, the commission herein defines RACT as any control device 

approved by the division that will reduce CO emissions to a level less than or equal to 0.050% of exhaust 

gases by volume. 

The only CO sources located in non-attainment areas of Colorado, which emit greater than 1,000 TPY 

are fluidized-bed catalytic cracking units (FCC) at Petroleum refineries. Uncontrolled emissions from 

these units can approach 10% (100,000 ppm). 

Control technology is readily available for use in FCC units. According to EPA publication AP-42, carbon 

monoxide boilers can reduce emissions to "negligible levels". Similarly, the use of combustion promoters 

can reduce CO emissions to less than 0.050%, according to the Encyclopedia of Chemical Technology. 

The requirement to apply RACT to carbon monoxide emission sources at refineries will reduce reported 

emissions, as used in the 1982 SIP Revision, from 125 tons per day to 11 tons per day, an improvement 

of about 91 %. This will result in a 4% reduction in the Denver Metro CO inventory, thus demonstrating 

further progress towards attainment of the National Ambient Air Quality Standards. (March 20, 1986) 

APPENDIX A Method of Measuring Opacity from Fugitive Particulate Emission Sources. 

Also in response to the referenced dicta in the Court of Appeal's CF&I decision, the commission has 

included a specified method for measuring opacity of fugitive particulate emissions from non-point 

sources. Although this may not be as precise as Method 9 (40 CFR. Part 60, Appendix A (July, 1992)) as 

applied to stacks since this is a guideline and not an enforceable standard the commission determined it 

to be quite adequate for these purposes. The method is a modified version of EPA Method 9 (40 CFR, 

Part 60, Appendix A (July, 1992)). Terminology was changed to reflect this method's applicability to 

fugitive particulate emission sources covered by Section III.DA of this regulation. Additional procedures 

are established for the positioning of the observer and the observing of emissions (at a point of release to 

the atmosphere). These procedures will become part of the training at "smoke schools" conducted by the 

Colorado Department of Health for certification of smoke and opacity observers. 

APPENDIX B. Method of Measurement of Off-Property Transport of Fugitive Particulate Emissions. 

The commission included this method of measurement of fugitive particulate emissions in order that the 

"Off-Property Transport" guideline is uniformly applied by observers. This method generally employs the 

same criteria for the positioning of an observer as the method of measurement of opacity in Section 

111.0.2. of this Regulation NO.1. This method will also be included in the "smoke school" training for the 

certification of smoke and opacity observers. 

a. Section V. (Adopted March 11, 1982) 

This rationale complies with the requirement of the Administrative Procedure Act, C.R.S. 1973,24-4­

103(4) that the Air Quality Control commission (commission) prepare a statement of basis and purpose 

for these amendments. The statutory authority for these amendments is in the Air Quality Control Act at 

C.R.S. 1973.25-7-102,25-7-105,25-7-106, and 25-7-109. The general purpose of the amendments was 

to require reasonably available control technology (RACT) be applied to particulate emission sources at 

existing iron and steel plants. The CF&I Steel Corporation (CF&I) and the U.S. Environmental Protection 

Agency (EPA) were the only parties to the rulemaking. The Air Pollution Control division (division) acted 

as staff for and advised the commission during the proceeding. 
The parties and the commission addressed two major areas of controversy: whether the use of clean 

water for coke quenching operations represents RACT and which methods of emission control for cast 

houses represents RACT. 

Coke quenching is considered by the commission to be a major source of particulate emissions from iron 

and steel plants and development of emission controls for coke quenching should be encouraged. As 

originally proposed, RACT for coke quenching would have required the use of water having no more than 

700 rng/I of total dissolved solids (TDS). However, upon review of the rulemaking record, the commission 

has determined that it has insufficient information to adopt an emission control regulation for coke 

quenching. Therefore, the commission is requiring the submission of reports on the capabilities of 

wastewater treatment facilities, the generation rates of wastewater, the relationship between TDS levels 

in coke quench water and other variables, the particulate-removing efficiency of existing baffling systems, 

and the costs of installation of alternative baffling systems. Based on these reports and information 

relating to the effectiveness of powder activated carbon in wastewater treatment facilities, the 

effectiveness of baffling systems at other iron and steel plants, the relationship of TDS levels to 

particulate emissions, and other relevant information, the commission will reconsider the issue of RACT 

for coke quenching. 

The commission has determined that non-capture technology (for example, shrouding and suppression) 

constitutes RACT for cast house particulate emissions, except for emissions from the iron notch, ladle 

and spouts. Due to the developing and proprietary nature of such technology, the commission has 

adopted a general requirement for use of such technology that will permit iron and steel plants to 

determine its most cost and pollution control effective application at such plants. Iron and steel plants will 

be allowed a period of two years to develop, evaluate and apply a non-capture technology at one of its 

cast houses. It is not considered feasible to apply such technology in a lesser time period. Based on the 

experience with this initial application, the commission expects to develop a more specific standard for 

the use of such technology at additional cast houses. Because there is not a basis in the record for 

concluding that capture technology is cost effective or RACT, the commission has determined not to 

require such technology. 

b.	 Amended Sections VA5.c. and V.B.5.a. (Adopted: February 24, 1983). 

This rationale complies with the requirement of the Administrative Procedure Act, C.R.S. 1973,24-4­

103(4) that the Air Quality Control commission (commission) prepare a statement of basis and purpose 

for these amendments. The statutory authority for these amendments are in the Air Quality Control Act at 

C.R.S. 1973,25-7-102,25-7-105,25-7-106, and 25-7-109. 

The commission has determined that the effective dates for meeting the requirements for coke quenching 

and cast houses as described above in paragraph B should be postponed for the following reasons: 

(1)	 Due to economic conditions the coke plant and blast furnaces at the iron and steel plants 

are currently not in operation. The studies and control measures outlined in Section V 

were to be conducted and implemented while those sources were in operation (with the 

exception of a study outlining the costs of installing and operating existing quench towers 

with alternative baffling system(s)). 

(2)	 With regard to the study outlining the costs of installing and operating existing quench 

towers with alternative baffling systems, the commission determined that (due to the 

current economic conditions and reduced work force at iron and steel plants) a 

postponement until "normal rate of production" at coke plants is again reached would 

result in more useful data being submitted. 

In regard to quenching of coke the time period for submittal of reports shall be fifteen months from the 

time that production levels return to 128 ovens per day. With regard to cast houses, the time period for 

implementing controls shall be determined from the date of return to service of one blast furnace. 
Regarding the issue of reasonably available control technology ("RACT"), for the iron notch, the iron ladle 

and the iron spout required to be addressed by Section V.B.5., the commission adopts the division's and 

CF&I's agreement that RACT is not currently available in non-capture emission controls for the iron spout 

and the iron ladle. However, there is reason to believe that U.S. Steel Corporation will soon be publicly 

revealing its non-capture technology for iron and steel plants. The division should review the available 

technology, and if RACT exists, return to the commission with a recommendation for rulemaking. 

For these reasons, the commission believes that emissions from iron and steel plants will be controlled as 

expeditiously as practicable under these delayed schedules. 

c.	 Written statements of the basis and purpose for the various provisions in Section VI of this 

regulation were prepared and adopted by the commission at the times such provisions were 

adopted. These written statements were incorporated in this regulation by reference and in 

accord with C.R.S. 1973,24-4-103 as amended. Copies are available at the office of the Air 

Quality Control commission. 

RATIONALE FOR THE PROMULGATION OF A NEW SOURCE EMISSION CONTROL REGULATION 

The Air Pollution Control commission of the State of Colorado has reviewed the oral testimony and 

documentary evidence submitted in the course of its rulemaking proceedings on proposed new ambient 

air standards for sulfur dioxide and new source emission standards for sulfur dioxide. The attached 

amendments to the existing Colorado ambient air quality standards for sulfur dioxide and the existing 

Regulation NO.1 of the Colorado Air Pollution Control commission are a result of study, analysis and 

technical evaluation by the commission and its staff and, in the judgment of the commission, represent 

those standards which will most effectively foster the welfare, convenience and comfort of Colorado 

residents in facilitating the enjoyment of nature, scenery, and other related resources of the State. In 

every respect, this commission's deliberations and determinations have been guided by the legislative 

declaration of the policy of the Colorado Air Pollution Control Act of 1970: to achieve the maximum 

practical degree of air purity in every portion of our State. 

New Source Emission Standards for Sulfur Dioxide 

It was evident throughout the course of public hearings and is obvious to the commission that the 

hazardous effects of sulfur dioxide are measured by its concentration in the ambient air. It is the quantity 

emitted per unit time that determines this ambient concentration rather than the concentration in any 

particular effluent stream. Emission rates are significant with respect to effects on the environment and on 

human population and vegetation, but ambient air concentrations are the primary consideration in terms 

of these effects and for that reason ambient air standards that are reasonably related to existing 

conditions in Colorado have been established. These new ambient standards and emission rates have 

been developed to reflect a consistent basis. 

The commission in the course of establishing these new sulfur dioxide standards has considered three 

general themes. (1) Best practical control technology must, in general, be employed. (2) For some 

industries the cost of such control technology might be prohibitive for certain small sources. Since the 

total emissions from such sources are not large and do not have a substantial effect on ambient 

concentrations, the commission has adopted emission standards which reflect economic considerations 

for small sources. (3) In response to overwhelming testimony from industry, from technical experts, and 

from the general public, the commission has acknowledged that emission standards should not be based 

on volumetric concentrations in the effluent stream but rather on the weight of sulfur dioxide emitted per 

energy input or unit of product as processed. 

Many witnesses representing industry and users of electrical power suggested that Colorado should 

adopt the EPA New Source Performance Standards (NSPS). The commission has considered this 

suggestion. However, it is the conclusion of the commission that EPA New Source Performance 

Standards are based on the use of high-sulfur coal as well as the application of best external control 

technology to the effluent gases. Given the availability of low-sulfur western coal for industrial usage in 
this state, it has been concluded that the application of best practical control technology should result in 

considerably lower emissions for Colorado sources than those specified in EPA New Source 

Performance Standards. Logically, the more stringent emissions standards are possible and desirable if 

low sulfur coal is employed. Testimony to support this conclusion was presented at the hearings. 

The commission has adopted certain features of the New Source Performance Standards: (1) The 

commission has established a two-hour averaging time for emission standards identical to that set forth in 

the NSPS. (2) The commission has recognized that small sources should not be subject to the substantial 

cost of external sulfur dioxide removal equipment, which is proportionately more costly for small industrial 

operations. The hazard to ambient air quality may be satisfactorily minimized in most instances by the use 

of low-sulfur fuels for these smaller sources. Where a distinction is made, the cut-off point for small 

sources is identical to that employed in the NSPS (250 million BTU per hour). 

Coal-Fired Operations Including Coal-Fired Steam Generation 

Take as a reference point the information supplied in the application for an emission permit for the 

proposed Pawnee 500 megawatt steam generating station. A heat input of 5,430 Million BTU per hour 

produces 500 megawatts of electrical power. The overall thermal efficiency is 31 % and 10.9 million BTU 

per hour are required per megawatt of power. 

Some eastern high-sulfur coals have caloric values on the order of 12,000 BTU per pound and sulfur 

contents on the order of 2.5%. If it is assumed that 5% of the sulfur is retained in the ash, the emission 

rate of an operation using this coal would be 3.96 pounds of sulfur dioxide per million BTU. Compliance 

with the New Source Performance Standards of 1.2 pounds per million BTU would require a sulfur dioxide 

removal efficiency of 70%. It is the finding of this commission, based in part upon testimony from 

industrial and non-industrial sources, that control efficiencies on the order of 70% sulfur dioxide removal 

may be attained without undue financial burden on large new sources. This 70% removal efficiency may 

be taken as a measure of the application of best practical control technology. Testimony presented before 

the commission indicated that steam coal readily available for use in Colorado had a caloric content on 

the order of 8,000 BTU per pound and a sulfur content of 0.5%. Uncontrolled emissions from the use of 

such coal would be 1.19 pounds of sulfur dioxide per million BTU. The best practical control technology, 

operating at an efficiency of 70% would reduce the emission rate to 0.36 pounds of sulfur dioxide per 

million BTU. The commission, therefore, adopted an emission standard of 0.4 pounds of sulfur dioxide 

per million BTU. The required removal efficiencies are shown as a function of coal parameters in Table I. 

For smaller sources an emission limit was set identical to the NSPS large source values. This standard 

may be met by the use of high quality low-sulfur western coal. The maximum emission under this 

standard would be 3.6 tons of sulfur dioxide per day and could result in the production of 23 megawatts of 

electrical power. Table II contains some information regarding the quality of coal required to meet this 

standard. 

Of special concern to the commission was the problem of conversion of facilities from other fuels to coal. 

This issue was frequently raised in the testimony. It was clearly indicated that the cost of installing 

external sulfur dioxide control equipment would be prohibitive in terms of the necessary modifications to 

eXisting equipment: lack of space in which to install the control equipment was termed an almost 

insurmountable obstacle. The commission therefore concluded that the sulfur dioxide emissions standard 

for operations converted to coal-firing from the use of other fuels would be the NSPS; namely, 1.2 pounds 

of sulfur dioxide per million BTU. This standard can be met through the use of available high quality coal. 

The maximum emission from such a converted 100-megawatt facility would be approximately 16 tons per 

day, or equivalent to the emissions from a 300-megawatt installation operating at an emission rate of 0.4 

pounds of sulfur dioxide per million BTU. The nature of the required coal quality is indicated in Table II. 
TABLE I REMOVAL EFFICIENCIES REQUIRED TO MEET AN EMISSION STANDARD OF 

Caloric Content Efficiency 

(%) (BTU/lb.) 

8.000 

9,000 

10,000 

11,000 

0.4 POUNDS PER MILLION BTU 

(Assumes 5% sulfur retention in ash) 

Percent Sulfur Removal 

0.4 58
 

0.5 66
 

0.6 72
 

0.8 79
 

0.9 81
 

0.5 62
 

0.6 69
 

0.8 76
 

1.0 81
 

0.6 65
 

0.7 70
 

0.9 77
 

1.1 81
 

0.6 62
 

0.7 67
 

0.9 74
 

1.1 79
 

TABLE II SULFUR DIOXIDE EMISSION FROM COAL 

(Assumes 5% sulfur retention in coal) 

BTU/pound 

8.000
 

Maximum Sulfur Content to 

Meet Emission Standard of 

1.2 pounds per million BTU 

0.50% 
TABLE II SULFUR DIOXIDE EMISSION FROM COAL 

(Assumes 5% sulfur retention in coal) 

9,000 0.57% 

10,000 0.63% 

11,000 0.69% 

Under certain circumstances the emission standards may be limiting; under other circumstances, the 

ambient air quality standards may govern the issuance of permits to new coal-fired sources. In any event, 

impact on ambient air quality is the ultimate concern and siting may thus become an important factor for 

new sources. Several Rocky Mountain States have adopted sulfur dioxide emission standards more 

restrictive than the Federal standards and in some cases, more restrictive than these Colorado 

Standards. 

Oil-Fired Operations Including Oil-Fired Steam Generation 

The New Source Performance Standards (NSPS) for oil-fired operations with a heat input greater than 

250 million BTU per hour is 0.8 pounds of sulfur dioxide per million BTU. In line with the philosophy of 

higher emission rates per unit of energy input for small sources and in line with the adoption of NSPS for 

new coal-fired sources of less than 250 million BTU input per hour, the commission adopted an emission 

standard of 0.8 pounds of sulfur dioxide per million BTU for sources with a heat input less than 250 million 

BTU per hour. The required degree of oil quality is shown in Table III, and oil of the quality necessary to 

meet these standards is available. 

For larger oil-fired operations (greater than 250 million BTU per hour) the commission again decided to 

require best practical control technology. The standard adopted is calculated from the ration of the NSPS 

standards for coal and oil applied to the adopted 0.4 pounds per million BTU standard for coal-fired 

operations. The standard for large new oil-fired operations thus becomes 0.3 pounds of sulfur dioxide per 

million BTU. At present, there is little expectation that large new oil-fired facilities will be constructed. No 

industry provided testimony at the hearings regarding its intent to construct a large oil-fired facility in 

Colorado. 

TABLE III SULFUR DIOXIDE EMISSIONS FROM FUEL OIL 

Percent sulfur Pounds per million BTU 

0.1 0.11 

0.2 0.21 

0.28* 0.30 

0.4 0.42 

0.6 0.42 

0.7 0.75 
TABLE '" SULFUR DIOXIDE EMISSIONS FROM FUEL OIL 

Percent sulfur Pounds per million BTU 

0.75** 0.80 

0.9 0.95 

1.0 1.05 

• Maximum sulfur content required to meet standard of 0.3 Ibs/million BTU 

•• Maximum sulfur content required to meet standard of 0.8 Ibs/million BTU 

The standard of 0.8 pounds of sulfur dioxide per million BTU would be applied to emissions for facilities 

converted from other fuels to oil. The rationale follows that given above for coal-fired operations. 

Combustion Turbines 

These are used largely for peaking operations. There is little likelihood that natural gas will be used as a 

fuel for such sources in the near future. The major fuel will be oil for new sources and sources converted 

from natural gas use. The commission adopted the same standards for emissions from combustion 

turbines as for emissions from oil-fired operations. High quality distillate will be required. 

Little testimony was presented on this issue. 

Natural Gas Desulfurization 

Natural gas (primarily methane) is a clean and desirable fuel for household use. It is considerably more 

efficient for such use than electrical energy obtained from coal combustion. The conversion efficiency for 

the conversion of coal to electrical energy is on the order of 30%; the conversion of the chemical energy 

of natural gas to thermal energy is on the order of 80%. 

Much natural gas as it comes from the well is "sour"; i.e. contains significant and varying concentrations of 

hydrogen sulfide. This substance must be removed before the gas is put into the pipeline. For smaller 

sources, the waste hydrogen sulfide may be "flared" and converted into sulfur dioxide and emitted as 

such. For larger sources, the gas is desulfurized by means of a process which converts the hydrogen 

sulfide into elemental sulfur. Sulfur dioxide is emitted as a by-product in such a process. Control 

technology exists for reduction of all such sulfur dioxide emissions. 

The caloric content of natural gas is on the order of one million BTU per 1,000 cubic feet. Small coal-fired 

electrical generating facilities have been assigned an emission standard of 1.2 pounds per million BTU. 

Considering the greater efficiency of natural gas in its usage (by factor of 80/30) it is reasonable to adopt 

a higher emission rate per unit of energy for natural gas desulfurization. However, the stacks employed in 

such desulfurization are lower than those normally used in coal-fired generation operations and hence, 

contribute significantly to increased ambient levels. A balancing process for establishment of these 

emission standards has therefore become necessary. 

Application of highly efficient sulfur dioxide removal equipment may be prohibitively expensive for small 

sources. The commission has, after review of the short stack considerations, decided to adopt a break 

point between large and small sources of 3 tons of sulfur dioxide emissions per day. The applicable 

standard for such small sources is set at 2 pounds of sulfur dioxide per 1,000 cubic feet (one million 

BTU). This recognizes the greater thermal efficiency of natural gas while minimizing impact on ambient air 

quality. 
For larger sources, the emission standard of 0.8 pounds of sulfur dioxide per 1,000 cubic feet of gas 

delivered to the pipeline gives weight to the increased energy efficiency of natural gas, as compared to 

coal, for the generation of applicable power. (This standard is roughly twice that for coal-fired operation.) 

Suitable technology is available for control in such large sources. Again little testimony was presented at 

the hearings. Table IV contains some pertinent data with respect to natural gas desulfurization. 

TABLE IV NATURAL GAS DESULFURIZATION 

Vol. % CO2 Vol. % H2S Ibs. S02/1 ,000 % Removal (2.0 % Removal (0.8 

Cubic feet Ibs.) Ibs.) 

10 16 38.6 95 98 

14 32.9 94 98 

12 27.5 93 97 

10 22.3 91 96 

8 17.4 89 95 

6 12.8 84 94 

4 8.3 76 90 

2 4.1 51 80 

2.0 60 

0.5 1.0 20 

0 16 34.0 94 98 

12 24.3 92 97 

8 15.5 87 95 

4 7.4 73 89 

1.8 56 

0.5 0.9 11 

Permitted Production per day in Cubic Feet at Uncontrolled 3 

tons of Sulfur Dioxide per day (Million cubic feet) 

16 0.177 

12 0.247 

8 0.387 
TABLE IV NATURAL GAS DESULFURIZATION 

Vol. % CO2 Ibs. S02/1,OOO 

Cubic feet 

% Removal (2.0 

Ibs.) 

% Removal (0.8 

lbs.) 

4 0.811 

3.334 

0.5 6.666 

Petroleum Refining 

The prediction and analysis of sulfur dioxide emissions from the refining of crude oil presents a complex 

problem. The sulfur content of the crude oil varies; the sulfur content of the various portions of refined 

products varies as does the mix of these products; the emissions are from several processes. The 

refineries now in operation in Colorado range in capacity from 6,000 to 35,000 barrels per day. The 

largest refinery processes crude oil with an average sulfur content of 0.9% and a range of about a factor 

of 2. This crude is considered "sour"; i.e. containing a significant concentration of elemental sulfur. Some 

sulfur dioxide escapes in this process as well as from other operations in the refining cycle. It is estimated 

that the total emissions from this refinery range from 10 to perhaps 15 tons per day. With a 35,000 barrel 

a day capacity the emission rate is thus 0.57 - 0.86 pounds of sulfur dioxide per barrel of oil processed. 

Little evidence was presented to the commission regarding technical aspects of new petroleum refining 

facilities. Further study by the commission and staff indicate that (1) emission standards should be set for 

the overall operation rather than on standards for the separate process units due to the complexity of this 

operation (2) that technology for new operations is available (tail-gas scrubbing) that would lower the 

emissions by at least a factor of three, and (3) such technology is economically feasible for new 

construction. The commission therefore adopted an emission standard of 0.3 pounds of sulfur dioxide per 

barrel of oil processed. Under this standard a 40,000 barrel a day plant would emit per day 6 tons of 

sulfur dioxide, equivalent to the emissions from a controlled 140 megawatt electrical generating facility. 

Production of Oil from Shale 

Due to the complexity of sulfur dioxide emission sources in a shale oil production facility, whether it 

involve surface retorting or "in situ" production, the commission adopted an emission standard which 

relates the permitted sulfur dioxide emission to the operation as a whole (in terms of quantity of oil 

produced). 

Some conflicting evidence was presented to the commission on this issue. The proposed Union Oil Plant 

would purportedly emit 6 tons of sulfur dioxide per day and produce 71,000 barrels a day; the emission 

rate would be 0.17 pounds of sulfur dioxide per barrel of oil produced. The proposed Colony surface 

retorting facility was described as emitting 3.9 tons per day with production of 43,000 barrels a day. The 

emission rate will be 0.18 pounds per barrel. Testimony from Standard Oil of Indiana projected an 

emission rate for a modified "in situ" process of close to a full pound of sulfur dioxide per barrel. This latter 

figure has, however, been significantly reduced, in the detailed development plan for this project, to 0.3 

pounds of sulfur dioxide per barrel of oil. The "in situ" process may offer other significant advantages in 

environmental impact over surface retorting. It was the decision of the commission, therefore, to adopt an 

emission standard for large oil shale production facilities of 0.3 pounds of sulfur dioxide per barrel of oil 

produced. This standard is to be applied to the total of such emissions from the production facility. The 

commission anticipates the construction of small experimental units to test new methods for the 

production of oil from shale. The nature of sulfur dioxide emissions from such sources would not be 

precisely known, nor would the total emissions be large. The commission has therefore decided to 

exempt sources with a production rate less than 1,000 barrels a day from process emission standards. 
Under these standards, the emission rate for a 50,000 barrel a day operation would be 75 tons a day 

which is equivalent to the emissions from a controlled 130 megawatt electrical generating plant. 

Refining of Oil Produced from Shale 

It appears that the sulfur content of the shale oil delivered to the refineries will be on the order of one 

percent. This is similar to the oil now being processed in the Conoco refinery in Denver. The same 

argument would therefore apply here as was advanced for the refining of conventional crude oil. The 

emission standard for large operations is thus set at 0.3 pounds of sulfur dioxide per barrel of oil refined. 

Again the commission has decided to exempt small experimental operations from process standards. The 

cut-off has been set at 1,000 barrels per day. Taking an extreme point of view (all the sulfur is emitted as 

sulfur dioxide and none retained in the product) the daily emissions from a 1,000 barrel a day operation 

would be 2.8 tons of sulfur dioxide per day which is equivalent to the emissions from a controlled 50 

megawatt electrical facility. 

Sulfuric Acid Production 

These are the EPA New Source Performance Standards and will require installation of control devices 

that are available. 

Any Sulfur Dioxide Source Not Specifically Regulated Above 

No evidence was introduced concerning such emissions. The commission is not aware of plans for 

construction of such sources or the nature of the sources. It is proposed, consistent with the general 

philosophy concerning small sources, to exempt sources with an emission rate of less than two tons per 

day (equivalent to the emissions from a controlled 36 megawatt installation) from process standards. For 

new large sources the application of best practical control technology will be required. Due to the 

unknown nature of these new sources, it is impossible to specify process emission rates, the nature of the 

control technology, and its efficiency. The Air Pollution Control division in its evaluation of the permit 

application is charged with determining whether best practical control technology will be utilized. The 

commission reserves the right to review such decisions. 

Ado~ed:August11, 1977 

COLORADO AIR POLLUTION CONTROL COMMISSION 

RATIONALE AND JUSTIFICATION FOR THE AMENDMENT OF AIR QUALITY CONTROL
 

COMMISSION REGULATION NO.1, SECTION IV, BY ADDING A NEW SUBSECTION D.
 

On April 9,1981 the Air Quality Control commission adopted an Amendment to Air Quality Control 

commission Regulation No.1, Section IV. concerning Limitation on Emissions from Sinter Plant 

Wind boxes at Existing Iron and Steel Plant Operations. 

Colorado'S only existing sinter plants at iron and steel facilities are located at the CF&I plant in Pueblo, 

Colorado. The Pueblo area is currently designated by the U.S. Environmental Protection Agency (EPA) 

as non-attainment with respect to the National Ambient Air Quality Standards (NMQS) for total 

suspended particulates. 

Section 172(b)(3) of the Federal Clean Air Act requires that State Implementation Plans for nonattainment areas require reduction of emissions from existing sources through adoption, at a minimum, of 

Reasonably Available Control Technology (RACT). 

EPA has proposed conditional approval of the Pueblo element of the Colorado State Implementation Plan 

in the December 12, 1980 Federal Register (45 Fed. Reg. 81789). In that proposed rulemaking notice, 
EPA indicated that the Air Quality Control commission's existing emission limitations for various sources 

at existing iron and steel plants do not represent Reasonably Available Control Technology and proposed 

approval of the Pueblo element of the SIP on condition, among others, that the Air Quality Control 

commission emission control regulations for existing iron and steel plants be revised to represent RACT. 

In response to the requirement of section 172 of the Clean Air Act and EPA's proposed conditional 

approval of the Pueblo element of the SIP, the commission is conducting public hearings to review and 

revise as appropriate, emission control regulations for sources at existing iron and steel plants. Because 

of an existing compliance order issued by the Air Pollution Control division and affirmed by the Air Quality 

Hearings Board, requiring CF&I to bring its sinter plant into compliance with existing standards, the 

commission decided to conduct rule making with respect to sinter plants as early as possible. 

With respect to the interpretation of the numerical standard "0.03 gr/dscf', such standard is intended to be 

interpreted as an absolute standard such that any emissions in excess of 0.03 gr/dscf, no matter how 

minimal, shall constitute a violation. In other words, the commission is approving the Air Pollution Control 

division's past and continuing interpretation of numerical standards as if they were followed by an 

unlimited number of zeros. This interpretation by the Air Pollution Control division is approved on the 

understanding that the Air Pollution Control division would normally not initiate enforcement action for 

extremely minimal violations (e.g., 0.0301). 

The Air Quality Control commission determined that there was no legal basis for adoption as part of the 

regulation of an exemption for CF&I from enforcement of the applicable existing, less stringent emission 

limitation (.037 gr/dscf equivalent) while CF&I implements the new, more stringent 0.03 gr/dscf standard. 

The Air Quality Control commission acknowledges that the Air Pollution Control division, not the Air 

Quality Control commission, is charged by statute (C.R.S. 1973,25-7-115) with enforcement of emission 

control regulations and trusts all relevant factors (including CF&I's efforts and success in complying with 

existing standards) will be considered by the Air Pollution Control division in exercising its enforcement 

authority. 

AIR QUALITY CONTROL COMMISSION 

ADOPTED: April 9, 1981 

STATEMENT OF BASIS AND PURPOSE 

Emergency Amendment to Regulation No.1 Section 111.0.1. (Fugitive Particulate Emissions) 

On April 8, 1982, the Air Quality Control commission adopted a new Regulation NO.1 which was 

scheduled to become effective May 30, 1982. On April 19, 1982, the Attorney General for the State of 

Colorado, in accordance with the provisions of C.R.S. 1973, 24-4-103(8)(b), issued an opinion as to the 

legality and constitutionality of the new regulation and disapproved in part Section 111.0. of the regulation 

(concerning control of fugitive particulate emissions). 

Recognizing that the Attorney General's opinion raises a substantial question as to the validity of portions 

of Section 111.0. of the regulation (and poses significant problems with respect to enforcement of said 

regulation; finding that having an enforceable regulation for the control of fugitive particulate emissions 

necessary to the preservation of the public health and welfare; and in order to avoid the circumstance of 

not having an enforceable regulation for the control of fugitive particulate emissions for any significant 

period of time [as would result if the normal rulemaking procedures were followed]); the Air Quality 

Control commission has determined adoption of amendment to Section 111.0. of the Air Quality Control 

commission Regulation No.1 is imperatively necessary for the preservation of the public health and 

welfare and that compliance with the normal rulemaking procedural requirements of C.R.S. 1973,24-4­

103 would be contrary to the public interest. 

Air Quality Control commission 
Adopted: August 26,1982 

STATEMENT OF BASIS, SPECIFIC STATUTORY AUTHORITY AND PURPOSE for REVISIONS TO 

REGULATION NO.5 concerning Alfalfa Dehydration Plants 

"Regulation NO.5" and sections 11.A.6 and III.C. of "Regulation NO.1" have previously exempted, until 

January 1, 1985, existing alfalfa dehydration plants from the 20 percent opacity standard otherwise 

applicable to sources of air pollution. In these amendments to "RegUlation NO.5" and sections 11.A.6. and 

III.C. of "Regulation NO.1" the commission has extended that exemption until January 1, 1987, in order to 

give the one existing alfalfa dehydration plant in Colorado an opportunity to come into compliance with 

the 20 percent standard. The commission expects compliance to be achieved by that date, and does not 

intend, through these amendments, to indicate that it will accept a permanent exemption from the 20 

percent standard. 

ADOPTED: January 19, 1985 

COLORADO AIR QUALITY CONTROL COMMISSION 

STATEMENT OF BASIS, SPECIFIC STATUTORY AUTHORITY AND PURPOSE REGULATIONS 1 

and 5 concerning Alfalfa Dehydration Plant Drum Dryers 

The revisions to Regulations 1 and 5 described below were adopted by the Air Quality Control 

Commission of the State of Colorado on January 15, 1987. This Statement of Basis, Specific Statutory 

Authority and Purpose is required by Section 24-4-103, C.R.S.. The specific statutory authority for these 

changes is Sections 25-7-105, -106, and -110, C.R.S.. 

The Air Quality Control commission's Regulation 1 and the recently expired Regulation NO.5 provided 

that existing alfalfa-dehydrating plants must operate so as not to exceed 40% opacity. This extension was 

adopted in January of 1985 and extended this exemption (40% opacity limit) until January 1, 1987, at 

which time Regulation NO.5 terminated. Existing alfalfa dehydrators then fell under the provisions of 

Regulation NO.1. The effect of this is to require existing alfalfa dehydrators to meet 20% opacity limits; 

thus treating existing plants the same as new plants. 

Mr. Graves claims to be the only operator of an existing plant which is subject to these requirements. Mr. 

Graves has asked the commission to establish a 30% opacity as the standard for existing plants. In 

making this request, Mr. Graves has indicated he intends to install reasonably available control 

equipment as it is made known and to take other steps in revising his process in order to minimize 

emissions. 

ADOPTED: January 15,1987 

COLORADO AIR QUALITY CONTROL COMMISSION 

STATEMENT OF BASIS, SPECIFIC STATUTORY AUTHORITY, AND PURPOSE for revision to 

Regulation No.1 Adding a new Paragraph A.9. to Section II.A. Opacity Requirement 

Exemption 

The Pueblo Army Depot has made application for an air pollution emission permit to dispose of Pershing 

rocket motors in accordance with the Intermediate-Range Nuclear Forces Treaty, as ratified. From the 

test static firing of one Pershing rocket motor on May 31, 1988, the division has determined, by qualified 

observer, that the opacity of the plume from this activity would exceed the standard of 20% set forth in the 

Air Quality Control commission's Regulation NO.1. Therefore, the Pueblo Army Depot, in order to obtain a 

permit for the destruction of the remaining rocket motors, must obtain a waiver from the above opacity 

standard, or the permit will be denied. This waiver would be necessary due to the fact that there are no 

presently available methods to reduce opacity to compliance levels for this source. 
The commission takes this action pursuant to their regulatory authority in Section 25-7-109 CRS. 

The commission has adopted this rule in order to exempt the static firing of intermediate range and 

shorter range Pershing Missile systems from the opacity limits contained in Regulation No.1, so long as 

such static firing results in emissions less than 250 tons per year of anyone pollutant, adequate 

monitoring is conducted, and air pollutants are not emitted in dangerous quantities. 

Specific statutory authority for limiting the total emissions to 250 tons per year is provided by Section 25­

7-109 CRS. Specific statutory authority for the requirement that the source conduct air monitoring is 

provided by Section 26-7-106(6) CRS; authority for requiring the source to provide the division with the 

results of such monitoring is provided by 25-7-111 (2) CRS; specific statutory authority for prohibiting 

potentially dangerous quantities of any air pollutant is provided by Section 26-7-109(3) CRS. 

COLORADO AIR QUALITY CONTROL COMMISSION 

Adopted: September 15, 1988 Effective: October 30, 1988 

STATEMENT OF BASIS, SPECIFIC STATUTORY AUTHORITY, AND PURPOSE Sections VII and VIII 

Adopted: August 19, 1993 

This Statement of Basis, Specific Statutory Authority, and Purpose complies with the requirements of the 

Administrative Procedures Act, CRS 1973, Section 24-4-103 (4) for adopted or modified regulations. 

The Colorado Attorney General's Office had determined that any control strategy for a non-attainment 

area must be adopted as a State regulation in order for the control strategy to be enforceable by the State 

of Colorado. Sections 25-7-105 and -109 of the Colorado Air Pollution Prevention and Control Act 

provides the specific statutory authority to adopt the emission control regulations necessary to assure 

attainment and maintenance of the National Ambient Air Quality Standards. 

The purpose of the revised regulation is to reduce the allowable emission from the affected facilities in the 

Denver PM1 0 non-attainment area so that future attainment and maintenance of the PM 10 National 

Ambient Air Quality Standard can be demonstrated. As committed in the Denver PM1 0 State 

Implementation Plan (SIP) Element, Regulation NO.1 is being revised to include the stationary source 

control measures adopted by the Colorado Air Quality Control commission on May 20,1993. These 

revisions establish emission limits for PM10 precursors at Public Service Company's Cherokee, 

Arapahoe, and Val mont stations. These revisions also require that oil be restricted as a back-up fuel for 

natural gas at the following facilities: Public Service Company's Zuni, Valmont, and Defgany stations, 

Fitzsimmons Army Medical Center, US Department of Energy's Rocky Flats Plant, Gates Rubber 

company, and Coors Brewery (Golden, CO). 

COLORADO AIR QUALITY CONTROL COMMISSION Statement of Basis, Specific Statutory 

Authority, and Purpose 

Revisions to Regulation No.1, Section II.A. 1, 4 and 10; Regulation No.6, Part B, Section II.C.3.a 

(Regarding opacity limitations and sulfur dioxide averaging provisions for coal-fired electric utility boilers 

during periods of startup, shutdown and upset.) 

Adopted: 'December 23, 1996 

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. 
Regulations 1 and 6 deal with opacity and sulfur dioxide emissions from various sources. This rule 

change addresses only coal-fired electric utility boilers. The Colorado Utilities Coalition ("CUC") requested 

that the commission modify the existing regulations to provide additional flexibility in meeting the opacity 

requirements and sulfur dioxide averaging, for coal-fired electric utility boilers during periods of start-up, 

shutdown, upset, process modification and adjustment of control equipment. 

Specific Statutory Authority 

The Colorado Air Pollution Prevention and Control Act, section 25-7-109(2), C.R.S., provides the authority 

for the commission to adopt and modify emissions control regulations pertaining to visible pollutants, 

particulates and sulfur oxides. Section 25-7-109(5) authorizes the commission to grant a rule change it 

feels is appropriate for periods of start-up, shutdown or malfunction or other conditions which justify 

temporary relief from controls. Section 25-7-105(1) provides the authority for the commission to make SIP 

revisions. Section 25-7-133(4)(a) provides the commission with the flexibility to determine what are 

necessary elements for the SIP. The commission's action is taken pursuant to authority granted and 

procedures set forth in sections 25-7-105, 25-7-109, and 25-7-110, C.R.S. 

Purpose 

The revisions to Regulation NO.1 and NO.6 are intended to provide a specific amount of flexibility related 

to compliance with opacity limitations and sulfur dioxide averaging provisions for coal-fired electric utility 

boilers during periods of startup, shutdown and upset. These revisions replace what is believed to be a 

problematic standard for these specific sources. CUC has demonstrated that there are instances during 

which these sources cannot comply with the 30% opacity limit and the S02 emissions limit during startups and shutdowns. Although these sources may exceed the opacity limit, CUC has presented the 

commission with a study prepared by Radian Corporation, which concludes that removing the 30% 

opacity limit for these sources will not result in such an increase in emissions that Colorado will likely 

violate the National Ambient Air Quality Standards or other federal requirements. CUC proposed 

replacement of the 30% limit with a standard that more closely mimics the federal standard, and which 

these sources will have more certainty complying with, particularly for Title V compliance certification 

requirements. CUC also provided an ambient air analysis related to S02 emissions which concluded that 

allowing a modification of S02 limitations for the periods of startup, shutdown and malfunction would have 

no adverse impact on related federal requirements. 

The division agreed that some flexibility in complying with the 30% opacity limit was appropriate for these 

sources. The division also proposed replacing the 30% opacity limit. 

Action Taken 

The commission concludes that a rule change is appropriate for this category of sources and is removing 

the application of the 30% opacity limitation to these sources during periods of start -up, shutdown and 

upset. In addition, the commission agrees that a rule change is merited from the current treatment of S02 

emissions during periods of start-up, shutdown and malfunction. The commission also concludes that this 

rule can be made clearer and easier to implement through the changes adopted. 

The commission adopts language substantially similar to the federal New Source Performance Standard 

requirement that, during periods of startup, shutdown and malfunction, these sources, to the extent 

practicable, shall maintain and operate associated air pollution control equipment in a manner consistent 

with good air pollution control practice for minimizing emissions. In the commission's view, incorporating 

this standard will provide an important balance to the removal of the 30% limit. 

The federal New Source Performance Standard refers to "malfunctions", while the commission has 

adopted an upset provision. The commission finds that these two terms are substantially similar, with the 

exception that an upset must be properly reported to the division to be excused. In order to avoid 
confusion, the commission decided to use the term upset consistent with the Common Provisions 

Regulation. 

The division expressed concern that the "good practices" standard is subjective and requires substantially 

more resources to enforce than a numerical limit. In addition, without the 30% limit, opacity from these 

facilities could be at very high levels periods of time. The commission concurs and in this regulation 

adopts the division's proposed measures to limit the overall time during which a source may exceed the 

underlying 20% opacity restriction. 

Good Air Pollution Control Practices 

The revisions to Regulation NO.1 were developed by the Regional Air Quality Council and the Colorado 

Air Pollution Control division. Comments from the affected facilities, the Colorado Attorney General's 

Office and the US Environmental Protection Agency were utilized in further developing the regulation. 

The submittal of these revisions to the commission demonstrates the Commitment from industry, and 

local and state governments, and the citizens that they represent, to implement control measures and 

improve the air quality in the Denver area. The revised Regulation NO.1 will be submitted to the EPA as 

part of the Denver PM1 0 SIP Element. 

This regulation sets overall limits, by percentage of operating time, during which opacity may exceed 20% 

and S02 emissions may exceed regulatory maximums. In the commission's view, this will allow more 

flexibility for the utilities without leaving them free of reasonable restriction. The percentages were 

determined based on a percentile of the exceedence times for all such sources within the state. 

Exceedence times were calculated based on the excess emissions reports submitted by each of the 

utilities over the last several years. These times included the periods of excess emissions due to the 

events listed in Regulation No.1, section II.AA [fire building, cleaning of fire boxes, soot blowing, start-up, 

process modification and adjustment or occasional cleaning of control equipment], as well as shutdowns 

and upsets. Accordingly, the data upon which the commission based its adoption of the percentages used 

to define good air pollution control practices included all times during which a source exceeded the 

applicable opacity limitation. In turn, the percentages adopted as the definition of good air pollution control 

practices include all times during which a source exceeds the 20% opacity limitation. Thus, all periods of 

start-up, shutdown, upset, fire building, process modification and adjustment or occasional cleaning of 

control equipment will be counted against the unit's compliance with the percentages. 

This general rule does not apply in two circumstances. First, start-ups following planned maintenance 

outages which require significant changes at the facility are treated separately, because the commission 

concluded that these infrequent events posed particular difficulties for the utilities. It appears that the 

duration of these events cannot be reasonably predicted and they are not to be included in the calculation 

of the source's compliance percentages. However, in order to ensure accountability of these sources 

during planned outages, the commission is imposing requirements for advance notice to the division. 

Advance notice will ensure that these are, indeed, planned outages. The notice must include a plan for 

minimizing emissions and an estimate of the time during which controls will not be operable while the unit 

is in operation, both in order to prevent inordinate startups beyond reasonable limits. During start-ups, the 

source must still use good air pollution control practices. An additional definition of start-up is provided to 

add certainty for all concerned about the duration of these significant planned outage start-ups. In 

addition, the commission restricts the application of the planned maintenance outage exception to events 

requiring significant changes at the facility, such as replacement of major facility components or 

installation of new processes (e.g., installation of low NOx burners). This exception addresses changes 

from which the resulting impact on plant operations cannot accurately be predicted. The exception is not 

intended to allow exclusion of excess emissions resulting from routine maintenance outages, such as 

annual replacement of standard equipment, from calculation of the exceedence percentage time 

allowance. 

Second, opacity emissions which are not a result of the combustion of fuel in the steam-generating unit 

are excluded from the calculation of the compliance percentage. This approach is consistent with the 
federal New Source Performance Standard found at 40 CFR Part 60, Subpart D. The commission 

concludes that these emissions control measures are not intended to limit emissions from cleaning of fire 

boxes, soot blowing and other activities when a unit is off-line, i.e., when no fuel is being fed to the unit. In 

addition, there are technical concerns related to the ability of monitoring devices to operate accurately 

when the unit is off-line. 

The commission agrees that all of these sources can perform somewhat better and intends that the 

percentages will serve as an as an achievable measure of good air pollution control practices during 

these specific periods. This approach will also force poorer-performing facilities to improve their 

operations and maintenance practices and bring their exceedence levels down to one more consistent 

with that at other facilities. For baghouse-equipped boilers, a single percentage will suffice for the 

indefinite future. However, utility units using electrostatic precipitators to control particulate emissions 

present more complicated issues. Accordingly, the commission elected to provide an interim period of 

approximately three years during which these units will have a higher allowance percentage. 

The commission does not impose at this time a requirement for electrostatic precipitator -equipped 

facilities to achieve the same exceedence percentage time allowance as baghouses. However, the 

commission's ultimate goal is for ESP-equipped facilities to meet the same compliance standard as is 

today imposed on baghouses. 

The commission endorses the concept that the utilities conduct a study to evaluate operations and 

maintenance practices and equipment modifications at ESP-equipped facilities. The purpose for this 

study is to improve understanding of the operators, the division and the commission related to ESP 

operations and potential improvements. The results of this study are not intended for use as evidence that 

pre-study operations do not constitute good air pollution control practices. 

The commission did not agree with the CUC proposal for limitations on the duration of individual incidents 

of start-up and shutdown because this approach also is subjective and would require more resources to 

enforce. The Sierra Club proposal, although substantially similar to that presented by the division, would 

require enforcement with exceedence allowances calculated for each ESP-equipped facility. The 

commission is not convinced that the benefits of a more specific exceedence allowance justify the 

resources required to enforce these percentages. 

The allowance percentages will give both sources and the division a clear definition and reasonable limits 

to the concept of "good air pollution control practices." This definition limits sources from arguing that 

longer periods of exceedence are good practices. The definition is also intended to allow the division to 

investigate the source's practices and determine whether, in light of their compliance history, process and 

control equipment and operations and maintenance procedures, the source is using good practices. This 

treatment of good practices will in no way prevent the division from initiating an enforcement action if the 

division determines that a source is not using "good air pollution control practices," regardless of the 

amount of time the source has been in violation of the 20% opacity standard. The division may use any 

available information in order to evaluate whether the source is using good practices. 

Federal and State Statutory, and State Implementation Plan, Issues 

The commission is cognizant that section 193 of the federal Clean Air Act precludes revisions to the state 

implementation plan relating to non-attainment areas which do not provide equivalent or greater 

emissions reductions to the existing provisions of the plan. Even under this federal law, however, the 

commission is entitled to modify its plan to make it more cost-effective and to improve overall compliance 

and implementation. The commission concludes that the division's proposal does not represent a 

relaxation of the existing rule. The regulatory change removing application of the 30% opacity limit 

appears on first impression to relax requirements for these units. However, by limiting the overall time 

during which the units may exceed the 20% opacity limit, the commission believes this approach will 

result in at least the same levels of compliance with the opacity standard and will likely result in lower 

overall emissions. 
The commission is also aware that section 110 of the federal Clean Air Act imposes additional limitations 

on revisions to the state implementation plan. CUC presented information relating to the impact of its 

proposal on ambient air concentrations. The commission relied on this information, although it did not 

adopt the CUC proposal for defining and limiting "good air pollution practices." The commission concludes 

that the changes made in this rulemaking will not lead to increased emissions in amounts substantial 

enough to interfere with the state's programs to attain and maintain the NAAQS or any other federal 

requirements. 

The commission also has evaluated the proposal adopted pursuant to the standards of section 25-7­

105.1, C.R.S. This rule change and the compliance levels adopted today for these limited periods for 

coal-fired electric utility boilers clarify the federal narrative standard adopted, providing both the utilities 

and the division with greater levels of certainty. The levels also put a practical limit on excursions by these 

sources above the opacity and S02 emissions limits and aid in ensuring that the NAAQS are attained or 

maintained and that no other applicable requirements are adversely affected. 

The commission has determined that continued enforcement of the Regulation NO.1 opacity provisions 

were relied on in development of the Denver PM10 element of the state implementation plan. The 

provisions deleted from Regulation NO.1 pertaining to electric power plants therefore must be replaced 

with substantially equivalent requirements. In the past, the division's enforcement discretion has been 

exercised to effectively allow 5% noncompliance by these sources. Substantial regulatory ambiguity in the 

opacity limitations applicable to startup and other periods also led to uncertainty and lower compliance 

levels. These revisions are substantially equivalent or better in their impact on emissions to the results of 

current law and practice because that past practice led to lower compliance than the anticipated 

compliance levels which will result from these changes. The commission finds that these modifications 

are necessary as parts of the state implementation plan. The commission also concludes that these 

revisions are not more stringent than federal requirements, considering the historical "5% policy" used by 

the division and EPA. Accordingly, the commission concludes that these changes should be forwarded to 

the General Assembly for review and then to EPA for inclusion in the state implementation plan. 

Finally, the commission adopts these rule changes subject to a delayed effective date insofar as the 

revisions apply to sources within the Denver PM 10 non-attainment area. The Environmental Protection 

Agency has expressed concerns about the potential effect of this rule change on the pending approval of 

the PM1 0 element of the state implementation plan for the Denver non-attainment area. In order to 

ensure that the proposed approval of the PM1 0 element for the Denver non-attainment area is not 

endangered, the commission designates the effective date for these revisions as they apply to sources 

within this non-attainment area as the date on which EPA approves these changes as a revision to the 

state implementation plan. 

The commission has taken into consideration the items enumerated in section 25-7-109(1 )(b), C.R.S. The 

commission also makes the following findin~ls regarding the adoption of these rule changes: 

1.	 The commission has considered, and has based its decision, on the reasonably available, 

validated, reviewed and sound scientific methodologies and information made available by the 

parties. 

2.	 Where these revisions are not administrative in nature, the record supports the conclusion that 

the provisions adopted will result in a demonstrable reduction in air pollution. This reduction is 

accomplished because the overall exceedence levels of the facilities will be lowered under the 

proposal adopted. 

3.	 The revisions selected maximize the air quality benefits of the emissions standards that apply. 

The revisions selected are the most cost-effective based on the documents submitted by the 

parties under section 25-7-110.5, ard provide the regulated community with fleXibility in meeting 

emissions limitations. Although the overall level of exceedences should be reduced under this 

rule change, operators of the units affected will have greater flexibility in start-up and shutdown of 

the facilities without incurring a violation. In addition, the greater levels of certainty provided by 
these changes will allow operators of affected facilities to more readily certify compliance with 

these applicable requirements under the Title V operating permit program. 

STATEMENT OF BASIS, SPECIFIC STATUTORY AUTHORITY, AND PURPOSE Revisions to 

Regulation No.1, Section II 

Adopted: July 17,1998 

The Fort Carson Army Installation has made application for an exemption to the opacity requirements in 

Regulation NO.1 during training exercises at Fort Carson and the Pinon Canon Maneuver Site that 

involve the generation of fog oil smoke and the use of other obscurants. Because the purpose in using 

obscurants is to train troops in situations of limited visibility, the opacity of the smoke generated is close to 

100%, which exceeds the 20% standard in the Air Quality Control commissions Regulation NO.1. 

As Fort Carson's training relies, in part, on smoke and obscurant usage, the potential for base closure 

increases if an exemption is not granted. If closed, projected economic impact within a 50-mile radius of 

the Installation is estimated at $621 million annually. 

The US Army and the division have used dispersion models to estimate the air quality impacts from fog oil 

generation. The impact levels for various averaging periods have been compared to National Ambient Air 

Quality Standards (NAAQS) for particulate matter and the National Research Council's (NRC) 1997 

guideline values for fog oil exposure. 

The Colorado Department of Public Health and Environment's Disease Control and Epidemiology division 

has reviewed the toxicological data for fog oil and compared that data to the National Research Council 

(NRC) guideline values. Based on this review the division feels that under current operating practices fog 

oil generation is unlikely to cause a serious public health problem. 

The modeling analysis suggests that fog oil generation can cause impacts exceeding the NAAQS or !\IRC 

guideline values within 3 kilometers of the fog oil generators. Modeled impacts greater than the NAAQS 

or NRC guideline values may occur at distances of up to ten kilometers depending on the meteorological 

conditions and the configuration of the fog oil generators. For example, modeling suggests that fog oil 

generation at a usage rate of 1540 gallons of fog oil over a four-hour period could cause or contribute to a 

NAAQS exceedence at distances of up to ten kilometers if the plume is transported in the same direction 

for several hours. Typical U. S. Army fog oil generation requires mobile, as opposed to stationary, source 

operations. This might limit the potential for such extensive off-site impacts. 

The division has determined that impacts in ambient air should be below the NAAQS and NRC values if 

standard U. S. Army fog oil generator operations and the mitigation measures in the exemption are 

followed. These mitigation measures should also address concerns from the United States Environmental 

Protection Agency that this exemption might lead to a violation of the federal National Ambient Air Quality 

Standard for PM 2.5. The commission determines, pursuant to section 25-7-117, C.R.S., that the smoke 

generation for the training in question is purposefully intended to be at or near 100% opacity and 

therefore cannot occur in compliance with the 20% opacity limitation in Regulation NO.1. Accordingly, 

control techniques are not desirable for this emission of air pollutants. This proposed revision to the state 

implementation plan is consistent with the legislative policy set forth in section 25-7-102; and adoption of 

this limited exception is consistent with the requirements of section 110 of the federal act. Regarding this 

element, the commission concludes, based on the modeling information presented, that the generation of 

fog oil smoke will not cause or contribute to a NAAQS violation at the reservation boundary if the 

proponent operates in compliance with the limitations placed on this exemption. As additional 

toxicological data on fog oil is expected over the next few years, the Air Quality Control commission will 

revisit this exemption based on an evaluation of the Fort Leonard Wood fog oil study, but will not be 

limited to this report. This report should evaluate the Fort Carson fog oil exemption in Air Quality Control 

commission's Regulation NO.1 with regard to the protection of the public health in Colorado. 
The commission takes this action pursuant to their regulatory authority in section 25-7-109 and section 

25-7-117. 

Findings 

This limited exception to the opacity restriction in Regulation NO.1 is not intended to reduce air pollution; 

accordingly, the commission makes no findings pursuant to section 25-7-110.8, C.RS. Pursuant to 

section 25-7-133(3), C.RS., the commission concludes that this limited exemption is not required by 

federal law nor is it more stringent than federal law. 

Statement of Basis, Specific Statutory Authority, and Purpose 

Revisions to Regulation No.1, Section VII, concerning emission limits for electric generating stations 

The April 19, 2001 amendments to Regulation No.1, section VII were adopted to support the 

redesignation of the Denver metropolitan area to an attainment area for particulate matter. The rule 

amendments codify emission limitations and shut down requirements for the purpose of incorporating 

such limitations and requirements into the federally enforceable SIP. 

Basis and Purpose 

One of the emission limitations used to show maintenance of the NAAQS (the 20% S02 limit for the 

Public Service Company of Colorado Cherokee facility) was previously found only in a state permit; it was 

not in a regulation. (Public Service Company is now doing business as Xcel Energy.) In 1997 EPA 

incorporated the permit for the Cherokee facility, together with the permits for several other stationary 

sources, into the SIP by reference. The EPA asserts that such incorporation is necessary to the extent 

the State relies on emission limits in the permits to demonstrate attainment of the PM-10 NAAQS. The 

incorporation of the permits into the SIP means that any revision to such permits must go through the 

extensive SIP revision process. The maintenance demonstration also relies on NOx limitations at the 

plant. NOx emissions are already subject to federal regulations that achieve the same result, albeit with a 

different averaging time and calculation method. EPA, however, has asserted that the limitation must be 

expressed as a short-term limit incorporated into the SIP. The division disagrees with EPA's interpretation 

of federal law, but does not believe that the circumstances warrant challenging EPA's position. Public 

Service Company has consented to the inclusion of certain S02 and NOx emission limitations (calculated 

on a rolling thirty-day average basis) in the regulation and the SIP in order to resolve the matter with EPA. 

EPA has indicated that these limitations are adequate to resolve its concerns and, with them as a 

substitute, will agree that the Cherokee and all other permits may be removed from the SIP. 

Therefore, all permit limits and conditions contained in permits for the following facilities are specifically 

removed from the SIP: Trigen-Colorado Energy; Public Service Company; Purina Mills; Electron 

Corporation; Ultramar Diamond Shamrock; Conoco Refinery; Rocky Mountain Bottle; and Robinson Brick. 

A SIP revision shall not be required to modify permit limits and conditions for these facilities. Any 

increases in emission limits contained in Regulation NO.1 that are also incorporated into the SIP would 

require a SIP revision. 

For these reasons, the commission has determined that it is appropriate to include the requirements in 

the SIP and the regulation. Public Service Company has asked, and the commission agrees, that these 

new emission limitations should not become effective unless and until EPA approves the SIP. 

In 1998, the commission approved a voluntary emission reduction agreement between Public Service 

Company and the division pursuant to C.RS. §25-7-1201et seq. Under that agreement as amended, 

Public Service Company agreed, among other things, that it would permanently shutdown and retire 

Arapahoe Units 1 and 2 on January 1, 2003. This retirement of these two units was also used to show 

maintenance of the NAAQS. Despite the fact that the retirement is an enforceable commitment of the 

company under state law, EPA objected to the assumption that Arapahoe Units 1 and 2 will shutdown in 
2003. The EPA asserts that the maintenance plan must include a federally enforceable provision 

mandating the closures. Again, the division disagrees with the EPA's position and believes that it may 

properly rely upon the provisions of the voluntary agreement to demonstrate maintenance of the 

standard. However, again in order to resolve the disagreement with the EPA, the Public Service 

Company consented to the inclusion of the shutdown requirements in the State regulations and the 

federally enforceable SIP. 

In the voluntary agreement, the retirement of Arapahoe Units 1 and 2 does not forbid Public Service 

Company (or some other person) from reusing the Arapahoe 1 and 2 plant site or equipment, provided 

that such reuse is subject to new source permitting requirements. The Company, as is its right under 

C.RS. §25-7-1203(6), consented to the EPA's desire to include the retirement in the SIP only if the SIP 

and the state regulations recognize that such reuse is allowed subject to the new source permitting 

requirements. Therefore, the commission has determined that language in the proposed regulation 

allowing for such reuse is necessary and appropriate. This language will allow PSCO or some other party 

to use the Arapahoe Unit 1 or 2 equipment or plant site for the construction and operation of a new 

source, provided that, depending on its level of emissions, the new source obtains the applicable minor or 

major source permit. 

The Company also asked that the regulatory SIP provision should not apply if EPA disapproves the 

maintenance plan and redesignation request. Therefore, the regulation expressly states that it will take 

effect upon EPA approval of the redesignation request. This provision in the regulation is not to be 

construed to mean that approval of redesignation request is required in order for the voluntary agreement 

between the State and the Public Service Company to take effect. The regulation is not intended to 

supercede or modify the agreement. The agreement shall be effective whether or not the regulation takes 

effect. The commission adopted the regulation in order to satisfy EPA's demand to incorporate the 

shutdown requirement in the SIP, without incorporating the entire agreement into the SIP. Only the 

provisions applicable to the Arapahoe 1 and 2 retirement described in the regulation have been 

incorporated into the SIP. 

Statutory Authority 

Specific statutory authority to redesignate areas to attainment is provided in section 25-7-107, C.RS. 

(1999). The authority to adopt the regulations necessary to maintain the NAAQS is set out at section 25­

7-105(1 )(a)(I). C.RS. The authority to control particulate emissions is set out in section 25-7-109(2)(b), 

C.RS. 

Findings pursuant to section 25-7-110.8 

Section 25-7-110.8 requires the commission to make specific findings concerning any regulation intended 

to reduce air pollution. The April 2001 amendments to Regulation No.1 put into regulation pre-existing 

requirements. Although the regulations change the averaging time for S02 and NOx limitations, and thus 

appear to make the existing requirements more stringent, the units were already in compliance with the 

revised standards based on the shorter averaging times. Thus, some of the determinations required by 

section 25-7-110.8 are irrelevant. To address the remaining, applicable requirements of 25-7-110.8, the 

commission determines that: (1) all validated, reviewed and sound scientific methodologies and 

information made available by interested parties has been considered; and (2) the amendments adopted 

represent the most cost-effective option. 

Adopted April 19, 2001 

COLORADO AIR QUALITY CONTROL COMMISSION 

Statement of Basis, Specific Statutory Authority, and Purpose 
Revisions to Regulation No.1: Sections II.A. 1-10; II.B.3., II.C.2.d.; Sections III.A.1.d., A.3.; III.BA.a. & 

b.; III.C.2-4; Section IV.I.; Section V; Section VI.A.f.; Section VI.B.2. and VI.BA.(iv); VI.C.1.; Sections 

VII.A.1, A.2. & A.3.; Sections VillA & E. 

Adopted: August 16, 2001 

This Statement of Basis, Specific Statutory Authority and Purpose complies with the requirements of the 

Colorado Administrative Procedures Act, section 24-4-103, C.RS., and the Colorado Air Pollution 

Prevention and Control Act, sections 25-7-110 and 25-7-110.5, C.RS. ("the Act"). 

Specific Statutory Authority 

The Act, section 25-7-109, C.RS., provides the commission the authority to adopt and revise rules and 

regulations that are consistent with state policy regarding air pollution and with federal recommendations 

and requirements. 

Regulation NO.1 deals with opacity, particulate, and sulfur dioxide emissions from various sources. This 

rule revises the title of the regulation, deletes obsolete parts of this regulation and conforms the regulation 

to the "Credible Evidence" rule adopted by the commission on April 19, 2001 (refer to Common 

Provisions Regulation, section 11.1.). The rule also deletes section II.A.10. and related provisions 

concerning good air pollution practices for coal-fired utility boilers. Finally, the rule revises the 

methodology and calculation for emissions from multiple fuel burning units ducted through a common 

stack in section III.A.1.d. 

Purpose 

In April 2001, the commission adopted the "Credible Evidence" rule into its Common Provisions 

Regulation, section 11.1. That rule allows for the use of any credible evidence for the purpose of submitting 

Title V compliance certifications or establishing whether a source has violated or is in violation of any 

emissions standard contained in any regulation that has been submitted to the U.S. Environmental 

Protection Agency. The revisions to Regulation NO.1 remove conflicting language from Regulation No.1, 

and clarify that the EPA Method 9 is the approved visible emissions reference test method for the credible 

evidence rule. The opacity requirements in Regulation NO.1 were adopted based on the use of Method 9 

for determining compliance with such requirements. This action also clarifies that, for purposes of 

compliance determinations, the particulate emissions standards found in Regulation NO.1 do not include 

the condensable or "back half' portion of the emissions train. 

In 1992, section 25-7-109(8), C.RS., was added to the Act to prohibit the regulation of most agricultural 

activities. In some circumstances, however, agricultural open burning may be subjected to commission 

regulation (section 25-7-123, C.RS.). In order to address the confusion regarding open burning of animal 

parts and carcasses, the rule now expressly states that the open burning of animal parts and carcasses is 

not exempt from permit requirements. A special allowance to conduct open burning activities without a 

permit is provided where the State Agricultural commission declares a public health emergency or a 

contagious or infectious outbreak of a disease that imperils livestock and diseased carcasses must be 

destroyed on weekends or holidays. In this case, voice mail messages must be left with the division and 

any local health department, and adequate notice must be provided to neighboring residences, schools, 

and businesses prior to burning. This allows the division to promptly respond to complaints about smoke 

from these activities and provides an opportunity for the neighboring community to take steps to minimize 

smoke exposure, e.g., close windows and schedule indoor activities. 

Certain provisions that regulate "grandfathered" sources that do not exist in Colorado, such as wigwam 

burners, static firing of Pershing missiles at the Pueblo Army Depot. and standards for iron and steel plant 

operations, are removed. Rocky Mountain Steel Mills is the only iron and steel plant in Colorado, and only 
those provisions that are relevant to this operation have been retained. Provisions regulating coke ovens 

at steel mills, blast ovens, basic oxygen furnaces, and sinter plants have been removed as obsolete. 

Section IIA1O, and related provisions found in II.A.4. and VI.B., concerning emissions from coal-fired 

utility boilers, is removed. These provisions were added in 1996, and have never been approved by the 

U.S. EPA. However, the commission reaffirms the findings in the Statement of Basis, Specific Statutory 

Authority and Purpose associated with the 1996 rulemaking. There are technical concerns related to the 

ability of continuous opacity monitors to obtain accurate readings during periods when the boilers, fans 

and process equipment at coal-fired electric utility plants are off. As an alternative approach, the 

commission has proposed adoption of Affirmative Defense Provisions to be added to the Common 

Provisions Regulation to recognize the issues related to periods of excess emissions during startup and 

shutdown conditions of coal-fired utility boilers and other sources. Consequently, leaving these provisions 

in Regulation NO.1 renders coal-fired utility boilers subject to federal opacity requirements and conflicting 

and confusing state-only requirements. The commission wishes to remove such conflict and confusion. 

The rule revises section 111.A.1.d. to more accurately calculate emissions from multiple fuel burning units 

ducting to a common stack (because it is not possible to sum the pounds per 106 British thermal units, as 

is currently reflected in the regulation). 

Regarding the approval of alternative performance test methods in sections 111.A.2. and 111.C.3., the 

commission intends that the existing practice of the division in consulting with the owner or operator of a 

source regarding appropriate alternative test methods will continue. Those consultations should include 

discussions why the reference method or other alternative methods are inappropriate. The commission 

recognizes that the division must approve any alternative test method but that the owner or operator of a 

source may appeal that determination to the commission. 

In section VII.,A.1., A.2. and A.3., the Public Service Compliance date of January 1, 1995 has been 

deleted as obsolete. In addition, emissions limitations are placed on the Valmont Electric Generating 

Station in Boulder, Colorado, Units 1, 2, 3, and 4. In reality, Valmont only has a Unit 5, and thus revisions 

are made to reflect this reality. 

In section VIII, fuel restrictions are placed on specified sources. The regulation is revised to reflect a 

name change of a source and to revise the example of a reporting tool referenced in this section. 

The Regulation NO.1 revisions adopted by the Air Quality Control commission as described above will be 

submitted to the EPA as part of the State Implementation Plan. 

COLORADO AIR QUALITY CONTROL COMMISSION 

ADOPTED: August 16, 2001 

APPENDIX A 

Method for Measuring Opacity from Fugitive Particulate Emission Sources 

a.	 Principle and Applicability 

(i)	 Principle. The opacity of emissions from fugitive particulate emission sources is 

determined visually by a qualified observer. 

(ii)	 Applicability. This method is applicable for the determination of the opacity of emissions 

from fugitive particulate emission sources and for qualifying observers for visually 

determining opacity of emissions; provided, however, this method shall not be used when 

wind velocities exceed 30 m.p.h. as determined by records from the nearest official 

station of the U.S. Weather Service, by interpretation of surface weather maps by a 
qualified meteorologist, or by use of one or more anemometers at the site. The division 

shall use anemometers where practicable. 

b.	 Procedures. The observer qualified in accordance with Section c. of this method shall use the 

following procedures for visually determining the opacity of emissions: 

(i)	 Position. The qualified observer shall stand at a distance sufficient to provide a clear view 

of the emissions with the sun oriented in the 1400 sector to his back. Consistent with 

maintaining the above requirement, the observer shall, as much as possible, make his 

observations from a position such that his line of vision is approximately perpendicular to 

the plume direction. The observer's line of sight should not include more than one plume 

at a time. Where the plumes from more than one source have been combined such that it 

is not possible to observe the emissions from a subject source alone this method shall 

not be applied to the "combined plume" to determine the opacity of emissions from any of 

the contributing sources. Emissions from rock or mineral drilling, crushing, conveying, 

screening, and storing are evaluated in the following manner: 

(A)	 Drilling. Emissions from drilling operations are evaluated at the point at which 

they are released from the drilling device or from the drill hole. 

(8)	 Crushing. Emissions included at this evaluation point are released as material is 

discharged from the primary and secondary crushing machines. Observations 

are performed on the same elevation as the discharge if possible. 

(C)	 Conveying. Visible emissions are evaluated as material is discharged at 

conveyer belt transfer points and loading points. Evaluation shall occur at the 

same elevation as the discharge if possible. 

(D)	 Screening. Visible emissions are evaluated as material is discharged from the 

screen into the chutes. The observer shall obtain an observation point as close to 

the same elevation of the screens as possible. 

(E)	 Storage. Observations are performed at ground level. 

(F)	 In operations involving rock or mineral drilling, moisture content of the material 

plays an important part in type and quantity of visible emissions. Therefore, any 

moisture in the feedstock or addition of moisture to the process should be noted 

on the field data sheet. 

(G)	 Emissions from all other sources of fugitive particulate emissions SUbject to this 

regulation shall be evaluated in a manner consistent with the above procedures. 

(ii)	 Field Records. The observer shall record the name of the plant, emission location, type 

facility, observer's name and affiliation, and the date on a field data sheet. The time, 

estimated distance to the emission location, approximate wind direction, estimated wind 

speed, description of the sky condition (presence and color of clouds), and plume 

background are recorded on a field data sheet at the time opacity readings are initiated 

and completed. 

(iii)	 Observations. Opacity observations shall be made at the point of greatest opacity in the 

plume and with a background of contrasting color. The observer shall not look 

continuously at the plume, but instead shall observe the plume momentarily at 15-second 

intervals. The observer shall record the approximate distance from the emission outlet to 

the point in the plume at which the observations are made. 
(iv)	 Recording Observations. Opacity observations shall be recorded to the nearest 5 percent 

at 15-second intervals on an observational record sheet. A minimum of 24 observations 

shall be recorded. Each momentary observation recorded shall be deemed to represent 

the average opacity of emissions for a 15-second period. 

(v)	 Data Reduction. Opacity shall be determined as an average of 24 consecutive 

observations recorded at 15-second intervals. Divide the observations recorded on the 

record sheet into sets of 24 consecutive observations. A set is composed of any 24 

consecutive observations. Sets need not be consecutive in time and in no case shall two 

sets overlap. For each set of 24 observations, calculate the average by summing the 

opacity of the 24 observations and dividing this sum by 24. If an applicable standard 

specifies an averaging time requiring more or less than 24 observations, calculate the 

average for all observations made during the specified time period. Record the average 

opacity on a record sheet. 

c.	 Qualifications and Testing 

(i)	 Certification requirements. To receive certification as a qualified observer, a candidate 

must be tested and demonstrate the ability to assign opacity readings in 5 percent 

increments to 25 different black plumes and 25 different white plumes, with an error not 

to exceed 15 percent opacity on anyone reading and an average error not to exceed 7.5 

percent opacity in each category. Candidates shall be tested according to the procedures 

described in paragraph c. (ij). Smoke generators used pursuant to this paragraph shall be 

equipped with a smoke meter which meets the requirements of paragraph c.(iii). 

The certification shall be valid for a period of six months, at which time the qualification 

procedure must be repeated by the observer in order to retain certification. 

(ii)	 Certification Procedure. The certification test consists of showing the candidate a 

complete run of 50 plumes - 25 black plumes and 25 white plumes - produced by a 

smoke generator. Plumes within each set of 25 black and 25 white runs shall be 

presented in random order. The candidate assigns an opacity value to each plume and 

records his observation on a suitable form. At the completion of each run of 50 readings, 

the score of the candidate is determined. If a candidate fails to qualify, the complete run 

of 50 readings must be repeated in any retest. The smoke test may be administered as 

part of a smoke school or training program, and may be preceded by training or 

familiarization runs of the smoke generator during which candidates are shown black and 

white plumes of known opacity. 

(iii)	 Smoke Generator Specifications. Any smoke generator used for the purposes of 

paragraph c. (ii) shall be equipped with a smoke meter installed to measure opacity 

across the diameter of the smoke generator stack. The smoke meter output shall display 

in stack opacity based upon a path length equal to the stack exit diameter, on a full 0 to 

100 percent chart recorder scale. The smoke meter optional design and performance 

shall meet the specifications shown in Table 1. The smoke meter shall be calibrated as 

prescribed in paragraph c. (iii)(A) prior to the conduct of each smoke reading test. At the 

completion of each test, the zero and span drift shall be checked and if the drift exceeds 

1 percent opacity, the condition shall be corrected prior to conducting any subsequent 

test runs. The smoke meter shall be demonstrated, at the time of installation, to meet the 

specifications listed in Table 1. This demonstration shall be repeated following any 

subsequent repair or replacement of the photocell or associated electronic circuitry 

including the chart recorder or output meter, or every 6 months, whichever occurs first. 

(A) Calibration. The smoke meter is calibrated after allowing a minimum of 30 minutes 

warm-up by alternately producing simulated opacity of 0 percent and 100 percent. 

When stable responses at 0 percent or 100 percent is noted, the smoke meter is 
adjusted to produce an output of a percent or 100 percent, as appropriate. This 

calibration shall be repeated until stable a percent or 100 percent readings are 

produced without adjustment. Simulated 0 percent and 100 percent opacity values 

may be produced by alternately switching the power to the light source on and off 

while the smoke generator is not producing smoke. 

Table 1 

Smoke Meter Design and Performance Specifications 

Parameter	 Specification 

a.	 Light Source Incandescent lamp 

operated at nominal 

rate voltage 

b.	 Spectral Photopic (daylight
 

Response of spectral response
 

Photocell	 of the human eye ­

reference d(iii))
 

c.	 Angle of View 15° maximum total
 

angle
 

d.	 Angle of Projection 15° maximum total
 

Angle
 

e.	 Calibration Error 3% opacity,
 

maximum
 

f.	 Zero and Span 1% opacity,
 

maximum
 

g. Response Time Five seconds 

S.	 Smoke Meter Evaluation. The smoke meter design and performance are to be 

evaluated as follows: 

(1)	 Light Source. Verify from manufacturer's data and from voltage 

measurements made at the lamp, as installed, that the lamp is operated 

within 6 percent of the nominal rated voltage. 

(2)	 Spectral Response of Photocell. Verify from manufacturer's data that the 

photocell has a photopic response; i.e., the spectral sensitivity of the cell 

shall closely approximate this standard spectral-luminosity curve for 

photopic vision which is referenced in (b) of Table 1. 

(3)	 Angle of View. Check construction geometry to ensure that the total 

angle of view of the smoke plume, as seen by the photocell, does not 

exceed 15°. The total angle of view may be calculated from: ?=2 tan d/2L 

where ?=total angle of view; d=the sum of the photocell diameter + the 

diameter of the limiting aperture; and L=the distance from the photocell 
to the limiting aperture. The limiting aperture is the point in the path 

between the photocell and the smoke plume where the angle of view is 

most restricted. In smoke generator smoke meters this is normally an 

orifice plate. 

(4)	 Angle of Projection. Check construction geometry to ensure that the total 

angle of projection of the lamp on the smoke plume does not exceed 15°. 

The total angle of projection may be calculated from: ?=2 tan-' d/2L, 

where ?=total angle of projection; d=the sum of the length of the lamp 

filament and the diameter of the limiting aperture; and L=the distance 

from the lamp to the limiting aperture. 

(5)	 Calibration Error. Using neutral-density filters of known opacity, check 

the error between the actual response and the theoretical linear 

response of the smoke meter. This check is accomplished by first 

calibrating the smoke meter according to (1) and then inserting a series 

of three neutral-density filters of nominal opacity of 20, 50, and 75 

percent in the smoke meter path length. Filters calibrated within 2 

percent shall be used. Care should be taken when inserting the filters to 

prevent stray light from affecting the meter. Make a total of five 

nonconsecutive readings for each filter. The maximum error on anyone 

reading shall be 3 percent opacity. 

(6)	 Zero and Span Drift. Determine the zero and span drift by calibrating and 

operating the smoke generator in a normal manner over a 1-hour period. 

The drift is measured by checking the zero and span at the end of this 

period. 

(7)	 Response Time. Determine the response time by producing the series of 

five simulated 0 percent and 100 percent opacity values and observing 

the time required to reach stable response. Opacity values of 0 percent 

and 100 percent may be simulated by alternately switching the power to 

the light source off and on while the smoke generator is not operating. 

References 

(i)	 Air Pollution Control District Rules and Regulations, Los Angeles County Air Pollution Control 

District, Regulation IV Prohibitions, Rule 50. 

(ii)	 Wefsburd, Melving L., Field Operations and Enforcement Manual for Air, U.S. Environmental 

Protection Agency, Research Triangle Park, N.C., APTD-1100, August 1972, pp. 4.1-4.36. 

(iii)	 Condon, E. U., and Oldshaw, H., Handbook of Physics, McGraw Hill Co., N.Y., N.Y. 1958, Table 

3.1, p. 6-52. 

(iv)	 EPA Visible Emission Inspection Procedures, August 1975. 

APPENDIX B 

Method of Measurement of Off-Property Transport of Fugitive Particulate Emissions 

a.	 Applicability. This method is applicable for the determination of the off-property transport of 

fugitive particulate emissions sources covered by Section III.D.2 of this regulation; provided, 

however, this method shall not be used when wind velocities exceed 30 m.p.h. as determined by 

records from the nearest official station of the U.S. Weather Service, by interpretation of surface 
weather maps by a qualified meteorologist, or by use of one or more anemometers at the site. 

The division shall use anemometers where practicable. 

b.	 Procedure 

(i)	 Position. The observer shall stand at a distance sufficient to provide a clear view of the 

emissions with the sun oriented in the 1400 sector to his back. The observer shall position 

himself off said property so as to be able to sight along a line which does not cross the 

property of emission origination. Consistent with maintaining the above requirements, the 

observer shall, to the extent possible, make his observations from a position such that his 

line of vision is approximately perpendicular to the plume direction. 

(ii)	 Field Records. The observer shall record the name of the plant, emission location, type 

facility, observer's name and affiliation, and the date on a field data sheet. The time, 

estimated distance and the emission location, approximate wind direction, estimated wind 

speed, description of the sky condition (presence and color of clouds), and plume 

background are recorded on a field data sheet at the time readings are initiated and 

completed. 

(iii)	 Observations. Observations shall be made in accordance with the provisions of this 

Appendix B sighting along a line which does not cross the property of emission 

origination and two such observations of fugitive particulate emissions transported off the 

property of at least 15 seconds in duration [within 24 hours] must be made and must be 

separated by at least fifteen (15) minutes. 

Statement of Basis, Specific Statutory Authority And Purpose 

Revisions to Colorado Air Quality Control commission Regulation No.1 January 17, 2002 

This Statement of Basis, Specific Statutory Authority and Purpose complies with the requirements of the 

Colorado Administrative Procedures Act, section 24-4-103, C.RS. and the Colorado Air Pollution 

Prevention and Control Act, sections 25-7-110 and 25-7-110.5 and implements parts of sections 25-7­

106(7) and (8),25-7-114.7 and 25-7-123, C.RS. 

These rule revisions implement the provisions of Senate Bill 01-214 and relocate, update and reorganize 

existing provisions of RegUlation NO.1 relating to open burning into Regulation No.9. Regulation NO.9 

deals solely with open burning activities. This new regulation contains permitting, monitoring, reporting 

and fee provisions, as well as requirements particular to significant users of prescribed fire. 

Specific Statutory Authoritv 

The Colorado Air Pollution Prevention and Control Act, sections 25-7-109(2)(e) and 25-7-123, C.R.S., 

provides the authority for the commission to adopt and modify a program including emissions control 

regulations to control burning activities. Sections 25-7-106(7) and 25-7-106(8), 25-7-114.7(2)(a)(III) and 

25-7-123, C.RS., set forth specific requirements relating to activities by significant users of prescribed 

fire, inclUding open burning activities by federal land managers. 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.RS. 

Purpose 

Open Burning 
The focus of SB 01-214 is on open burning activities by significant users of prescribed fire. Addressing 

open burning issues is necessary in order to address emissions from natural and prescribed fires. The 

Grand Canyon Visibility Transport commission identified these fires as having enough episodic impact on 

visibility at class I areas to overwhelm progress made through other emission control measures. The 

commission views reduction of visibility impairment from fires as an important component in achieving 

federal and state visibility goals. This regulation should ensure that users of prescribed fire consider air 

pollution impacts in making determinations whether, and under what conditions, to use fire for grassland 

or forest management. 

Permitting 

The regulation continues the existing prohibition on open burning absent a permit from the division or a 

local agency. The exemptions from this requirement also remain largely the same. In particular, 

agricultural open burning activity does not require a permit. 

The regulation specifies factors that the division must consider in deciding whether, and under what 

conditions, to issue a burning permit. These factors differ depending on the type of permit applicable to 

the proposed activity. 

General open burning permits are the basic permits for most burning activities. General permits require 

that an applicant use best smoke management techniques to reduce or eliminate smoke impacts on the 

health and welfare of the public. Although the regulation includes a partial listing of methods to minimize 

fire emissions and smoke impacts, the commission intends that the division will exercise its discretion to 

achieve the goals of this regulation without imposing unreasonable conditions. General open burning may 

be delegated by the division to local counties. 

The next category of fire addressed by this regulation is planned ignition fires, which are a subset of 

prescribed fires for grassland and forestland management. The commission decided to establish an 

emissions and smoke de minimus threshold below which a permit applicant must only obtain a general 

open burning permit. For fires that will exceed that threshold, applicants intending to initiate a fire must 

obtain a permit for a planned ignition fire. Permits for this type of fire must address additional concerns 

beyond those applicable to general open burning activities. The commission listed factors for division 

consideration in determining whether, and under what conditions, to issue a permit. This list is not 

exclusive and the division may incorporate in permits additional conditions if it finds them necessary to 

minimize the impacts of fire on visibility and on public health and welfare. These factors focus on 

identifying and minimizing impacts to smoke-sensitive receptors. In addition, planned ignition permit 

conditions should ensure that the permittee will take appropriate action to ensure that the fire remains 

within the terms of the permit or is managed so as to return it within those terms, or that the permittee will 

suppress the fire if compliance with permit terms cannot otherwise be achieved. 

Unplanned ignition fire permits offer persons a mechanism to use fire for grassland or forest management 

even though the precise time and location of a particular prescribed fire cannot be anticipated. These 

permits generally will apply to larger parcels of land, in some portion of which unplanned ignition may 

occur. The purpose of this permit type is to determine before ignition the conditions under which the fire 

may be used for resource benefit. As with planned ignition fires, permit conditions should ensure that the 

permittee will take appropriate action to ensure that the fire remains within the terms of the permit or is 

managed so as to return it within those terms, or that the permittee will suppress the fire if compliance 

with permit terms cannot otherwise be achieved. 

This regulation focuses on fires that a person intends to use for a beneficial purpose, such as grassland 

or forest management. The commission distinguished between those fires and wildfires. Wildfires are 

beyond the scope of this regulation and no permitting requirements apply to a land manager within whose 

jurisdiction a wildfire occurs. 

The commission also concluded that a public comment opportunity should be available regarding fires 

with a high smoke risk. The commission intends that a high smoke risk rating be equivalent to a rating of 
41 or greater from the draft Smoke Risk Rating Worksheet prepared by the division in conjunction with 

some users of prescribed fire and attached to this Statement of Basis and Purpose as Attachment A. The 

commission recognizes that the division and users of prescribed fire may find it appropriate to revise the 

smoke risk rating methodology in the future. If this is done, the commission intends that what constitutes 

a high smoke risk burn will consider at least the same factors as in Attachment A, and the point at which a 

fire becomes a high smoke risk should be equivalent to a rating of 41 on Attachment A. 

The division will determine which fires have a high smoke risk through consideration of the factors 

reflected in Attachment A. If, after considering these factors, the division concludes that the fire has a high 

smoke risk, it will allow the public thirty days in which to submit comments regarding whether a permit 

should be issued and what conditions are appropriate for inclusion in the permit. For planned ignition 

prescribed fires, the notice will include information about location of the fire, expected burn dates, 

expected duration of the fire, potential emissions, and potential air quality and visibility impacts at smoke 

sensitive receptors. The commission intends that the division either add appropriate conditions or 

combine permits to prevent circumvention of the public comment requirement, should a permit applicant 

submit separate applications that may have the effect of dividing burns that are more appropriately 

considered together. This comment opportunity is subject to the commission's Procedural Rules and 

includes the rights to a public comment hearing provided in those Rules. The comment opportunity does 

not include a right to an adjudicatory hearing to appeal issuance of a permit, as only the permit applicant 

may request such a hearing. Persons would still have recourse to seek judicial review of permits pursuant 

to the Administrative Procedures Act. 

Significant users of prescribed fire 

Senate Bill 01-214 imposes on significant users of prescribed fire additional requirements to ensure that 

that those users consider air quality impacts in making decisions about when, and under what conditions, 

they will use fire for grassland or forest management. Senate Bill 01-214 defined a significant user of 

prescribed fire as a person or agency that collectively manages or owns more than 10,000 acres of land 

and that uses prescribed fire. The commission enlarged on the part of this definition dealing with use of 

prescribed fire by establishing a minimum activity level based on PM10 emissions during a calendar year. 

The commission concludes that users of prescribed fire at levels below this threshold do not have 

significant enough an impact on visibility and air quality to justify their inclusion in this part of the smoke 

management program. This provision will focus the regulatory requirements and the resources of the 

division and others on the prescribed fires with the greatest potential impact on visibility and human 

health and welfare. The commission did not establish a de minimus threshold for other open burns, as 

even small fires intended to dispose of trash, rubbish and similar materials may have disproportionate 

impacts on local air quality. 

The regulation imposes additional duties on significant users of prescribed fire, consistent with specific 

requirements in SB 01-214. Section 25-7-106(8)(b), C.R.S., requires that significant users submit 

planning documents to the commission for comment and recommendations. This section also anticipates 

a hearing on the plans to allow public input. This public hearing requirement is similar to public hearing 

options applicable to major stationary source permitting. Public input on regulatory compliance and 

permits for major sources is important to public confidence in air pollution control efforts, particularly for 

long-term planning documents. 

The commission will hold public hearings to review the planning documents and may make comments 

and recommendations regarding the plans. Open burning permits for general, planned and unplanned 

ignition fires can only be issued to significant users of prescribed fire if the permit is consistent with the 

comments and recommendations of the commission. The commission intends that, wherever possible, 

the division will issue a permit with appropriate conditions in order to meet this requirement, rather than 

denying the permit altogether. This approach recognizes the value of prescribed fire in grassland and 

forestland management, but ensures that the air quality goals of SB 01-214 and this regUlation are 

adequately protected. 
The commission defined planning documents and tailored the applicable regulatory requirements to focus 

submittals and commission review on the process used by a significant user of prescribed fire, rather than 

on the results of that process in a specific instance. The commission does not intend to challenge land 

use decisions made by the land manager. The purpose of the commission comments and 

recommendations will be to ensure that the land manager adequately considers air quality impacts when 

making decisions whether, and under what conditions, to use prescribed fire. The commission planning 

document review will focus on how a significant user of prescribed fire will meet the state air quality 

protection standard expressed in section 25-7-106(7)(e), C.R.S 

Planning documents should summarize the decision process by which the land manager identifies and 

selects among alternative treatment methods for fuel reduction. The documents should provide a specific 

description relevant to accomplishment of the state air quality goal expressed in § 25-7-106(7)(e), C.R.S. 

This requirement will focus the land manager decision-making process on the goals of Senate Bill 01-214. 

The commission recognizes that planning documents will vary in their level of detail and sophistication in 

describing decision mechanisms used by land managers, particularly during the initial set of commission 

reviews. commission comments and recommendations may extend to beneficial changes in planning 

documents as well as improvements in the land manager planning process related to consideration of the 

state air quality goal. 

Specific permit conditions may be excluded from a permit if a federal land manager asserts that a federal 

statute specifically prohibits the compliance with the condition. In adopting this regulation, the commission 

made no evaluation whether any particular federal statute or permit condition may justify exclusion of a 

permit condition Nevertheless, section 118 of the federal Clean Air Act, 42 U.S.C. §7418, subjects 

federal agencies engaging in activities resulting, or which may result, in discharge of air pollutants to state 

requirements on control and abatement of air pollution "in the same manner, and to the same extent as 

any nongovernmental entity." This waiver of federal sovereign immunity allows states to subject federal 

agencies to any substantive, procedural, permitting, fee or any other requirement. The Colorado General 

Assembly enacted §25-7-106(7), C.R.S., pursuant to §118 and directed that this subsection be construed 

to exercise the full extent of the state's authority regarding pollution from federal facilities. The 

commission intends these revisions to comport with §118 and to exercise the state's authority to its full 

extent. The division should consider this intent in deciding whether a federal statute specifically prohibits 

imposition of a particular permit condition. 

The rule also establishes a means for dealing with outdated plans or documents. The commission chose 

to view a plan as being outdated upon expiration of the period for which the plan itself states it is 

applicable, up to ten years. The commission may make comments or recommendations in the review 

process that urge a shorter applicable period than anticipated in the planning document. Any such 

comments will recognize applicable constraints on preparation of updated documents, such as the 

provisions of the National Environmental Policy Act. 

The regulation establishes a means for dealing with lands acquired by a significant user of prescribed fire 

after the commission reviews an initial or later version of a planning document. The commission 

concluded that requiring changes and further review of planning documents whenever a significant user 

acquires land would unduly increase the burdens of the review process on the commission, the division 

and the land managers. In general, the commission anticipates addressing planning documents for these 

lands at the next regular review, so long as the acquired lands will be managed in largely the same way 

as those already addressed by the commission. Where there will be a substantial difference in 

management of the acquired lands, the commission concluded that the land manager must submit 

planning documents to address the anticipated management. 

Fees and Monitoring 

Senate Bill 01-214 directed the commission to include within its smoke management program provisions 

for fees necessary to pay for administration of the program. Since the General Assembly granted the 

direct authority to develop a fee program for the smoke management program, the commission is not 
required to utilize the fee mechanism applicable to traditional stationary sources. The commission chose 

to apportion the cost of administering the program among users of prescribed fire rather than relying on 

traditional emissions fees. In part, this conclusion was due to the unique characteristics of this emission 

source category including highly variable emissions from one year to the next. Therefore, the commission 

.concluded that the traditional emission fee approach would result in substantially greater administrative 

burdens for both the division and for users of prescribed fire. The methodology adopted combines the 

proportion of the total number of permits and total PM10 emissions of a particular user to determine the 

appropriate fraction of the program cost payable by that user. This approach will provide an equitable 

distribution of the costs of administering the common elements of the program. The commission intends 

that fees paid by stationary sources will not be used to pay any portion of the smoke management 

program costs. 

The total administrative cost of $129,646.45 at the outset is specified in an appendix to the regulation and 

the commission intends that any change to it or the distribution methodology occur only through a 

properly noticed public rule-making hearing before the commission. To that end, the cost is included in 

the regulation as the regulatory "fee." The division cost for program administration will be recalculated 

annually and reported to the commission each August. If the total cumulative dollar difference between 

the cost reflected in the regulation and the division's annual calculation exceeds five percent, the division 

will seek a fee change through a commission rulemaking. The "total cumulative dollar difference" between 

the regulatory fee and the annual cost will be calculated considering personnel and indirect and operating 

costs associated with the program, and the cumulative dollar difference from the previous year. This 

calculation will be performed substantially in accordance with the Colorado Smoke Management Program 

Cost and Fee Calculation Template (Attachment B). The commission also intends that the actual revenue 

collected be reported annually. If collections are consistently below projections, the division shall seek an 

appropriate fee adjustment consistent with the shortfall in revenue. 

In addition, the commission imposed a fee pursuant to section 25-7-114.7(2)(A)(III), C.R.S., to cover the 

direct and indirect costs of evaluating planning documents submitted to the commission. In order to 

reduce the administrative burden on the division and permittees, both the evaluation fees and the 

administration fee will be billed annually. 

The rule revisions adopted address the procedural mechanisms for accomplishing the mandatory 

requirements of Senate Bill 01-214. The general structure of the smoke management program has been 

established by statute. The commission's rule implements that legislative prescription; the revisions 

adopted set a de minimus level for significant users of prescribed fire, establish a fee mechanism and 

delineate the specifics of the program anticipated by the statute. 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.RS. The commission 

also concludes it has no discretion under state law to adopt alternative rules that differ significantly from 

these revisions, for the purposes of § 25-7-110.8(1), C.RS. 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 25-7-1 09( 1)(b), 

C.RS. 

COLORADO AIR QUALITY CONTROL COMMISSION 

ADOPTED: JANUARY 17, 2002 

Statement of Basis, Specific Statutory Authority, and Purpose Revision to Regulation No.1: 

Section VIII.A Adopted June 19,2003 
This Statement of Basis, Specific Statutory Authority and Purpose complies with the requirements of the 

Colorado Administrative Procedures Act, § 24-4-103, C.RS., 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 

Section 25-7-107, C.RS., provides the commission authority to review the current classification of any 

attainment, non-attainment, or unclassifiable area within the State. In addition, § 25-7-109, C.RS., 

provides the commission authority to adopt, promulgate, modify and/or repeal emission control 

regulations that require the use of air pollution controls, including those regulations pertaining to 

particulates [§ 25-7-1 09(2)(b), C.RS.]. 

Basis and Purpose 

Regulation NO.1 deals with opacity, particulate, and sulfur dioxide emissions from various sources. This 

amendment to Regulation No.1 revises Section VIII.A, wherein a clerical error, which inadvertently 

materialized subsequent to the adoption of unrelated revisions to Regulation NO.1 during the August 

2001 hearing, misrepresents the Denver area's PM-1 0 attainment/maintenance status. Section VIII.A 

erroneously referred to the Denver PM-1 0 non-attainment area, even though the area has been 

redesignated to "attainment/maintenance" for PM-1 0 (50 CFR 81.306). The EPA noted the discrepancy 

and asked the State to fix it when it approved the Denver PM-1 0 maintenance plan in September 2002 

(40 CFR 52.320(c)(95)(i)(I)). This revision remedies the error. 

COLORADO AIR QUALITY CONTROL COMMISSION ADOPTED: June 19, 2003 

Statement of Basis, Specific Statutory Authority, and Purpose 

Revision to Regulation No.1, Particulate Matter, Smoke, Carbon Monoxide and Sulfur Oxides 

July 21, 2005 

This Statement of Basis, Specific Statutory Authority and Purpose complies with the requirements of the 

Colorado Administrative Procedures Act, § 24-4-103, C.RS., and the Colorado Air Pollution Prevention 

and Control Act, §§ 25-7-110 and 25-7-110.5, C.RS ("the Act"). 

Specific Statutory Authority 

Section 25-7-109, C.RS., provides the Commission authority to adopt, promulgate, modify and/or repeal 

emission control regulations that require the use of air pollution controls. [§ 25-7-109(1 )(a), C.RS.]. 

Basis and Purpose 

Regulation NO.1 generally sets forth emission limitations, equipment requirements, and work practices 

(abatement and control measures) intended to control the emissions of particulates, smokes, and sulfur 

oxides from new and existing stationary sources. This revision to Regulation NO.1 is intended to address 

Ft. Carson's need to use obscurants during training and to respond to EPA's August 8, 2001 letter 

regarding Regulation No. 1.Ft. Carson Obscurant usage 

The Commission adopted Regulation No.1, Section II.C. on July 17, 1998, to allow soldiers to 

train with smoke or obscurants on Fort Carson, while requiring that visible emissions from these 

sources not cross the Installation boundary. This was accomplished by limiting the generation of 

smoke and obscurants to training areas at least three kilometers away from the Installation 

boundary. 
Section II.A of the regulation sets a general standard prohibiting emission into the atmosphere of 

any air pollutant which is in excess of 20% opacity. In recognition that smoke and obscurant 

generation in training by the United States Army purposefully intends to be at or near 100% 

opacity, Section II.C was added to Regulation NO.1 in 1998. Section II.C allowed the use of 

military smokes and obscurants at Fort Carson and the Pinon Canyon Maneuver Site (PCMS) 

(both of which will be referred to as Fort Carson or the Installation in this document), subject to 

specified limitations and conditions. 

Since the 1998 adoption, Ft. Carson has documented that the three-kilometer restriction placed 

essential training areas, such as drop zones for airborne operations, an urban war-fighting 

training complex, and a Combined Arms Live Fire Exercise Range, off limits for smoke or 

obscurant training. Consequently, by reducing the amount of available training area, the size and 

scope of training maneuvers were constrained, which diminished how realistic these battlefield 

environments were for the soldiers. Due to world events since 1998, and more particularly since 

September 11, 2001, the training demand at Fort Carson expanded considerably and will likely 

remain at a high level for the foreseeable future, placing even higher demand on limited training 

areas and threatening an inability to train soldiers to standard in a timely manner. The 1998 

version of the regulation also restricted the types of smoke and obscurants, which did not provide 

realistic training for soldiers who would normally use other types of materials during combat 

situations. 

Therefore, the Commission has approved an amendment to the regulation to permit the use of 

more training acreage on Fort Carson for smoke or obscurants, as well as to allow the use of 

current or new Department of Defense- approved materials that create obscurant effects. Such 

changes to the regulation will allow the flexible and realistic military training that the Army 

requires to responsively address lessons learned from actual missions. 

Specifically, the amendment includes the following changes: 

• It replaces the specific reference to fog oil with a general reference to smoke or 

obscurants. This allows the use of other materials and devices that may be used only 

after an authorized Department of Defense official has approved them; 

• It cites more accurately that the training manuals and guidance for using smoke and 

obscurants are Department of Defense documents, not solely those from Fort Carson; 

• It removes the daily fog oil limitations. The relationship of those limitations to protecting 

the national ambient air quality standards appears nonexistent. In contrast, the additional 

specific controls on Fort Carson's use of smoke and obscurants imposed by the 

amended regulation provide a clear basis for compliance with the basic requirement of 

Section II.C, i.e., no transport of emissions from smoke or obscurants off Fort Carson; 

• Similarly, the revision replaces the three-kilometer buffer zone, the scientific basis for 

which has been called into question, with more realistic, yet still effective, planning and 

operating procedures that are equally or more likely to prevent visible emissions from 

crossing the Installation boundary; and 

• It imposes on Fort Carson specific, required measures to be executed before and 

during smoke and obscurant training. These measures will preclude commencement of 

such training under unsatisfactory conditions and stop such training if conditions 

unexpectedly deteriorate. In large part, imposition of these measures recognizes the fact 
that the duty of the Commission to protect the quality of Colorado's air is at one with the 

goal of the Army to provide effective, realistic training. For the Commission, smoke and 

obscurant use must be closely controlled to avoid off-Fort Carson transport. For the 

Army, training must replicate combat conditions. Under those conditions, use of smoke 

and obscurants must likewise be carefully controlled. If a plume travels too quickly or in 

unexpected directions, it will be ineffective at best, counter-productive at worst. 

To complement the specific operational requirements in the amended regulation, Fort Carson will 

revise its internal training regulations to incorporate those requirements. Thus, violations of the 

requirements of the regulation will be subject to military disciplinary or adverse administrative 

action as well as compliance actions under Colorado and federal law. 

Based on discussion between Ft. Carson, the Colorado Department of Public Health and 

Environment, Air Pollution Control Division, and the Environmental Protection Agency, the 

Commission believes that the NAAQS are protected if no visible emissions cross the Installation 

boundary. The Commission has concluded that the more comprehensive and practical control 

measures in the amended regulation provide as great or greater assurances that off-Installation 

transport will not occur as compared to the limitations and conditions in the 1998 version. Thus, 

the amended regulation comports with section 110(1) of the federal Clean Air Act. 

EPA August 2001 letter 

EPA's August 2001 letter raised several issues concerning Regulation NO.1. Some of EPA's issues 

concern changes contained in 1996 and 2001 SIP revisions that are currently pending before EPA. Other 

EPA comments related to provisions of the regulation that are already approved into the SIP. The 

Commission not only amends Regulation No.1, it also hereby amends the SIP and withdraws some 

portions of the previous SIP submittal as appropriate to respond to EPA's comments. The reasons for 

such changes are described here. The scope of the SIP revision is set out below in the section entitled 

"Revisions to the Colorado State Implementation Plan". 

Section III. Particulate Matter 

EPA concern: 

In a recent review of a Colorado operating permit, we ran into confusion regarding the 

applicability of each subsection of Reg. 1, III.C.1. The problem stems from whether the 

categorization of a source as either above or below 30 tons per hour process weight rate is based 

upon the actual process weight rate at a given time for the unit, or based upon the maximum or 

design process weight rate for that unit. The Division indicated that, while it interprets the 

regulation to read as the former, it is considering a revision to the design rate interpretation. It 

would be appropriate and timely for the Division to include this change now with the extensive 

Reg. 1 updates it is making. The Division would be required to provide reasoning that shows that 

the change does not relax the SIP requirements. 

The Commission agrees and has changed the section to read design rate. The division currently uses 

design rate for this purpose so this change only clarifies the current practice. 

Section VI. Sulfur Dioxide 

EPA Concern: 

This part seems to indicate that the emission limit averaging time for sources using fuel sampling 

will be the frequency of the fuel sampling specified in the fuel sampling plan submitted pursuant 

A.1 
to section IV.B.2. We have two concerns with this requirement. First, the averaging time of the 

emission limit should not vary based on the frequency of fuel sampling. Among other things, the 

fuel-sampling plan should describe the test method used to sample the fuel as well as the 

frequency at which the fuel should be sampled. The frequency of sampling should depend on 

whether or not the sulfur in the fuel is expected to remain constant. If it is not constant, it should 

be sampled more frequently than if it does remain constant. The amount of sulfur in the fuel will 

be considered a constant until the fuel is re sampled. If, for example, a fuel is sampled once/day, 

that measured concentration of sulfur in the fuel will be assumed to remain constant for all time 

periods of the day. Compliance with the emission limit is then based on the concentration of 

sulfur in the fuel and the feed rate of the fuel to the source. Second, section IV.B.2 applies only 

to fossil fuel fired stem generators greater then 250 mm BTU/hour heat input, whereas the S02 

emission limits in the section apply to different types of sources including sources less than 250 

mm BTU/hr heat input. Referencing Section IV.B.2 limits section VIA1. 

The Commission agrees that the fuel sampling needs to be tied to the likelihood of the sulfur content in 

the fuel changing. The sampling should be scheduled so that changes in the fuel sulfur are monitored. 

A.3.f 

EPA Concern: 

The end of the first paragraph in Part f - Cement Manufacture- discusses "new sources" We 

question why this paragraph mentions new sources since section VI.A applies to "existing 

sources"? Additionally, section VI.B, which applies to new sources, does not contain emission 

limits for Cement Manufacture, Did you intend the Emission limits for existing Cement 

Manufacture to apply to new sources? 

New cement manufacturing plants will be covered by NSR permits that will include more stringent S02 

emissions limitations than are set out in Regulation NO.1. Therefore, the Commission is removing the 

reference to new cement manufacturing plants in section VI.A.3.f as unnecessary and redundant. 

A& B.1 

EPA Concern: 

These sections are written to make it seem that an existing permitted source (i.e. permitted 

before August 11, 1977) which makes a modification would not be required to meet either 

sections VI.A or VI.B. Section VI.A only applies to sources constructed or modified prior to 

August 11, 1977. Section VI.B does not apply to sources, which constructed or modified and 

have not been issued a permit prior to August 11, 1977. Usually regulations are written so that 

existing sources which modify have to meet more stringent requirements, in this case Section 

VI.B. Is it your intent that existing permitted sources (i.e., permitted before August 11, 1977) 

which make modifications should not be subject to either section VI.A or VI.B? 

The Commission does not believe that there is an issue here. Section VI.A covers sources constructed 

or modified prior to August 11, 1977. Section VI.B covers new sources defined as newly constructed or 

modified which have not been issued an Emission Permit prior to August 11, 1977. Thus a source 

permitted before August 11, 1977 which made a modification would continue to be subject to Section 

VIA While EPA is correct that this does not subject the source to an increased stringency, the source 

would be subject to the regulation. 

EPA Concern: 

B.4 
B.5 

Comments here are on Parts e and g pertaining to emission limit relaxation. The existing SIPapproved rules limit S02 emissions to 0.3 Ibs/day. The State has revised the daily limit to 0.7 

Ibs/day. We view this as a relaxation to the SIP. Section 110(1) of the Act provides that we 

cannot approve a revision to a SIP if the revision would interfere with any applicable requirement 

concerning attainment and reasonable further progress, or any other applicable requirement of 

the Act. Section 110(1) applies to both attainment and unclassifiable areas, as well as nonattainment areas. The revisions may be a relaxation of existing requirements at sources that 

impact PM-1 0 non-attainment areas. As a result, the revisions may aggravate ambient air quality 

problems in the non-attainment area. The State should submit an analysis indicating whether the 

relaxation in the emissions limit will impact the non-attainment area. Also, the state should 

evaluate whether or not the emission limit relaxation would cause or contribute to a violation of 

the S02 increments. Finally, the State should investigate whether section 193 of the Act would 

apply to the relaxed emission limitations. To the extent section 193 does apply, the SIP revision 

would have to provide equivalent or greater emission reductions to offset any emissions 

increases. 

Second, we do not understand why the rules indicate that "the Division shall not limit the 

determination of barrels processed per day to 24 hour period." What is the purpose of this 

sentence? This sentence is also found in section VI.A.3.g.ii 

The division attempted to model compliance with the new standard and found violations of the NAAQS. 

The Commission agrees that the previous language should be reinstated to protect the NAAQS, because 

the modeling did not support the relaxation of the standard. Such changes merely amend the state 

regulation to match the language already contained in the SIP and, therefore, need not be submitted to 

EPA as a SIP revision. Accordingly, the Commission is withdrawing the previously submitted language 

currently pending before EPA as a SIP revision. 

EPA Concern: 

The state deleted this section, which limited emissions of any new source not specifically 

regulated by the rule to 2 tons per day of S02 and to utilize BACT. The same concerns 

we have in our comment in Section B.4.e and g above also apply here. 

The Commission had previously deleted this language because there is similar language in Regulation 

No.6, Section 111.0. However, Regulation No.6, Section 111.0 is not part of Colorado's SIP. Therefore the 

Commission will reinstate the language in Regulation NO.1 and delete the state-only language in 

Regulation NO.6 in a future rule making. 

Other changes 

The division is also addressing several clean up and clarifying changes. 

The open burning provisions of Section II.C are being reinstated in the regulation. Section II.C was 

removed when the division created Regulation No.9, Open Burning, Prescribed Fire, And Permitting. 

The Commission never intended that Regulation NO.9 become part of the SIP, so to maintain the 

integrity of the SIP the Commission is reinstating the open burning provisions in Regulation No.1. 

The Commission is removing the Gates and Rocky Flats boilers from Section VilLA because these boilers 

no longer exist or operate. 

REVISIONS TO THE COLORADO STATE IMPLEMENTATION PLAN 
The AQCC hereby revises and updates the SIP to reflect the July 21,2005 amendments to Regulation 

NO.1. Most of Regulation NO.1 is already in the SIP. Accordingly, only the revisions to the provisions 

listed below adopted on July 21,2005 are SIP revisions. For the convenience of EPA, and because the 

Commission simultaneous made non-substantive numbering changes throughout Regulation No.1, a 

copy of Regulation No.1, as adopted on July 21, 2005, is attached as Appendix A in its entirety. 

Appendix A shall not be construed to be a SIP revision for any provision that has already been 

incorporated into the SIP in its current form, except that EPA may adjust the numbering scheme in the 

SIP to reflect the new numbering scheme. Only the following provisions are submitted as SIP revisions: 

The unnumbered introductory paragraph that is the first paragraph of page 4 of Appendix A. 

Section I.A 

Section II.A.1
 

Section II.A.3
 

Sections II.C
 

Section 11.0
 

Section III.B.2.a
 

Section III.B.3
 

Section III.C.1
 

Section II.C.1.a
 

Section II.C.1.b
 

Section IV.O.2
 

Section IV.A.1
 

Section IV.A.3.f
 

Section VI.A.5
 

Section VI.B.7
 

Section VI.B.5
 

Section VI.0.2.b
 

Section VIII.A.5
 

Section VIII.A.6 

Section IX. 

In addition to submitting the revisions to the twenty-one sections of Regulation NO.1 listed above, the 

Commission also retracts all previously submitted revisions to sections VI.BA.e. and VI.BA.g.(ii). On July 

21, 2005 the Commission revised these two sections of Regulation NO.1 to match these two provisions 

as already incorporated into SIP verbatim. Thus, the versions of these two sections previously submitted 
as SIP revisions no longer match the state regulation and are hereby retracted as SIP revisions. Since 

the versions of sections VI.B.4.e and VI.B.g.(ii) adopted on July 21,2005 match the provisions already 

approved into the SIP, it is not necessary to resubmit them as SIP revisions. In effect, the Commission 

has merely made conforming changes to the state rule to conform to the approved SIP. 

COLORADO AIR QUALITY CONTROL COMMISSION 

ADOPTED: JULY 21, 2005 

Statement of Basis, Specific Statutory Authority, and Purpose 

Revision to Regulation No.1 

September 21,2006 

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 Colorado Air Pollution Prevention and Control Act, section 25-7-109, CR.S., provides the 

commission the authority to adopt and revise rules and regulations that are consistent with state policy 

regarding air pollution and with federal recommendations and requirements. 

Basis and Purpose 

The U.S. Environmental Protection Agency (EPA) promulgated a New Source Performance Standard for 

Commercial and Industrial Solid Waste Incinerators (CISWI) at 40 CFR Part 60, Subpart CCCC on 

December 1, 2000. The Commission incorporated the new standard by reference into Regulation No.6, 

Part A in February 2002. At that time, there were no sources in Colorado subject to Subpart CCCC. In 

September 2005 a new unit subject to Subpart CCCC commenced construction, which raised an issue 

regarding performance-testing requirements for that unit. 

Subpart CCCC of 40 CFR Part 60 applies to air curtain destructors that combust wood or yard wastes at 

a commercial or industrial facility. Subpart CCCC includes performance-testing requirements for such 

units. The Commission's Common Provisions regulation defines air curtain destructors sUbject to 40 CFR 

Part 60 as incinerators, which also subjects them to grain loading standards and performance testing 

requirements under Regulation No.1, Section III.B. It is not feasible, however, to conduct performance 

testing on air curtain destructors for grain loading emissions as specified in Section III.B. due to their lack 

of a stack. 

In order to ensure that appropriate and reasonable emission standards and performance testing 

requirements are applied to air curtain incinerators, the Commission has adopted revisions to Regulation 

No.1, Section III.B. clarifying that air curtain incinerators subject to 40 CFR Part 60 are not subject to 

Section III.B. 

Further, these revisions will include any typographical and grammatical errors throughout the regulation. 

COLORADO AIR QUALITY CONTROL COMMISSION 

ADOPTED: SEPTEMBER 21, 2006 
Notice of Final Adoption
 
STATE OF COLORADO
 Bill Owens. Governor
 

Denn is E. Ellis, Execu rive Director
 

Dedicllted to prorecting and improving the hea(rh and enVlronmenr ofthe people ofColorado 

COLORADO AIR QUALITY CONTROL COMMISSION 

http://www.cdphe.state.co_us 

EDO-AQCC -AS 

4300 Cherry Creek Drive South 

Denver, Colorado 80246-1530 

Phone (303) 692-3100 Colorado Department Fax (303)691-7702 of Public Health TDD (303) 69/-7700 and Environment 

NOTICE OF FINAL ADOPTION 

PURSUANT to the provisions of sections 25-7-105, 25-7-105(12), 25-7-114 through 25-7-114,7, 25-7­

106,25-7-119 and 25-7-132 CR.S. of the Colorado Pollution Prevention and Control Act 

NOTICE IS HEREBY GIVEN that after a public rulemaking hearing September 21, 2006, and in 

compliance with the requirements of sections 25-7-105, 25-7-110, and 25-7-110.5, CR.S., the Colorado 

Air Quality Control Commission made revisions to: 

Regulation Number 6 - Standards of Performance for New Stationary Sources
 

and
 

Regulation Number 1 - Emission Control for Particulate Matter, Smoke,
 

Carbon Monoxide and Sulfur Oxides
 

The Commission adopted revisions to Regulation Number 6 and Regulation Number 1. Pursuant to 

section 25-7-105 to 109 and 25-7-1 14, CR.S. the Commission hereby adopted considerations for 

Regulation 6 by reference a set of provisions to incorporate changes to the federal program in recent 

months and for Regulation Number 1 revisions to the performance testing requirements for air curtain 

destructors. 

This action was submitted to the Secretary of State's Office within 20 days after adoption for publication 

in the Colorado Register, pursuant to 24-4-103(5) and (ll)(d), CR.S_, and will become effective 

November 30, 2006. 

Additionally, pursuant to 24-4-103(8)(d), CR.S., within 20 days after the date of the Attorney General's 

Opinion, this action will be submitted to the Office of Legislative Legal Services for review_ 

Dated this 2nd day of October 2006 at Denver, Colorado_ 

COLORADO AIR QUALITY CONTROL COMMISSION 

Douglas A. Lempke, Administrator